TIDMPTR
RNS Number : 2967R
Petroneft Resources PLC
29 June 2020
PetroNeft Resources plc
29(th) June 2020
PetroNeft Resources plc ('PetroNeft' or 'the Company')
2019 and Q1 2020 Operations Update
Delay in Publication of 2019 Annual Report
PetroNeft (AIM: PTR) an oil & gas exploration and production
company, operating in the Tomsk Oblast, Russian Federation, and 50%
owner and operator of Licences 61 and 67 is pleased to provide the
following extensive operations update covering the full year 2019
and Q1 2020. This information is being provided to update
shareholders on operations while we are working towards completion
of our audit and publication of the 2019 Annual Report - both
having been delayed due to Covid. An extension has been granted by
Dublin ESM and London AIM markets.
Highlights
-- Licence 61
o 2019 production total 589,165 barrels of oil at an average
daily rate of 1,614 bopd. Q1 2020 average daily rate of 1,679
bopd.
o Sibkrayevskoye field connected enabling year-round production,
good well performance after six months of continuous production,
average daily rate Q1 2020 270 bopd (Q1 2019 279 bopd).
o Mini refinery construction re-started utilizing our own
equipment and personnel, completion expected by end of 2020.
-- Licence 67
o Following approval by the Russian State Reserves Committee of
19.26 mmbbls of C1+C2 reserves on the Cheremshanskoye field,
successfully re-entered, produced and sold 1,200 bbls of oil from
the C-4 well during Q1 2020.
o Project and planning work ongoing to enable construction of
basic field facilities to ensure year-round production from end of
2020.
o Well re-entry program halted half way through the C3 well
re-entry during Q1 2020 due to the combination of low oil price
combined with outbreak of Covid-19. C currently evaluating optimum
way to re start this program.
-- Finance & Corporate
o Continued focus on cost reduction and optimization across the
company.
o Due to the effects of the Covid-19 pandemic, the company has
been granted an extension to its filing deadline for its Final
Results from 30 June 2020 to 30 September 2020
David Sturt, CEO PetroNeft commented:
'2019 saw PetroNeft implement a cost effective, locally driven,
operations programme based on a significant improvement of our
understanding of our assets. We have implemented a range of
low-cost measures aimed at stabilizing production at existing
wells, identifying new opportunities for low cost exploration and
development and reducing costs through more effective use of our
assets. This has led to some significant wins, which give us
further hope for our assets.
Developments in 2020 have hit our industry hard. We are working
to manage the impact of Covid, to ensure the safety of our team and
the sustainability of our business. We are seeing some recovery but
this is fragile and we will maintain our discipline in the weeks
and months ahead.'
Licence 61
Production
Gross production from Licence 61 during 2019 was 589,165 bbls
(713,603 bbls in 2018) at an average rate of 1,614 bopd (1,955 bopd
in 2018) for the year; this represents a 17.4% decline in
production. Part of the lower production was due to extensive data
acquisition which required shutting in several wells to acquire
bottom hole pressure data and injection logging information. This
short-term reduction should help to achieve greater results over
the lifetime of the field.
As shown in table 1 below the decline rates across our fields
vary greatly. Thanks to our intensive data gathering and
interpretation project in 2019, we are now better positioned to
understand how to allocate resources and investment where they can
achieve the greatest economic benefit.
Field 2018 2019 Change %
BOPD BOPD BOPD Change
------ ------ ------- --------
Lineynoye 703 712 9 1.28%
------ ------ ------- --------
Arbuzovskoye 1,041 772 -269 -25.84%
------ ------ ------- --------
Tungolskoye 108 29 -79 -73.15%
------ ------ ------- --------
Sibkrayevskoye 103 101 -2 -1.94%
------ ------ ------- --------
Kondrashevskoye 0 0 0 0.00%
------ ------ ------- --------
Total 1,955 1,614 -341 -17.40%
------ ------ ------- --------
Table 1: Licence 61 daily production rate (bopd) per field for
2018 and 2019.
