TIDMJOG
RNS Number : 9417Q
Jersey Oil and Gas PLC
03 March 2021
3 March 2021
Jersey Oil and Gas plc
("Jersey Oil & Gas", "JOG" or the "Company")
Greater Buchan Area Development Project
Concept Select Update
"Potential for 172 MMboe 2C contingent resource estimates to be
developed from a fully electrified platform"
Jersey Oil & Gas (AIM: JOG), an independent upstream oil and
gas company focused on the UK Continental Shelf ("UKCS") region of
the North Sea, is pleased to announce the key findings of its
detailed and comprehensive Concept Select Report ("CSR") in respect
of its Greater Buchan Area ("GBA") Development Project which
contains an aggregate 172 million barrels of oil equivalent
("MMboe") 2C contingent resource estimates of light sweet crude and
associated gas. The planned development is centred on resuming
production at the Buchan oil field and producing the J2 and Verbier
oil discoveries as well as other existing and yet to find
discoveries within the GBA as future upside.
Highlights
- A three-phase development centered around a single integrated
wellhead, production, utilities and quarters platform located at
the Buchan field - the GBA hub
- The development concept is based on P50 Technically
Recoverable Resource estimates of, in aggregate, 172 MMboe of light
sweet crude and associated gas within the Core GBA, which includes
the Buchan oil field and J2 and Verbier oil discoveries
- JOG aims to deliver production from the planned GBA
Development Project at an industry leading carbon intensity level
due to Platform Electrification, as seen in certain fields in the
Norwegian sector
o Overall carbon emissions from the GBA with platform
electrification estimated by management at <1kg/boe
- Project economic estimates by management for the Core GBA
selecting Platform Electrification as our preferred low carbon
power solution, are:
o Pre-tax free cashflow of US$6.4 billion with an NPV (pre-tax)
of US$1.7 billion
o Payback period under 3 years
o Project internal rate of return ("IRR") greater than 25%
- Development costs (Capex and Opex) based on today's values are
estimated to be approximately US$30/boe
o Capex estimate for Phase 1 of approximately GBP1 billion
(including 20% contingency)
o Opex estimate during plateau production of US$8/boe to
US$9/boe
- The GBA hub nameplate capacity has been set at 40,000 barrels
of oil per day ("bopd") with expected plateau production of more
than 3 years
- Significant upside potential from 4 drill ready exploration
prospects within the GBA that have combined prospective resource
estimates totaling an additional 219 MMboe
o The close proximity of the GBA exploration prospects, will
enable their development, on discovery, as low cost subsea
tie-backs to the planned GBA hub
o A discovery in line with P50 estimates at any of the drill
ready exploration prospects has the potential to extend plateau
production significantly and materially increase project
economics
- With the preferred development concept identified, JOG is now
ready to launch its planned and previously announced farm-out
process for the GBA
A concept select update presentation is also available to
download on the Company's website at:
www.jerseyoilandgas.com/investors/presentations/
Andrew Benitz, CEO of Jersey Oil & Gas, commented :
"The GBA has the scale to be extremely low carbon through
platform electrification at the same time as offering highly
favourable project economics. As a result of a significant amount
of work from Jersey Oil & Gas' excellent project team, working
with specialist contractors, consultants and service providers, we
are well on track to deliver on our Licence commitment to deliver
the Concept Select to the Oil and Gas Authority ("OGA") by July
this year.
"We now plan to launch a farm-out process , which we expect to
be highly attractive to a wide range of oil companies in light of
the project's scale, economics and low carbon potential through
platform electrification, characteristic of certain fully
electrified fields offshore Norway."
Summary of Concept Select Findings
Delivering Concept Select has been a comprehensive work effort
led by our project team requiring over 14,000 JOG hours and 18,000
contractor hours. In early 2020, JOG completed an Appraise phase
assessment of the various development options for the GBA. This
option screening phase concluded that development of the GBA's
resources via a fixed production platform located at the Buchan
field, offered the optimum solution when considering environmental
factors, safety issues, technical feasibility, execution risk,
schedule, capital and operating costs, project economics,
availability and operability.
