TIDMNOG
RNS Number : 9966T
Nostrum Oil & Gas PLC
26 March 2019
NOT FOR RELEASE, PUBLICATION OR DISTRIBUTION, IN WHOLE OR IN
PART, IN, INTO OR FROM ANY JURISDICTION WHERE TO DO SO WOULD
CONSTITUTE A VIOLATION OF THE RELEVANT LAWS OF THAT
JURISDICTION
London, 26 March 2019
Full Year Results for the Year Ending 31 December 2018
Nostrum Oil & Gas PLC (LSE: NOG) ("Nostrum", or "the
Company"), an independent oil and gas company engaging in the
production, development and exploration of oil and gas in the
pre-Caspian Basin, today announces its full year financial results
for the twelve months ending 31 December 2018, together with the
publication of the 2018 Annual Report for Nostrum and its
subsidiaries taken as a whole ("the Group").
2018 Financial and Operational highlights of the Group:
Operational
-- 2019 average daily production to date above 32,500 boepd
-- 2018 average daily production of 31,254 boepd (2017: 39,199
boepd) corresponding to average daily sales volumes of 29,516 boepd
(2017: 37,844 boepd)
-- Mechanical completion of the third Gas Treatment Unit
("GTU3") in December 2018, with full commissioning expected before
the end of Q3 2019
-- Completed drilling of Well 40 with stable test production over 1,500 boepd
-- 45 wells producing at the Chinarevskoye field as at 31
December 2018 - 20 oil wells and 25 gas condensate wells
-- Total Group 2P reserves of 410mmboe as at 1 January 2019
following Ryder Scott independent reserve report and total Group
contingent resources of 249 mmboe
Financial
-- Revenue of US$389.9 million (2017: US$405.5 million)
-- EBITDA(1) of US$231.2 million (2017: US$232.0 million)
-- EBITDA margin of 59.3% (2017: 57.2%)
-- Net operating cash flows(2) of US$214.0 million (2017: US$182.6 million)
-- 12% reduction in operating costs(3) to US$49.9 million (2017: US$56.6 million)
-- Over 30% reduction in general & administrative costs(4)
to US$20.3 million (2017: US$31.0 million)
-- Transport costs reduced to US$4.6/boe (2017: US$4.8/boe)
-- Closing cash5 for the period of US$121.8 million (2017: US$127.0 million)
-- Net debt of US$1,007.8 million (2017: US$960.9 million)
-- Total debt(6) of US$1,129.6 million (2017: US$1,087.9 million)
-- Net debt / LTM EBITDA ratio of 4.4x (2017: 4.1x)
-- US$150 million impairment from 78mmboe reduction in Group 2P reserves
2019 Drilling and sales volume guidance
-- With two drilling rigs we will be able to drill up to six wells during 2019
-- The first two wells are in the Northern area of the field around well 40 (wells 41 and 42)
-- The location of additional wells will be finalised once we
have completed the evaluation of wells drilled during 2018 and
those currently being drilled
2019 production guidance remains unchanged at 30,000 boepd,
corresponding to sales volumes of 28,000 boepd. Given that we are
not drilling in proven areas of the field there is a range of
possible outcomes from the Northern wells and therefore, the above
production guidance does not include any additional production from
new wells planned this year
Other
Binding agreements with Ural Oil & Gas LLP
On 2 August 2018 Nostrum announced that through its subsidiary
Zhaikmunai LLP it entered into binding agreements to purchase and
process third party hydrocarbons delivered by Ural Oil & Gas
LLP ("UOG").
UOG is a company that is owned by KazMunaiGas ("KMG") (50%),
Sinopec (27.5%) and MOL Group ("MOL") (22.5%). According to the
2017 KMG Annual Report, the Rozhkovskoye field has 196 million boe
2P reserves. Research by Wood Mackenzie states that the field has
eight wells drilled and completed. The Rozhkovskoye field is within
20km of Nostrum's Chinarevskoye field.
Once UOG has obtained all necessary internal approvals they will
fund the infrastructure required to deliver the hydrocarbons to the
boundary of the Chinarevskoye field. The high-level commercial
terms comprise of two parts:
-- a tolling fee for the stabilisation of liquid condensate at US$8 per barrel; and
-- the purchase of raw gas from UOG.
Strategic focus for 2019:
-- Maintain stable production levels at Chinarevskoye while operational issues are addressed
-- Optimise Group cost profile with a focus on operating costs, G&A, and drilling capex
-- Appraise the Northern area discovery
-- Access resources in the region to maximise the value of our infrastructure
-- Focus on expanding QHSE policies and developing GHG reduction strategies
-- Foster diversity at all levels of the Group
Kai-Uwe Kessel, CEO of Nostrum Oil & Gas commented:
"Looking forward to 2019 I want to ensure we continue the
positive trend we set in Q4 of stabilising production combined with
some of the lowest drilling costs we have ever achieved. I am
optimistic that we can grow production based on the lessons we have
learnt and the results of the Schlumberger study due in the third
quarter of 2019. We currently have two rigs drilling in the North
and have access to more rigs when the time comes to accelerate
drilling."
Conference call
Nostrum's management team will present the FY 2018 Results and
will be available for a Q&A session with analysts and investors
today at 2:00 pm UK time, 26 March 2019. If you would like to
participate in this call, please register by clicking on the
following link and following instructions: Results Call
Download: Results Presentation
Download: Consolidated Group Financials
Download: 2018 Annual Report
Download: Ryder Scott Report
(1) Defined as profit before tax net of non-recurring expenses,
finance costs, foreign exchange loss/gain, ESOP, depreciation,
interest income, other income and expenses.
