DJ Genel Energy PLC: Full-Year Results
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Genel Energy PLC (GENL)
Genel Energy PLC: Full-Year Results
20-March-2019 / 07:00 GMT/BST
Dissemination of a Regulatory Announcement that contains inside information
according to REGULATION (EU) No 596/2014 (MAR), transmitted by EQS Group.
The issuer is solely responsible for the content of this announcement.
20 March 2019
Genel Energy plc
Audited results for the year ended 31 December 2018
Genel Energy plc ('Genel' or 'the Company') announces its audited results
for the year ended 31 December 2018.
Murat Özgül, Chief Executive of Genel, said:
"Genel's strategy at the start of 2018 was clear - generate material free
cash flow from producing assets, build and invest in a rich funnel of
transformational development opportunities, and return capital to
shareholders at the appropriate time. We are delivering on this strategy.
2018 was another year of material free cash flow generation, we continued to
transform our balance sheet and the addition of assets with the potential of
Sarta and Qara Dagh led to a very successful delivery on the first two parts
of our strategy. We will continue to develop opportunities and invest in
growth. As we do so, a robust cash flow outlook and our confidence in
Genel's future prospects underpins our initiation of a material and
sustainable dividend policy."
Results summary ($ million unless stated)
2018 2017
Production (bopd, working interest) 33,700 35,200
Revenue 355.1 228.9
EBITDAX 1 304.1 475.5
Depreciation and amortisation (136.2) (117.4)
Exploration credit / (expense) 1.5 (1.9)
Impairment of property, plant and equipment - (58.2)
Impairment of intangible assets (424.0) -
Operating (loss) / profit (254.6) 298.0
Cash flow from operating activities 299.2 221.0
Capital expenditure 95.5 94.1
Free cash flow2 164.2 99.1
Cash3 334.3 162.0
Total debt 300.0 300.0
Net cash / (debt)4 37.0 (134.8)
Basic EPS (¢ per share) (101.6) 97.1
Underlying EPS (¢ per share)5 109.0 65.1
1) EBITDAX is operating profit / (loss) adjusted for the add back of
depreciation and amortisation ($136.2 million), exploration credit ($1.5
million) and impairment of intangible assets ($424.0 million)
2) Free cash flow is net cash generated from operating activities less
cash outflow due to purchase of intangible assets ($39.7 million),
purchase of property, plant and equipment ($65.3 million) and interest
paid ($30.0 million)
3) Cash reported at 31 December 2018 excludes $10.0 million of restricted
cash
4) Reported cash less ($334.3 million) less reported balance sheet debt
($297.3 million)
5) EBITDAX less net gain arising from the Receivable Settlement Agreement
('RSA') divided by the weighted average number of ordinary shares
Highlights
· $335 million of cash proceeds were received in 2018 (2017: $263 million)
· Strong cash flow generation, with free cash flow totalling $164 million
in 2018 (2017: $99 million), an increase of 66%
· Financial strength continues to increase, with unrestricted cash
balances at 28 February 2019 of $378 million, and net cash at $81 million
· Addition of Sarta and Qara Dagh to the portfolio in 2019 brings further
near-term production and material growth potential
· Increase in 1P and 2P reserves as of 31 December 2018 to 99 MMbbls (31
December 2017: 97 MMbbls) and 155 MMbbls (31 December 2017: 150 MMbbls)
respectively, including Sarta
· As disclosed in our trading statement, the carrying value of the Miran
licence has been under review. Due to the focus on the development of Bina
Bawi, while Genel continues to see significant opportunity in the licence,
this has resulted in an accounting impairment to the carrying value
Outlook
· Production guidance maintained - net production during 2019 is expected
to be close to Q4 2018 levels of 36,900 bopd, an increase of c.10%
year-on-year
· Capital expenditure guidance updated to include spend on Sarta and Qara
Dagh, with net capital expenditure now forecast to be $150-170 million
(from c.$115 million)
· Opex and G&A guidance unchanged at c.$30 million and c.$20 million
respectively
· Genel expects to generate material free cash flow of over $100 million
in 2019, inclusive of investment in Sarta and Qara Dagh
· Given the strong free cash flow forecast of the business, even after
investment in growth opportunities, Genel is initiating a material and
sustainable dividend policy
· The Company intends to pay a minimum dividend of $40 million per annum
starting in 2020, with the intention for this to grow
· The dividend will be split between an interim and final dividend, to
be paid one-third/two-thirds
· The Company is set to approach bondholders to request a temporary
waiver of the dividend restriction, which limits dividends to 50% of
annual net profit, in relation to accelerating the start of distribution
to 2019
· The Company continues to actively pursue growth and appraise
opportunities to make value-accretive additions to the portfolio
Enquiries:
Genel Energy +44 20 7659 5100
Andrew Benbow, Head of Communications
Vigo Communications +44 20 7390 0230
Patrick d'Ancona
There will be a presentation for analysts and investors today at 0900 GMT,
with an associated webcast available on the Company's website,
www.genelenergy.com [1].
This announcement includes inside information.
Disclaimer
This announcement contains certain forward-looking statements that are
subject to the usual risk factors and uncertainties associated with the oil
& gas exploration and production business. Whilst the Company believes the
expectations reflected herein to be reasonable in light of the information
available to them at this time, the actual outcome may be materially
different owing to factors beyond the Company's control or within the
Company's control where, for example, the Company decides on a change of
plan or strategy. Accordingly no reliance may be placed on the figures
contained in such forward looking statements.
CHAIRMAN'S STATEMENT
I am pleased to welcome you to Genel Energy's eighth annual results
statement. Political stability in the Kurdistan Region of Iraq and a
recovery in the oil price provided a positive backdrop for our operations in
2018. With a firm focus on our renewed strategy, Genel delivered across all
key areas of its business, with the economic tailwinds helping to deliver
material free cash flow and to create significant shareholder value. Highly
cash generative and growing production, supplemented by recent additions to
the portfolio, and our financial strength, position us well to continue this
performance in coming years.
Delivering on our strategy
Our strategic bedrock remains our highly cash-generative producing assets.
The success of Peshkabir, where production grew almost five-fold over the
year to over 50,000 bopd, ahead of schedule and under budget, provided rapid
growth on the Tawke PSC. The increase at Peshkabir was supported by the
redeployment of Taq Taq's early processing facility, and field management
work at the Taq Taq field itself helped to stabilise production and provide
a base from which we expect to now add growth in 2019. The combination of
the two led to Genel slightly outperforming on production guidance for the
year.
Maximising the value of these assets, and generating material free cash
flow, was our core priority and positions us to now focus on progressing the
material opportunities in our portfolio. As we demonstrated our capability
to grow and expand operations, we moved firmly into a net cash position, and
our free cash flow will continue to more than fund our investment programme
for the foreseeable future. Our financial strength will increase further
even as we ramp up our disciplined expenditure, allowing us to initiate a
material and sustainable dividend policy. Our compelling mix of operational
expertise and balance sheet strength has helped us to join up with major
partners as we look to provide a long-term increase in shareholder value.
Growth on all key metrics
As we progress through 2019 we continue to grow on all key metrics. Our cash
position is rising on a monthly basis, our production is forecast to
increase 10% year-on-year, and the addition of Sarta and growth at Peshkabir
has delivered an increase in our 2P reserves.
Last year we stated that Genel aimed to add assets that build on the
strengths of the current portfolio, prioritising areas of low to moderate
political risk while retaining a focus on cash generation. Given the
successful elections and ongoing improvement in the economic situation, we
now see the KRI as such an area, as reflected in the reduction of our
internal discount rate and reinforced by well over three years of
consecutive payments for oil exports.
We were delighted with the addition of stakes in Sarta and Qara Dagh to the
Genel portfolio, which are a key step as we continue to develop
opportunities to expand our portfolio of high-value assets. Being chosen as
a partner by Chevron was a strong endorsement of Genel's technical and
commercial strengths, and the projects are an ideal fit for our strategy.
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DJ Genel Energy PLC: Full-Year Results -2-
Qara Dagh has a proven hydrocarbon system and significant resource potential
estimated by Genel at c.200 MMbbls, while Sarta offers near-term production.
With unrisked gross P50 resources estimated at c.500 MMbbls Sarta has the
potential to scale up and be a low-cost, long-life, cash-generative asset.
Should appraisal work prove successful, field production should materially
increase just as payments from the Receivable Settlement Agreement tail
away, ensuring significant free cash flow generation for years to come.
