Production Focus,
Sustainable Returns
2019 Annual Report
3
C
o
n
t
e
n
t
s
2019 Review
Foreword from Dennis McShane – Non-Executive Chairman
Chief Executive Officer’s Review
4 – 5
6 – 9
10 – 11
Highlights
2019 Financial Overview
Financial Overview
COVID-19
Impact of COVID-19
Review of Operations
Portfolio and Assets Overview
Sustainability Report
Sustainability Report
Corporate Governance
Board Profiles
Management Profiles
Corporate Governance Report
Consolidated Financial Statements
Management’s Report
12 – 13
14 – 15
16 – 21
22 – 43
46 – 47
48 – 49
50 – 57
60
61 – 64
Independent Auditor’s Report
65
66
67
68
Consolidated Statement of Profit or Loss and Other Comprehensive Income
Consolidated Statement of Financial Position
Consolidated Statement of Changes in Equity
Consolidated Statement of Cash Flows
69 – 115
Notes to the Consolidated Financial Statements
Management’s Discussion and Analysis
116 – 147 Management’s Discussion and Analysis
Reserves Summary
148 – 149 Reserves Summary
Other Information
Glossary
150
Jadestone is a leading independent
upstream oil and gas company focused
on the Asia Pacific region. Its strategy
is to acquire production and near-term
development assets, create value
through smart reinvestment and
generate increasing cash flow from
an expanding portfolio of balanced,
low risk assets across the region.
Cover Photo:
Mark Pearce, a mechanical technician on the Montara Venture FPSO
Jadestone Energy 2019 Annual Report
4
Foreword from Dennis McShane
Non-Executive Chairman
5
Dennis McShane
Non-Executive Chairman
Dear Fellow Shareholder,
On behalf of the Board of Directors of your Company, I am pleased to present the 2019
Jadestone Energy Annual Report. Your Company had an exceptional year in 2019 with major
project completions, improved operational efficiencies, expanded asset opportunities, and
the strongest financial results in our history. Management focused on the full integration and
operating improvements at Montara since acquiring the assets in late 2018, infill drilling at Stag,
and driving forward the Nam Du/U Minh gas development in Vietnam. All this was achieved
with a focus on continued adherence to our disciplined HSE culture.
Later in the year the Company also announced the acquisition from OMV
of an operated 69% interest in the Maari Project, offshore New Zealand.
The acquisition is an excellent fit with our growth-oriented strategy,
which includes bolting on mid-life producing assets where management
can continue to deploy the existing capabilities within the team.
I wish to congratulate our senior executives, Paul, Dan and Michael along
with their entire team on this tremendous success. Through their efforts
your Company entered 2020 with the financial strength and operational
expertise to further our successful growth strategy.
ESG Progress
I am also pleased to report an outstanding year from an HSE perspective,
with zero lost time incidents and zero serious injuries. HSE performance
is at the core of what we do, and helps to drive operational performance,
which is at the root of value for shareholders. We have strengthened our
Board to reinforce the principle that health, safety and environmental
performance, as well as risk management, are intrinsic to our business
and we have expanded our governance to more closely monitor the
Company’s progress in these areas.
We are also working to minimise waste from our business, reducing
emissions and discharges, by ensuring operations are as efficient as
possible. We are increasingly measuring our impact on the environment,
setting targets for continual improvement, and have published this year,
for the first time in Jadestone’s short history, our Sustainability Report.
Our intention is to be transparent about what we do and how we do
it. We work tirelessly to improve our performance in everything we do,
so that we build a reputation within the investment community and
amongst all stakeholders of open communication, honesty and integrity.
We have set measurable targets such as continuous improvement
in recordable safety incidents, reduced gas flaring and diesel usage,
recruiting and training local nationals and of course maintaining the
highest standards of governance. These are but a few of the areas that
form a major part of management’s 2020 KPI’s. Our aim is to earn your
trust and keep it over the long term.
Dividend
As previously committed to the market, we announced guidance for our
maiden dividend, to be paid later in 2020/2021, and targeted in the range
of $7.5 to $12.5 million. We have structured the Jadestone business to
be one that is strongly cash generative, and fundamentally predisposed
to generating distributable returns for shareholders. Going forward, we
expect to issue further dividends to shareholders at a rate which is yet
to be confirmed but will be commensurate with the Company’s growth
performance and financial strength.
Board
I would like to take this opportunity to thank all my colleagues at
Jadestone for their dedication and hard work during the year.
I’d particularly like to thank Eric Schwitzer who stepped down as a non-
executive director in December, for his many years of dedicated service
to, and support of, the transformation of Jadestone Energy. I welcome
Lisa Stewart as a new non-executive director. Lisa has over 30 years
of experience in the upstream oil and gas industry, in engineering and
management positions, and I am confident that we will come to rely
on both her technical skills and her extensive international experience.
Outlook
The world has changed dramatically since the end of 2019. As I write
this letter to you, we are in the midst of the global COVID-19 pandemic,
an economic shutdown not witnessed in this generation and, a collapse
in oil prices. As a result, your Company has made the prudent shift
in strategy to preserve our financial strength. A number of capital
programmes have been deferred, non-essential investments have
been postponed and, compensation increases have been cut in order
to conserve cash in the business. We are proud to report that our people
are rising to the daily challenges of this crisis with the same resolve and
ingenuity as they did in building this Company.
Looking toward the rest of 2020, Jadestone remains as nimble as ever
and highly selective in deploying resources. Our focus continues to be on
driving the business forward with rigorous attention to cash flow and
value generation through organic activity and accretive investments.
Thank you for your continued support.
Dennis McShane
Non-Executive Chairman
Stag platform with the Ensco 107 drilling rig
Jadestone Energy 2019 Annual Report 6
Chief Executive Officer’s Review
7
We are underpinning the growth of our business
with ongoing value accretive investments into
our producing assets, completing our acquisition
of an operated interest in the Maari assets,
offshore New Zealand, and preserving balance
sheet strength to be opportunistic for further
inorganic growth when the right options emerge.
Paul Blakeley
Executive Director, President and Chief Executive Officer
Reflecting on 2019, we have added value to every one of our assets through strong and
improving operational performance. We have executed our investment plans broadly as laid
out at the beginning of the year, and have kept our guidance promises with regard to delivering
production growth, improved efficiency and shareholder returns.
We achieved significant success across all fronts of our business in
2019. We improved operational output and effectiveness, completed
major capital projects, expanded our reserves base and enhanced our
financial strength, including paying down the reserve based loan which
supported the Montara acquisiton. We find ourselves well positioned to
weather the effect of the current economic environment, with a strong
net cash position, low operating costs break even down to $20/bbl,
significant optionality with discretionary capital, an ongoing hedging
programme and high quality crudes which have attracted significant
premiums to Brent.
Asset Review
In the last 12 months Montara has been turned around. With Jadestone
operating leaders seconded to the asset early in the transition process,
we were able to move quickly to deliver a number of major investments
at Montara, including restoring gas-lift to the subsea wells and
accessing additional reservoir sands through an innovative riserless
light well intervention programme. We also completed the subsea
umbilical replacement, which will ensure the reliability of subsea
operations throughout the remaining life of the asset.
At Stag, after seasonal weather delays, we drilled the first infill well
on the asset in over six years. The project was completed on time and
budget, and contributed to both production and reserves, with initial
rates at around 1,400 bopd, as prognosed. This reinforces our view of
the reservoir model and, two years into operating Stag, its performance
confirms our view of the asset being a long term, stable cash generator
for the Company. Oil price realisations continued to be strong during the
year and, with global demand for cleaner burning fuels driving increased
differentials for low sulphur crudes, Stag crude oil premiums rose from
$4 to over $10/bbl by year end, continuing even higher in early 2020.
We made significant progress on the Nam Du and U Minh gas
development in Vietnam in 2019. We signed a Heads of Agreement
relating to gas sales from the fields, completed the front-end
engineering and design work, finished all pre-development
environmental studies and site surveys, and submitted our Field
Development Plan on schedule, in November. Events have since taken
over and, with the Government delaying project approval by over three
months, and the subsequent collapse in oil price, we have elected to
push the project back by 12 months and reassess market conditions in
due course.
We continue to see Nam Du and U Minh as a key part of our mid to
longer-term growth profile and are now working with the Vietnam
Government to optimise the future timing of this very important
project. The development of these fields still provides a critical source
of domestic gas supply for Vietnam, and is of vital importance to the
continued growth of the Southwest region of the country, in what is one
of the powerhouse economies of the Asia Pacific region.
Adding the New Zealand Maari asset to our portfolio, as announced in
November 2019, establishes a new operating area for us, and creates a
platform to further deploy our mid-life field expertise. This acquisition
is further evidence of running room for our M&A strategy in the region.
I firmly believe we will see more opportunities in the prolific Taranaki
basin, and the asset itself carries all the key criteria for Jadestone to add
reserves, extend field life and create significant value for shareholders.
Results Review
In 2019 the business generated $325 million in net revenue, almost
three times higher than the previous year. We lifted 4.5 mm bbls of
crude oil, and made $177 million cash from operations before working
capital changes, with adjusted EBITDAX of $188 million (or $73 million
in unadjusted net profit before tax). This was a transformational
year for Jadestone and I am proud of the efforts of the whole team
for their hard work and effort in achieving these results, which were
also delivered with an exemplary health, safety and environmental
performance. There were no accidents, incidents or spills of any
significance, nor any regulatory non-conformance, as we continue
to strive to deliver a “target zero” outcome for the business.
