TIDMFPM
RNS Number : 6548E
Faroe Petroleum PLC
13 February 2018
13 February 2018
Faroe Petroleum plc
("Faroe", "Faroe Petroleum", the "Company")
Operational Update and 2018 Guidance
Faroe Petroleum, the independent oil and gas company focussing
principally on exploration, appraisal and production opportunities
in Norway and the UK, is pleased to provide an update on operations
and guidance for 2018.
Highlights
- 2017 average production of 14,300 boepd at the upper end of 2017 guidance
- 2018 production is expected to be in the range of 12,000 to 15,000 boepd
- 20% increase in 2P reserves to 97.7 mmboe at year-end
following the successful Brasse appraisal well in 2017 and after
adjusting for the Fenja transaction announced yesterday(1) .
Year-end 2C resources are 78.6 mmboe, as adjusted for Fenja
- Fully funded for Brasse and ongoing development projects: Oda;
Njord Future; Bauge and Fenja, following the divestment of 17.5% of
Fenja
- High quality E&A drilling programme under way for 2018
with two wells already drilling: Iris/Hades and Fogelberg and with
three further wells added: Rungne, Cassidy and Pabow
Graham Stewart, Chief Executive of Faroe Petroleum
commented:
"2017 has been another very good year for Faroe with strong
operational performance enhanced by a general recovery in commodity
prices and market sentiment. A highly successful appraisal well on
our Brasse oil and gas discovery in Norway and its conversion to 2P
reserves, combined with positive reserves revisions in Ula and
Tambar led to Faroe's highest ever recorded year-end 2P reserves at
97.7 mmboe, an increase of 20% even after adjusting for the reduced
interest in Fenja announced yesterday. The Tambar production
project commenced last year and the two infill wells have now been
drilled and early results are very positive showing good potential
for increased production with the new wells expected on stream
during February.
"We announced yesterday that we have agreed a part-disposal of
17.5% of Fenja to Suncor, reducing our working interest from 25% to
7.5%. As well as generating an immediate cash consideration of
$54.5 million, this will decrease our future capex on Fenja from an
estimated GBP232 million to approximately GBP70 million. As a
result, and with our existing cash position and unused debt, we are
now fully funded for the operated Brasse project, which remains
uncommitted at this stage, as well as our committed and ongoing
Norwegian development projects.
"As we embark on another very busy year for the business, Faroe
is again well positioned to capture the growth opportunities which
we continue to generate from our balanced portfolio of development
and exploration and appraisal opportunities, backed by our
sustainable and increasingly cash generative production base."
(1) as adjusted for sale of a 17.5% interest in Fenja
2017 operational update detail:
Production - significantly enhanced by the field development
programme to deliver long term profitable production growth
-- Total average economic production for the full year 2017 was
approximately 14,300 boepd, of which approximately 55% was liquids
and 45% gas. Table 1 as attached, presents preliminary 2017
production data per field net to Faroe's participating
interests
-- In a transaction with JX Nippon, Faroe increased its working
interest in Blane, on attractive terms, to 44.5%, with a
corresponding increase in production
-- Average full year 2018 production is currently forecast to be
in the range of 12,000 to 15,000 boepd from all fields, split
approximately 67% liquids and 33% gas. The range in this initial
forecast reflects short term uncertainty on both the upside
potential of the new wells due to come on stream on the Tambar and
Brage fields, and the duration of the temporary shut in of the Trym
field as a result of a pipeline integrity issue at the Tyra
gathering hub. The range will be narrowed when there is greater
clarity on production from these fields
-- Average Opex in 2017 for producing assets was approximately
$26.5 per boe (excluding accrued tariff costs in relation to future
upgrades ($29.5 per boe including tariff costs in relation to
future upgrades))
-- Opex in 2018 is expected to be in the range of $23 to $27 per
boe. Unit Opex is expected to decrease further as new production is
brought on stream in 2019 and beyond
-- Faroe continues to seek suitable value-enhancing production
acquisitions, taking advantage of the Company's strong balance
sheet
Reserves and Resources - 20% increase in reserves in 2017 to
record level of 97.7 mmboe
Faroe has completed its internal assessment of reserves and
resources at 1 January 2018, which are as follows and include an
adjustment for the disposal of a 17.5% interest in the Fenja
Field:
-- 2P Reserves increased by 20% with closing reserves at 97.7
mmboe (1 Jan-17: 81.3 mmboe). The significant increase (reserves
replacement in excess of 700%) is a result of the conversion of
Brasse from contingent resources to reserves and incremental
projects across the portfolio, which generated positive reserve
revisions notably on Tambar, which more than compensate for the
divestment of a 17.5% interest in the Fenja field
-- 2C Contingent Resources are 14% lower at 78.6 mmboe (1
Jan-17: 90.9 mmboe) as a result of the additional contingent
resources, mainly in Ula, Tambar and Oselvar, not fully
compensating for the transfer of Brasse to reserves and divestment
in Fenja
Table 2 of this announcement, as attached, presents Faroe's net
2P Reserves per field, split into liquids (oil and NGL) and gas
reserves.