Gross production from Licence 61 during Q1 2020 was 152,786bbls
(172,070bbls in Q1 2019) at an average rate of 1,679 bopd (1,912
bopd in Q1 2019). This represents a 12.2% decline in production or
233 bopd. Over 70% of the decline was attributable to the decline
in the A-214 Horizontal well. During Q1 2020 water injection
started on Pad 2 of the Arbuzovskoye field, it is anticipated that
with this intervention, decline should slow down as reservoir
pressure starts to increase.
Field Q1 2019 Q1 2020 Change %
----------------- -------- --------
BOPD Change
----------------- -------- -------- ------- --------
Lineynoye 731 693 -38 -5.20%
-------- -------- ------- --------
Arbuzovskoye 851 670 -181 -21.27%
-------- -------- ------- --------
Tungolskoye 60 32 -28 -46.67%
-------- -------- ------- --------
Sibkrayevskoye 270 279 9 3.33%
-------- -------- ------- --------
Kondrashevskoye 0 5 5 0.00%
-------- -------- ------- --------
Total 1,912 1,679 -233 -12.20%
-------- -------- ------- --------
Table 2: Licence 61 daily production rate (bopd) per field Q1
2019 versus Q1 2019
Current gross production rate has remained steady at
approximately 1,600 bopd so far this year, except for mid-April
thru early May when some production was shut-in due to the severe
drop in oil prices combined with high Mineral Extraction Tax rates.
By shutting down some production the company minimised the amount
of oil that had to be produced at a loss. During the first week in
May all wells were successfully brought back into production as the
price of oil recovered.
Lineynoye & West Lineynoye
Production from the Lineynoye and West Lineynoye fields actually
increased year on year by 2.3% and was the result of focusing
workover resource on this field through the summer months to ensure
we maintained production.
The West Lineynoye wells continued to produce at just under 200
bopd through the year. These wells have now produced at stable
rates for 7 years which combined with a consistent less than 5%
water cut through this period highlights the potential for further
development of this resource. Any further development of this
resource will however utilise long offset (1,000m) horizontals
rather than the previous 300m horizontal wells. Longer offset
horizontal wells are able to drain the reservoir at higher rates
and more efficiently, thereby increasing production, lowering
development costs and increasing reserve recovery
Arbuzovskoye Field
Arbuzovskoye field production declined by 25.3% through the year
which accounted for approximately 80% of the overall Licence 61
decline. The majority of this decline came from one well, the
A-214H, which is still producing over 200 bopd. After a review of
data gathered during 2019, we identified potential pressure support
issues around the southern part of the field. During Q1 2020 we
took remedial action by switching one well on this part of the
field to water injection to provide pressure support. We are
already starting to see the flattening of the decline at the A-214
Hz well, and the adjacent A-215 Hz well has already stabilized.
Sibkrayevskoye Field
This field has historically only been on production during the
winter months from the S-373 and S-375s wells through trucking over
winter roads. During the winter 2019/20 we successfully connected
the field to the main Central Processing Facility enabling
year-round production from two wells. The project was completed on
time and significantly under budget.
To date the field has been producing for almost six months at
very stable rates with gross production Q1 2020 averaging 279 bopd,
versus 270 bopd for Q1 2019.
The stable production rates from these wells is very
encouraging, providing confidence in the future viability of the
full development of this field. Development plans are being
reviewed, but will likely focus on the use of 3D seismic data to
enable development wells to pinpoint the main Upper Jurassic thick
channel systems thereby increasing chances of success. This is a
technology that has been used on analogous fields with success
within this region for this reservoir section.
Tungolskoye
At Tungolskoye, we continue to evaluate ways of increasing
production from this field in the most cost-effective way. Since
moving forward with development of this field in 2015, production
results have been very disappointing. Following further review in
2019 the decision was taken to switch production to winter only to
minimize operational costs as maintaining production through the
summer would have required dedicated personnel and work over crew -
a cost the production levels could not justify.