96% of production was replaced, adding 4.8 mm bbls of 1P reserves
or 4.0 mm bbls on a 2P basis, with positive adjustments at both Stag
and Montara. This does not include the 13.9 mm bbls of 2P reserves
associated with the Maari acquisition and which will be added when
we complete the deal later in 2020. These are all outcomes we can
be proud of.
Company Strategy
In a short period of time, we have built Jadestone into a business
delivering a solid free cash flow stream which we are redeploying into
accretive investment in the business and in inorganic activity, while
providing direct returns to shareholders in the form of dividends,
beginning this year. Our acquisition screening criteria is stringent, but I
am confident that we will continue to find more opportunities which fit
our strategy to re-invest and generate incremental value well beyond
the seller’s view, as with all the acquisitions done to date.
Jadestone Energy 2019 Annual Report 8
Chief Executive Officer’s Review
9
Our strategy is working, and our performance in 2019 is confirmation
that we have set the right course in Asia Pacific, are doing the right
things, and with our operating capabilities are generating significant
value for shareholders through production, acquisition and near-term
developments. At the same time, we remain steadfast in our focus on
health, safety, and environmental responsibility, and are pleased to
have delivered a solid year of performance with no significant incidents
to report. As part of our first annual report, I am pleased to present our
Sustainability Report, outlining our principles of Environmental, Social,
and Governance practices, which we see as central to the health and
durability of our business.
Response to COVID-19
The COVID-19 pandemic, the related steep oil price decline, and the
various government and community responses to address the virus,
have created significant challenges for the upstream oil & gas industry,
and is impacting almost every part of the global economy.
As we exit the first quarter of 2020, the significant current headwinds
for our industry are creating uncertainty for the remainder of the year,
and possibly well beyond. To ensure Jadestone is able to continue to
operate with minimal disruption during these extraordinary times, and
also to maintain its highly resilient financial and operational position as
and when conditions normalise, a wide range of steps have been taken
to date, as summarised on pages 14-15.
Outlook
Notwithstanding these extraordinary challenges, we are fortunate to
have a very strong balance sheet, a resilient business model, and a
portfolio with significant flexibility which we are and, will continue to
fully exercise. Maari remains an accretive acquisition with operating
costs below $20/bbl and we continue to push towards closure, while
slowing down other discretionary capital where value can be either
retained or enhanced in doing so. By protecting the balance sheet,
we not only protect the integrity of the business and shareholders’
capital, but we also create additional financial flexibility to pursue
opportunities for further accretive, inorganic growth, that this current
oil price environment will undoubtedly present.
Finally, I would like to thank the outstanding group of people who work
for the Company, to the Board for their support, to all stakeholders who
work with us and, not least to our shareholders for their confidence in
what we are doing at Jadestone.
A. Paul Blakeley, OBE
Executive Director, President and Chief Executive Officer
Raroa FPSO and Maari platform
Jadestone Energy 2019 Annual Report 10
Highlights
11
Corporate and Financial Highlights
Operational Highlights
Sales
4.5 mm bbls
[ 1.7 mm bbls in 2018 ]
Revenue
$325 million
[ $113 million in 2018 ]
Operating costs
$22.85 /bbl
[ $28.72/bbl in 2018 ]
Operating cash flow*
$177 million
[ ($0.3) million in 2018 ]
2019
2019
2019
2019
2018
2018
2018
2018
0 mm bbls
1
2
3
4
5
$0
million
100
200
300
400
$0
/bbl
10
20
30
40
$0
million
50
100
150
200
* Before movements in working capital
Workers on the Riserless Light Well Intervention vessel
OH&S
Occupational
Health & Safety
0 Zero total
recordable injury
frequency rate
Environmental
management
0 Reportable
environmental
incidents
Production
13.531 mbbls/d
[ 4.057 mboe/d in 2018 ]
Uptime*
80%
[ 68% in 2018 ]
2019
2018
0
mboe/d
5
10
15
0
%
25
50
2019
2018
75
100
* Combined Montara and Stag uptime, excluding planned downtime
In 2019, the Company had crude oil sales of 4.496 mm
bbls from 10 liftings through the year. Sales were a
three-fold increase over the 1.683 mm bbls sold in 2018.
The increase primarily reflects a full year of production
from the Montara asset, offshore Australia. Net sales
revenue was $325 million, which was also a three-fold
increase over the $113 million revenue in 2018.
Safe operations are paramount to the longevity of
Jadestone’s business, and during 2019 the Company
had no serious HSE incidents to report. Protecting the
well-being of the entire Jadestone team and ensuring
world class environmental stewardship will always
be our highest priority.
Jadestone generated cash flow from operations of $177 million in 2019,
versus a net use of cash of $0.3 million in the prior year.
Underlying the Company’s financial performance was an improvement
in efficiency in all of its operations, demonstrated by full year operating
costs falling to $22.85/bbl (excluding non-recurring items). This is a
new record for the Company, and a result of deploying the Company’s
operating philosophy for mid-life assets and driving cost efficiency deep
into ongoing operations.
At the same time, the Company made substantial investments into its
assets, including infill drilling, well interventions, and remedial works
designed to ensure the longevity of its operations and to correct all
outstanding deficiencies.
Even after investing $77 million through major spending during the year
(including capex and major project opex), the Company’s cash position
increased while debt continues to be paid down. As at the end of 2019,
the Company was in a net cash position of $40 million, compared to net
debt of $30 million at year-end 2018 (both figures excluding restricted
cash of $10 million relating to a bank guarantee).
Jadestone continues to focus on near-term cash flow generating assets
as a way to grow investor returns.
During the fourth quarter of 2019, the Company announced the
acquisition of an operated 69% interest in the Maari asset, offshore
New Zealand for a cash consideration of $50 million. The asset is a
natural strategic fit for Jadestone, adding 13.9 mm bbls of 2P reserves,
and production of 4,000 - 4,500 bbls/d, on a net basis, with an effective
date of January 1, 2019. The acquisition is expected to close in the second
half of 2020.
Enscco 107 drilling rig and Stag platform
Jadestone achieved its production target for 2019, producing an average
of 13,531 bbls/d, versus 4,057 boe/d in the prior year. This increase
reflects the addition of a year of production from the Montara asset,
which averaged 10,483 bbls/d in 2019, in addition to ongoing production
from Stag, which averaged 3,049 bbls/d.
At Montara, the Company began the year by correcting all outstanding
regulatory deficiencies inherited when the asset was acquired, and
thereafter began its first wave of major investments into the asset.
This included an innovative riserless light well intervention programme -
a highly engineered scope of work to restore gas lift to subsea wells and
access additional reservoir sands, and the installation of a new subsea
umbilical - a once-in-a-decade task to ensure the ongoing reliability
of subsea wells.
At Stag, the Company drilled the first infill well in six years, which
encountered its target, came on production, and contributed new
reserves all in line with pre-drill expectations. The Company’s workover
programme resulted in all Stag wells returning to production, while
operating costs continued to fall (part of a trend under Jadestone’s
operatorship).
In Vietnam, the Company made progress toward commercialising its
Nam Du and U Minh gas fields, including signing a Heads of Agreement
relating to gas sales from the development and submitting a Field
Development Plan to Petrovietnam for consideration. In early 2020,
the Company opted to delay the project as part of a review of its capital
programme aimed at maintaining the Company’s strong balance sheet.
Jadestone Energy 2019 Annual Report 12
Financial Overview
13
Full year revenue for 2019 was $325 million
compared to $113 million for year 2018.
This was in large part due to total oil lifted in 2019
being 4.5 mm boe, compared to 1.7 mm boe in
2018. Price realisations remained relatively flat at
$69.07/bbl in 2019 compared to $69.39/boe in 2018.
During the year benchmark prices declined from
$71.31/ bbl in 2018 to $64.27/bbl in 2019 but this
decline was largely offset by increasing premiums
at Stag and Montara.
The Company’s hedging programme provides very strong downside
oil price protection. Approximately half of Montara's production is
hedged through to September 30, 2020 at an average Brent swap
price of $68.45/bbl, or $74.55/bbl inclusive of the $6.10/bbl premium
most recently achieved.
Full year production costs for 2019 were $119.9 million, versus $90.9
million for 2018. Adjusting to remove non-recurring items, this equates
to unit operating costs of $22.85/bbl versus $28.72/boe for 2018.
The Company delivered adjusted positive EBITDAX of $187.5 million,
compared to $10.2 million for 2018, as the 2019-year benefits from a full
year of Montara production compared to approximately one month of
production in 2018 under Jadestone’s ownership, prior to the voluntary
shutdown in November and December 2018 to address a legacy
inspection and maintenance backlog.
The Company generated positive operating cash flow before movements
in working capital of $176.7 million, compared to $0.3 million used in
operations in 2018, again reflecting a full year of Montara production
compared to one month in 2018.
For the full year, the Company invested $77.2 million, inclusive of large
abnormal operating expense, including work associated with a portion
the riserless light well intervention programme, and compared to $10.0
million invested in 2018.
At year end, the Company had $75.9 million cash, plus $13.5 million of
debt service reserve cash and a further $10.0 million of cash in support
of a bank guarantee. A further $12.8 million of the reserve based loan
principal was repaid on March 29, 2020, resulting in gross outstanding
debt at March 31, 2020 of $37.3 million.