(2) IFRS term based on indirect cash flow method
(3) Cost of sales net of depreciation
(4) General & administrative expenses net of
depreciation
(5) Defined as cash and cash equivalents including restricted
cash, current and non-current investments
(6) Defined as total debt minus cash and cash equivalents
LEI: 2138007VWEP4MM3J8B29
Disclosure of inside information in accordance with Article 17
of Regulation (EU) 596/2014 (16 April 2014) relating to Nostrum Oil
& Gas PLC and Zhaikmunai LLP
Further information
For further information please visit www.nog.co.uk
Further enquiries
Nostrum Oil & Gas PLC - Investor Relations
Kirsty Hamilton-Smith
Amy Barlow
+44 203 740 7433
ir@nog.co.uk
Instinctif Partners - UK
David Simonson
Dinara Shikhametova
Sarah Hourahane
nostrum@instinctif.com
+ 44 (0) 207 457 2020
Promo Group Communications - Kazakhstan
Asel Karaulova
Irina Noskova
+ 7 (727) 264 67 37
Notifying person
Thomas Hartnett
Company Secretary
About Nostrum Oil & Gas
Nostrum Oil & Gas PLC is an independent oil and gas company
currently engaging in the production, development and exploration
of oil and gas in the pre-Caspian Basin. Its shares are listed on
the London Stock Exchange (ticker symbol: NOG). The principal
producing asset of Nostrum Oil & Gas PLC is the Chinarevskoye
field, in which it holds a 100% interest and is the operator
through its wholly-owned subsidiary Zhaikmunai LLP. In addition,
Nostrum Oil & Gas holds a 100% interest in and is the operator
of the Rostoshinskoye, Darjinskoye and Yuzhno-Gremyachinskoye oil
and gas fields through the same subsidiary. Located in the
pre-Caspian basin to the north-west of Uralsk, these exploration
and development fields are situated approximately 60 and 120
kilometres respectively from the Chinarevskoye field.
Forward-Looking Statements
Some of the statements in this document are forward-looking.
Forward-looking statements include statements regarding the intent,
belief and current expectations of the Partnership or its officers
with respect to various matters. When used in this document, the
words "expects," "believes," "anticipates," "plans," "may," "will,"
"should" and similar expressions, and the negatives thereof, are
intended to identify forward-looking statements. Such statements
are not promises or guarantees, and are subject to risks and
uncertainties that could cause actual outcomes to differ materially
from those suggested by any such statements.
No part of this announcement constitutes, or shall be taken to
constitute, an invitation or inducement to invest in the Company or
any other entity, and shareholders of the Company are cautioned not
to place undue reliance on the forward-looking statements. Save as
required by the Listing Rules and applicable law, the Company does
not undertake to update or change any forward-looking statements to
reflect events occurring after the date of this announcement.
Significant news after the reporting period:
Appointment of Robert Tinkhof
Mr. Robert Tinkhof joined the Company as its new Chief Operating
Officer on 12 February 2019, replacing Mr. Heinz Wendel who is
retiring. Prior to this he held several senior management
positions, most recently as Managing Director at the Scientific
Research Institute of KMG for Production & Technology in
Kazakhstan. Mr. Tinkhof has more than 30 years of experience in the
oil and gas industry, mainly with Royal Dutch Shell with
assignments in the Netherlands, UK, Syria, Iran, Egypt, Iraq and
Russia.
Board changes
On 21 March 2019 the Company's Board of Directors established a
Health, Safety, Environment and Communities Committee of the Board
as part of the Company's initiatives to further develop its
sustainability practices across the Company and its operations and
take further steps in its commitment to improve overall health,
safety, environmental and social performance and better address
important issues such as climate change and gender diversity.
The new committee will be chaired by independent non-executive
director Kaat Van Hecke, and also includes CEO and director Kai-Uwe
Kessel and independent non-executive director Martin Cocker. The
HSEC Committee will work closely with Company management and will
report on its activities to the full Board.
In addition, the Board decided on 21 March that with effect
immediately following the Company's annual general meeting of
shareholders, Martin Cocker will replace Sir Christopher Codrington
as chairman of the Audit Committee of the Board. Sir Christopher
will remain a member of the Committee.
The Board has designated Sir Christopher as the non-executive
director who will lead the Board's engagement with Nostrum's
workforce as foreseen in Provision 5 of the 2018 UK Corporate
Governance Code.
Operational Overview:
Sales volumes
The sales volumes split for FY 2018 was as follows:
Products FY 2018 sales volumes FY 2018 Product Mix
(boepd) (%)
Crude Oil & Stabilised
Condensate 11,415 38.67%
--------------------- -------------------
LPG (Liquid Petroleum
Gas) 3,877 13.14%
--------------------- -------------------
Dry Gas 14,224 48.19%
--------------------- -------------------
Total 29,516 100.00%
--------------------- -------------------
The difference between production and sales volumes is primarily
due to internal consumption of gas
Q4 2018 Drilling
-- As at 31 December 2018, the Company had 45 wells in
production (20 oil wells and 25 gas condensate wells)
-- Completed drilling of Biyski North-east wells 228 and 231
with combined production from these wells exceeding 2,500 boepd
-- One of the three drilling rigs has been demobilised and the
remaining two units moved to the Northern part of the field to
drill step-out wells from Well 40
2019 Drilling and sales volume guidance
-- With two drilling rigs we will be able to drill up to six wells during 2019
-- The first two wells will be in the Northern area of the field
around Well 40 (wells 41 and 42)
-- The location of additional wells will be finalised once we
have completed the evaluation of wells drilled during 2018 and
those currently being drilled
-- 2019 production guidance remains unchanged at 30,000 boepd,
corresponding to sales volumes of 28,000 boepd. Given that we are
not drilling in proven areas of the field there is a range of
possible outcomes from the Northern wells and therefore, the above
production guidance does not include any additional production from
new wells planned this year
Progress on the development of GTU3
Mechanical completion of GTU3 was achieved in December 2018.
Cold commissioning has now started with first gas targeted for Q2
2019 and full commissioning of the plant before the end of Q3
2019.
The below figures reflect all future cash payments expected to
be made (excluding VAT) on GTU3.
Remaining cash spend on US$34.6 million
GTU3 (excl VAT) as at 31
December 2018
Hedging
Nostrum's hedge came to its conclusion in December 2018. Given
the recent weakness in the oil prices combined with high volatility
the company has not entered into a new hedge. It continues to
monitor the market in regard to hedging a portion of its liquid
production.
Reserves and resources
2018 Audited reserves Proven Probable Total
Chinarevskoye 124 234 358
------- --------- ---------
Trident Licenses - 131 131
------- --------- ---------
Total 124 365 488
------- --------- ---------
Changes to reserves Proven Probable Total
------- --------- ---------
2018 production (11) - (11)
------- --------- ---------
Chinarevskoye (14) (38) (52)
------- --------- ---------
Trident Licenses - (15) (15)
------- --------- ---------
Total (25) (53) (78)
------- --------- ---------
2019 Audited reserves Proven Probable Total 2P
------- --------- ---------
Chinarevskoye 98 196 294
------- --------- ---------
Trident Licenses - 116 116
------- --------- ---------
Total 98 312 410
------- --------- ---------
As at 1 January 2019, the Company's independent reserve
reviewer, Ryder Scott, confirmed the Group's 2P reserves of 410
mmboe. 1P reserves at the Chinarevskoye license were 98 mmboe. The
Ryder Scott Reserves Report also confirmed Nostrum has 2P reserves
of 116 mmboe in the Rostoshinskoye, Darjinskoye and
Yuzhno-Gremyachinskoye fields ("Trident Licenses") adjacent to the
Chinarevskoye licence, which were acquired for a consideration of
US$16 million in 2013. This is in addition to having approximately
127 mmboe and 731 billion cubic feet of sales gas contingent
resources.