Generating cash, creating opportunity
The generation of free cash flow is a key focus for Genel, and a core tenet
of our strategy for value creation. It is our aim to generate cash while
delivering transformational growth. In 2018 we generated $164 million in
free cash flow at the same time as increasing Peshkabir production and
progressing the development of our asset portfolio. 2019 will see this
strategy ramp up. We will be involved in the drilling of around 20 wells in
the Kurdistan Region of Iraq, progressing plans for Sarta and Qara Dagh,
finalising the commercial discussion relating to Bina Bawi, and still expect
to generate free cash flow of well over $100 million.
We are a Company that is focused on providing material growth and are
investing accordingly. Ingrained capital discipline and a focus on cash flow
generation provides us with increased confidence over our long-term cash
flows, reaffirming our commitment to share success directly with our
shareholders and leading us to initiate a material and sustainable dividend.
As we look to provide investors with a compelling proposition combining both
growth and a material annual return, we are set to approach bondholders to
request a waiver of the dividend restriction so we might facilitate the
acceleration of a first dividend distribution into 2019.
Long-term value creation
Genel has a balanced portfolio combining near-term cash generation and
potentially transformational growth opportunities. We do not see the
additions of the stakes in Sarta and Qara Dagh as being the end of our
ambitions by any means, and we continue to selectively seek further
additions to the portfolio that match our strategic focus.
2018 was a hugely successful year that also sets up the Company for material
growth in years to come. I would like to take this opportunity to thank our
supportive shareholders, whose patience is now being rewarded, and reaffirm
our commitment to becoming a world-class independent E&P creator of
shareholder value.
CEO STATEMENT
2018 was another successful year for Genel. Our continued focus on our key
objectives helped us to deliver our strategic goals, growing reserves,
production, and cash while adding material growth opportunities.
While looking to grow the business, we never forget that our first priority
is the safety and security of our workforce and the communities in which we
operate. We are pleased to report another year of operations without a lost
time incident and there has now been no such incident at Genel or TTOPCO
operations since 2015, over eight million working hours. In 2018 we also met
our objective of zero losses of primary containment. Genel takes great pride
in our operations, and we work hard to continuously improve our systems and
make sure that all possible precautions are in place. This focus, and the
quality of our workforce, is a factor that is attractive to potential
partners, and therefore important to our overall strategic goals.
Material cash generation
Our primary strategic goal in 2018 was the maximisation of free cash flow
from our producing operations. This was our key capital allocation priority,
and the majority of our $95 million of capital expenditure was invested in
the Tawke and Taq Taq PSCs. As previously stated, we look to invest our
capital in those areas that promise to deliver the most value to
shareholders. In 2018 the priority was therefore Peshkabir, where
exceptional well performance delivers returns of over $8 for every $1
invested, with cost recovery on the initial investment less than a month
after production begins. Few assets anywhere offer such a rapid return.
The investment in the well programme boosted Peshkabir production from
12,000 bopd at the start of 2018 to 55,000 bopd by the year-end. Due to the
high investment returns at Peshkabir, drilling on the Tawke field was
limited in the year, and the field therefore naturally declined. As
Peshkabir moves from appraisal to development, the focus of drilling in 2019
will move back to Tawke. Up to 14 wells are set to be drilled on the main
Tawke field, with the operator expecting production to stabilise at c.75,000
bopd as a result.
Drilling activity at Taq Taq was also limited in 2018. Work in H1 2018
focused on workovers and well management, and so the performance of the
field ahead of the resumption of drilling was very encouraging, with minimal
production declines. We are now two wells into a five well drilling
programme, focused on the flanks of the field. Production from the last two
wells, TT-29w and TT-32, has been robust - and illustrates that there are
still wells to be drilled at Taq Taq that are attractive economically. The
positive performance has significantly increased well profitability, making
wells at Taq Taq again an attractive capital allocation option.
This focus on capital allocation, and the positive drilling results, helped
boost our free cash flow to $164 million. We expect to continue generating
material free cash flow in 2019 - $44 million was generated in the first two
months of the year - even after investing in the tremendous profitable
growth opportunities within our portfolio.
Adding growth opportunities
The addition of stakes in Sarta and Qara Dagh was a huge positive for Genel.
The two fields provide precisely what we are looking for as we take steps to
build a portfolio of high-value assets - low-cost, low-risk entry into
opportunities that promise near-term production, with material growth
potential and significant longer term upside.
Sarta will be brought on to production in 2020, and it has the potential for
production to ramp up to transformational levels. In the success case, Sarta
perfectly fits into Genel's production profile, with the potential to add
company-changing cash flows after the override payments under the receivable
settlement agreement end in H2 2022.
Being chosen as a partner by Chevron is a real boost for Genel, and the
combination of the two companies brings together Genel's experience in the
KRI and low-cost operating capability on the ground with Chevron's oil major
capabilities.
We look forward to getting started both at Sarta and Qara Dagh, with the
latter most likely being the premier remaining appraisal opportunity in the
KRI. There is a proven hydrocarbon system on the block, with a previous well
drilled off structure flowing light oil. The chance to therefore drill a
more optimally located well is enormously exciting.
Bina Bawi is the third asset in our portfolio that has transformational
growth potential. With light oil able to be produced within six months of
the agreement of commercial terms with the government it is a significant
opportunity, although progress on reaching such an agreement with the
Kurdistan Regional Government ('KRG') has been challenging. A field
development plan ('FDP') for Bina Bawi relating to both oil and gas was
submitted in H2 2018 detailing the early production of light oil and taking
a phased development approach towards the gas, which would reduce initial
capital expenditure and achieve the earliest date for first gas.
Talks have recently focused on how best to develop the oil and progress the
gas project. The deadline to meet the conditions precedent related to the
Bina Bawi gas lifting agreement has been extended until 30 April 2019, after
which there is a further 12 months to renegotiate the gas lifting agreement.
Constructive talks are continuing, and can do so after April, and any
significant further investment in the Bina Bawi licence will be subject to
an appropriate commercial solution agreed with the KRG.
A field development plan was also submitted for Miran. As noted in our
trading and operations update in January, with the focus on Bina Bawi, we
have reviewed of the value of the Miran PSC carried in the Company accounts.
The decision has been made to write down the Miran asset by $424 million,
pending any movement on field development discussions. We continue to
believe that the licence holds significant potential, and development can
follow a similar plan to Bina Bawi, but pending clarity on a development
timeline, this is a prudent action based on accounting principles.
Returning capital to shareholders
Genel has a balanced portfolio, with material production and cash generation
and transformational growth opportunities in the pipeline. These
opportunities are more than funded out of our current cash flow, and our
outlook illustrates that our cash position will continue to grow over the
long-term while still allowing for ongoing portfolio investment and more. As
such, now is the right time for us to initiate a material and sustainable
dividend policy.
Outlook
In 2019 we expect production to grow, material cash generation, and the
progression of the opportunities in our portfolio.
Our strategic ambitions remain clear - we will focus on generating cash,
investing in opportunities, and returning capital to shareholders. Our
ability to do the latter is the next step in delivering on our strategy. We
remain committed to materially growing the company, and will actively
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DJ Genel Energy PLC: Full-Year Results -3-
appraise opportunities to make disciplined additions to the portfolio that
will further bolster our cash generation story.
OPERATING REVIEW
Reserves and resources development
Genel's proven (1P) and proven plus probable (2P) net working interest
reserves totalled 99 MMbbls and 155 MMbbls respectively, a reserve
replacement ratio of 117% and 141%.
This increase follows successful drilling at Peshkabir helping bolster
reserves replacement on the Tawke PSC, stability at Taq Taq, and the
addition of reserves at Sarta post-period end.
Remaining reserves Resources (MMboe)
(MMboe)
Contingent Prospective
1P 2P 1C 2C Best
Gross Net Gross Net Gross Net Gross Net Gross Net
31 December 371 97 559 150 1,306 1,2 3,022 2,81 3,682 2,549
2017 39 3
Production (46) (12) (46) (12) - - - - - -
Extensions - - - - - - - - - -
and
discoveries
New - - - - - - - - - -
development
s
Revision of 44 11 27 7 (32) (9) (197) (52) (15) (7)
previous
estimates
31 December 369 96 540 145 1,274 1,2 2,826 2,76 4,267 2,731
2018 30 1
Post-period 10 3 34 10 - - - - 600 189
acquisition
Updated 379 99 574 155 1,274 1,2 2,826 2,76 3,667 2,542
reserves 30 1
and
resources
Production
Production in 2018 was 33,700 bopd, with the success at Peshkabir and
stability at Taq Taq helping to offset the natural field declines at Tawke.