Financial and Operating Highlights
USD’000, unless otherwise indicated
2019
2018
2019
2018
THREE MONTHS ENDED
DECEMBER 31
TWELVE MONTHS ENDED
DECEMBER 31
Financial
Revenue
Production costs
Gross profit
Profit/(loss) before tax
Profit/(loss) after tax
Profit/(loss) after tax per ordinary share
Operating cash flow before changes in WC
Cash generated from operations
Cash
Restricted cash
Gross debt
Net cash/(debt)
Major spend/capital expenditure
Total assets
Book equity
Operational
Production (boe/d)
Sales (mboe)
Avg realised liquids price ($/bbl)
Operating costs ($/bbl)
91,200
(25,876)
65,324
27,062
10,364
0.02
57,978
50,303
75,934
23,485
49,123
40,296
26,340
755,081
225,467
14,702
1,266
69.24
20.26
44,972
(50,602)
(5,630)
(4,935)
(6,573)
(0.01)
(7,568)
40,078
52,981
28,644
101,813
32,469
7,624
730,367
215,261
5,215
657
67.51
28.94
325,406
(119,898)
205,508
73,281
40,505
0.09
176,744
147,484
75,934
23,485
49,123
40,296
77,240
755,081
225,467
13,531
4,496
69.07
22.85
113,423
(90,939)
22,484
(21,466)
(31,033)
(0.10)
(268)
26,422
52,981
28,644
101,813
(30,188)
10,000
730,367
215,261
4,057
1,683
69.39
28.72
Montara Venture FPSO and support vessels
Jadestone Energy 2019 Annual Report 14
Impact of COVID-19
15
On January 30, 2020, the COVID-19 outbreak was
declared a public health emergency of international
concern, and on March 10, 2020, the WHO declared
COVID-19 a pandemic.
Jadestone recognises the gravity of this situation,
and acknowledges that the actions taken to
mitigate COVID-19 globally have had, and are
expected to continue to have, an adverse impact
on the economies and financial markets of many
countries, including the geographical area in which
the Company operates.
For its part, Jadestone has undertaken a
methodical assessment of both operational and
financial risks for its ongoing business, and has
set in place measures to maximise the Company's
ongoing success.
Operational
The Company recognises that its offshore production locations
require an ongoing supply of key materials and services, and with
the widespread impact of business disruptions due to COVID-19,
some aspects of the Company’s supply chain may be compromised.
In response, the Company is maintaining a conservative six-month
work plan for its assets, and as usual, is carrying sufficient inventory
of critical spares to mitigate the risk of not having the right materials
available to maintain ongoing operations. In addition, the Company is
working closely with suppliers of critical offshore services to prepare
contingency plans and ensure suitably skilled personnel can be
mobilised as and when required. This collaboration also extends to
local industry organisations to establish best practices, and control
mechanisms to ensure smooth logistics operations throughout the
pandemic.
COVID-19 has given rise to a risk of staff not being available to conduct
work, both offshore and onshore. The Company has implemented
several measures in response, including enacting its business continuity
plan to arrange for designated individuals to step into critical roles as
required. In addition, the Company has implemented enhanced HSE
guidelines at all locations, developed in conjunction with WHO and
International SOS recommendations. This includes work-from-home
provisions wherever possible, enhanced hygiene, cleaning, social
distancing, and health checks, as well as split working arrangements
whereby critical leaders are prohibited from working in the same place
and time.
Travel restrictions have been imposed world-wide in response to
COVID-19, including bans on inter-state travel within Australia, in
addition to restrictions on entering and leaving various other countries
where Jadestone staff conduct their work. In response, Jadestone
has embraced home working as the norm for onshore staff, and has
implemented a revised offshore work cycle intended to minimise travel
time and ensure adherence to mandatory self-isolation requirements.
With these measures in place, to this point the Company has
experienced no disruptions to its ongoing operations whatsoever.
With the requirement for much of the Company’s personnel to work
remotely, electronic connectivity is critical. Jadestone is well positioned
in this regard, with IT infrastructure and systems already designed to
minimise business disruption with remote working arrangements. To
date, there have been no disruptions to IT services or support.
Financial
Jadestone has entered the current COVID-19 period of unprecedented
lockdowns in a strong financial position.
The Company’s total cash on hand as at March 31, 2020 is $109.4
million, excluding $10.0 million restricted cash. Aside from common
equity, the Company’s sole form of external financing, and its sole
interest-bearing debt, is the Company’s existing senior reserve-based
loan, which has an outstanding balance of US$37.3 million as at March
31, 2020. The most recent borrowing base redetermination set the
borrowing base at a substantial premium to the drawn balance, and
even at the current low oil price, the Company is able to comfortably
meet the covenants on the loan. This is in part due to the existing
capped swap hedge programme that covers approximately 50% of
Montara’s planned production to September 30, 2020 at an average
Dated Brent oil price of $68.45/bbl, and before the premium it achieves
on its crude oil price realisations over Brent.
The Company’s 2020 capital programme is highly discretionary.
With the ongoing delays in Vietnamese Government approvals for
the final field development plans for Nam Du/U Minh, the Company
announced on March 19, 2020 a delay to the development of this
project. This results in a $90.0 million reduction in the 2020 capital
programme; a prudent step amidst the ongoing uncertainty.
Additionally, the Company has announced a delay in the Australian
2020 infill drilling. This delay aims to best align capital spending with
a strengthening oil price environment, maximising potential future
returns, while preserving the Company’s balance sheet and net cash
position today.
Collectively, this has reduced the Company’s total capex guidance for
2020 by around 80% to US$30.0–35.0 million.
The portfolio remains operating cashflow positive, even down to Brent
oil prices below $20/bbl.
The Company will lock in additional hedging as and when conditions are
considered favourable to reduce volatility in short term oil price and/or
foreign currency outcomes.
Conclusion
Jadestone is proactive in understanding and mitigating the potential
risks to its business with regards to both its ongoing operations, and its
long-term financial well being. To this point, operations have continued
very much as intended, and the Company believes it will emerge from
this pandemic in strong financial shape, and with its strategy to add
value intact and unchanged.
Jadestone Energy 2019 Annual Report 16
Review of Operations
17
Assets
Country/Asset
Australia
Montara (AC/L7, AC/L8)
Stag (WA-15-L)
Indonesia
Ogan Komering 1
New Zealand
Maari (PMP 38160) 2
Philippines
SC56
SC573
Vietnam
Nam Du (Block 46/07)
U Minh, Tho Chu (Block 51)
Block 05-1b & 05-1c 4
WORKING
INTEREST
OPERATOR
GROSS
ACREAGE (KM2)
LOCATION
WATER
DEPTH (M)
100%
100%
--
69%
25%
21%
100%
100%
30%
Jadestone
Jadestone
252
160
Offshore Western Australia
Offshore Western Australia
Pertamina
1,152
Onshore South Sumatra
Jadestone
81
Offshore Taranki Basin
Total
CNOOC
Jadestone
Jadestone
Idemitsu
6,220
7,200
3,281
2,848
1,054
Sulu Sea
Offshore Palawan Island
Malay-Tho Chu Basin
Malay-Tho Chu Basin
Nam Con Son Basin
71
47
n/a
100
1,802
1,500
48
64
110
(1) Jadestone, as a prior partner in the Ogan Komering Production Sharing Contract (which expired in May 2018), is progressing discussions with Pertamina for participation in the asset, and
is continuing to seek an arrangement whereby it will once again acquire an interest in the block.
(2) Subject to completing Jadestone’s acquisition, expected in H2 2020.
(3) Currently in force majeure.
(4) Jadestone announced on August 9, 2016 that it had signed a SPA with Teikoku, a wholly-owned subsidiary of Inpex Corporation as seller, for the acquisition of a 30% non-operated
working interest in Blocks 05-1b & 05-1c. The transaction has not been completed.
Offices
The Company is listed on the AIM market of the London Stock Exchange in the
United Kingdom. Jadestone’s head office is in Singapore and its technical centre
of excellence is in Kuala Lumpur, Malaysia. Australia operations are managed from
its Perth office and Vietnam operations from an office in Ho Chi Minh City. In addition,
the Company is in the process of setting up a new office in New Plymouth to support
its New Zealand operations.
Stag platform, Ensco 107 drilling rig and support vessel
Portfolio Overview
Jadestone operates all of its producing and development assets,
which currently include oil production in Australia and a near-term
gas development in Vietnam. In addition, the Company holds a legacy
exploration interest in the Philippines, is seeking to re-enter into an
onshore asset in Indonesia and has entered into a Sale and Purchase
Agreement for the Maari oil asset in New Zealand.
Vietnam
Block SC 57
Block 05-1b/1c PSC
Block 51 PSC
Block 46/07 PSC
Block SC 56
Philippines
Ogan Komering
Indonesia
Montara
Australia
Stag
New Zealand
Maari
Jadestone Energy 2019 Annual Report 18
Review of Operations
Asset Overview
Montara
Australia
Working Interest 100%
Gross Acreage 252 km2
Offshore Western Australia
Water Depth 71m
The Montara assets are located in the Timor Sea,
offshore Australia, approximately 690 km west of Darwin.
The assets are in licences AC/L7 and AC/L8 which cover
252 km2 in area, and include three producing oil fields:
Montara, Skua and Swift/Swallow, produced through
a Floating Production Storage and Offloading (“FPSO”)
vessel, the Montara Venture FPSO. The Montara field is
developed with a fixed wellhead riser platform, while the
Skua and Swift/Swallow fields are subsea completions.