Nostrum has been appraising, developing and producing crude oil
and gas condensate in North-western Kazakhstan for over a decade.
This has allowed the Company to accumulate considerable knowledge
of the Chinarevskoye field and surrounding regional geology. The
Company seeks to leverage this competitive advantage to pursue
value-accretive transactions which enhance our commercial reserve
base and allow the company to fully utilise its infrastructure
beyond 2021.
The Ryder Scott Reserves Report is available on our website:
http://www.nog.co.uk
Executive Chairman's Statement - Atul Gupta
Ensuring stability and Delivery
What has been the biggest challenge for Nostrum during 2018?
The single biggest challenge we faced in 2018 was the
disappointing operational performance of the Biyski North-east
reservoir and western area of Chinarevskoye. Therefore, while our
long-term vision and growth expectations remain unchanged, we have
not made the progress we wanted to make in 2018 owing to these
unforeseen operational difficulties within our licence area. The
impact of subsurface challenges is a reduction in our 2P reserves
by 78 million boe. We are focused on reversing both production
decline and reserve decline during 2019.
How has the Board sought to address these challenges?
The Board has assumed greater oversight of operational decision
making. We now hold technical workshops each quarter where those
Board members with a technical background act as a further sounding
board for management on our decisions related to drilling and
reservoir plans. Given improving production is our priority, this
is where the Board has specifically sought to support management in
its decision making.
In addition to the Board bringing its own technical knowledge,
it has requested that we seek leading external advice. Accordingly,
we have contracted Schlumberger to conduct a technical study of our
main reservoirs to better understand their behavior. We have also
requested Schlumberger to evaluate the best way forward to complete
our multi-frac appraisal well 234 in the west of the field. The
technical work required to be able to move forward with further
drilling activities in both areas is expected to be complete in Q3
2019.
We are also cognisant the cash position of the Company needs to
be carefully monitored to avoid any stress on our short-term
liquidity position. As a result, the Board requested that we reduce
the number of rigs from three to two, which will be focused in the
Northern area, whilst we are working on both Schlumberger studies.
In addition, the Board also now approves each well that is drilled
to ensure we are all taking responsibility for maximizing the best
possible chance of success on the investments we make.
From a financial perspective, the Board decided to err on the
side of caution and take an impairment against the reduction in our
2P reserves. Whilst we have a significant volume of 2P reserves, we
are cognisant of the challenges we faced with 2018 production and
therefore have looked to stress the 2P production profile with
higher sensitivities, resulting in an impairment being taken.
How has the Board responded to shareholders in 2018?
We have always listened and responded to concerns raised by our
shareholders. For example, we made improvements to our Remuneration
Committee structure and remuneration packages during the year.
Michael Calvey, who continues to serve as a Director of Board,
stepped down as a member of the Remuneration Committee in August
this year. Following this change the committee is comprised solely
of independent non-executive directors, thereby ensuring that the
Company is in full compliance with Provision D.2.1 of the UK
Corporate Governance Code.
Following consultation with our shareholders over the course of
the year regarding independent non-executive director participation
in our LTIP scheme, we have since amended the terms of the LTIP to
make non-executive directors ineligible to participate and will
modify the remuneration policy to prohibit non-executive directors
from participating gin the LTIP in the future.
We have provided additional information and clarity regarding
KPIs for bonuses for executive directors in the future in the
remuneration report within this Annual Report, which can be found
on page 86.
What will you bring as Executive Chairman?
At the end of last year, the Board took the decision to appoint
me as Executive Chairman. Whilst the Board is mindful of best
practice corporate governance regarding the Chairman role, ensuring
operational delivery and meeting our stated targets is the
Company's and my number one priority in order to deliver value for
our shareholders, and I will endeavor to do this to the best of my
abilities.
I will be working closely with the management team to ensure
this happens. My experience is firmly grounded in petroleum
engineering with over thirty years working in the upstream sector,
which I'm confident will prove useful for the Company at
present.
As a result, I have stepped down from the Board's Nomination and
Governance Committee in line with best practice. More information
on our Nomination and Governance, Audit, and Remuneration
Committees can be found in the corporate governance section of this
Annual Report and on our website.
I am now working closely with our CEO, Kai-Uwe Kessel, on how
best to turn around the operational issues we have been confronted
with and, most importantly, how we can increase production.
Where do you see the biggest risks to Nostrum in 2019?
While the commodity price environment is an ever-present risk in
the industry, the key risks to Nostrum in 2019 are encountering
poor drilling results in the Northern Area.
We understand that the Company needs to deliver on the guidance
it gives to the market and 2019 is about hitting the targets that
we set and can control. In 2018, we rebased our production guidance
for this year based on current producing wells, which we believe is
appropriately conservative given the drilling programme is focusing
on the unproved Northern Area.
We are awaiting the results from the technical studies
undertaken on Biyski North-east and the western area which will
help us define our drilling strategy going forward and therefore
present an inherent risk.
However, we believe our tight cost control, focused drilling
campaign, third-party contractor and buyer relationships leave us
well placed from a balance sheet perspective to maintain a healthy
cash position and mitigate financial risk.
How are you positioning the business for a sustainable
future?
An environmental, social and governance focus.
ESG performance has and will always be central to how Nostrum
operates as a business. This includes maintaining high standards of
QHSE, with the health and safety of our employees being
paramount.
Our 2018 Health, Safety and Environment Compliance Audit,
conducted independently by AMEC, found our HSE systems conform to
all applicable standard and best practice, and have consistently
shown improvement year-on-year.
To demonstrate that we take our responsibility with regard to
the environment and climate change seriously, we plan to begin
reporting to the CDP initiative this year.
We are proposing a new committee of the Board be established to
deal with Health, Safety, Environment and Communities, and
attention to climate change issues will be among the duties of this
committee.