Drilling in 2018 was concentrated on the successful appraisal campaign at
Peshkabir, with only limited activity at the Tawke field and Taq Taq. 2019
will see more development work at Peshkabir, while 10 wells are set to be
drilled at Tawke and four at Taq Taq. Through stabilising production at
Tawke, Genel expects production in 2019 to be roughly in line with that of
Q4 2018, 36,900 bopd, an increase of approximately 10% year-on-year.
Work over the last two years has significantly diversified our producing
well stock. At the start of 2017 production came from 46 wells at two
fields. The number of producing wells had increased by 50% by January 2019,
and our production now comes from 69 wells at three fields, making the
portfolio more diverse and reliable for production and cash flow.
Average production in 2019 to date is 37,200 bopd, in line with guidance.
KRI assets
Tawke PSC (25% working interest)
Production on the Tawke PSC, operated by DNO, averaged 113,020 bopd in 2018,
with production from Peshkabir contributing 27,660 bopd to this figure. With
drilling activity on the Tawke PSC concentrating on Peshkabir, production at
the Tawke field declined to 75,000 bopd by the end of 2018. Work in 2019
will be focused on stabilising production, and 10 wells have been included
in Genel's firm activity plan for the year, with the operator planning to
drill up to 14.
Activity in H1 2018 included ongoing workovers of existing wells, and
limited drilling resumed in H2. One deep Cretaceous well and two shallow
Jeribe wells were brought onstream, and these zones will continue to be
targeted for production in 2019.
Peshkabir
Ongoing drilling success at Peshkabir resulted in production increasing from
12,000 bopd in January to over 55,000 bopd at the end of 2018, ahead of
schedule and under budget. Wells were drilled across the structure, and each
successfully added to production.
Ahead of the commissioning of a 50,000 bopd central processing facility
('CPF') each well produced via test spreads, a cost-effective way of
maximising cash generation while appraising the field. This is a model that
we will look to replicate at Sarta and Qara Dagh.
In 2018 the focus at the field was on drilling and appraising, and six wells
were drilled in the year. Another two are scheduled in our firm budget for
2019, when field development work will come to the fore. As well as the
ongoing commissioning of a 50,000 bopd CPF, a 60,000 bopd capacity pipeline
is under construction and work will begin later in the year on building the
gas gathering and processing facilities to enable reinjection of the
associated gas produced at the field into the Tawke field, both reducing
flaring and increasing recoverability at the latter. The gas gathering and
injection system is forecast to be operational in early 2020.
The first well in the 2019 programme, Peshkabir-9, has now been completed as
a producing well. The well was drilled on the eastern flank of the
structure, two kilometres from the Peshkabir-3 well, and therefore confirms
production across the entirety of the Peshkabir structure. Production at
Peshkabir is currently c.55,000 bopd.
Taq Taq (44% working interest, joint operator)
Taq Taq performed well in 2018, with production stabilising in the second
half of the year through successful field management operations and
workovers. Drilling on the field has restarted in earnest, with successful
progress being made on our five well programme targeting the flanks of the
field. Two wells in the programme have now been completed.
The TT-32 well on the northern flank followed the success of TT-29w, and it
is currently contributing c.3,000 bopd to overall field production. The rig
has now moved to drill the TT-20 well, with a further three wells scheduled
to be drilled at Taq Taq in 2019. We will continue with the current well
programme, with the aim of adding to overall field production.
Sarta (30% working interest)
Having completed the transaction in February, the field partners are now
progressing with the development of the asset, which will be done in phases.
Phase 1A begins with the recompletion of the Sarta-2 well and the placing of
the Sarta-3 well on production, both of which flowed c.7,500 bopd on test,
and the construction of a central processing facility with a 20,000 bopd
capacity. The processing facility will be installed on a lease operate
maintain basis.
First oil is expected in the middle of 2020, with a total cost to Genel of
$60 million to the end of 2020. Initial production will be trucked.
Following the completion of the initial wells in 2020, it is expected that
the rig will move to drill back to back development wells as we rapidly
appraise the field. Further production capacity will then be added as
required as the field is developed and production ramps up, with test
spreads being used in a similar way as they were in the development of
Peshkabir.
The use of an appraise while producing strategy akin to Peshkabir will allow
for the optimal evaluation of the gross resources with further production
capacity being added as the field is appraised.
Qara Dagh (40% working interest, operator)
Genel acquired 40% equity in the Qara Dagh appraisal licence and became the
operator through a carry arrangement, covering activity for the QD-2 well.
This well is estimated to cost c.$40 million and is set to be drilled in H1
2020.
Qara Dagh offers an exciting appraisal opportunity. The QD-1 well, completed
in 2011, tested light oil in two zones from the Shiranish formation. This is
despite it being drilled on a location based on an incorrect structural
model, which has since been re-evaluated through the subsequent reprocessing
of 2D seismic, further 2D seismic acquisition, and the integration of
learnings from the QD-1 well.
The QD-2 well is designed to test a more crestal position on the structure
with a high angle well to maximise contact with reservoir fractures. Work is
underway on assessing the optimal location for the well.
Bina Bawi and Miran (100% working interest, operator)
Bina Bawi and Miran are assets that have the potential to generate
significant shareholder value, and efforts in 2018 continued to explore a
commercial solution to allow the unlocking of the material resources.
Work is focused on Bina Bawi, where the potential for the development of
light oil provides the opportunity for near-term revenues that in turn can
be used to expedite the development of the 8.2 Tcf of gas resources. The
field is also preferentially situated, being only 30 km from Taq Taq's
central processing facility and export route.
The FDP for oil at Bina Bawi detailed the production of 15 MMbbls of light
oil during the first phase, with first oil production being possible around
six months following final investment decision, which is predicated on
approval by the KRG.
The FDP for gas at Bina Bawi detailed a gas project with an initial raw gas
capacity of 250-300 MMscfd, adopting a modular development strategy that
would utilise incremental increases as facilities are replicated. This
reduces the capital expenditure requirement to first gas while retaining
material future upside. Operational progress at Bina Bawi is dependent on an
agreement on commercial terms, and Genel will step up efforts to bring in a
partner once the project is more clearly defined. Any progress at Miran
would be subsequent to Bina Bawi.