All fields are connected to the Montara Venture FPSO
which stabilises and stores crude oil for offload. The fields
produce light, sweet crude oil (42o API), which sells at a
premium to Brent, historically in the $3 - $4/bbl range,
but has increased in late 2019 and early 2020 to $6-7/bbl
range. Jadestone is the operator and holds a 100% working
interest in all assets, including the Montara Venture FPSO.
In late 2018, the Company successfully carried out an extensive
maintenance and inspection shutdown which remedied all outstanding
maintenance and inspection tasks inherited from the prior operator.
Jadestone also conducted an innovative riserless light well intervention
programme which successfully restored gas lift to key subsea wells and
accessed additional reservoir sands through new perforations.
In August, the Company’s safety case for Montara was accepted by
Australia’s National Offshore Petroleum Safety and Environmental
Management Authority, resulting in formal transfer of operatorship to
Jadestone, and subsequent transfer of the full 100% legal interest in the
titles for Montara’s licences, AC/L7 and AC/L8. Following the transfer of
operatorship, Jadestone installed replacement subsea umbilical cables at
the Montara complex, aimed at ensuring ongoing reliable operations of
Montara’s subsea fields for the remainder of the fields’ lives.
Montara
Timor Sea
Montara
Indian Ocean
Stag
Western Australia
Western Australia
0
25
50
75
100kms
0
25
50
75
100kms
Stag
Ensco 107 drilling rig at the Stag platform
Importantly, all work at Montara was conducted in accordance with
the Company’s high standards for health, safety, and environmental
performance, resulting in no significant incidents. All major projects
were completed on-budget and contributed to both reserves and
production in line with the Company’s expectations. Jadestone added
0.4 mm bbls of 2P reserves at Montara, after prodution of 3.8 mm bbls,
or 10,778 bbls/d (from its January 11 restart).
In Q1 2020, Jadestone acquired new 3D broadband seismic over the
entire Montara blocks’ area, aimed at assessing near-field exploration
opportunities and adding to the Company’s inventory of development
drilling targets. Jadestone intends to drill several infill wells starting in
2021, starting with the Montara H6 well, which will target unswept oil
close to the western bounding fault of the Montara field.
Crude oil offload from the Montara Venture FPSO
19
Stag
Australia
Working Interest 100%
Gross Acreage 160 km2
Offshore Western Australia
Water Depth 47m
The Stag oilfield is located in the Carnarvon Basin,
approximately 60 km offshore, Western Australia
and is part of the highly productive North West Shelf
hydrocarbon province. The assets are in licence
WA-15-L, which covers 160 km2 in area, and includes the
Stag fixed production platform, which is connected to a
leased Floating Storage and Offloading ("FSO") vessel,
the Dampier Spirit. The Stag oilfield produces heavy,
sweet crude oil (19o API), which historically sells at a
premium to Brent of $1 - $4/bbl, but has recently realised
premiums of more than $20/bbl. Jadestone is the operator
and holds a 100% working interest in the field and
production platform.
In 2019, Jadestone drilled the first infill well on Stag in six years
and Jadestone’s first well as operator. The well, Stag 49H, came on
production at an initial rate of 1,400 bbls/d as expected, and continued
to produce in line with the Company’s expectations throughout the year.
In addition, the Company undertook several routine well workovers in
2019, primarily to replace electric submersible pumps ("ESPs"), resulting
in all wells being on-line by year-end. At December 31, 2019 Stag’s 2P
reserves totalled 14.8 mm bbls, after 2019 production of 1.1 mm bbls,
or 3,049 bbls/d.
The Company also undertook several initiatives to improve both
operating cost efficiency and facility uptime, which contributed to
further improvements in unit opex ($ per bbl). The combined effect of
adding reserves and enhancing efficiency have resulted in an extension
to the field’s anticipated life, to 2035.
In 2020, Jadestone plans to undertake various maintenance and repair
works on the Stag FSO, aimed at ensuring ongoing asset integrity and
reliability. In addition, the Company will continue the well workover
programme, required by the need to replace ESPs at the end of their
useful life, and will conduct well planning, in preparation for further
drilling anticipated in the following year.
Jadestone Energy 2019 Annual Report 20
Review of Operations
Asset Overview
Nam Du and U Minh
Vietnam
Working Interest 100%
Gross Acreage: Block 46/07 – 3,281km2, Block 51 – 2,848km2
Malay-Tho Chu Basin
Water Depth: Block 46/07 – 48m, Block 51 – 64m
The Nam Du and U Minh gas fields are located in the
offshore Malay/Tho Chu basin, approximately 150 km
southwest of Ca Mau province in Vietnam. The fields
are in blocks 46/07 and 51, respectively, which cover
6,129 km2 in area. The fields were discovered in 2013
and 1997, respectively. Subject to formal approval of its
Field Development Plan, Jadestone intends to construct
a fixed wellhead riser platform on each field, which will
be connected to a leased FPSO vessel, in turn connected
to a nearby, pre-existing gas export pipeline, which will
ultimately deliver gas to the Ca Mau power generation
and fertiliser complex, onshore southwest Vietnam.
The Company is expecting to achieve first production no
earlier than late 2022. Jadestone is the operator and holds
a 100% working interest in both licences.
In 2019, Jadestone progressed engineering and contracting work relating
to the Nam Du and U Minh development, including selection of major
contractors relating to the design and construction of wellhead platform
facilities and pipelines, as well as provider of the FPSO. The project
Environmental Impact Assessment was approved by the Vietnam
government in December 2019. In addition, the Company signed a Heads
of Agreement relating to an eventual Gas Sales and Purchase Agreement
and, in November, submitted its final Field Development Plan (“FDP”)
to Petrovietnam for approval. In early 2020, amid delays in Vietnamese
Government approvals and the drop in global oil prices related to
COVID-19, the Company opted to delay the project, as part of a review
of its capital programme, aimed at maintaining the Company’s strong
balance sheet.
21
Tasman Sea
Maari
New Zealand
Maari
New Zealand
Working Interest 69%
Gross Acreage 81km2
Offshore Taranki Basin
Water Depth 100m
Phnom Penh
Cambodia
Ho Chi Minh
Vietnam
Vietnam
Thailand
Cambodia
Block 51
Block 46/07
Malaysia
Block
05-1b
05-1c
Singapore
Indonesia
Block 05-1b 05-1c
Maari
Cook Strait
0 25 50 75 100kms
0
25
50
75kms
Gulf of Thailand
Ca Mau
Block 51
Gas Pipeline
Block 46/07
Tho Chu
Vietnam
The Tho Chu gas field is located in block 51, offshore
Malay/Tho Chu basin, approximately 50 km to the
northwest of the U Minh field, which is also within
block 51.
The field was discovered and appraised by the 51-TC-2X well and
has since been recorded by the Company as holding 63.7 mm boe
of contingent resource. Due to its relative distance from existing
infrastructure (unlike the Nam Du and U Minh fields), Tho Chu is in a
suspended development status, pending access to export ullage, and
will be the subject of a future field development proposal, potentially
in coordination with other nearby assets which are yet to be developed.
Maari well head platform
Block SC56 and SC57
Philippines
Working Interest: SC56 25%, SC57 21%
Gross Acreage: SC56 – 6,220km2, SC57 – 7,200km2
SC56 – Sulu Sea, SC57 – Offshore Palawan Island
Water Depth: SC56 1,802m, SC57 1,500m
SC 56 is a deepwater exploration block located in the
Sulu Sea, and covering 6,220 km2 in area. Jadestone holds
a 25% non-operated working interest with the balance,
and operatorship, held by Total.
In 2019, the Company pursued an arbitration action against Total
in response to a breach of the 2012 farm out agreement between
the companies, claiming that, among other things, Total failed to
drill an exploration well on the block’s Halcon prospect. In early 2020,
the tribunal found in favour of Jadesone, and awarded monetary
damages and legal costs which were partly offset by repayment of
third-party funding facilities used to finance the arbitration action
and other related fees.
SC 57 is a deepwater exploration block located offshore Palawan
island, and covering 7,200 km2. In 2006 Jadestone agreed to acquire
a 21% working interest in the block through a farm-in agreement,
however the transaction has not been completed, and the block
is currently under force majeure.
The Maari project assets are located in the offshore
Taranaki basin, approximately 80 km west of New
Zealand’s North Island. The assets are in permit 38160
which covers 81 km2 in area and includes two producing
oil fields: Maari and Manaia, which are produced through
a self-elevated jack-up wellhead platform connected
to an owned FPSO, the Raroa, a sister vessel to the
Montara Venture. The fields produce light, sweet
crude oil (37o API), which sells at a premium to Brent
of approximately $1-2/bbl. Jadestone is acquiring
an operated 69% working interest in the Maari project,
with an economic effective date of January 1, 2019.
In 2019, the Company announced the acquisition and began working
toward satisfying various conditions to the deal, which include
acceptance of Jadestone as operator by the Maari joint venture partners,
New Zealand Government approvals relating to title transfer, and change
of operatorship.
Jadestone expects to close the acquisition in the second half of
2020. The Company intends to pursue several further development
opportunities on the asset including optimising water injection,
drilling additional wells and adding horizontal laterals through coil
tubing drilling, with a view to increasing recovery factors for all
producing reservoirs.