The Audit Committee and the Board have recognised that climate
change should be included among the risks and uncertainties faced
by Nostrum and we will seek to quantify climate change related
risks.
Developing our people and culture
I am proud of our people and the culture at Nostrum. That
culture must be harnessed to focus on operational excellence in
2019 and on delivery against our targets, whilst ensuring Nostrum
is an attractive place to work with an inclusive environment that
celebrates diversity.
We will continue to focus on diversity, and in particular gender
diversity, across all levels throughout the Group. We are setting
up a mechanism for regular reporting by our Human Resources team to
the Board on this issue and we are grateful fo the quality and
commitment of our employees.
What is the company strategy to create shareholder value in the
medium to long-term?
Our fundamental mission is to maximise the value of our
reservoirs and the associated infrastructure we have built. In a
region rich in hydrocarbon resources and in particular gas, we not
only have both our own hydrocarbons to process but can also seek to
enter into agreements with surrounding licences to ensure we fill
our gas plants as quickly as possible. We successfully signed a
deal with Ural Oil & Gas in 2018 that will result in gas and
condensate from their licence area being processed in Nostrum's
facilities, and this is anticipated towards the end of next year.
This will provide an immediate source of free cash flow for
Nostrum. The infrastructure we have built will last for many years
and the quicker we can fill it, the higher the value will be for
nostrum stakeholders. As such, we will continue to seek business
development opportunities during 2019.
We recognise that our future growth must be achieved
sustainably, with a focus on our social and environmental impact in
the region in which we operate. We continue to invest in social
development locally as well as education and training. We are
constantly improving our independent environmental impact auditing
and mitigation to ensure our future growth and long-term value
creation is measured with a sustainable approach for all
stakeholders.
I look forward to sharing our story with you over the coming
months and thank you for your ongoing support.
Atul Gupta
Executive Chairman
Chief Executive Officer's review - Kai-Uwe Kessel
Establishing a solid foundation for operational success
2018 was a tough year in terms of production and missed
guidance. What were the main issues and how can this be turned
around?
During 2017 we saw three wells water out in our main producing
reservoir, the Biyski North-east. The plan for 2018 was to
stabilize our production decline by drilling four production wells
in this reservoir. Unfortunately, our first well encountered water
leading to a longer than anticipated period without new production
coming online, and further questions being raised regarding the
source of the water. We had a further delay on the second well due
to technical drilling issues. Overall, these issues set back our
production guidance by roughly six months.
In the second half of the year we successfully brought three
producing wells in the Biyski online and stabilized production
about 30,000 boepd. However, as a result of the water inflow we
have seen, before we invest further money in to the Biyski
North-east we will conduct a thorough review of the reservoir with
Schlumberger. This will allow us to more accurately estimate what
additional wells we can drill or recover to further stabilize and
continue to grow production in 2019 and beyond.
We had planned to bring the western area of the field into
production during 2018 with a mulit-frac planned for well 234.
Unfortunately, before we were able to test the reservoir qualities,
we suffered a wellbore collapse, meaning we could not continue with
the planned multi-frac. Given the importance of this area, with 81m
barrels of probable reserves attributed to it, we have decided to
halt all further drilling investment in the Biyski West until we
receive a full analysis from Schlumberger. Due to the well bore
collapse of 234, we did not have any production from the western
part of the field which, again, impacted our production guidance.
We remain optimistic that we can prove the technology works and
bring the reserves to production in 2020 and into the future.
As a result of the issues we faced in 2018, we uncovered more
information about our existing reservoirs which resulted in a
reduction in our 2P reserved by 78 million boe, in accordance with
an independent report by Ryder Scott. This is largely down to two
factors. Firstly, the water in the Biyski North-east meant that we
lost reserves in the areas to this, and secondly, we have seen the
commercial rates of some probable areas in the Mullinski reservoir
in the North-east not being commercial to drill under current oil
prices.
Looking forward, we have three key areas to focus on in order to
grown production.
1) Identifying additional areas from production from the Biyski North-east;
2) Demonstrating the multi-frac can work in the west and
unlocking the probable reserves there; and
3) Developing the Northern Area around wells 724 and 40.
How strong is Nostrum's financial position?
A challenging operational year was tempered by a more positive
financial performance. While this was in part due to improved
prices for our sales products during 2018 as a result of higher
commodity prices, our continued implementation of cost reduction
initiatives across the business led to a healthy EBITDA margin in
2018. We managed to reduce our total General & Administrative
expenses to US$22.3m and total operating costs to US$50.0m and we
proactively managed the best possible netbacks across our sales
products in the period, leading to stable operating cash flow
margins.
We also successfully refinanced the remaining part of our debt.
As a result, we have no debt maturities due until July 2022. This
provides time to focus on turning around our operational
performance and engage with the prudent research being undertaken
into the issues faced.
Balancing capital preservation with investment into drilling
during 2019 will remain a priority for the Company as we work
through the challenges we encountered at the Chinarevskoye field,
to increase our production.
Can you provide an update on the GTU3 project?
We successfully achieved mechanical completion of GTU3 in
December 2018 and we are now looking forward to commissioning the
plant. Cold commissioning has commenced, with first gas targeted
for Q2 2019 and full commissioning of the plant during 2019.
When commissioning in completed, GTU3 - our third gas treatment
unit - will double our production capacity to over 100,000.
What is the strategy to grow production outside of Chinarevskoye
as you have a deal to process raw gas from Ural Oil & Gas?
Our long-term strategy is to build a portfolio of reserves and
resources in North-western Kazakhstan to fill the GTU capacity for
the next 25 years. We are not tied to owning the licences but the
goal is ensuring that we can monetise the infrastructure we have
built by processing all the raw gas in the region at economically
attractive terms to Nostrum. Given our limited liquidity position,
we cannot develop all our licences at once. Thus, I was pleased to
announce the binding agreements we signed with Ural Oil & Gas
('UOG') in 2018. This is an alternative to acquiring reserves and
resources whereby we are generating a return through agreements
that result in Nostrum making money from hydrocarbons UOG delivers
to our plant. We are not required to invest in any material capital
expenditure and will simply allocate part of our GTU for processing
their raw gas. This is an extremely economic and effective way to
monetise our infrastructure without us having to risk money on
drilling. This deal demonstrates the value our infrastructure has
in North-western Kazakhstan and we are continuously assessing other
opportunities in the region.
What are your development plans for Chinarevskoye?