Subsequently, the Company has progressed this development option
through the Concept Select phase, with work commencing in April
2020. The objective of this Select Phase was to deliver a single,
economically acceptable concept to develop the GBA in order to take
the project forward into the Define Phase.
The selected concept for the GBA Development is planned to be
executed in three Phases. Phase 1 will deliver a single integrated
wellhead, production, utilities and quarters (WPUQ) Platform
located at the Buchan field. Production from the reservoirs will be
supported by injection of both produced water and seawater. The
facility will be normally manned. The Buchan wells will be drilled
utilising a heavy-duty jack-up (HDJU) located over a 12 slot well
bay. The Phase 1 facilities will be designed to accommodate Phase 2
and Phase 3 of the development. Phase 2 will develop the J2 West,
J2 East and Verbier East discoveries via a subsea tie-back to the
GBA platform. Phase 3 will develop the Verbier West discovery via
connection to the Phase 2 subsea infrastructure. Field life is
anticipated to be 31 years.
The Buchan location benefits from close proximity to existing
export infrastructure for both oil and gas. Selection of the final
oil and gas export routes will be subject to a detailed economic
and risk assessment through formal requests for service issued in
February 2021. Initial negotiations with pipeline operators will be
conducted in accordance with Oil & Gas UK's Infrastructure Code
of Practice. It is scheduled that this work will be completed to
inform FEED (Front End Engineering and Design), currently planned
to take place later this year.
Work has also been conducted to identify the optimum type of
artificial lift for the production wells. Gas lift and electrical
submersible pumps (ESPs) were investigated. The use of ESPs was
shown to deliver a higher production rate and thus greater
recoverable volumes over the same period than gas lifted wells.
Project Economic and Cost estimates
Cost estimates for each phase have been prepared in accordance
with the detailed work break down structures for Phase 1, 2 and 3.
The CAPEX, OPEX and DRILLEX estimates were developed in line with
the American Association of Cost Engineers International (AACEI)
Class 4, with an expected accuracy of +/- 30%. CAPEX costs for
Phase 1 are estimated to be approximately GBP1 billion. Operating
costs during plateau production are estimated at US$8/boe to
US$9/boe, with a payback period estimated at under 3 years. Plateau
production is estimated for more than 3 years. Total project costs
based on current day values are estimated to be approximately
US$30/boe.
Summary economic estimates by management for the Core GBA
Project selecting platform electrification as the Company's
preferred low carbon power solution:
Commodity Pricing Brent Phase 1 Core GBA
Inflation (2%) Nominal Nominal
-------- -----------------------------
Economic Resources Mmboe 122 162
Life of Field Years 31 31
CO(2) / Production kg/boe <1kg <1kg
Pre-Tax cumulative cash
flow $bn 4.7 6.4
Post-Tax cumulative cash
flow $bn 3.1 4.2
NPV (Pre-Tax) $bn 1.3 1.7
NPV (Post-Tax) $bn 0.9 1.1
IRR % >25% >25%
Payback from first oil (years) 1.9 2.8
Phase 1 Core GBA
Real Real
-------- ---------
CAPEX $bn 1.4 2.1
OPEX $bn 2.6 2.7
CAPEX / boe $/boe 11.1 13.1
OPEX / boe $/boe 21.0 16.9
ABEX / boe $/boe 1.6 2.6
The following economic assumptions have been used in the
Company's economic model:
-- An oil price of US$65/bbl in 2021, escalated by 2% per annum from 2022
-- Economic date of 1(st) January 2021
-- All costs are referenced to 2021 and inflated by 2% per annum from 1(st) January 2022
-- All cost inputs are in GBP and are converted to US$ using a
constant foreign exchange rate of 1.3
-- Discount rate of 10%
Electrification
In line with the UK Government's Net Zero policies, JOG
recognises the need for a low carbon power solution and has an
aspiration to deliver production from the GBA Development Project
at an industry-leading carbon intensity level. Accordingly, options
have been assessed that offer the opportunity to eliminate carbon
dioxide emissions associated with power generation on the planned
production facility. Economics have been run based on the provision
of power from the UK national grid via the installation of a subsea
cable to shore.