Development - portfolio of high quality developments progressing
well
The Brasse Area
-- Brasse oil and gas discovery (Faroe 50%): The preliminary
reservoir drainage plan includes three to six subsea production
wells and possible water injection for pressure support. Gross
plateau flow rates for this field have the potential to reach
30,000 boepd, and first production is targeted for 2021.
-- At the end of 2017, the Brasse feasibility study phase was
completed confirming several attractive development solutions and
export routes. The key project milestone for 2018 will be the
Concept Selection including the selection of a reservoir drainage
plan and a processing host. The Plan for Development and Operation
(PDO) submission is expected in 2019.
-- The Brage field (Faroe 14.3%): the infill well programme
continues, with two producer-injector pairs in the Statfjord
formation and one producer in the Fensfjord formation. The first
Statfjord producer and the Fensfjord producer are on stream. The
second Statfjord producer is to be put on stream during March and
based on drilling results is expected to deliver production rates
well above pre-drill expectations.
The Ula Hub Area
-- The development programme on the Tambar field (Faroe 45%)
continues with the drilling of two infill wells and the
installation of gas lift in three existing wells to increase
overall field production. The two infill wells, which targeted
undrained areas in the north and south of the field, have now been
drilled and the results are promising, with both wells exceeding
pre-drill expectations. The operator plans to bring the first well
on stream this month and a second shortly thereafter. Initial
production rates from the two wells are estimated to be in the
range of 10,000 - 15,000 boepd (Faroe 4,500-6,750 boepd). It is
expected that the overall development programme including gas lift
will extend field life by up to 10 years, contributing to lower
unit operating costs in the Ula hub area. The encouraging results
from the infill campaign will be used to refine the field model and
plan further development of the Tambar reservoir.
-- The Oda oil field (Faroe 15%) is being developed as a subsea
tie back to the Ula platform (Faroe 20%), approximately 13
kilometres to the east. The project, which is both on schedule and
within budget is now entering a busy offshore construction phase
this spring with three wells being drilled in the field (two
producers and one water injection well). First oil is scheduled for
mid-2019, with gross plateau production expected to be 30,000 boepd
(4,500 boepd net to Faroe). Production from the Oselvar field
(Faroe operated 55%) is scheduled to cease in Q2 2018 to allow the
Oda tie-in to be undertaken. Upon cessation of production the
Oselvar owners (Faroe 55%) will receive a final compensation
payment, dependent on the Oselvar field production level at shut
down.
-- On the Ula field (Faroe 20%), the operator continues to
mature targets for a new infill campaign which is expected to
commence in 2019. Potential infill targets include wells to expand
the use of WAG (water alternating gas) injection to increase
recovery, the deeper Triassic reservoir which has only one well in
production today, as well as near field discoveries such as Ula
North. The 4D seismic survey successfully acquired in 2017 will
provide important new information when processing is completed in
Q2 this year. A number of significant upgrades to the field
facilities are also under way which will support long term
production.
-- On the Blane Field (Faroe 44.5%), following the successful
completion of the subsea upgrades in 2017 aimed at improving
reliability, the operator is now considering infill targets.