Exploration and appraisal
Africa
Onshore Somaliland, seismic processing completed on the SL-10-B/13 block
(Genel 75% working interest, operator) in Q4 2018, and analysis and
interpretation is underway. Initial indications confirm the Company view
that the block has hydrocarbon potential. Genel continues to develop a
prospect inventory and assess next steps ahead of a farm-out process and
potentially spudding a well with a partner in 2020. On the Odewayne block
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DJ Genel Energy PLC: Full-Year Results -4-
further seismic processing is to be undertaken in order to complete the Company's understanding of the prospectivity of the block. On the Sidi Moussa block offshore Morocco (Genel 75% working interest, operator), the acquisition of a c.3,500 km2 multi-azimuth broadband 3D seismic survey completed in November. PSTM and PSDM processing will continue through 2019. Genel has no additional work commitments relating to the licence. The Company will undertake a farm-out campaign once processing and interpretation has progressed sufficiently, ahead of a decision on whether to drill a well in the future. FINANCIAL REVIEW Overview The Company has maintained its disciplined and value focused capital allocation philosophy, investing primarily in its producing assets in 2018. The result is significant free cash flow generation of $164 million, an increase of 66% on the previous year, and a transformed balance sheet, with net cash of $37 million reported at year-end, a figure that increased to $81 million by the end of February. Proceeds of $335 million were significantly higher than the previous year (2017: $263 million), as a result of a full year of benefit from the RSA, which was effective from August 2017 and an improved average oil price average of $71/bbl (2017: $54/bbl). EBITDAX of $304 million was an increase of 67% on last year, if the one-off gain arising from the RSA is excluded. The Company's capital allocation priority remains unchanged: investing in the growth of the business, both on existing assets and also adding new assets. With an enhanced long term portfolio, continuous focus on value and increased cash generation, we are confident in delivering on our objective to become the industry leading generator of shareholder value. The financial strength of the business, its strong future cash generation and its resilience to downside scenarios has led us to initiate a material and sustainable dividend policy. We intend to pay a minimum dividend of $40 million per annum, with the intention of growing this as our liquidity increases. Due to our resilience, this minimum is payable at a lower oil price, but we will of course ensure that payments made are appropriate. We will pay a dividend in 2020 relating to the 2019 financial year, with the intention that this will be split between an interim and final dividend, to be paid one-third/two-third. Although we have been strengthening our credit continuously, and will continue to do the same, the non-cash impairment of the Miran gas asset means that we need to seek a waiver from our bondholders for a dividend in 2019. Subject to acceptable waiver discussions with our bondholders, we intend to accelerate the distribution and pay a dividend in 2019. Our dividend policy provides a meaningful and competitive return to shareholders, appropriately commensurate with the underlying value of the business, without in any way compromising our ability to invest in growth through progression of value realisation from our existing portfolio and the acquisition of appropriate new assets. Successful focus on financial objectives For 2018, the financial priorities of the Company were the following: · Continued focus on capital allocation, with prioritisation of highest value investment in assets with ongoing or near-term cash generation · Continued focus on cost optimisation and performance management · Maintenance of a strong balance sheet and management of liquidity runway throughout the development of the Bina Bawi and Miran fields · Selective investment in value accretive opportunities that provide visible cash generation and debt capacity Cost recoverable investment in producing assets led to positive results. At Peshkabir a high performance ramp up was achieved, increasing production from c.15,000 bopd to c.55,000 bopd. At Taq Taq, wells drilled successfully increased production at the end of the year, and TT-32 suggests there is potential for additional upside production that can be unlocked from further drilling work. Towards the end of the year, work on Tawke included workovers and the drilling of additional wells. We expect to realise the benefits of these wells next year when, together with further wells planned in 2019, the incremental production is planned to stabilise production at this mature field. Operating expenditure at our producing assets was already one of the lowest in the world at c.$2.5/bbl - in 2018 the average operating expense per barrel remained at around the same level. At Bina Bawi, commercial discussions have been ongoing with capital investment delayed until an appropriate commercial structure with an appropriate derisked cash flow profile can be agreed. We continue to look at the best way to develop the asset and minimise spend while maximising the potential for value creation. We will continue this approach in 2019. At Miran, any progress would be subsequent to Bina Bawi, with Miran effectively held on a care and maintenance basis in the meantime. The clear separation of the two assets and the prioritisation of Bina Bawi has resulted in a significant impairment to the carrying value of the Miran PSC. Detail is provided in note 1 to the financial statements. Through the year, the Company has assessed potential asset acquisition opportunities with a priority on low-cost entry and near-term cash generation. This has resulted in the completion of the acquisition of interests in the Sarta and Qara Dagh licences in early 2019, which represent significant growth potential for the Company. We will pursue further acquisition activity in the future. For 2019 the financial priorities of the Company are the following: · Continued focus on capital allocation, with prioritisation of highest value investment in assets with ongoing or near-term cash and value generation · Investment in lower risk development of opportunities with high potential, currently these are targeting first oil in 2020 at Sarta and drilling an exploration well on a discovered resource at Qara Dagh. Investment at Bina Bawi will be added should appropriate commercial terms and conditions be reached · Continued focus on identifying assets to add to the portfolio that offer potential for adding significant value to the Company with near to mid-term cash generation, primarily to build the Company's cash generation options when the override royalty agreement ends in Q3 2022 and provide the basis for increasing the dividend in the future · Continued focus on the capital structure of the Company A summary of the financial results for the year is provided below. Financial results for the year Income statement Working interest production of 33,700 bopd was slightly reduced compared to last year (2017: 35,200 bopd), principally as a result of decline in Tawke which was mostly offset by Peshkabir. Revenue increased from $228.9 million to $355.1 million. The year-on-year increase was caused principally by improved oil price of average $71/bbl (2017 average: $54/bbl) and a full year impact of the RSA, which was effective from August 2017. Production costs of $28.7 million slightly increased from last year (2017: $27.5 million) primarily as a result of production contribution from Peshkabir. The increase in revenue resulted in EBITDAX of $304.1 million, this is lower than last year (2017: $475.5 million), which included the one off gain on RSA of $293.8 million. Excluding the one-off gain last year, EBITDAX improved by 67%. Depreciation of $72.4 million (2017: $83.3 million) reduced year-on-year as a result of lower production. Amortisation of Tawke intangibles increased to $62.1 million due to a full year impact of the RSA (2017: $32.8 million). Exploration expense resulted with a credit balance of $1.5 million with the net effect of $1.3 million release of previous years' accruals for already relinquished Cote d'Ivoire licence and net $0.2 million for Morocco licence (2017: $1.9 million expense). An impairment expense of $424.0 million (2017: $58.2 million) was recorded in relation to the Miran PSC, which is explained further in note 1. Cash general and administrative costs of $17.4 million were largely unchanged (2017: $16.9 million). Finance income of $4.4 million (2017: $4.9 million) was bank interest income (2017: $2.2 million). Other finance expense of $3.2 million (2017: $28.0 million) was comprised of non-cash discount unwind expense on liabilities (2017: $8.3 million) whereas last year there was $3.7 million premium paid and $16.0 million accelerated discount unwind on redemption of the bonds. There is no taxation on operational profits: under the terms of KRI PSC's, corporate income tax due is paid on behalf of the Company by the KRG from the KRG's own share of revenues, resulting in no corporate income tax payment required or expected to be made by the Company. Tax presented in the income statement of $0.2 million (2017: $1.0 million) was related to taxation of the Turkish and UK service companies. Capital expenditure Capital expenditure in the year was $95.5 million (2017: $94.1 million). Cost recovered spend on producing assets in the KRI was $70.4 million (2017: $59.5 million) with spend on exploration and appraisal assets amounting to $25.1 million (2017: $34.6 million), principally incurred on the Miran, Bina Bawi and Somaliland PSCs. Cash flow and cash Net cash flow from operations was $299.2 million (2017: $221.0 million). This was positively impacted by $92.5 million (2017: $86.5) of proceeds being received for the historic KRG receivable, and $242.6 million (2017: $176.8 million) received for current sales.
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DJ Genel Energy PLC: Full-Year Results -5-
Free cash flow before interest was $194.2 million (2017: $141.8 million) and
free cash flow after interest was $164.2 million (2017: $99.1 million).
$10.0 million (2017: $18.5 million) of cash was restricted and therefore
excluded from reported cash of $334.3 million (2017: $162.0 million).
Overall, there was a net increase in cash of $172.7 million compared to a
decrease of $245.1 million last year.
Debt
Total debt was at $297.3 million (2017: $296.8 million) and resulted in net
cash of $37.0 million (2017: $134.8 million net debt).
The bond has three financial covenant maintenance tests:
Financial covenant Test YE2018
Net debt / EBITDAX< 3.0 (0.1)
Equity ratio (Total equity/Total assets) > 40% 73%
Minimum liquidity > $30m $334m
Net assets
Net assets at 31 December 2018 were $1,331.4 million (2017: $1,609.8
million) and consist primarily of oil and gas assets of $1,384.2 million
(2017: $1,847.9 million), trade receivables of $94.8 million (2017: $73.3
million) and net cash of $37.0 million (2017: $134.8 million net debt).
Liquidity / cash counterparty risk management
The Company monitors its cash position, cash forecasts and liquidity on a
regular basis. The Company holds surplus cash in treasury bills or on time
deposits with a number of major financial institutions. Suitability of banks
is assessed using a combination of sovereign risk, credit default swap
pricing and credit rating.
Dividend
No dividend (2017: nil) has been declared for the year ended 31 December
2018. Note that the Companies (Jersey) Law 1991 does not define the
expression "dividend" but refers instead to "distributions". Distributions
may be debited to any account or reserve of the Company (including share
premium account), save for nominal capital account or capital redemption
reserve. In all cases, the Company is only permitted to make a distribution
if the Directors authorising it have made a prior solvency statement. The
Directors will decide which account to debit in relation to each specific
distribution.
Going concern
The Directors have assessed that the Company's forecast liquidity provides
adequate headroom over forecast expenditure for the 12 months following the
signing of the annual report for the period ended 31 December 2018 and
consequently that the Company is considered a going concern.