The provision of power from shore offers the opportunity to
remove rotating equipment from the offshore facilities along with
supporting utilities, e.g. fuel gas treatment equipment. A fully
electrified facility also allows for the removal of traditional
utility systems such as instrument air. This provides both a CAPEX
reduction for the topside facilities and an associated OPEX
reduction due to the lower maintenance burden. Removing the
requirement to utilise associated gas as fuel also increases gas
export revenues. Such CAPEX and OPEX reductions are however offset
by the cost of the grid connection and subsea cable and the
in-service purchase price of electricity.
A "Net Zero" solution for the GBA Development Project is
economically attractive, despite a 'Green Premium' compared to the
conventional case utilising gas turbines. The costs associated with
the provision of a subsea cable and grid connection outweigh the
cost reductions associated with the removal of gas turbines and
associated utility systems, resulting in a CAPEX increase of
approximately GBP80 million.
Overall carbon emissions from the GBA with platform
electrification are estimated to be <1kg/boe. This compares to
estimated carbon emissions from the GBA development using gas
turbines of 13kg/boe, which is less than the UKCS average of
approximately 20kg/boe.
The forecast economic outturn for the power from shore case
relative to the conventional gas turbine case is based on current
UK Government carbon tax forecasts up to 2030 and the cost of
sourcing power from the UK. Based on these assumptions, the "Green
Premium" results in a project NPV reduction of approximately
8%.
The GBA is optimally located in the heart of the UK Central
North Sea such that there is exciting potential for JOG to be an
enabler for regional electrification. Collaboration with other
regional operators could reduce overall capital costs associated
with the cable infrastructure. Additionally early stage engagement
with infrastructure funds has indicated that there is potential
interest in financing the capital costs in return for future tariff
payments. The Company continues to progress studies that may lead
to electrification costs reducing in line with conventional power
solutions.
A decision to adopt a power from shore case takes into account
environmental, social and corporate governance (ESG) and Licence to
Operate considerations and details of our Corporate Carbon Policy
will be announced shortly.
Regional Hub Potential
Collaborative studies conducted in parallel with the GBA Concept
Select Phase, have identified the potential for significant
synergies with neighbouring, third party discovered resources. The
production of such resources through the GBA facility offers the
potential for both parties to realise reductions in development
costs and OPEX costs offering the potential to increase incremental
recovery of oil from the GBA and neighbouring discoveries.
JOG continues to seek further collaboration with neighbouring,
third party discovered resources, with the aim of providing JOG and
owners of neighbouring fields with details of the costs and
associated economic outturns for various development scenarios.
Future Exploration Upside
As detailed in JOG's announcement of 14(th) December 2020, the
GBA includes four drill ready exploration prospects, namely Wengen,
Cortina, Verbier Deep and Zermatt, which have combined P50
prospective resource estimates of an additional 219 MMboe. An
assessment has been performed to determine the optimum drilling
sequence of these various exploration prospects, resulting in the
following sequence (subject to funding).
-- Wengen - Q2 2023
-- Cortina NE - Q2 2023
Analysis shows that in a P50 resource success case, each
exploration prospect offers a highly economic tie-back opportunity
to the GBA development. A successful outcome at either of the
Wengen or Cortina prospects has been shown to offer the potential
to extend the GBA Development Project's plateau production period
into the mid- to late- 2030s with enhanced economics.