The Njord Hub Area
-- In December 2017 a PDO was submitted for the Fenja field in
the Greater Njord Area (Faroe 7.5% following completion of the
Suncor transaction announced yesterday), comprising three
horizontal production wells - one gas injector well and two water
injector wells - tied back to the Njord A floating production
facility for processing and export via the Njord B FSO (floating
storage and offloading vessel). The Fenja licence partners are
planning to invest NOK 10.2 billion (approximately GBP900 million)
with planned production start-up in Q1 2021 and a planned field
life of 16 years.
-- The Njord Future project encompasses refurbishment of the
Njord facilities for continued production and development of the
Njord and Hyme fields and upgrading and modifications to enable the
Bauge and Fenja fields to be tied back. The Njord Future Project is
progressing on schedule and within budget. In 2018, key milestones
include installation of blisters on all four columns, installation
of column top extensions and deck boxes. Trusswork reinforcement
work is also ongoing. Current timing is for the Njord A platform to
be towed offshore during spring 2020.
-- The Bauge development project is also progressing on schedule
and within budget. Contracts for marine and drilling operations are
currently being progressed.
-- Njord and Hyme is expected to recommence production in Q4
2020 followed by first oil from Bauge shortly thereafter.
-- The table set out below provides an illustrative development
project matrix for the committed and ongoing development project as
well as for the operated and uncommitted Brasse project.
Illustrative Development Project Metrics
-------------------------------------------------------------------------------
Field WI Prod Production Reserves Capex Opex
(%) start (1) Net mmboe (2) ($/boe)
Net boepd Net (GBPm)
------------ ------ ------ ------------ ---------- ----------- ----------
Oda 15.0 2019 4,500 7.2 74 10 - 15
------------ ------ ------ ------------ ---------- ----------- ----------
Njord and
Hyme 7.5 2020 6,500 13.1 97 10 - 15
------------ ------ ------ ------------ ---------- ----------- ----------
Bauge 7.5 2020 2,000 5.4 28 6 - 10
------------ ------ ------ ------------ ---------- ----------- ----------
Fenja (3) 7.5 2021 2,500 7.0 70 10 - 15
------------ ------ ------ ------------ ---------- ----------- ----------
Brasse
(4) 50.0 2021 15,000 30.7 240 10 - 20
------------ ------ ------ ------------ ---------- ----------- ----------
(1) Target Plateau Rate
(2) From PDO date converted from NOK assuming a NOK/GBP rate of
11.0
(3) The reduction in the participating interest of Fenja to 7.5%
remains subject to approval by Norwegian Authorities
(4) Brasse is less mature than the committed projects. Capex and
opex levels depend on development concept and commercial terms for
tie-back
Exploration & Appraisal - High impact and near field
exploration and appraisal programme continuing
-- The Iris/Hades well (Faroe 20%) spud in November 2017,
targeting two separate formations, one Cretaceous and the other
Jurassic. Well results are expected in the coming weeks.
-- The Fogelberg appraisal well (Faroe 28%) commenced drilling
in February 2018 with the main objective of narrowing the range in
the resources estimate of between 105 and 530 bcf (between 19 and
116 mmboe including the condensate) and to provide additional
information for development planning.
-- In H2 2018, Faroe expects to drill the operated Rungne (40%)
exploration well. Rungne is located in licence PL825 immediately
north of the Oseberg field in the Northern North Sea. The primary
target will be the Middle Jurassic Oseberg Formation, with
secondary targets in the Etive, Ness and Tarbert formations. The
unrisked gross resources (100%) are estimated to be c. 70 mmboe.
Work is ongoing to secure a rig for this drilling operation.
-- The Cassidy exploration well (Faroe 15%) is also expected to
be drilled in H2 2018, back-to-back with the production wells in
Oda. Cassidy sits within the PL405 Oda licence to the north of Oda
in the Southern North Sea. The well will target a prospect with the
same Jurassic Ula formation level as the Oda field with gross
unrisked potential of c. 50 mmboe.