Ogan Komering
Indonesia
Gross Acreage: 1,152 km2
Onshore South Sumatra Basin
The Ogan Komering working area is located onshore South
Sumatra, and covers 1,152 km2. The asset includes several
gas and oil producing fields, and is situated amongst
extensive gathering and processing infrastructure.
Jadestone, as a prior partner in the Ogan Komering Production Sharing
Contract (which expired in May 2018), has been directed to proceed with
direct negotiations for participation in the new Ogan Komering Gross
Split PSC.
In 2019, the Company progressed its discussions with Pertamina for
participation in the asset, and is continuing to seek an arrangement
whereby it will once again acquire an interest in the block.
Jadestone Energy 2019 Annual Report 22
23
R
e
p
o
r
t
S
u
s
t
a
i
n
a
b
i
l
i
t
y
Jadestone - providing energy
in the most efficient and
sustainable way.
Whale spotted near Stag platform
Jadestone Energy 2019 Annual Report 24
Sustainability Report
25
Paul Blakeley – on Montara
A message from the CEO
Welcome to the
Jadestone Sustainability
Report 2019
Ensuring the sustainability
of our business is not just
about what we do, but
how we do it.
I am pleased to present Jadestone Energy’s Sustainability
Report for 2019.
At Jadestone Energy we have continued to expand our presence as a leading independent
upstream oil and gas company in Asia Pacific, whilst being respected as an operator and
employer of choice.
We understand that our operations affect people and nearby communities, and we
will always strive to find ways to provide benefit for our stakeholders and everyone
associated with our activities. We also know there are impacts on both the local and global
environment, and we are working to minimise these through reductions in emissions,
waste and discharges, and recycling wherever possible. To achieve such an outcome, we
are committed to assessing all the associated impacts of our operations to eliminate
potentially harmful outcomes and to contribute to a more sustainable future.
We have mapped our activities against our Environmental, Social and Governance (“ESG”)
framework, and I am excited to be publishing our first Sustainability Report, which sets
out our approach, and establishes some key objectives to drive continuous improvement
in our business.
Our strategy is to work only within existing hydrocarbon provinces where infrastructure
is already present, and to maximise the recovery from existing producing fields, as well as
to develop discovered hydrocarbons that may otherwise be left stranded or uneconomic
in the hands of other operators.
Our contribution towards a sustainable world is to ensure the most
efficient use of existing facilities and infrastructure, and that reservoirs
are more fully depleted than the original owners and stakeholders had
envisaged. The greatest possible benefits for everyone can only be
achieved when we deliver results that exceed previous expectations.
Such an approach requires the highest standards in safety, integrity and
environmental performance and we constantly strive to deliver this.
We believe that maximising the value of our assets is a key factor towards a more
sustainable world and why sustainability is identified as one of Jadestone Energy’s
core values. This report provides us with the opportunity to be transparent with all our
stakeholders and to describe the work being undertaken at Jadestone to improve how
we manage our ESG responsibilities. The report also includes strategic goals to further
improve our ESG performance. These goals form the basis of our ESG Key Performance
Indicators (“KPI’s”) that will be measured and managed alongside our operational
and financial KPIs and, in the spirit of continuous improvement, will be expanded
and improved upon in the future.
Paul Blakeley
Executive Director, President and Chief Executive Officer
Những Ước Mơ Xanh (‘Green Dreams’) Organisation
Vietnam
Block SC 57
Block 05-1b/1c PSC
Block 51 PSC
Block 46/07 PSC
Block SC 56
Philippines
Ogan Komering
Indonesia
Montara
Australia
Stag
Who We Are
Creating Value
Jadestone Energy Inc. (AIM:JSE) (“Jadestone” or the “Company”) is
an independent oil and gas company listed on the London Alternative
Investment Market (“AIM”). Jadestone’s business model focuses on
acquiring mid-life producing assets and stranded discoveries in the
Asia Pacific region and through significant additional capital investment,
maximise reserves recovery and improve operating performance,
thereby extending field life beyond any previous expectations and
creating significant shareholder value.
Where Do We Operate?
Jadestone is focused solely on the Asia Pacific region, headquartered
in Singapore, its principal technical team in Kuala Lumpur and
country operations based in Perth, Jakarta, Ho Chi Minh City and most
recently in New Plymouth. The Company’s asset portfolio includes the
100%-owned producing Montara project, offshore Australia / Timor Sea;
the 100%-owned producing Stag oilfield, offshore Australia / North-
West Shelf; and a 100% interest in the pre-development Nam Du and
U Minh gas fields offshore southern Vietnam. Jadestone is also
expanding its footprint into New Zealand following the signing of the
Sale and Purchase Agreement with OMV in November 2019 to acquire
an operated 69% interest in the Maari and Manaia producing fields,
offshore New Zealand.
New Zealand
Maari
Jadestone Energy 2019 Annual Report
26
Sustainability Report
27
Jadestone ESG at a Glance
We aim to do it right first time, look for innovative ways to deliver
exceptional value, while protecting the people and environments
in which we operate. Jadestone strives for excellence, with a target
of zero incidents, accidents and impact where possible.
0
No harm to
environment and zero
‘reportable’ incidents
ENVIRONMENTAL
MANAGEMENT
0
No uncontrolled
hydrocarbon releases
to the environment
EMISSIONS AND
DISCHARGES
10%
reduction target set
Reducing our
energy and
GHG emissions
GHG
0
A zero lost time injury
frequency rate
OH&S
25%
Females in
leadership positions
WORKFORCE
10%
increased
investment target set
Engaged and
consulted stakeholders
STAKEHOLDER
MANAGEMENT
Almost US$ 177 million
in operating cashflow
before working capital changes
ECONOMIC
PERFORMANCE
Top Quartile
Governance Standards
Performance
based leadership
LEADERSHIP
AND GOVERNANCE
0
Zero regulatory
enforcements
REGULATORY
MANANAGMENT
0
Zero critical
risk incidents
CRITICAL INCIDENT
RISK MANAGEMENT
0
Zero tier 1 asset integrity or
process safety incidents
ASSET INTEGRITY
AND PROCESS SAFETY
0
Zero incidents
of non-compliance
BUSINESS ETHICS
AND TRANSPARENCY
Gordon Lattimer a production technician on Montara asset
Environmental
Excellence in environmental management
Reducing our energy and greenhouse gas (“GHG”) emissions
Providing energy to meet global demand in the most efficient
& sustainable way
Maximising use of existing infrastructure to reduce industry
footprint
Continuous improvement in ESG performance
Social and Human Capital
Exceptional occupational health and safety culture
Promoting workplace diversity
Engaged, supported and diverse workforce
Improving our understanding of our impact on communities
Growing engagement and investment in our communities
Local recruitment, including graduates and intern programmes
Governance and Leadership
Demonstrating strong leadership and strengthened governance
Prioritising asset integrity and process safety
Critical incident risk management in place and tested
Exceptional regulatory management
Excellence in business ethics and transparency
Economic contribution to country economies
Sustainability at Jadestone
Jadestone manages its business in line with it’s core
values, which helps to ensure the business operates
in a safe, secure, environmental and socially
responsible way. The foundations of people,
partnership, operational excellence and efficiency,
underpin Jadestone Energy’s operations and align
closely with the ESG Framework.
Jadestone’s system of Company-wide standards, procedures and
guidelines, ensures that the risks associated with environmental
and social aspects of its operations are managed comprehensively.
Through integrated planning and decision-making, Jadestone identifies
and prioritises sustainability risks, develops mitigation plans, tracks
performance against goals, and adjusts plans as conditions evolve.
Depending on the nature of the risks, these are either managed by local
business units or at the corporate level.
The business has clear and effective governance structures in place that
are supported by policies, standards, procedures and guidelines.
Code of Conduct Policy;
These include:
• HSE Policy;
•
• Anti-Bribery and Anti-Corruption Policy;
•
•
•
Insider Trading Policy;
Gender and Workplace Diversity Policy; and
Sustainability Policy.
Ensuring the sustainability of our business is not
just about what we do, but how we do it.
Teo Chun Tat and Yeoh Xiao Qi, subsurface team in Kuala Lumpur
Jadestone Energy 2019 Annual Report
28
Sustainability Report
29
Frameworks and Standards
This Sustainability Report presents Jadestone’s sustainability
performance for the year ending December 31, 2019. It describes how
the business performed, the value it created and plans for the future.
The Sustainability Report focuses on what matters most to Jadestone
Energy stakeholders and the business (see Material Matters).
This report has been prepared in accordance with the Global Reporting
Initiative (“GRI”) Standards: Core Option. Guidance prepared by
IPIECA (the global oil and gas industry association for environmental
and social issues) was also consulted, and the report is aligned to
recommendations made by the Task Force on Climate-related
Financial Disclosures (“TCFD”), and the Equator Principles (“EP”).
The UN Sustainable Development Goals (SDGs)
Jadestone believes it can play a meaningful role in helping to address
the UN SDG. Its activities were scored against the SDG’s as part of the
material mapping process, to measure its contribution to them.
Task Force on Climate-Related Financial Disclosures
Over the past year, Jadestone has taken significant steps to develop its
disclosures on climate-related business risk to align with the TCFD.
Equator Principles
The EPs provide a risk management framework, adopted by financial
institutions, for determining, assessing and managing environmental
and social risk in projects and is primarily intended to provide a
minimum standard for due diligence and monitoring to support
responsible risk decision-making. This report aligns with the principles.