During the year we saw encouraging results from our drilling
operations at well 40 in the northern part of the Chinarevskoye
exploration licence area, and we confirmed the discovery made in
well 724 at the end of last year in the Upper Devonian
formation.
Well 40 was tested with flow rates exceeding 1,500 boe per day.
This is a very significant result as it can potentially open up a
new area in the Chinarevskoye field that is rich in hydrocarbons
and is of material scale. This is one of the highest yielding
condensate wells in the field's history.
Therefore, to better understand the full potential of those
reserves in 2019, our two-rig drilling programme during the first
half of 2019 will pursue the area around well 40 (wells 41 and 42)
to define the extent of this encouraging prospect.
What is your production guidance for 2019?
Our 2019 drilling programme will be conducted with only two rigs
and we are expecting to drill six wells in the year. As we
prioritized capital preservation this year, we believe this
programme is a sound allocation of capital that will ensure we
sustain existing production wile targeting de-risked growth
opportunities.
While the Northern area has shown encouraging results, it is not
yet fully appraised and therefore carries some uncertainty in
predicting potential production volumes. As a result, we are
changing our approach to production guidance so as not to include
any appraisal wells to be drilled in 2019. Ths means that the
average forecast field production for 2019 will be 30,000 boepd*,
corresponding to sales volumes of approximately 28,000 boepd
Kai-Uwe Kessel
Chief Executive Officer
*The difference of 2,000 boepd between the field production and
sales volumes is largely the amount of produced gas that is
consumed within our extensive processing facilities.
Results of operations for the years ended 31 December 2018 and
2017
The table below sets forth the line items of the Group's
consolidated statement of comprehensive income for the years ended
31 December 2018 and 2017 in US Dollars and as a percentage of
revenue.
For the year ended 31 December
================================================
In thousands of US dollars 2018 % of revenue 2017 % of revenue
=============================================== ========= ============ ========= ============
Revenue 389,927 100.0% 405,533 100.0%
Cost of sales (165,145) 42.4% (177,246) 43.7%
=============================================== ========= ============ ========= ============
Gross profit 224,782 57.6% 228,287 56.3%
=============================================== ========= ============ ========= ============
General and administrative expenses (22,212) 5.7% (33,303) 8.2%
Selling and transportation expenses (49,984) 12.8% (66,441) 16.4%
Taxes other than income tax (29,702) 7.6% (19,967) 4.9%
Impairment charge (150,000) 12.7% (59,752) 14.7%
Finance costs (49,383) 12.7% (59,752) 14.7%
Employee share options - fair value adjustment 1,320 0.3% 2,099 0.5%
Foreign exchange loss, net (978) 0.3% (688) 0.2%
Loss on derivative financial instruments (12,387) 3.2% (6,658) 1.6%
Interest income 514 0.1% 374 0.1%
Other income 4,374 1.1% 4,071 1.0%
Other expenses (8,504) 2.2% (22,055) 5.4%
=============================================== ========= ============ ========= ============
Profit before income tax (92,160) 14.8% 25,967 6.4%
=============================================== ========= ============ ========= ============
Income tax expense (28,535) 16.4% (49,849) 12.3%
=============================================== ========= ============ ========= ============
Loss for the year (120,695) 1.6% (23,882) 5.9%
=============================================== ========= ============ ========= ============
Other comprehensive (loss)/income for
the year (895) 0.2% 825 0.2%
=============================================== ========= ============ ========= ============
Total comprehensive loss for the year (121,590) 1.8% (23,057) 5.7%
=============================================== ========= ============ ========= ============
General note
For the year ended 31 December 2018 (the "reporting period")
total comprehensive loss increased by US$98.5 million to US$121.6
million
(FY 2017: US$23.1 million). The increase in loss is mainly due
to the impairment charge for the year, which was partially offset
by the improvement mainly driven by reductions in cost of sales,
general and administrative expenses, selling and transportation
expenses and finance costs, , as explained in more detail
below.
Revenue
The Group's revenue decreased by 3.8% to US$389.9 million for
the reporting period (FY 2017: US$405.5 million). This is mainly
explained by the decrease in production and sales volumes, which
was partially offset by increase in the average Brent crude oil
price from 54.2 US$/bbl during 2017 to 71.7 US$/bbl during the
reporting period. The pricing for all the Group's crude oil,
condensate and LPG is, directly or indirectly, related to the price
of Brent crude oil.
Revenues from sales to the Group's largest three customers
amounted to US$258.9 million, US$80.5 million and US$7.0 million
respectively (FY 2017: US$200.6 million, US$102.8 million and
US$30.9 million).
The following tables present the Group's revenue breakdown by
products and sales volumes and the breakdown by export/domestic
sales for the reporting period and FY 2017:
For the year ended 31 December
==============================================
Variance,
In thousands of US dollars 2018 2017 Variance %
======================================== ========== ========== =========== =========
Oil and gas condensate 267,815 261,069 6,746 2.6%
Gas and LPG 122,112 144,464 (22,352) (15.5)%
======================================== ========== ========== =========== =========
Total revenue 389,927 405,533 (15,606) (3.8)%
======================================== ========== ========== =========== =========
Sales volumes (boe) 10,773,266 13,813,060 (3,039,794) (22.0)%
======================================== ========== ========== =========== =========
Average Brent crude oil price (US$/bbl) 71.7 54.7
======================================== ========== ========== =========== =========
For the year ended 31 December
=====================================
Variance,
In thousands of US dollars 2018 2017 Variance %
============================ ======= ======= ======== =========
Revenue from export sales 296,034 262,767 33,267 12.7%
Revenue from domestic sales 93,893 142,766 (48,873) (34.2)%
============================ ======= ======= ======== =========
Total 389,927 405,533 (15,606) (3.8)%
============================ ======= ======= ======== =========
Cost of sales
For the year ended 31 December
=====================================
Variance,
In thousands of US dollars 2018 2017 Variance %
========================================= ======= ======= ======== =========
Depreciation, depletion and amortisation 115,212 120,692 (5,480) (4.5)%
Payroll and related taxes 18,326 17,652 674 3.8%
Repair, maintenance and other services 16,133 18,960 (2,827) (14.9)%
Other transportation services 6,116 8,335 (2,219) (26.6)%
Materials and supplies 5,253 6,333 (1,080) (17.1)%
Well workover costs 2,767 4,159 (1,392) (33.5)%
Environmental levies 367 375 (8) (2.1)%
Change in stock 134 297 (163) (54.9)%
Other 837 443 394 88.9%
========================================= ======= ======= ======== =========
Total 165,145 177,246 (12,101) (6.8)%
========================================= ======= ======= ======== =========
Cost of sales decreased by 6.8% to US$165.1 million for the
reporting period (FY 2017: US$177.2 million). The decrease is
primarily explained by the decrease in depreciation, depletion and
amortization, repair, maintenance and other services, other
transportation services, materials and supplies and well workover
costs, further described in more detail below. On a boe basis, cost
of sales increased by 19.6% to US$15.33 for the reporting period
(FY 2017: US$12.83) and cost of sales net of depreciation per boe
increased by US$0.54, or 13.2%, to US$4.63 (FY 2017: US$4.09).