-- Two further exploration wells have been committed to recently
- the Statoil operated Pabow prospect (Faroe 20%) and the
Wintershall operated Yoshi prospect (Faroe 30%):
o Pabow is located on the western flank of the Stord Basin in
licence PL870 to the east of the Utsira High and the Ringhorne East
field in the Northern North Sea. The primary target in the Lower
Jurassic Statfjord Group has a gross (100%) unrisked gas resources
potential of c. 70 mmboe, and with considerable upside. The well is
expected to be drilled in late 2018 or in 2019.
o Yoshi is located in licence PL 836 S immediately to the
south-west of the Smørbukk South Field and West of the former Faroe
Maria Field in the Norwegian Sea. The Jurassic Fangst Group
reservoirs, proven and effective in numerous nearby fields, are
expected to be present within a fault bounded structural closure on
the licence. Gross (100%) unrisked resources of c. 30 MMboe have
been estimated. The well is expected to be drilled in 2019.
-- Progress is being made in the seismic interpretation of
Brasse and the evaluation of the potential for adding further
resources to Brasse in northern and eastern directions. A possible
exploration and appraisal well to target this area is currently
being considered for drilling in late 2018 or 2019.
Financial - Faroe ended 2017 in a robust and differentiated
financial position with significant cash reserves, enhanced
production cashflow and an undrawn seven year RBL facility of $250
million
-- 2017 year-end unaudited cash was approximately GBP149 million
and net cash (net of the 2017 NOK Bond) was
GBP75 million
-- 2017 exploration and appraisal capex was approximately GBP48
million pre-tax (GBP11 million post-tax) and development and
production capex was approximately GBP96 million (unaudited)
-- 2018 exploration and appraisal capex is estimated to be
approximately GBP80 million pre-tax (GBP20 million post-tax) and
development and production capex approximately GBP175 million,
split as follows:
o Njord Area: GBP57 million
o Ula Area: GBP96 million
o Brage Area: GBP22 million
-- 2018 decommissioning costs is expected at approximately GBP13 million
-- Opex in 2018 is expected to be between $23-27 per boe
-- 2018 hedging programme in place to underpin value:
o approximately 70% of gas production hedged on a post-tax basis
at average price of 42.5p/therm, mainly with put options
o approximately 60% of post-tax oil production hedged at
$57/bbl, all with put options
- Ends -
Site Visit
On 20 February and 21 February 2018, Faroe will be hosting a
sell-side analyst visit to its offices in Stavanger. The site visit
will include presentations by Faroe management and operational team
on the producing field performance, the development projects and
the exploration drilling programme.
For further information please contact:
Faroe Petroleum plc Tel: +44 (0) 1224 650
Graham Stewart, CEO 920
Stifel Nicolaus Europe Tel: +44 (0) 20 7710
Limited 7600
Callum Stewart / Nicholas
Rhodes / Ashton Clanfield
BMO Capital Markets Tel: +44 (0) 207 236
Neil Haycock / Tom 1010
Rider / Jeremy Low
FTI Consulting Tel: +44 (0) 20 3727
Edward Westropp / Emerson 1000
Clarke
John Wood, UK Asset Manager of the Company with over 15 years'
experience of the oil and gas industry and who holds an M.Sc in
Petroleum Engineering from Imperial College, has read and approved
the production and development disclosure in this regulatory
announcement.
Andrew Roberts, Group Exploration Manager of Faroe Petroleum and
a Geophysicist (BSc. Joint Honours in Physics and Chemistry from
Manchester University), who has been involved in the energy
industry for more than 25 years, has read and approved the
exploration and appraisal disclosure in this regulatory
announcement.
The information contained within this announcement is considered
to be inside information prior to its release, as defined in
Article 7 of the Market Abuse Regulation No. 596/2014, and is
disclosed in accordance with the Company's obligations under
Article 17 of those Regulations.