Platinum Sponsor Member of the Energy Club NT;
Memberships and Ratings
•
• Australian Petroleum Production & Exploration Association; and
•
Indonesian Petroleum Association.
Reporting Boundaries
Defining boundaries for sustainability reporting can be challenging
due to complex and sometimes changing ownership structures and
operational arrangements. Jadestone is committed to being transparent
about sustainability reporting boundaries and the effect of any changes
in future reporting years.
Reporting boundaries for this report included all Company assets and
offices. Where there was not appropriate data available for both the
2018 and 2019 calender year for an asset or office location, this was
omitted from the disclosure. As a result, the Stag asset and office
in Australia was a focus for many of the environmental disclosures.
However, corporate governance and social capital disclosures are
reported for the other offices in Asia Pacific. The available data against
each disclosure and those omitted are summarised in the table on
page 42. Jadestone is committed to collecting more data against
the disclosures from across the Jadestone portfolio for future
Sustainability Reports.
1 NO
POVERTY
2
NO
HUNGER
3
GOOD
HEALTH
Material Matters
Jadestone conducted a mapping exercise to identify topics that were of
most significance to Jadestone’s business and stakeholders, referred to
as material matters. The outputs (material matters) from the mapping
exercise were used to inform this report and were selected as GRI
disclosures and are illustrated below. Jadestone recognises the topics
‘of most importance’ to stakeholders also demand respect and attention
and are referenced and disclosed in this report where data is available.
4
QUALITY
EDUCATION
5
GENDER
EQUALITY
6
CLEAN WATER
AND SANITATION
Materiality Map
7
RENEWABLE
ENERGY
8
GOOD JOBS
AND ECONOMIC
GROWTH
9
INNOVATION AND
INFRASTRUCTURE
10
REDUCED
INEQUALITIES
11
SUSTAINABLE
CITIES AND
COMMUNITIES
12
RESPONSIBLE
CONSUMPTION
Stakeholder Management
Leadership and Governance
Business Ethics
and Transparency
Occupational
H & S
Climate Change
– GHG
Emissions
and Discharges
Economic
Performance
Asset Integrity
and Process Safety
13
CLIMATE
ACTION
14
LIFE BELOW
WATER
15
LIFE
ON LAND
Regulatory
Management
Workforce
Management
Critical Incident
Risk Management
Environmental
Management
16
PEACE AND
JUSTICE
17
PARTNERSHIPS
FOR THE GOALS
United Nations Sustainable Development Goals
Những Ước Mơ Xanh (‘Green Dreams’) Organisation
3
2
1
0
s
r
e
d
l
o
h
e
k
a
t
S
o
T
t
n
a
t
r
o
p
m
I
Human Rights
And Modern Slavery
Energy Consumption
Local Community
Impacts
Stakeholder Management
Leadership and Governance
Climate Change
– GHG
Business Ethics
and Transparency
Emissions
and Discharges
Occupational
H & S
Economic
Performance
Asset Integrity
and Process Safety
Diversity
Regulatory
Management
Workforce
Management
Critical Incident
Risk Management
Environmental
Management
Indigenous Peoples
Fossil Fuel Substitutes
Waste
Cyber Security
Innovation and Technology
Important To Jadestone
1
2
3
Figure 2: Jadestone’s Materiality Map
Jadestone Energy 2019 Annual Report
30
Sustainability Report
31
E.1 | Environmental Management
Jadestone recognises that its development and production activities,
including operations at all its facilities, offshore installations, offices
and warehouses, have the potential to impact the environment.
As a result, environmental management is central to everything within
the business. As an operator of oil and gas assets, Jadestone is well
aware of its environmental and safety commitments and stewardship
responsibilities. This focuses on prevention of spills and discharges,
but equally to having effective and reliable emergency response and
preparedness systems, including hydrocarbon spill response capability,
should it be required.
Jadestone HSE Policy
Jadestone’s philosophy is to ensure that health, safety and
environmental protection is intrinsic to, and within, our operating
activities. The business focusses on those things that deliver top
performance and value optimisation while eliminating waste. A focus
on HSE performance provides a safe and rewarding work environment
for Jadestone employees, and the achievement of sustainable business
activities in the local and global communities where they work.
Within the HSE Policy, Jadestone has committed to:
• Promote a strong HSE culture through visible leadership and
an engaged, competent workforce aligned with Jadestone’s
shared values;
• Assess all risks and manage them to as low as reasonably
practicable;
• Maintain an ever-improving HSE management system through
setting and monitoring performance targets to achieve our aims
within a framework of continuous improvement;
• Take all necessary actions to prevent incidents, with an aspiration
of targeting zero. Investigate and apply learnings;
• Encourage and promote the ownership of HSE performance by all
employees and contractors;
• Ensure all contractor companies working with us have a
management system that either equals or exceeds Jadestone’s own
management system;
• Manage and maintain plant, equipment and machinery to achieve
required performance, safety and integrity;
• Openly monitor, evaluate and report HSE performance, and
communicate to all relevant stakeholders; and
• Comply with all regulatory requirements as an absolute minimum.
In addition to the overarching Group HSE Policy, the Company has
strong local HSE management processes in place wherever the Company
operates, in order to understand and manage potential impacts to the
environment and local biodiversity, as well as potential cumulative
effects through the life cycle of all its assets. The business aims to
make the most efficient use of existing facilities, and is also committed
to the removal of equipment when production ceases. Robust impact
assessment and risk management (which considers the application of
the precautionary principle in the event of uncertainty), is a key element
to Jadestone’s approach, regardless of region or the regulatory regime.
Jadestone uses its operational experience to continually improve health,
safety and environmental performance.
As a responsible oil and gas operator, Jadestone’s environmental
management approach includes effective and reliable emergency
response and preparedness systems, including hydrocarbon spill
response capability (See G.3).
Whale shark spotted by the Nam Du survey vessel
Environmental / HSE Regulatory Management
All regulatory approvals within the jurisdictions where the Company
operates have been prepared, obtained, and upheld within the scope of
the relevant country legislation (currently Australia and Vietnam). This
includes Environmental Impact Statements, Environment Plans, Oil
Pollution Emergency Plans and Safety Cases.
In Australia: Annual environmental performance reporting to
the regulator is also completed to demonstrate compliance with
commitments made in the Company’s regulatory approvals documents.
Jadestone has had zero ‘reportable*’ environmental
incidents (hydrocarbon and non-hydrocarbon spills) for
the Stag Facility for 2019.
*
'Reportable' meaning no breach of the Environmental Performance
Outcomes (or greater than 80 Litres).
In Vietnam: An offshore environmental baseline survey and
Environmental Impact Assessment was completed for the Nam Du /
U Minh field development, and was approved by the Vietnamese
Ministry of Natural Resources and the Environment on
December 2, 2019.
This included:
• A social and economic survey;
• Communication with local authority and sensitive areas
management teams;
• A forward plan for Environmental and Social Impact Assessment
activities to meet regulatory and stakeholder requirements; and
Compliance with the Equator Principles.
•
2020 ESG Strategic Corporate Goal
•
Exceptional regulatory management
– Target Zero regulatory enforcement notices and zero fines for
regulatory breaches
E.2 | Climate Change, Energy and Emissions
Jadestone understands that climate change may affect its stakeholders,
its operations and the broader economy, environment and communities
in which it operates. As society responds and transitions to a low-carbon
economy, the leadership team maintains that Jadestone’s contribution
towards a more sustainable future is to ensure the most efficient use of
existing facilities, while also meeting the ongoing need for energy.
Jadestone’s Vietnam Nam Du and U Minh gas field development
will also provide natural gas into the growing Vietnamese economy.
Natural gas, as a replacement for coal in electricity generation, is a
critical part of a credible low-carbon strategy. These two fields have
the lowest concentrations of CO2 of all the discovered resource in the
immediate area.
There are many uncertainties in energy transition, including the pace of
the transition. New technologies, stricter climate change policies and
new entrants and technologies may disrupt the energy industry.
Jadestone believes that nothing prepares the business
better for uncertainty than agility and innovation,
allowing Jadestone to adapt to a changing energy world.
Case Study – Australia
Each year Jadestone Australia is required to report GHG emissions
for its Australian assets under the National Greenhouse and Energy
Reporting. Figure E.1 shows the Scope 1 and 2 emissions for the Stag
Facility for 2018 and 2019 1,2. The emissions at Stag are significantly
below the 100,000 tonnes of CO2 level set by the Clean Energy Regulator.
Additional assets (e.g. Montara) will be reported in subsequent reports
when the Company has two years of data under its operatorship.
1 Data collected for Stag facility NGERS reporting 1 July to 30 June
2 No Scope 2 emissions
Sunrise – Montara
Australian Energy
and GHG Emissions
Stag Facility Scope 1
Emmisions (tCO2)
)
t
n
e
l
a
v
i
u
q
e
e
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i
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a
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o
s
e
n
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o
t
(
e
–
2
O
C
t
600,000
500,000
400,000
300,000
200,000
100,000
0
600,000
500,000
400,000
300,000
200,000
100,000
0
)
j
G
(
s
e
l
u
o
j
a
g
i
G
)
s
e
n
n
o
t
(
2
O
C
t
100,000
75,000
50,000
25,000
0
Stag 2018
Stag 2019
Gross Energy Consumed (Gj)
Net Energy Consumed (Gj)
Scope 1 (tCO2)
Stag
2018
Stag
2019
Time
Figure E.1 Australian Stag facility energy consumption and GHG emissions
The identification and development of programmes and projects
to reduce flaring and /or other emissions, such as those caused by
burning fuel gas, remains a priority for Jadestone. These are all being
investigated through the formation of a Climate Change Working Group
and an Emissions Reduction Road Map.