Consolidated statement of comprehensive income
For the year ended 31 December 2018
Note 2018 2017
$m $m
Revenue 2 355.1 228.9
Production costs 3 (28.7) (27.5)
Depreciation and amortisation of oil assets 3 (134.5) (116.1)
Gross profit 191.9 85.3
Exploration credit / (expense) 3 1.5 (1.9)
Impairment of property, plant and equipment 3 - (58.2)
Impairment of intangible assets 3 (424.0) -
General and administrative costs 3 (24.0) (21.0)
Net gain arising from the RSA 10 - 293.8
Operating (loss) / profit (254.6) 298.0
Operating (loss) / profit is comprised of:
EBITDAX 304.1 475.5
Depreciation and amortisation 3 (136.2) (117.4)
Exploration credit / (expense) 3 1.5 (1.9)
Impairment of property, plant and equipment 3 - (58.2)
Impairment of intangible assets 3 (424.0) -
Gain arising from bond buy back 15 - 32.6
Finance income 5 4.4 4.9
Bond interest expense 5 (30.0) (35.5)
Other finance expense 5 (3.2) (28.0)
(Loss) / Profit before income tax (283.4) 272.0
Income tax expense 6 (0.2) (1.0)
(Loss) / Profit and total comprehensive (283.6) 271.0
(expense) / income
Attributable to:
Shareholders' equity (283.6) 271.0
(283.6) 271.0
(Loss) / Profit per ordinary share ¢ ¢
Basic 7 (101.6) 97.1
Diluted 7 (101.6) 96.7
Consolidated balance sheet
At 31 December 2018
Note 2018 2017
$m $m
Assets
Non-current assets
Intangible assets 8 818.4 1,282.9
Property, plant and equipment 9 565.8 565.0
1,384.2 1,847.9
Current assets
Trade and other receivables 10 99.4 78.5
Restricted cash 11 10.0 18.5
Cash and cash equivalents 11 334.3 162.0
443.7 259.0
Total assets 1,827.9 2,106.9
Liabilities
Non-current liabilities
Trade and other payables 12 (76.8) (70.7)
Deferred income 13 (31.9) (36.1)
Provisions 14 (32.9) (29.3)
Borrowings 15 (297.3) (296.8)
(438.9) (432.9)
Current liabilities
Trade and other payables 12 (52.6) (59.4)
Deferred income 13 (5.0) (4.8)
(57.6) (64.2)
Total liabilities (496.5) (497.1)
Net assets 1,331.4 1,609.8
Owners of the parent
Share capital 17 43.8 43.8
Share premium account 4,074.2 4,074.2
Accumulated losses (2,786.6) (2,508.2)
Total equity 1,331.4 1,609.8
Consolidated statement of changes in equity
For the year ended 31 December 2018
Share Share Accumulated Total equity
capital premium losses
$m
$m $m $m
At 1 January 43.8 4,074.2 (2,784.6) 1,333.4
2017
Profit and - - 271.0 271.0
total
comprehensive
income
Share-based - - 5.4 5.4
payments
At 31 December 43.8 4,074.2 (2,508.2) 1,609.8
2017 and 1
January 2018
(Loss) and - - (283.6) (283.6)
total
comprehensive
(expense)
Share-based - - 5.2 5.2
payments
At 31 December 43.8 4,074.2 (2,786.6) 1,331.4
2018
Consolidated cash flow statement
For the year ended 31 December 2018
Note 2018 2017
$m $m
Cash flows from operating activities
(Loss) / Profit and total comprehensive (283.6) 271.0
(expense) / income
Adjustments for:
Gain on bond buy back 15 - (32.6)
Finance income 5 (4.4) (4.9)
Bond interest expense 5 30.0 35.5
Other finance expense 5 3.2 28.0
Taxation 6 0.2 1.0
Depreciation and amortisation 3 136.2 117.4
Exploration (credit) / expense 3 (1.5) 1.9
Impairment of property, plant and equipment 3 - 58.2
Impairment of intangible assets 3 424.0 -
Net gain arising from the RSA 10 - (293.8)
Other non-cash items 3 4.9 2.8
Changes in working capital:
(Increase) / decrease in trade receivables (21.5) 38.3
(Increase) in other receivables (1.1) (4.3)
Increase in trade and other payables 9.2 0.6
Cash generated from operations 295.6 219.1
Interest received 5 4.4 2.2
Taxation paid (0.8) (0.3)
Net cash generated from operating 299.2 221.0
activities
Cash flows from investing activities
Purchase of intangible assets (39.7) (26.8)
Purchase of property, plant and equipment (65.3) (52.4)
Restricted cash 11 8.5 1.0
Net cash used in investing activities (96.5) (78.2)
Cash flows from financing activities
Repurchase of Company bonds 15 - (216.7)
Bond refinancing 15 - (128.5)
Interest paid (30.0) (42.7)
Net cash used in financing activities (30.0) (387.9)
Net increase / (decrease) in cash and cash 172.7 (245.1)
equivalents
Foreign exchange (loss) / income on cash (0.4) 0.1
and cash equivalents
Cash and cash equivalents at 1 January 11 162.0 407.0
Cash and cash equivalents at 31 December 11 334.3 162.0
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 - registration
number: 107897 (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
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'IFRS'); are prepared under the historical cost convention except as where
stated; and comply with Company (Jersey) Law 1991. The significant
accounting policies are set out below and have been applied consistently
throughout the period.
The Company prepares its financial statements on a historical cost basis,
unless accounting standards require an alternate measurement basis. Where
there are assets and liabilities calculated on a different basis, this fact
is disclosed either in the relevant accounting policy or in the notes to the
financial statements.
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
judgements and estimates on pages 18 and 21.
The Company provides non-Gaap measures to provide greater understanding of
its financial performance and financial position. EBITDAX is presented in
order for the users of the financial statements to understand the cash
profitability of the Company, which excludes the impact of costs
attributable to exploration activity, which tend to be one-off in nature,
and the non-cash costs relating to depreciation, amortisation and
impairments. EBITDAX is used as the basis for underlying earnings per share,
for the reasons provided above. Free cash flow is presented in order to show
the free cash flow generated that is available for the Board to invest in
the business. Net debt is reported in order for users of the financial
statements to understand how much debt remains unpaid if the Company paid
its debt obligations from its available cash. There have been no changes in
related parties since last year.
Going concern
The Company regularly evaluates its financial position, cash flow forecasts
and its covenants by sensitizing with a range of scenarios which
incorporates change in oil prices, discount rates, production volumes as
well as capital and operational spend. As a result, the Directors have
assessed that the Company's forecast liquidity provides adequate headroom
over its forecast expenditure for the 12 months following the signing of the
annual report for the period ended 31 December 2018 and consequently that
the Company is considered a going concern.
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 has neither control nor
joint control are classified as associates and accounted for under the
equity method.
The Company recognises its assets and liabilities relating to its interests
in joint operations, including its share of assets held jointly and
liabilities incurred jointly with other partners.
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 and estimates
The preparation of the financial statements in accordance with IFRS requires
the Company to make judgements and estimates that affect the reported
results, assets and liabilities. Where judgements and estimates are made,
there is a risk that the actual outcome could differ from the judgement or
estimate made. The Company has assessed the following as being areas where
changes in judgements or estimates could have a significant impact on the
financial statements.
Significant judgements
The following is the critical judgement, apart from those involving
estimations (which are dealt with separately below), that the directors have
made in the process of applying the Company's accounting policies and that
has the most significant effect on the amounts recognised in the financial
statements.
Tawke CGU
Tawke RSA intangible asset (which is explained below) cash flows had the
same risk profile as revenue generated from the Tawke PSC; oil price,
production profile, reserves and discount rate were estimated using the same
methodology as used for the impairment testing of the Tawke PSC property,
plant and equipment, as a result, both assets are combined as a single cash
generating unit for impairment testing.
Significant estimates
Estimation of hydrocarbon reserves and resources and associated production
profiles and costs
Estimates of hydrocarbon reserves and resources are inherently imprecise and
are subject to future revision. The Company's estimation of the quantum of
oil and gas reserves and resources and the timing of its production, cost
and monetisation impact the Company's financial statements in a number of
ways, including: testing recoverable values for impairment; the calculation
of depreciation and amortisation and assessing the cost and likely timing of
decommissioning activity and associated costs. This estimation also impacts
the assessment of going concern and the viability statement.
Proven and probable reserves are estimates of the amount of hydrocarbons
that can be economically extracted from the Company's assets. The Company
estimates its reserves using standard recognised evaluation techniques.
Assets assessed as proven and probable reserves ("2P" - generally accepted
to have circa 50% probability) are generally classified as property, plant
and equipment as development or producing assets and depreciated using the
units of production methodology. The Company considers its best estimate for
future production and quantity of oil within an asset based on a combination
of internal and external evaluations and uses this as the basis of
calculating depreciation, amortisation of oil and gas assets and testing for
impairment.
Hydrocarbons that are not assessed as 2P are considered to be resources and
are classified as exploration and evaluation assets. These assets are
expenditures incurred before technical feasibility and commercial viability
is demonstrable. Estimates of resources for undeveloped or partially
developed fields are subject to greater uncertainty over their future life
than estimates of reserves for fields that are substantially developed and
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DJ Genel Energy PLC: Full-Year Results -7-
being depleted and are likely to contain estimates and judgements with a
wide range of possibilities. These assets are considered for impairment
under IFRS6.