Depreciation, depletion and amortisation decreased marginally by
4.5% to US$115.2 million for the reporting period (FY 2017:
US$120.7 million). Depreciation is calculated applying units of
production method. Decrease of depreciation in 2018 in comparison
with prior period is a consequence of the ratio change between the
volumes produced and the proved developed reserves as well as
addition to O&G assets in the amount of US$131.5 million during
reporting period.
Repair, maintenance services decreased by 14.9% to US$16.1
million for the reporting period (FY 2017:US$19.0 million) and
materials and supplies decreased by 17.1% to US$5.3 million for the
reporting period (FY 2017: US$6.3 million). These expenses include
services on repairs and maintenance of the facilities, specifically
for the gas treatment facility as well as related spare parts and
other materials. These costs fluctuate depending on the timing of
the periodic scheduled maintenance works.
Other transportation services decreased by 26.6% to
US$6.1million for the reporting period (FY 2017:US$8.3 million).
The decrease is explained by the successful cost optimisation
implemented by the Group during the reporting period.
General and administrative expenses
For the year ended 31 December
====================================
Variance,
In thousands of US dollars 2018 2017 Variance %
============================== ======= ====== ======== =========
Payroll and related taxes 11,292 13,578 (2,286) (16.8)%
Professional services 4,346 11,095 (6,749) (60.8)%
Depreciation and amortisation 1,869 2,294 (425) (18.5)%
Insurance fees 1,570 1,640 (70) (4.3)%
Lease payments 846 797 49 6.1%
Business travel 774 1,487 (713) (47.9)%
Communication 357 411 (54) (13.1)%
Materials and supplies 168 363 (195) (53.7)%
Bank charges 165 221 (56) (25.3)%
Other 825 1,417 (592) (41.8)%
============================== ======= ====== ======== =========
Total 22,212 33,303 (11,091) (33.3)%
============================== ======= ====== ======== =========
General and administrative expenses decreased by 33.3% to
US$22.2 million for the reporting period (FY 2017: US$33.3
million). This was mainly driven by US$6.7 million or 60.8%
decrease in professional services from US$11.1 million in 2017 to
US$4.3 million in 2018.
Selling and transportation expenses
For the year ended 31 December
====================================
Variance,
In thousands of US dollars 2018 2017 Variance %
=========================== ======= ====== ======== =========
Loading and storage costs 18,881 26,940 (8,059) (29.9)%
Transportation costs 15,017 20,160 (5,143) (25.5)%
Marketing services 10,963 14,363 (3,400) (23.7)%
Payroll and related taxes 2,565 2,033 532 26.2%
Other 2,558 2,945 (387) (13.1)%
=========================== ======= ====== ======== =========
Total 49,984 66,441 (16,457) (24.8)%
=========================== ======= ====== ======== =========
Selling and transportation expenses decreased by 24.8% to
US$50.0 million for the reporting period (FY 2017: US$66.4
million), owing primarily to decrease in sales volumes as well as
further decrease effect in oil transportation costs resulting from
successful connection to the KTO pipeline.
Taxes other than income tax
For the year ended 31 December
====================================
Variance,
In thousands of US dollars 2018 2017 Variance %
=========================== ======= ====== ======== =========
Royalties 15,155 15,724 (569) (3.6)%
Export customs duty 11,233 3,864 7,369 190.7%
Government profit share 3,277 248 3,029 1221.4%
Other taxes 37 131 (94) (71.8)%
=========================== ======= ====== ======== =========
Total 29,702 19,967 9,735 48.8%
=========================== ======= ====== ======== =========
Royalties, which are calculated based on production and market
prices for the different products, decreased by 3.6% to US$15.1
million for the reporting period (FY 2017: US$15.7 million), which
is mainly owing to the relative decrease in the production
volumes.
Export customs duty on crude oil increased by 190.7% to US$11.2
million for the reporting period (FY 2017: US$3.8 million), mainly
owing to the relative decrease of export sales to CIS countries,
which are not subject to export duties.
Government profit share increased by US$3.0 million to US$3.3
million for the reporting period (FY 2017: US$0.2 million).
Impairment charge
Considering the reserves downgrade the Group has stress-tested
the impairment model with higher sensitivities and recognised
non-cash impairment charge totalling US$150.0 million (FY 2017:
nil), including impairment of goodwill in the amount of US$32.4
million and impairment of oil and gas assets of US$117.6
million.
Finance costs
For the year ended 31 December
====================================
Variance,
In thousands of US dollars 2018 2017 Variance %
===================================== ======= ====== ======== =========
Interest expense on borrowings 41,143 42,797 (1,654) (3.9)%
Transaction costs 6,648 15,709 (9,061) (57.7)%
Unwinding of discount on amounts due
to Government of Kazakhstan 845 866 (21) (2.4)%
Unwinding of discount on abandonment
and site restoration provision 399 225 174 77.3%
Other finance costs 214 - 214 100%
Finance charges under finance leases 134 155 (21) (13.5)%
===================================== ======= ====== ======== =========
Total 49,383 59,752 (10,369) (17.4)%
===================================== ======= ====== ======== =========
Finance costs decreased by 17.4% to US$49.4 million for the
reporting period (FY 2017: US$59.8 million), which is mainly owing
to lower transactions costs on bonds refinancing, as well as
relatively higher interest capitalisation rate.
Other
Loss on derivative financial instruments amounted to US$12.4
million in the reporting period and relates to fair value of the
hedging contract covering oil sales. Based on the contract the
Group has covered the cost of the floor price by selling a number
of call options with different strike prices for each quarter:
Q1:US$67.5/bbl, Q2:US$64.1/bbl, Q3:US$64.1/bbl, Q4:US$64.1/bbl. The
amount of upside given away has been capped through the purchase of
a number of call options with different strike prices:
Q1:US$71.5/bbl, Q2:US$69.1/bbl, Q3:US$69.6/bbl, Q4:US$69.6/bbl.