Figure E.2 illustrates Scope 1 emissions as well as energy consumption
from the Jadestone Energy Australia office between 2018 and 20192.
The Perth office was relocated during the reporting time and represents
the time period of June 2018 to December 2019. Jadestone continues
to introduce energy efficiency initiatives, aimed to reduce energy
consumption within the office.
Jadestone Perth Office Energy and GHG Emissions
Scope 1
(tCO2-e)
Net Energy
Consumed (Gj)
Gross Energy
Consumed (Gj)
0
0
Gigajoules (Gj)
50
100
150
200
250
300
50
100
150
200
250
300
tCO2
–e (tonnes of carbon dioxide equivalent)
Perth Office 2019
Figure E.2: Australian Perth office energy consumption and GHG emissions
Task Force Climate Disclosure
In 2019, Jadestone took significant further steps to develop
disclosures on climate-related business risk to align with the TCFD.
The implementation of the Climate Change Working Group will also
ensure climate considerations are embedded in Company strategy,
decision-making, incentives and reporting.
2020 ESG Strategic Corporate Goal
• Reducing our energy and GHG emissions
– Reduce gas flaring at Montara (GHG emissions) by 10%
and reduce diesel usage at Montara by 10%
Jadestone Energy 2019 Annual Report
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E.3 | Emissions and Discharges
Every environment has a unique combination of habitats, plant and
animal species. A key challenge for Jadestone in managing the potential
impact on the marine environment from its offshore facilities, concerns
the treatment and discharge of operational waste streams, for example,
produced water. Jadestone recognises the importance of appropriate
utilisation or disposal of discharges.
Jadestone’s main objective for responsible management of produced
water is to reduce the oil in water content to as low as reasonably
practicable. This is achieved through best practice topside management,
which contributes to an overarching adaptive management framework.
Changes to the chemical injection regime and full usage of the in-situ
slops tanks on the Stag facility have achieved improvements in oil
in water concentrations in produced water from near 15mg/L at the
beginning of 2019, reducing to around 5mg/L on average. Jadestone
ensures that any area of impact from produced water discharge does not
compromise management objectives within the relevant Environment
Plan for the facility.
The environmental performance outcome for Stag
produced water discharges is to achieve the national
marine water quality guidelines for protection of 99%
of species and the sediment quality ISQG-low values,
as defined by ANZECC/ ARMCANZ (2000) at the
boundary of the area of impact.
Air Emissions
Jadestone implements management measures including scheduled
maintenance of equipment and availability of critical equipment spares,
to keep air pollutant emissions from Jadestone operations as low and
clean as possible. Programmes and projects to reduce air emissions,
such as those caused by burning fuel gas, are regularly assessed for
effectiveness and to look for improvements. Jadestone reports to the
National Pollution Inventory, the levels of nitrogen oxides (“NOx”),
sulphur oxides (“SOx”) and Volatile Organic Compounds (“VOC”) are
all relatively low for the Stag facility (Figure E.3).
Air Emissions for Stag Facility 2018-2019
r
a
e
y
/
g
k
200,000
150,000
100,000
50,000
0
NOx
SOx
VOC
2018
2019
Figure E.3 1 Air emissions for Stag Facility
1 Data collected for National Pollution Inventory data July 1 to June 30
Other routine operational discharges may also cause a localised
reduction in water quality, such as a temporary increase in nutrient
concentrations, temperature and salinity. Jadestone minimises potential
impact due to operational discharges through the efficient use of more
environmentally friendly chemicals wherever practicable.
In 2019 a new well was drilled at Stag for the first time in six years.
Recorded NOx levels grew in 2019, relative to 2018, due to the associated
gas from the 49H infill well first produced in May 2019, and which
targeted a different part of the reservoir. All associated gas is flared at
the Stag facility. The associated gas from the new well has returned
to previous levels.
Montara Sunrise
2020 ESG Strategic Corporate Goal
•
Excellence in environmental management
– Ensure zero Loss of Primary Containment (Tier 1)
– Improve overall oil-in-water discharge performance at both
facilities by 10% < 30mg/l
Health, Safety & Environment Policy
Respect
Integrity
Safety
Results-Orientated
Sustainability
Passion
Vision
At Jadestone, HSE performance is central to everything we do. Our
vision is to ensure that health, safety and environmental performance is
intrinsic to our business activities. We focus on those things that deliver
top performance while eliminating waste. Together with our Shared
Values, a focus on HSE performance provides a safe and rewarding work
environment for our people, and achievement of sustainable business
activities in our local and global communities.
Responsibility
Everyone who is engaged to work for Jadestone shall be familiar with
this policy and its contents.
Everyone must take responsibility for ensuring their own safety, the
safety of those around them, and the protection of the environment,
by following Jadestone’s policies and procedures. That includes taking all
necessary precautions and immediately acting upon and reporting any
HSE concerns they may have.
Everyone has the right to stop the job and a responsibility to intervene
in work or colleague’s activities if they feel there is a risk to themselves,
their workmates and to the environment.
Execution
To achieve this Jadestone shall:
•
Promote a strong HSE culture through visible leadership and
an engaged, competent workforce aligned with Jadestone
Shared Values;
•
Assess all risks and manage them to as low as reasonably practical;
• Maintain an ever-improving HSE management system through
setting and monitoring performance targets to achieve our aims;
•
•
•
Take all necessary actions to prevent incidents, with an aspiration
of targeting zero. Investigate and apply learnings;
Encourage and promote the ownership of HSE performance by all
employees and contractors;
Ensure all contractor companies working with Jadestone have a
management system that either equals or exceeds the Company’s
own management system;
• Manage and maintain plant, equipment and machinery to achieve
required performance, safety and integrity;
•
•
Openly monitor, evaluate and report HSE performance, and
communicate to all relevant stakeholders; and
Comply with all regulatory requirements as a minimum.
Figure E.4 Jadestone Energy’s HSE Framework
Jadestone Energy 2019 Annual Report
34
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Some key achievements for HSE in Australia 2019 included:
• Health, Safety and Environmental performance was managed
and measured on a daily basis;
• Revision of the HSE Policy;
•
•
•
“Safety Mate” - The behavioural based HSE programme;
The introduction of the HSE Committee;
The establishment of a comprehensive Competency and Learning
Management System; and
The establishment of an Injury Management database for
management of injuries.
•
Through implementing these measures Jadestone was able to achieve
a total recordable incident injury frequency rate of zero incidents per
million manhours worked for the Stag facility, compared to the APPEA
industry average Total Recordable Injury Frequency Rate
of approximately 3.4 incidents per million manhours worked.
The Total Recordable Injury Frequency Rate on
Jadestone Stag facility for 2018 and 2019 was zero.
2020 ESG Strategic Corporate Goal
•
Exceptional occupational health and safety culture
– Target Zero Recordable Incidents, with continuous
improvement year on year (<2)
– Reduce Medical Treatment Cases by 10% through leadership
and culture
– Provide full time medic to indigenous communities at
Truscott during during the COVID-19 pandemic
Wayne Roff, Shay Leahy, Nathan Lee on the Fast Rescue Craft at Montara asset
S.1 | Occupational Health and Safety
Health and safety performance is a central focus at Jadestone.
The business objective is to provide a safe and rewarding work
environment for Jadestone people, and to maintain an exceptional
health and safety performance wherever the Company operates.
Case Study – Australian Stag Asset
In Australia, Jadestone’s Safety Management System is integrated
within the Company’s Business Management System, which describes
the systems, standards, procedures and behaviours necessary to achieve
the desired HSE performance and outcomes. An HSE Committee, which
includes representatives from the onshore support office, the offshore
workforce and senior management, meets quarterly to review whether
standards are being met and to identify opportunities for improvement.
To manage risks and hazards associated with work on the facilities,
Jadestone employs an Integrated Safe System of Work (“ISSOW”), which
provides a framework through which all work can be safely and uniformly
managed. ISSOW achieves this by controlling approval authorities
and ensuring oversight of a Permit to Work process, supporting
communication between management, team leaders, technicians and
work parties, and providing the tools, processes and hardware that allow
facilities to perform work safely and efficiently. In addition, ISSOW
provides for isolations management, overrides, permitted operations
and stand-alone risk assessment process.
All incidents and observations are recorded in an electronic incident
management and hazard reporting tool. Investigations and actions
that arise from reported events are assigned and tracked. HSE KPIs are
set for each facility and reviewed by management on a monthly basis.
Records are maintained in the Company’s Computerised Maintenance
Management System and performance is displayed on each facility
notice board for the workforce.
Jadestone approaches safety proactively. In Australia, all personnel
visiting site complete Jadestone’s formal on-line HSE induction training.
Employees and Contractors must also attend a site-specific induction
upon arrival offshore and undergo formal helicopter and sea survival
training.
Offshore crew at Stag, celebrating 7 years without Lost time Injury on Stag
S.2 | Our Stakeholders
Jadestone’s overarching business strategy and contribution towards
a sustainable world is to ensure the most efficient use of existing
facilities to derive the greatest possible benefits for all stakeholders.