Technical studies are ongoing to see if remedial well work such
as side-tracking wells, utilization of coiled tubing, or
potentially fracking, could improve productivity and thereby
enhance drainage of the reservoir.
Mini Refinery
Construction of the mini oil processing facility was halted
during Q1 2020 till winter 2021 due to a combination of the fall in
the oil price combined with the outbreak of the Covid-19 pandemic.
Construction has now re-started using internal resources instead of
outside contractors. This is resulting in further cost savings and
the new plan is to complete the project before end of 2020.
This is a key project for the company, in 2019 a total of 1,200
tons of fuel was purchased for approximately Rub 70M (approximately
US $1.1M), this equates to an operational cost of 2019 of $1.8/bbl.
The project once complete, will reduce operational costs by over
$1/bbl.
Emtorskaya Prospect
The strong production performance at the Lineynoye field is very
encouraging for the future potential of the Emtorskaya prospect,
which lies updip and is geologically similar. The original 2020
work program had planned to re-enter and re-test the old Soviet era
well No. 300 to test the potential of the Upper Jurassic
reservoirs. It was decided due to the combination of very mild
winter conditions combined with the low oil prices that this work
would be postponed to ensure additional costs were not
incurred.
The company is currently re-evaluating all the Emtorskaya
prospect data to decide on the next steps forward which may still
involve re-entering the old No. 300 well.
Ryder Scott evaluated the prospect and assigned possible
resources (P3) of 63.9 million bbls (gross) booked for this
structure out of a total Licence 61 exploration resource potential
of 405 million bbls (gross)
Licence 67
Following a detailed technical review in 2019 combined with the
significant economic advantages of developing such assets in close
proximity to infrastructure, we see this licence as holding
considerable potential value for the company and will be focused on
bringing this licence onto year-round production from the end of
2020.
In 2019 we started a low cost five well re-entry program on the
Cheremshanskoye, Ledovoye and Sklonovoye fields and prospects. This
well re-entry program successfully started during Q4 2019/Q1 2020
on the C-4 well and was part way through the C-3 well when it was
suspended due to a combination of low oil price and Covid-19
pandemic.
Cheremshanskoye Field
During Q1 2019, GKN (Russian State Reserves Committee) approved
C1+C2 (approximately equal to International 2P reserves category)
reserves for the field of 19.26 million barrels.
The well re-entry program successfully started with re-entry and
testing of the C-4 well. Despite very mild winter conditions we
were able to test and produce approximately 1,200 barrels of oil
which flowed naturally at up to 476 bopd. The pre-drill estimates
utilising a down hole pump was 400 bopd so achieving such a high
rate under natural flowing conditions was a significant
success.
The oil produced was successfully sold for market rates at well
head without any transportation costs and achieving the 20% MET
discount thereby proving the enhanced commercial value of future
production from this field.
Work on the C-3 well re-entry was halted due to the current
economic crisis. The lower J-14 interval however was tested and
yielded non-commercial quantities of gas and light oil. These
results are being integrated into the geological model to decide on
the forward steps. We believe that the C-3 well tested a condensate
rich gas cap in the J-14 sand. The C-1 well located to the west
lies down-dip of the C-3 well and has much better reservoir sands
within this same interval. Although the reservoir was tight in the
C-3 well, there is potential to frack this reservoir in the future
which is a technique applied successfully on an adjacent field with
the same reservoir.
The company is now evaluating the optimum way forward for this
licence but it is likely to include bringing the Cheremshanskoye
field onto year-round production from the end of this year combined
with a continuation of the well re-entry program.
Covid-19
PetroNeft prioritises the safety of our staff and our
stakeholders in scheduling our operations at this time. All
unnecessary travel has been suspended. Operations have been
redesigned to ensure that social distancing is incorporated.
Covid 19 significantly impacted on oil markets and on the
financial position of all oil companies. PetroNeft has taken
further steps to trim our already lean operating model. These moves
will help to secure the future viability of the business.
Market Outlook
The prices we receive for our oil sales have improved from their
low point in April, but we remain cautious about the potential for
further recovery in 2020, however even this recovery has allowed us
to re commence certain projects such as the mini oil processing
facility.