Movement in fair value of financial derivative instruments is
disclosed in Note 29 of the Consolidated financial statements
included in this report.
Other expenses decreased to US$13.5 million for the reporting
period (FY 2017: US$22.0 million). Such a significant decrease in
other expenses is mainly explained by non-recurring business
development expenses incurred in 2017 in relation to potential
acquisitions of oil and gas exploration and appraisal assets in
Kazakhstan.
Income tax expense decreased by US$21.3 million to US$28.5
million for the reporting period (FY 2017: US$49.8 million). The
decrease in income tax expense was primarily driven by impairment
of oil and gas properties in the current period, the effect of
which on the deferred tax liabilities was partially offset by the
devaluation of Tenge against US Dollar during the reporting
period.
Liquidity and capital resources
During the period under review, Nostrum's principal sources of
funds were cash from operations and amounts raised under the 2018
Notes. Its liquidity requirements primarily relate to meeting
ongoing debt service obligations (under the 2017 Notes and the 2018
Notes) and to funding capital expenditures and working capital
requirements.
Cash flows
The following table sets forth the Group's consolidated cash
flow statement data for the reporting period and FY 2017:
For the year ended
31 December
====================
In thousands of US dollars 2018 2017
============================================================== ========= =========
Cash and cash equivalents at the beginning of the year 126,951 101,134
============================================================== ========= =========
Net cash flows from operating activities 214,041 182,788
Net cash used in investing activities (172,021) (192,391)
Net cash (used in)/from financing activities (47,009) 34,589
Effects of exchange rate changes on cash and cash equivalents (209) 831
============================================================== ========= =========
Cash and cash equivalents at the end of the year 121,753 126,951
============================================================== ========= =========
Net cash flows from operating activities
Net cash flow from operating activities was US$214.0 million for
the reporting period (FY 2017: US$182.8 million) and was primarily
attributable to:
-- Loss before income tax for the reporting period of US$92.2
million (FY 2017: profit before income tax of US$26.0 million),
adjusted by a non-cash charge for depreciation, depletion and
amortisation of US$117.1 million (FY 2017: US$123.0 million),
impairment charge of US$150.0 million (FY 2017: nil), finance costs
of US$49.4 million (FY 2017: US$59.8 million), loss on derivatives
of US$12.4 million (FY 2017: US$6.7million) and payments made under
derivatives of US$8.6 million.
-- A US$4.0 million decrease in working capital (FY 2017:
US$18.8 million increase) was mainly due to a decrease in
prepayments and other current assets of US$7.7 million (FY 2017: a
increase of US$5.7 million), a decrease in trade payables of US$3.2
(FY 2017: US$4.6 million) and a decrease in other current
liabilities of US$5.5 million (FY 2017: a decrease of US$1.6
million).
-- Income tax paid of US$9.1 million (FY 2017: US$15.9
million).
Net cash used in investing activities
The substantial portion of cash used in investing activities is
related to the drilling programme and the construction of a third
unit for the gas treatment facility.
Net cash used in investing activities for the reporting period
was US$172.0 million (FY 2017: US$192.4 million) due primarily to
costs associated with the drilling of new wells of US$87.5 million
for the reporting period FY 2017: US$57.5 million), costs
associated with the third gas treatment unit of US$55.8 million (FY
2017: US$157.5 million), and costs associated with Rostoshinskoye,
Darjinskoye and Yuzhno-Gremyachinskoye fields of US$2.5 million (FY
2017: US$3.6 million).
Net cash from/(used) in financing activities
Net cash used in financing activities during the reporting
period made up US$47.0 million, and was mainly represented by
proceeds from issue
of 2018 Notes in the amount of US$397.3 million, offset by the
early redemption of 2012 Notes and 2014 Notes totalling US$353.2
million, the fees and premium paid for the arrangement of these
transactions in the amount of US$9.3 million, and the payment of
US$81.1 million of the finance costs, primarily on the Group's 2017
Notes and 2018 Notes. Net cash from financing activities during FY
2017 made up US$34.6 million, which was mainly represented by
proceeds from issue of 2017 Notes in the amount of US$725 million,
offset by the early redemption of 2012 Notes and 2014 Notes
totalling US$606.8 million, the fees and premium paid for the
arrangement of these transactions in the amount of US$27.0 million,
and the payment of US$57.0 million of the finance costs on the
Group's 2012 Notes and 2014 Notes.
Commitments
Liquidity risk is the risk that the Group will encounter
difficulty raising funds to meet commitments associated with its
financial liabilities. Liquidity requirements are monitored on a
regular basis and management seeks to ensure that sufficient funds
are available to meet any commitments
as they arise.
The table below summarises the maturity profile of the Group's
financial liabilities as at 31 December 2018 based on
contractual
undiscounted payments:
Less than More than
As at 31 December 2018 On demand 3 months 3-12 months 1-5 years 5 years Total
========================== ========= ========= =========== ========== ========= ==========
Borrowings - 43,000 43,000 1,011,000 456,000 1,553,000
Trade payables 37,843 - 15,033 - - 52,876
Other current liabilities 29,858 - - - - 29,858
Due to Government of
Kazakhstan - 258 773 4,124 7,474 12,629
========================== ========= ========= =========== ========== ========= ==========
67,701 43,258 58,806 1,015,124 463,474 1,648,363
========================== ========= ========= =========== ========== ========= ==========
Capital commitments
During the reporting period, Nostrum's cash used in capital
expenditures for purchase of property, plant and equipment
(excluding VAT) was approximately US$131.4 million (FY 2017:
US$188.1 million). This mainly reflects costs associated with the
construction of the third gas treatment unit, drilling costs and
other field infrastructure development projects.
Gas Treatment Facility
Following the successful completion of the first phase of the
gas treatment facility, consisting of two units, the Group achieved
mechanical completion of a third unit in December 2018, with
commissioning anticipated to be completed in 2019. The construction
of GTU3 is important for implementing the Group's strategy to
increase operating capacity and as a result increase production and
processing of liquid hydrocarbons. Management estimates, based on
the production profile of both proved and probable reserves
reported in the 2018 Ryder Scott Report and assuming the full
commissioning of the gas treatment facility in H2 2019, that the
Company's annual production will gradually increase from 2019
onwards. The remaining costs for the completion of GTU3 are
estimated at US$34.6 million.