Once a field commences production, the amount of proved reserves will be
subject to future revision once additional information becomes available
through, for example, the drilling of additional wells or the observation of
long-term reservoir performance under producing conditions. As those fields
are further developed, new information may lead to revisions.
Assessment of reserves and resources are determined using estimates of oil
and gas in place, recovery factors and future commodity prices, the latter
having an impact on the total amount of recoverable reserves.
Change in accounting estimate
The Company has updated its estimated reserves and resources with the
accounting impact summarised below under estimation of oil and gas asset
values.
Estimation of oil and gas asset values
Estimation of the asset value of oil and gas assets is calculated from a
number of inputs that require varying degrees of estimation. Principally oil
and gas assets are valued by estimating the future cash flows based on a
combination of reserves and resources, costs of appraisal, development and
production, production profile and future sales price and discounting those
cash flows at an appropriate discount rate.
Future costs of appraisal, development and production are estimated taking
into account the level of development required to produce those reserves and
are based on past costs, experience and data from similar assets in the
region, future petroleum prices and the planned development of the asset.
However, actual costs may be different from those estimated.
Discount rate is assessed by the Company using various inputs from market
data, external advisers and internal calculations. A discount rate of 12.5%
was used for impairment testing of the oil assets of the Company.
In addition, the estimation of the recoverable amount of the both the Miran
and Bina Bawi CGUs, which are classified under IFRS as an exploration and
evaluation intangible asset and consequently carries the inherent
uncertainty explained above, include the key assessment that the projects
will progress, which is outside of the control of management and is
dependent on the progress of government to government discussions regarding
supply of gas and sanctioning of development of both of the midstream for
gas and the upstream for oil. Lack of progress could result in significant
delays in value realisation and consequently a lower asset value.
Change in accounting estimate - Discount rate for assessing recoverable
amount of producing assets
Following the significant change in the macro geo-political, economic and
industry environment, the Company has updated the discount rate used for
assessing the recoverable amount of its producing assets from 15% to 12.5%.
This has had no impact on the financial statements, although it has a
positive impact on the recoverable amount of both the Tawke CGU and the Taq
Taq CGU. At the end of last year, the Company disclosed that a 2.5% change
in discount rate would have a $70 million impact on the recoverable amount
of the Tawke CGU and a $5 million impact on the Taq Taq CGU. The disclosures
for the year-end are provided in note 9.
Change in accounting estimate and judgement - Miran PSC (intangible assets)
As a result of the development of negotiations through 2018, management
assess the Bina Bawi and Miran PSCs as separate cash generating units,
whereas last year they were assessed as one cash generating unit. Whereas
previously a large scale combined processing facility serving both assets
was considered, with delivery of required gas volumes contributed from
either licence, discussions are now focused on commencing with a smaller
scale development of the Bina Bawi asset that would then be scaled up in
phases, with development of the Miran PSC deprioritised. Management assesses
the deprioritisation of the Miran PSC, with discussions on Bina Bawi active
and detailed, as an impairment indicator and consequently have tested its
carrying value for impairment. Principal changes to past estimates relating
to the fair value less costs of disposal valuation of Miran relate to
timing, cost estimates and risking. Because of the uncertainties existing
around these items, as well as approach and commercial terms for the
development of the asset, the assessment of valuation carries inherent
uncertainty and for this reason, in addition to the estimates made, the
Board has included contingencies for costs and timing and additionally an
overall reduction in valuation to reflect risking of the project. The
risking has been applied at 50% of the calculated value, which was assessed
using a discount rate of 15%. This has resulted in an estimate of the
recoverable value of Miran as $113 million, which results in an impairment
charge of $424 million.
Tawke RSA intangible asset
On 23 August 2017 the Company signed documentation confirming an agreement
had been reached with the KRG to put in place a definitive mechanisms for
the payment to the Company of trade receivables built up from overdue
amounts with nominal value of $469 million owed for sales since mid-2014
('overdue KRG receivable') together with nominal value of circa $300 million
amounts owed for export sales marketed by SOMO made before 2014 for which
the Company has never recognised revenue ('overdue pre-2014 receivable').
Until the RSA, the Company reported the overdue KRG receivable in the
balance sheet at its amortised cost. Key inputs to the assessment of
amortised cost were: oil price, production forecast and mechanism for
payment. Estimates of oil price and production forecast were based on the
inputs used for testing of property, plant and equipment for impairment.
When estimating the payment mechanism, although the Company expected either
an increase in payments, or an alternative structure to be agreed to
accelerate payments, it was assessed that there was not sufficient evidence
to support the use of anything other than the existing payment mechanism,
which was 5% of the asset level revenue for the Tawke and Taq Taq licences.
At the year-ended 31 December 2016, this resulted in the amortised cost
being lower than carrying value and consequently the overdue KRG receivable
was impaired to its reported book value of $207 million compared to its
nominal value of $469 million.
In 2017, the RSA resulted in the overdue KRG receivable balance being waived
and in return the Company received: (1) a 4.5% royalty interest on gross
Tawke PSC revenue lasting for 5 years ("the ORRI); (2) the waiver of
capacity building payments due on all profit oil received under the Tawke
PSC; and (3) the waiver of $4.6 million of amounts due to the KRG. As the
RSA occurred at arm's length, the fair value of the consideration received
from the KRG described above, which was recognised as an intangible asset
'Tawke RSA', was considered to be equal to the fair value of the
receivables. The Tawke RSA exceeded the carrying amount of receivables at
the time of settlement resulting in a gain of $293.8 million being
recognised in the profit or loss.
Assessing the fair value of both items required the estimation of future oil
price, production profile and reserves and the appropriate discount rate.
Estimation of future oil price and netback price
The estimation of future oil price has a significant impact throughout the
financial statements, primarily in relation to the estimation of the
recoverable value of property, plant and equipment, intangible assets and
net gain arising from the RSA for the year ended 31 December 2017. It is
also relevant to the assessment of going concern and the viability
statement.
The Company's forecast of average Brent oil price for future years is based
on a range of publicly available market estimates and is summarised in the
table below, with the 2023 price then inflated at 2% per annum.
$/bbl 2019 2020 2021 2022 2023
Forecast 65 66 68 71 72
Prior year forecast 63 66 72 74 n/a
Netback price is used to value the Company's revenue, trade receivables and
its forecast cash flows used for impairment testing and viability. It is the
aggregation of realised price less transportation and handling costs. The
Company does not have direct visibility on the components of the netback
price realised for its oil because sales are managed by the KRG, but
invoices are currently raised for payments on account using a netback price
agreed with the KRG.
The trade receivable is recognised when the control on oil is transferred to
the customer at the metering point, as this is the time the consideration
becomes unconditional. The trade receivable reflects the Company's
entitlement based on the netback price and oil transferred.
Change in accounting estimate - Netback price
The Company has increased the estimated netback price adjustment by $1/bbl
using the methodology agreed with the KRG for raising invoices for all sales
of oil, effective from 1 August 2017. Netback adjustments to Brent are now
estimated as $13/bbl discount for the Tawke PSC (2017: $12/bbl) and a $6/bbl
discount for the Taq Taq PSC (2017: $5/bbl). This has resulted in a decrease
of $3.6 million to H1 2018 revenue, of which $2.2 million relates to 2017.
At the end of last year, the Company disclosed that a $5/bbl change in
Long-term Brent would impact the Tawke CGU by $23 million and the Taq Taq
CGU by $2 million, so a $1/bbl change in netback adjustment has an impact of
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around $5 million in total across the two CGUs. The netback adjustment price
agreed with the KRG may change in the future. A $1/bbl difference in netback
price would impact current year revenue by circa $5 million and trade
receivables by circa $1 million with disclosures on the sensitivities of the
recoverable amount of producing assets provided in note 9.
1.3 Accounting policies
The accounting policies adopted in preparation of these financial statements
are consistent with those used in preparation of the annual financial
statements for the year ended 31 December 2017, adjusted for transitional
requirements where necessary, further explained under revenue and changes in
accounting policies headings.
Revenue
Revenue for oil sales is recognised when the control of the product is
deemed to have passed to the customer, in exchange for the consideration
amount determined by the terms of the contract. For exports the control
passes to the customer when the oil enters the export pipe, for domestic
sales this is when oil is collected by truck by the customer.