Table 1
Production data
------------------------------------------------------------------------------------
Preliminary
2017
Net Economic
Production(1)
--------------- --------- ---------------- --------------------------------------
Field Working boepd Notes
Interest
--------------- --------- ---------------- --------------------------------------
Ula 20.0% 1,610
--------------- --------- ---------------- --------------------------------------
Tambar 45.0% 1,740
--------------- --------- ---------------- --------------------------------------
The field is expected to shut
down in April 2018. The pipeline
between Oselvar and Ula will be
cut to allow Oda to connect to
the Ula facility, for which the
Oselvar 55.0% 1,210 Oselvar owners are being compensated
--------------- --------- ---------------- --------------------------------------
Production guidance for 2018 assumes
that Trym will recommence production
in full at the beginning of April
Trym 50.0% 4,540 2018
--------------- --------- ---------------- --------------------------------------
Brage 14.3% 1,240
--------------- --------- ---------------- --------------------------------------
Ringhorne
Øst 7.8% 590
--------------- --------- ---------------- --------------------------------------
Total Norway 10,930
--------------- --------- ---------------- --------------------------------------
Schooner The fields are expected to permanently
& Ketch 60.% 2,220 cease production in Q3 2018
--------------- --------- ---------------- --------------------------------------
(1) Includes 210 boepd of production
attributable to the acquired 14%
of the Blane field interest, where
Faroe received the economic benefit
of production from 1 January 2017
but can only account for it from
the completion of the acquisition
Blane 44.5% 880 on 31 October 2017
--------------- --------- ---------------- --------------------------------------
Other UK 270
--------------- --------- ---------------- --------------------------------------
Group 14,300 (1) Accounting production, was
14,100 boepd
--------------- --------- ---------------- --------------------------------------
Table 2
Proven plus Probable (2P) Reserves at 1 January 2018
(1)
---------------------------------------------------------------------------
Field Working Interest Liquids Gas (bcf) Total (mmboe)
(mmstb)
--------------- ---------------- ---------- ----------- ---------------
Ula 20.0% 9.7 0.0 9.7
--------------- ---------------- ---------- ----------- ---------------
Oda 15.0% 6.8 2.5 7.2
--------------- ---------------- ---------- ----------- ---------------
Tambar 45.0% 9.8 15.7 12.4
--------------- ---------------- ---------- ----------- ---------------
Trym 50.0% 0.6 11.9 2.6
--------------- ---------------- ---------- ----------- ---------------
Brage 14.3% 2.5 3.3 3.1
--------------- ---------------- ---------- ----------- ---------------
Ringhorne
Øst 7.8% 2.3 0.0 2.3
--------------- ---------------- ---------- ----------- ---------------
Brasse 50.0% 25.0 34.1 30.7
--------------- ---------------- ---------- ----------- ---------------
Njord 7.5% 6.2 37.6 12.5
--------------- ---------------- ---------- ----------- ---------------
Hyme 7.5% 0.5 0.4 0.6
--------------- ---------------- ---------- ----------- ---------------
Bauge 7.5% 4.6 4.9 5.4
--------------- ---------------- ---------- ----------- ---------------
Fenja (2) 7.5% 5.6 8.3 7.0
--------------- ---------------- ---------- ----------- ---------------
Other 0.2 0.3 0.3
--------------- ---------------- ---------- ----------- ---------------
Total Norway 73.9 119.1 93.7
--------------- ---------------- ---------- ----------- ---------------
UK (incl.
Blane) 3.4 3.4 4.0
--------------- ---------------- ---------- ----------- ---------------
Group 77.3 122.5 97.7
--------------- ---------------- ---------- ----------- ---------------
(1) As adjusted for the disposal of a 17.5% participating
interest in Fenja
(2) The reduction in the participating interest of Fenja to 7.5%
remains subject to approval by Norwegian Authorities
Reserves Assessment
This table presents the 2P Reserves net to Faroe per field and
split into oil and liquids reserves and gas reserves. To assess the
reserves, the Company has used the definitions and guidelines set
out in the 2007 Petroleum Resources Management System prepared by
the Oil and Gas Reserves Committee of the Society of Petroleum
Engineers (SPE) and reviewed and jointly sponsored by the World
Petroleum Council (WPC), the American Association of Petroleum
Geologists (AAPG) and the Society of Petroleum Evaluation Engineers
(SPEE).