Cash and gross debt
As of 31 December 2019 and 31 March 2020, the Group's cash
balance was US$0.3 million and US$0.7 million respectively.
In January 2020, the Company placed 107,755,037 ordinary shares
at GBP0.015 per share (58% premium to closing market price)
resulting in cash proceeds of US $1.590 million and payables of
US$531,000 being converted into ordinary shares.
As of 31 December 2019 and 31 March 2020, the Group's gross debt
was US$4.3 million.
The company has two outstanding debt facilities, a convertible
loan note with various related parties and a loan with Petrogrand
AB.
(i) The convertible loan facility is for US$1.3 million and
carries an interest rate of 8% above the 3-month USD LIBOR rate.
Lenders can elect at any time to convert up to 65% of the
outstanding loan to shares at a conversion price of US$0.01547
(1.547 cent), this being the five-day weighted average share price
prior to execution of the loan facility.
(ii) The second loan facility is with Petrogrand AB. The loan
was initially signed 16(th) January 2018 providing a US$2 million
loan facility. This facility was increased to US$2.5 million on 14
February 2019 and was due for repayment in full on 15 (th) December
2019. The company successfully negotiated a one-year extension to
the loan facility which included both the loan principal and
interest outstanding at that time, with an additional potential
second year extension if 20% of the capital is repaid by 15(th)
December 2020. If the conditions on the second one-year extension
are met, the interest rate will reduce from LIBOR + 9% to LIBOR +6%
in December 2020. The company has been paying interest, on the
latest extension on the revised loan amount as it become due from
December 2019 onwards.
Capex and Overhead
Through to the end of June 2020, the Group will have expensed US
$0.74 million on key infrastructure projects, most notably the mini
oil processing facility which will substantially reduce diesel
overhead from fiscal 2021 onwards.
The Group continues to actively mitigate the challenges of the
current business environment by proactively working with its key
suppliers and service partners in managing working capital through
securing payment in advance for oil deliveries and extending credit
periods on key payables. Combined with an active ongoing overhead
reduction programs and the seasonality of its capex programs which
are weighted historically to the first quarter of each fiscal year,
it is envisaged planned expenditures can be financed from future
cash flows.
Delay in Publication of 2019 Annual Report
The Covid-19 pandemic has resulted in lockdowns in all areas
where the company operates or has offices. The delay in publication
reflects the additional time needed to complete the audit given the
associated travel restrictions and delays in fulfilling audit
requests.
Accordingly, the Company has requested and received an extension
from both the ISE and AIM to its filing deadline for its Final
Results from 30 June 2020 to 30 September 2020.
For further information, contact:
+971 55 1919
David Sturt, CEO, PetroNeft Resources plc 808
+353 1 679
John Frain/Brian Garrahy, Davy (NOMAD and Broker) 6363
+353 1 498
Joe Heron / Douglas Keatinge, Murray Consultants 0300
The information contained in this announcement has been reviewed
and verified by Mr. David Sturt, Chief Executive Officer and
Executive Director of PetroNeft, for the purposes of the Guidance
Note for Mining and Oil & Gas Companies issued by the London
Stock Exchange in June 2009. Mr. Sturt holds a B.Sc. Degree in
Earth Sciences from Kingston University and an MSc. in Exploration
Geophysics from The University of Leeds. He is a member of the
Petroleum Exploration Society Great Britain and has over 35 years'
experience in oil and gas exploration and development.
Glossary
bopd Barrels of oil per day
bbls Barrels
------------------------------------------------------
Rub Russian Ruble
------------------------------------------------------
mmbbls Million barrels
------------------------------------------------------
MET Mineral Extraction Tax
------------------------------------------------------
C1 + C2 Russian State Reserves C1 + C2, equivalent
to 2P (Proven and Probable)
------------------------------------------------------
2P Proven and Probable reserves under the Society
of Petroleum Engineers Petroleum Reserves Management
System
------------------------------------------------------
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END
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