Revenue is oil sales. Revenue is earned based on the entitlement mechanism
under the terms of the relevant PSC; ORRI, which is earned on 4.5% of gross
field revenue from the Tawke licence until July 2022; 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 from Taq Taq licence, 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. Capacity building
payments due on Tawke profit oil receipts were waived from August 2017
onwards as part of the RSA. ORRI is calculated as 4.5% of Tawke PSC field
revenue. Royalty income was received in advance and is recognised in line
with production.
The Company's oil sales are made to the KRG which is the counterparty of the
PSCs 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.
The payment terms for the Company's sales are typically due within 30 days
but under the normal operating cycle, payments are received on 75 days
average. The Company does not expect to have any contracts where the period
between the transfer of oil to the customer and the payment exceeds one
year. Therefore, the transaction price is not adjusted for the time value of
money.
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.
The Company adopted IFRS 15 Revenue from Contracts with Customers for the
year commencing 1 January 2018. IFRS 15 addresses the way that revenue
derived from contracts with customers is recognised in the financial
statements and replaces IAS 18 Revenue. The transition from IAS 18 to IFRS
15 does not have an impact on revenue recognised in the financial
statements.
For the year ended 31 December 2018, in accordance with IFRS 15, the Company
has identified its contracts with its single customer (the KRG) as each oil
sale contract (PSC) for each field licence. The Company's single performance
obligation within these contracts is the delivery of oil and the transaction
price within these contracts is dated Brent adjusted for the netback amount.
The performance obligation is satisfied and the Company recognises revenue
when control of the oil is transferred to the customer at the metering
point.
For the prior year ended 31 December 2017, under IAS 18, the Company also
recognised revenue when the oil was transferred to the customer at the
metering point as this was when the significant risks and rewards of
ownership were deemed to have passed to the customer, it could be measured
reliably and it was assessed as probable that economic benefit would flow to
the Company. Therefore, there has been no significant change in the
Company's revenue recognition on transition to the new standard IFRS 15.
In applying IFRS 15 as set out above, there are no significant judgements
made in determining the timing of the satisfaction of the performance
obligation, the transaction price or the amounts allocated to performance
obligations. The Company has adopted IFRS 15 using the modified
retrospective approach, under this approach the prior year's financial
statements are not restated and the impact of adoption is recognised in the
opening reserves at 1 January 2018. As the impact of adoption on the Company
is not material, no adjustment has been recognised in opening reserves.
Intangible assets
Exploration and evaluation assets
Oil and gas assets classified as exploration and evaluation assets are
explained under Oil and Gas assets below.
Tawke RSA
Intangible assets include the Receivable Settlement Agreement
('RSA')effective from 1 August 2017, which was entered into in exchange for
trade receivables due from KRG for Taq Taq and Tawke past sales. The RSA was
recognised at cost and is amortised on a units of production basis in line
with the economic lives of the rights acquired, as further explained in Note
8.
Other intangible assets
Other intangible assets 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
Development assets
Oil and gas assets classified as development assets 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 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 so long as the activity is assessed to be de-risking the
asset and the Company expects continued activity on the asset into the
foreseeable future. Costs of activity that do not identify oil and gas
reserves are expensed.
All 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 de-risking nor adding value to the asset, the
associated costs are expensed to the income statement.
Impairment testing of oil and gas assets is considered in the context of
each cash generating unit. A cash generating unit is generally a licence,
with the discounted value of the future cash flows of the CGU compared to
the book value of the relevant assets and liabilities. As an example, the
Tawke CGU is comprised of the Tawke RSA intangible asset, property, plant
and equipment (relating to both the Tawke field and the Peshkabir field) and
the associated decommissioning provision.
Subsequent costs
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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.
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.
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
The Company adopted IFRS 9 Financial Instruments, for the year commencing 1
January 2018. IFRS 9 addresses the classification, measurement and
recognition of financial assets and financial liabilities. IFRS 9 replaces
IAS 39 Financial instruments: Recognition and measurement.
The transition from IAS 39 to IFRS 9 does not have a significant impact on
the financial statements and no adjustment has been recognised in the
opening reserves at 1 January 2018.
Changes in the Company's accounting policies resulting from the adoption of
IFRS 9 are set out under the subheadings below.
Classification
The Company assesses the classification of its financial assets on initial
recognition at amortised cost, fair value through other comprehensive income
or fair value through profit and loss. 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. Trade and other receivables, trade and other payables,
borrowings and deferred contingent consideration are subsequently carried at
amortised cost using the effective interest method.
The impact of adoption of IFRS 9 on financial instrument classification and
measurement is shown in the table below.
Financial Note Classification Measurement Classification 2018 $m 2017 $m
instrument under IAS 39 under IAS and
category 39 measurement
under IFRS9
Cash and 11 Loans and Amortised Amortised cost 334.3 162.0
cash receivables cost
equivalent
s
Restricted 11 Loans and Amortised Amortised cost 10.0 18.5
cash receivables cost
Trade and 10 Loans and Amortised Amortised cost 97.0 76.8
other receivables cost
receivable
s
Trade and 12 Other Amortised Amortised cost (60.9) (69.7)
other financial cost
payables liabilities
Borrowings 15 Other Amortised Amortised cost (297.3) (296.8)
financial cost
liabilities
Deferred 12 Other Amortised Amortised cost (68.5) (60.4)
contingent financial cost
considerat liabilities
ion
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. The Company's assessment of impairment model based on expected
credit loss is explained below.
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.
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.
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.
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 nominal post 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 (which are assumed to be immaterial). 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.
Non-financial assets that suffered impairment are reviewed for possible
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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 of disposal. The Company assets' recoverable amount is determined by fair value less costs of disposal. Financial assets IFRS 9 introduces a forward-looking impairment model based on expected credit losses (ECLs) of financial assets. The standard requires the Company to book an allowance for ECLs for its financial assets. The Company has assessed impact of the new requirement on its trade receivables as at 31 December 2018, which are expected to be collected in 2019 under the normal operating cycle. For the contracts under IFRS 15 with no significant financing component, allowance is provided for lifetime ECLs of the financial asset. The model calculates net present value of outstanding receivables discounted by the discount rate, for a range of possible scenarios including short and mid-term delays and no payment with a probability assigned to each, and determines the ECL as the weighted average of these scenarios. The Company uses both past track record of receivables, information available until the reporting date and future expected performance. The result of the Company's assessment is that the effect of the ECL on the financial statements is not determined to be material and no amount is recorded in the accounts. For the year ended 31 December 2017, no bad debt provision was recorded against trade receivables and therefore the changes from the incurred credit loss model under IAS 39 to the expected credit loss model under IFRS 9 has no significant impact to the Company's financial statements. 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. 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 KRI PSC's, corporate income tax due is paid on behalf of the Company by the KRG from the KRG's own share of revenues, resulting in no corporate income tax payment required or expected to be made by the Company. It is not known at what rate tax is paid, but it is estimated that the current tax rate would be between 15% and 40. If this was known it would result in a gross up of revenue with a corresponding debit entry to taxation expense with no net impact on the income statement or on cash. In addition, it would be necessary to assess whether any deferred tax asset or liability was required to be recognised. Current tax expense is incurred on the profits of the Turkish and UK services companies. Segmental reporting IFRS 8 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 The new accounting standards and amendments to existing standards have been adopted by the Company effective 1 January 2018: IFRS 15 - Revenue from Contracts with Customers, IFRS 9 - Financial Instruments, Amendments to IFRS 2, Amendments to IAS 40 and IFRIC 22 Foreign Currency Transactions and Advance Consideration. The adoption of IFRS 15 and IFRS 9 are further explained under the changes in accounting policies heading. Amendments to IFRS 2, Amendments to IAS 40 and IFRIC 22 Foreign Currency Transactions and Advance Consideration have no impact to the financial statements as at 31 December 2018. IFRS 16 - Leases, which becomes effective by 1 January 2019, requires the lessee to recognise the right to use the asset and the liability, depreciate the associated asset, re-measure and reduce the liability through lease payments; unless the underlying leased asset is of low value and/or short term in nature. The Company is not considering early application of the Standard. The Company's leases are mostly low value or short term in nature. Had the Company early adopted the standard, it is estimated that the assets and liabilities would increase by $2m and income statement would be debited net by $0.1m as at 31 December 2018. The following new accounting standards, amendments to existing standards and interpretations have been issued and endorsed by the EU but are not yet effective: Amendments to IFRS 9 Financial Instruments (effective 1 January 2019), Amendments to IAS 28 - Investments in Associates and Joint Ventures (effective 1 January 2019) and IFRIC 23 - Uncertainty over Income Tax Treatments (effective 1 January 2019). None of these standards have been early adopted. The following new accounting standards, amendments to existing standards and interpretations have been issued but are not yet effective and have not yet been endorsed by the EU: Annual Improvements to IFRS Standards 2015-2017 (effective 1 January 2019), Amendments to IAS 19 - Plan Amendment, Curtailment or Settlement (effective 1 January 2019)and Amendment to IFRS 3 Business Combinations (effective 1 January 2020). None of these standards have been early adopted. Changes in accounting policies Revenue recognition under IFRS 15 - Revenue from Contracts with Customers - requires a 5 step approach which is defined as the identification of the contract with the customer, performance obligations, transaction price, allocation of price into performance obligations and revenue recognition when the conditions are met. The Company's performance obligation in its contract with the single customer is the delivery of crude oil at a netback adjustment to dated Brent and the control is transferred to the buyer at the metering point when the revenue is recognised. Transition to IFRS 15 resulted in no adjustment to the measurement of the Company's previous year revenue in its financial statements. Transition to IFRS 9 - Financial Instruments - introduced two significant changes that may have effect on the Company financial statements which are derecognition of financial liabilities and the change from incurred credit loss model to the expected credit loss model for financial assets. The Company's accounting treatment of the bond buyback for the year ended 31 December 2017 was in line with the requirements of IFRS 9 hence no transitional adjustments were made. In applying IFRS 9 on trade receivables
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as set out above, the expected credit loss under the new standard is not
determined to be material.