Drilling
Drilling expenditures amounted to US$87.5 million for the
reporting period (FY 2017 US$57.5 million). After the completion of
GTU3, it is expected that the drilling expenditure will become the
primary driver of the Company's investing activities.
Dividend policy
The Group currently pays no dividend and has not done so for the
last three years, as the Board determined it was not in the
Company's best interests to do so. This will be reviewed annually
by the Board.
In millions of US$ (unless mentioned 2018 2017 2016 2015 2014
otherwise)
========================================= ======= ======= ======= ======= =======
EBITDA reconciliation
(Loss)/profit before income tax (92.2) 26.0 (65.5) 72.3 311.7
Add back
Impairment charge 150.0 - - - -
Finance costs 49.4 59.8 41.7 46.0 61.9
Finance costs - reorganisation(1) - - - 1.1 29.6
Employee share options - fair
value adjustment (1.3) (2.1) (0.1) (2.2) (3.1)
Foreign exchange loss, net 1.0 0.7 0.4 21.2 4.2
Loss on derivative financial
instruments 12.4 6.7 63.2 (37.1) (60.3)
Interest income (0.5) (0.4) (0.5) (0.5) (1.0)
Other expenses 8.4 22.0 (1.8) 30.6 49.8
Export customs duty(2) - - - (14.7) (19.7)
Other income (4.4) (4.1) (2.2) (11.3) (10.1)
Depreciation, depletion and amortisation 117.1 123.0 131.6 109.4 111.9
Proceeds from derivative financial
instruments(3) - - 27.2 92.3 -
Purchase of derivative financial
instruments(3) (8.6) - - (92.0) -
========================================= ======= ======= ======= ======= =======
EBITDA 231.3 231.6 194.0 215.0 475.0
========================================= ======= ======= ======= ======= =======
Operating costs reconciliation
Cost of sales 165.1 177.2 182.2 186.6 221.9
Less
Depreciation, depletion and amortisation (115.2) (120.7) (129.4) (107.7) (110.5)
Royalties - - - (14.4) (24.3)
Government profit share - - - (1.9) (4.6)
========================================= ======= ======= ======= ======= =======
Operating costs 49.9 56.5 52.8 62.6 82.5
========================================= ======= ======= ======= ======= =======
Net debt reconciliation
Long-term borrowings 1,094.0 1,056.5 943.5 936.5 930.1
Current portion of long-term
borrowings 35.6 31.3 15.5 15.0 15.0
Less
Current investments - - - - 25.0
Cash and cash equivalents 121.8 127.0 101.1 165.6 375.4
========================================= ======= ======= ======= ======= =======
Net debt 1,007.8 960.8 857.9 785.9 544.7
========================================= ======= ======= ======= ======= =======
Net cash flows from operating
activities 214.0 182.8 202.1 153.3 349.1
Net cash used in investing activities (172.0) (192.2) (200.3) (245.3) (304.5)
Net cash from / (used in) financing
activities (47.0) 34.6 (66.3) (115.9) 147.5
EBITDA margin 59.3% 57.1% 55.7% 47.9% 60.7%
Equity/assets ratio % 29.6% 32.8% 35.4% 41.6%
Share price at end of period
(US$) 1.03 4.41 4.75 5.97 6.56
Shares outstanding ('000s) 188,183 188,183 188,183 188,183 188,183
Options outstanding ('000s) 3,432 3,333 2,536 2,611 2,611
Dividend per share (US$) - - - 0.27 0.35
========================================= ======= ======= ======= ======= =======
1. The reorganisation costs are represented by the costs
associated with the introduction of Nostrum as the new holding
company of the Group and the respective reorganisation that took
place in June 2014.
2. In 2016, 2017 and 2018, Export customs duty is included
within Profit / (loss) before income tax (presented within 'taxes
other than income tax'). In 2014 and 2015, Export customs duty is
included within 'other expenses', therefore an adjustment is made
to re-include Export customs duty within respective EBITDA.
3. Cash received from hedge contract represents the cash
proceeds from the long-term hedging contract which in accordance
with IAS7 Statement of Cash Flows is included within operating cash
flows. While this item is not required to be presented in the
Consolidated Income Statement, we have included this in our
definition of EBIT and EBITDA in order to better align these
non-GAAP measures with our operating cash flows.
4. Depreciation as it applies to operating assets only.
5. Prior to 2016, royalties and government profit share were
reported within the cost of sales line.
6. IFRS term based on indirect cash flow methodology
7. EBIDTA margin is calculated as EBITDA divided by total
revenue.
8. Prior to 20 June 2014 the equity of the Group was represented
by GDRs, the share price as at 31 December 2018 was 1.03 GBP/share
x 1.28 US$/GBP = 1.32 US$/share
Alternative performance measures
In the discussion of the Group's reported operating results,
alternative performance measures (APMs) are presented to provide
readers with additional financial information that is regularly
reviewed by management to assess the financial performance or
financial health of the Group,
or is useful to investors and stakeholders to assess the Group's
performance and position. However, this additional information
presented is not uniformly defined by all companies including those
in the Group's industry. Accordingly, it may not be comparable with
similarly titled measures and disclosures by other companies.
Certain information presented is derived from amounts calculated in
accordance with IFRS but is not itself an expressly permitted IFRS
measure. Such measures should not be viewed in isolation or as an
alternative to the equivalent IFRS measure.
EBITDA
EBITDA is defined as the results of operating activities before
depreciation and amortisation, share-based compensation, fair value
gains and losses on derivative instruments, foreign exchange
losses, finance costs, finance income, non-core income or expenses
and taxes, and includes any cash proceeds received or paid out from
hedging activity. This metric is relevant as it allows management
to assess the operating performance of the Group in absence of
exceptional and non-cash items.
Operating costs
Operating costs are the cost of sales less depreciation,
royalties and government profit share(5) . This metric is relevant
as it allows management to see the cost base of the company on a
cash basis.
This information is provided by RNS, the news service of the
London Stock Exchange. RNS is approved by the Financial Conduct
Authority to act as a Primary Information Provider in the United
Kingdom. Terms and conditions relating to the use and distribution
of this information may apply. For further information, please
contact rns@lseg.com or visit www.rns.com.
END
FR EAKDKASLNEEF
(END) Dow Jones Newswires
March 26, 2019 03:01 ET (07:01 GMT)
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