Glossary
"2C Resources" Best estimate of Contingent
Resources
"bcf" billions of standard cubic feet
"boe" barrel of oil equivalent
"boepd" barrels of oil equivalent per
day
"capex" capital expenditure
"Contingent Resources" Those quantities of petroleum
estimated, as of a given date,
to be potentially recoverable
from known accumulations by
application of development projects
but which are not currently
considered to be commercially
recoverable due to one or more
contingencies. Contingent Resources
are a class of discovered recoverable
resources
"E&A" exploration and appraisal
"FSO" Floating storage and offloading
vessel
"mmboe" millions of barrels of oil equivalent
"mmstb" millions of barrels of stock
tank oil
"net" the portion that are attributed
to the equity interests of Faroe
"Opex" operating expenditure
"Proved + Probable those additional Reserves which
Reserves" or "2P" analysis of geoscience and engineering
data indicate are less likely
to be recovered than Proved
Reserves but more certain to
be recovered than Possible Reserves.
It is equally likely that actual
remaining quantities recovered
will be greater than or less
than the sum of the estimated
Proved plus Probable Reserves
(2P). In this context, when
probabilistic methods are used,
there should be at least a 50%
probability that the actual
quantities recovered will equal
or exceed the 2P estimate
"PDO" The Plan for Development and
Operation
"reserves" reserves are those quantities
of petroleum anticipated to
be commercially recoverable
by application of development
projects to known accumulations
from a given date forward under
defined conditions. Reserves
must further satisfy four criteria:
they must be discovered, recoverable,
commercial, and remaining (as
of the evaluation date) based
on the development project(s)
applied. Reserves are further
categorized in accordance with
the level of certainty associated
with the estimates and may be
sub-classified based on project
maturity and/or characterized
by development and production
status
"WAG" water alternating gas
Notes to Editors
The Company has, through successive licence applications and
acquisitions, built a substantial and diversified portfolio of
exploration, appraisal, development and production assets in
Norway, the UK and Ireland.
Faroe Petroleum is an experienced licence operator having
operated several exploration wells successfully in Norway and the
UK and is also the production operator of the Schooner and Ketch
gas fields in the U.K. Southern Gas Basin and the Trym and Oselvar
fields in the Norwegian North Sea. Faroe also has extensive
experience working with major and independent oil companies both in
Norway and in the UK.
The Company's substantial licence portfolio provides a
considerable spread of risk and reward. Faroe has an active E&A
drilling programme and has interests in a portfolio of producing
oil and gas fields in the UK and Norway, including the Schooner and
Ketch gas fields and the Blane oil field in the UK, and interests
in the Brage, Ringhorne East, Ula, Tambar, Oselvar and Trym fields
in Norway. In December 2016 the Company completed the acquisition
of a package of Norwegian producing assets from DONG Energy
including interests in the Ula, Tambar, Oselvar and Trym fields.
Full year average production for 2018, is estimated to be between
12-15,000 boepd.
In November 2013 and March 2014 Faroe announced the Snilehorn
and Pil (Fenja) discoveries in the Norwegian Sea in close proximity
to the Njord and Hyme fields. In July 2016 the Company announced
the Brasse discovery, next to the Brage field, and the Njord North
Flank discovery, next to the Njord field, both in Norway. In
February 2018, the Company announced the sale of part of its
interest in the Fenja field.
Norway operates a tax efficient system which incentivises
exploration, through reimbursement of 78% of costs in the
subsequent year. Faroe has built an extensive portfolio of high
potential exploration licences in Norway which, together with its
established UK North Sea positions provides the majority of
prospects targeted by the Company's sustainable exploration
drilling programme.
Faroe Petroleum is quoted on the AIM Market of London Stock
Exchange. The Company is funded from cash reserves and cash flow,
and has access to a $250million reserve base lending facility, with
a further US$100million available on an uncommitted "accordion"
basis. Faroe has a highly experienced technical team who are
leaders in the areas of seismic and geological interpretation,
reservoir engineering and field development, focused on creating
exceptional value for its shareholders.
This information is provided by RNS
The company news service from the London Stock Exchange
END
DRLLLLLFVLFFBBE
(END) Dow Jones Newswires
February 13, 2018 02:00 ET (07:00 GMT)
Faroe Petroleum (LSE:FPM)
Historical Stock Chart
From Apr 2024 to May 2024
Faroe Petroleum (LSE:FPM)
Historical Stock Chart
From May 2023 to May 2024