2. Segmental information
************************
The Company has three reportable business segments: Oil, Miran/Bina Bawi
('MBB') and Exploration ('Expl.'). Capital allocation decisions for the oil
segment are considered in the context of the cash flows expected from the
production and sale of crude oil. The oil segment is comprised of the
producing fields on the Tawke PSC and the Taq Taq PSC, which are located in
the KRI and make sales predominantly to the KRG. The Miran/Bina Bawi segment
is comprised of the oil and gas upstream and midstream activity on the Miran
PSC and the Bina Bawi PSC, which are both in the KRI - this was previously
labelled as the 'Gas' segment. The exploration segment is comprised of
exploration activity, principally located in Somaliland and Morocco. '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 2018
Expl. Total
Oil MBB Other
$m $m $m $m $m
Revenue from contracts 350.3 - - - 350.3
with customers
Revenue from other 4.8 - - - 4.8
sources
Cost of sales (163.2) - - - (163.2)
Gross profit 191.9 - - - 191.9
Exploration (expense) / - (0.4) 1.9 - 1.5
credit
Impairment of intangible - (424.0) - - (424.0)
assets
General and - - - (24.0) (24.0)
administrative costs
Operating profit / (loss) 191.9 (424.4) 1.9 (24.0) (254.6)
Operating profit / (loss)
is comprised of
EBITDAX 326.4 - - (22.3) 304.1
Depreciation and (134.5) - - (1.7) (136.2)
amortisation
Exploration (expense) / - (0.4) 1.9 - 1.5
credit
Impairment of intangible - (424.0) - - (424.0)
assets
Finance income - - - 4.4 4.4
Bond interest expense - - - (30.0) (30.0)
Other finance expense (1.7) (0.2) - (1.3) (3.2)
Profit / (Loss) before 190.2 (424.6) 1.9 (50.9) (283.4)
income tax
Capital expenditure 70.4 12.0 13.1 - 95.5
Total assets 1,015.4 457.7 35.5 319.3 1,827.9
Total liabilities (89.1) (84.4) (16.1) (306.9) (496.5)
Revenue from contracts with customers includes $105.4 million (2017: $33.9
million) arising from the ORRI. The ORRI will expire at the end of July 2022
and is explained further under significant accounting estimates and
judgements under the Tawke RSA intangible asset. Total assets and
liabilities in the other segment are predominantly cash and debt balances.
For the period ended 31 December 2017
MBB Expl. Other
Oil Total
$m $m $m $m $m
Revenue from contracts 224.4 - - - 224.4
with customers
Revenue from other sources 4.5 - - - 4.5
Cost of sales (143.6) - - - (143.6)
Gross profit 85.3 - - - 85.3
Exploration (expense) / - (4.6) 2.7 - (1.9)
credit
Impairment of property, (58.2) - - - (58.2)
plant and equipment
Net gain arising from the 293.8 - - - 293.8
RSA
General and administrative - - - (21.0) (21.0)
costs
Operating profit / (loss) 320.9 (4.6) 2.7 (21.0) 298.0
Operating profit / (loss)
is comprised of
EBITDAX 495.2 - - (19.7) 475.5
Depreciation and (116.1) - - (1.3) (117.4)
amortisation
Exploration (expense) / - (4.6) 2.7 - (1.9)
credit
Impairment of property, (58.2) - - - (58.2)
plant and equipment
Gain arising from bond buy - - - 32.6 32.6
back
Finance income 2.7 - - 2.2 4.9
Bond interest expense - - - (35.5) (35.5)
Other finance expense (1.1) (0.1) - (26.8) (28.0)
Profit / (Loss) before 322.5 (4.7) 2.7 (48.5) 272.0
income tax
Capital expenditure 59.5 15.5 19.1 - 94.1
Total assets 1,057.9 860.8 34.0 154.2 2,106.9
Total liabilities (84.3) (75.3) (32.4) (305.1) (497.1)
Total assets and liabilities in the other segment are predominantly cash and
debt balances.
3. Operating costs
2018 2017
$m $m
Production costs 28.7 27.5
Depreciation of oil and 72.4 83.3
gas property, plant and
equipment
Amortisation of oil and 62.1 32.8
gas intangible assets
Cost of sales 163.2 143.6
Exploration (credit) / (1.5) 1.9
expense
Impairment of property, - 58.2
plant and equipment
(note 9)
Impairment of intangible 424.0 -
assets (note 8)
Corporate cash costs 17.4 16.9
Corporate share based 4.9 2.8
payment expense
Depreciation and 1.7 1.3
amortisation of
corporate assets
General and 24.0 21.0
administrative expenses
Exploration expense relates to accruals for costs or
obligations relating to licences where there is ongoing
activity or that have been, or are in the process of being,
relinquished.
Fees payable to the Company's auditors:
2018 2017
$m $m
Audit of consolidated and 0.4 0.6
subsidiary financial statements
Tax and advisory services 0.3 0.1
Total fees 0.7 0.7
4. Staff costs and headcount
2018 2017
$m $m
Wages and salaries 17.1 20.6
Social security costs 1.0 1.0
Share based payments 6.3 5.4
24.4 27.0
Average headcount was:
2018 number 2017
number
Turkey 64 65
KRI 15 15
UK 17 17
Somaliland 17 24
113 121
5. Finance expense and income
2018 2017
$m $m
Bond interest payable (30.0) (35.5)
Unwind of discount on liabilities / premium paid (3.2) (28.0)
on bond buyback
Finance expense (33.2) (63.5)
Bank interest income 4.4 2.2
Unwind of discount on trade receivables - 2.7
Finance income 4.4 4.9
Bond interest payable is the cash interest cost of Company bond debt. In
2018, unwind of discount on liabilities primarily relates to the discount
unwind on the bond (note 15) and on the asset retirement obligation
provision (note 14). In 2017, the Company extended the maturity of $300.0
million of its bonds and redeemed bonds with a nominal value of $121.8
million. This resulted in the derecognition of the existing debt balance and
recognition of an expense of $19.7 million, comprised of $3.7 million
relating to the premium paid and $16.0 million accelerated discount unwind.
6. Income tax expense
*********************
Current tax expense is incurred on the profits of the Turkish and UK
services companies. Under the terms of the KRI PSCs, the Company is not
required to pay any cash corporate income taxes as explained in note 1.
7. Earnings per share
*********************
Basic
Basic earnings per share is calculated by dividing the profit attributable
to equity holders of the Company by the weighted average number of shares in
issue during the period.
2018 2017
(Loss) / Profit attributable to equity (283.6) 271.0
holders of the Company ($m)
Weighted average number of ordinary 279,065,717 279,013,724
shares - number 1
Basic (loss) / earnings per share - (101.6) 97.1
cents per share
1Excluding shares held as treasury shares
Diluted
The Company purchases shares in the market to satisfy share plan
requirements so diluted earnings per share is only adjusted for restricted
shares not included in the calculation of basic earnings per share:
2018 2017
(Loss) / Profit attributable to equity (283.6) 271.0
holders of the Company ($m)
Weighted average number of ordinary 279,065,717 279,013,724
shares - number1
Adjustment for performance shares, 1,182,481 1,234,474
restricted shares and share options
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