Next Steps
A separate Concept Select Report summarising the Company's
findings, as outlined herein, will be submitted for approval to the
OGA by 31(st) July 2021 in compliance with JOG's commitment under
the P2498 licence, which contains Buchan. Work continues apace with
respect to the issuance of tenders for marine surveys to support
the Environmental Statement required for the Field Development
Plan. Tendering processes for the provision of FEED engineering
services is also underway. JOG is currently working towards being
ready to enter the FEED phase of the GBA project in Q3 2021, with
FID (Final Investment Decision) currently anticipated for H2
2022.
With its Concept Select Report finalised, JOG is now in a
position to launch its previously announced farm-out process to
seek to secure an industry partner for the GBA Development Project.
JOG's Board anticipates that this will be well received by the
industry as an exciting investment opportunity, in light of its
scale, economics and low carbon production approach, and currently
intends to conclude this process before the end of 2021.
Enquiries :
Jersey Oil and Gas plc Andrew Benitz, CEO C/o Camarco:
Tel: 020 3757 4983
Strand Hanson Limited James Harris Tel: 020 7409 3494
Matthew Chandler
James Bellman
Arden Partners plc Paul Shackleton Tel: 020 7614 5900
Benjamin Cryer
Camarco Billy Clegg Tel: 020 3757 4983
James Crothers
Qualified Person's Statement
The information contained in this announcement has been reviewed
and approved by Ronald Lansdell, Chief Operating Officer of Jersey
Oil & Gas, a qualified Geologist and Fellow of the Geological
Society, who has over 40 years' relevant experience within the
sector.
Notes to Editors :
Jersey Oil & Gas is a UK E&P company focused on building
an upstream oil and gas business in the North Sea. The Company
holds a significant acreage position within the Central North Sea
referred to as the Greater Buchan Area ("GBA"), which includes
operatorship and 100% working interests in blocks that contain the
Buchan oil field and J2 and Glenn oil discoveries and an 100%
working interest in the P2170 Licence Blocks 20/5b & 21/1d
(subject to OGA approval of the acquisition of CIECO V&C UK
Limited as announced on 26 November 2020), that contain the Verbier
oil discovery and other exploration prospects
JOG's total GBA acreage is estimated by management to contain
190 million barrels of oil equivalent ("mmboe") of discovered P50
recoverable resources net to JOG, in addition to significant
exploration upside potential of approximately 220 mmboe of
prospective resources in close proximity to our planned Buchan
platform. JOG has recently concluded the Concept Select Phase of an
FDP for the Greater Buchan Area and plans to progress into Front
End Engineering and Design (FEED) later this year.
JOG is focused on delivering shareholder value and growth
through creative deal-making, operational success and licensing
rounds. Its management is convinced that opportunity exists within
the UK North Sea to deliver on this strategy and the Company has a
solid track-record of tangible success.
The information contained within this announcement is deemed by
the Company to constitute inside information as stipulated under
the Market Abuse Regulation (EU) No. 596/2014 as it forms part of
United Kingdom domestic law by virtue of the European (Withdrawal)
Act 2018.
This announcement includes "forward-looking statements" which
include all statements other than statements of historical facts,
including, without limitation, those regarding the Group's
financial position, business strategy, plans and objectives of
management for future operations, or any statements preceded by,
followed by or that include the words "targets", "believes",
"expects", "aims", "intends", "will", "may", "anticipates",
"would", "could" or similar expressions or negatives thereof. Such
forward-looking statements involve known and unknown risks,
uncertainties and other important factors beyond the Company's
control that could cause the actual results, performance or
achievements of the Group to be materially different from future
results, performance or achievements expressed or implied by such
forward-looking statements. Such forward-looking statements are
based on numerous assumptions regarding the Group's present and
future business strategies and the environment in which the Group
will operate in the future. These forward-looking statements speak
only as at the date of this announcement. The Company expressly
disclaims any obligation or undertaking to disseminate any updates
or revisions to any forward-looking statements contained herein to
reflect any change in the Company's expectations with regard
thereto or any change in events, conditions or circumstances on
which any such statements are based unless required to do so by
applicable law or the AIM Rules.
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