Jadestone openly communicates with people and organisations which
may be affected by business activities. Going beyond the legislated
requirements to engage, Jadestone seeks to develop close and long-
lasting relationships with its stakeholders and encourages ongoing
dialogue.
The Jadestone Stakeholder Consultation Guideline describes how
Jadestone identifies, maps and engages, depending on the nature of the
activity, interest and influence of stakeholders. Jadestone re-maps key
stakeholders each time an activity is initiated, or when new issues arise.
Over the past year Jadestone has engaged with key stakeholders
in a number of ways.
In the material mapping process (described on pg 29) Jadestone has
considered the reasonable expectations and interests of stakeholders
including employees, shareholders, community and other groups
including non-governmental organisations. Jadestone identified
its sustainability priorities, to inform the material mapping for this
report, through engaging with key internal and external stakeholders.
Stakeholder inclusiveness is addressed for Jadestone by collecting
information from:
•
Targeted consultations with key stakeholders, as part of the
regulatory process;
• Annual General Meetings;
•
• Media; and
• Human Resources.
Investor Relations feedback;
Sapura Constructor offshore support vessel at Montara wellhead platform
Jadestone’s key social achievements in Asia Pacific for 2019 included:
•
Developing a ‘Partnerships for Future’ programme to strengthen
the strategic approach to stakeholder engagement and
management across Asia Pacific;
• Material Mapping completed to understand important ESG metrics
to the business and stakeholders;
• A social and economic survey conducted in Vietnam to assess the
impact on local communities and economies; and
• An independent third-party assessment undertaken for Vietnam to
check project compliance with the Equator Principles (page 30).
The Company maintains a constant and active dialogue with its
investors and with AIM, a sub-market of the London Stock Exchange.
Investor dialogue is facilitated via regular one-on-one investor
roadshows and group events, regular published webcasts covering
financial results or major corporate events, and an annual capital market
review involving a deeper dive on the business and the forward 12
month outlook, as well as ongoing communications with AIM, with our
Nominated Advisor (NOMAD), and other ad hoc communications.
2020 ESG Strategic Corporate Goal
•
•
Improving our understanding of our impact on communities
Growing engagement and investment in our communities
– Build open relationships with key local stakeholders and
communities
– Develop increasing effort and investment into local social
support. Target 10% increase y-on-y
– Develop a local stakeholder consultation strategy
OUR STAKEHOLDERS
HOW WE ENGAGE
Employees
Communities
Presentations, internal news updates, monthly ‘connect’ meetings, townhalls
Regular meetings, website, support through community programmes and events, consultation prior
to activities
Contractors and suppliers
Regular meetings
Regulators
Regular meetings, representation on industry associations, site visits, ongoing information sharing
Shareholders and investment
community
Annual General Meeting, investment conferences, roadshows, webcasts and conference calls,
website and social media, direct correspondence and investor presentations
Non-government organisations
Website, representations through industry associations
Media
Industry peers
Website, media releases, contact through dedicated media liaison function
Industry conferences and presentations, representation on industry associations
Jadestone Energy 2019 Annual Report
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Community Projects
Partnering With Local NGO In Vietnam To Support
Communities
Jadestone Vietnam supported the Những Ước Mơ Xanh (‘Green
Dreams’) Organisation (NUMX) during their mid-Autumn festival
celebration programme in 2019. With Jadestone’s support, NUMX were
able to increase participation from 150 to 400 children from Vinh Hai
1 elementary school in Vinh Chau township, Soc Trang province.
Vinh Chau is in one of the poorest areas of the country, where the
majority of the local population belong to the minority Khmer ethnic
group and is a centre of shallot production. Local farmers suffer from
high rates of blindness and other eye diseases caused by shallot
farming practices. Jadestone employees supported NUMX to deliver
milk and food to the school as well as gifts of lanterns for the children
to celebrate the mid-Autumn festival.
Cash for Containers
The Montara facility has been involved in ‘Cash for Containers’ since
2015. Personnel collect all 600ml water bottles, aluminium cans and
soft drink bottles used on the facility. The bottles are donated to
the Down Syndrome Association of Northern Territory (Australia)
(“DSA-NT”). The DSA-NT workers remove and count the lids and receive
Cash for Containers donations equating to about $6,000 a year.
The DSA-NT Cash for Containers programme is a social enterprise which
offers employment opportunities for young people with disabilities.
The NT Government scheme of paying 10c per unit for recycling
containers has created an opportunity to raise funds and awareness.
The programme provides casual employment for 12 people.
Supporting Indigenous Communities
Jadestone Australia is currently supporting local indigenous and non-
indigenous communities in Darwin, through donations and redundant
equipment provided from the warehouse and supply chain group.
Top photo – School children in Vinh Hai 1 Elementary school in Vinh Chau, Soc Trang province
Bottom photo – Cash for Containers – Darwin Team
S.3 | Workforce Management
Jadestone offers an innovative and dynamic working environment
to its employees. Jadestone looks for individuals who are motivated to
challenge the status quo and collaborate to achieve outstanding results.
By extending the life of the assets the business acquires, Jadestone also
extends the work opportunities for those employed there.
The Jadestone business strategy recognises that developing employees
is a key to its ongoing success. Employees are encouraged to actively
drive their own career path and to shape their professional development.
Figure S.1 provides the breakdown of training hours (average per person)
provided to all employees across our regions. There was an increase
in the number of training hours provided to employees in 2019 across
all employment categories, which is indicative of the growth of the
Company over the same period and the implementation of competency
assessments. There were more training hours provided to full time
employees compared to contractors/fixed term, which reflects the shift
towards more full-time employees in the Company. Females received
the most training (average hours) across the Asia Pacific region, which is
largely due to the high proportion of female permanent employees in the
Vietnam office (87%).
Australia – Training & Competency
Training hours (per person) – 2018 & 2019
Contractor
Fixed Term
Fulltime
Female
Male
0
5
10
15
20
30
25
Average hours training
35
40
45
50
Average 2019
Average 2018
Figure S.1 Training hours (average per person), 2018-2019 for Jadestone, Asia Pacific
In Australia, Jadestone provides training and competency assessments
to all our employees through the implementation of role-specific training
matrices for office and offshore employees, and through our educational
assistance programme and study leave. Jadestone competency training
covers:
•
•
•
•
Emergency response training;
Technical skills training (electrical, mechanical, crane operations);
Vendor specific (specialised equipment);
Business skills training (auditing, system learning, technical
writing);
Leadership training (coaching, having difficult conversations,
regulations); and
Corporate training (Code of Conduct).
•
•
At the end of 2019, Jadestone had 165 permanent
employees located at onshore offices and offshore
facilities.
2020 ESG Strategic Corporate Goal
•
•
Promoting workplace diversity
Engaged, supported and diverse workforce
– Build a Strong, Diverse and Sustainable Organisation
– Recruit and train local nationals where possible, and to the
highest standards.
– Provide training programmes for four interns, and recruit two
new graduates in 2020.
– Ensure robust succession plan in place & high retention of
92% with positive feedback.
Plastic Free July Initiative – Vietnam team
Những Ước Mơ Xanh (‘Green Dreams’) Organisation
Plastic Free July
The grass roots commitment to improving sustainability within
Jadestone was demonstrated by employees across Jadestone offices
during a ‘Plastic Free July’ month. There were initiatives developed
in all country offices and facilities to reduce waste (especially plastic).
This included:
•
Discontinued usage of plastic plates, cutlery, and single use bottles,
for any catered meetings or events;
Education and awareness events led by employees;
Improved recycling within offices; and
Jadestone keep-cups (travel cups) and canvas shopping bags were
provided to employees to reduce personal single use plastic and
coffee cups to landfill.
•
•
•
Perth office increased its volume of recycled waste
by >30% and reduced landfill by 50%.
These changes were embraced by employees with great success and
enthusiasm and have continued throughout the year.
Jadestone Energy 2019 Annual Report
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People and Diversity
While falling outside of Jadestone’s material mapping, People and
Diversity is recognised as an important metric to the business and
our stakeholders. Jadestone celebrates the diversity of its workforce.
It has a talent acquisition process, based on merit, but which also takes
into account diversity, to ensure the Company develops and maintains
an inclusive workforce that is representative of the places the business
operates in, and brings a range of knowledge, skills and perspectives to
the business. The business strategy identifies diversity and inclusion as
important ingredients to making the Company more agile and innovative.
In 2019 Jadestone hired 90 new employees, with over 17% of the new
hires being women. This continues to build on Jadestone’s commitment
to diversity, with women representing 32% of the total onshore workforce
(Figure S.2) and 25% of leadership positions at years end. Onshore gender
diversity at Jadestone (32%) is above the industry average. The reason
that ‘all’ gender diversity is lower (23%) reflects the nature of the oil
and gas industry, in particular the predominance of male employees in
offshore roles. This is a common challenge for most oil and gas operators
(Eniday 2019). Jadestone’s age diversity statistics also demonstrate that
there is recognition within the business that there is value in the diversity
of experience represented by different age cohorts (Figure S.3).
Jadestone embraces the diversity of its workforce with over twelve
nationalities making up the workforce and six across the leadership team.
Jadestone is committed to a workplace culture that promotes the
engagement of highly qualified, diverse and motivated individuals across
all levels of the organisation. Jadestone does not tolerate any form of
workplace harassment, including sexual harassment. This is reinforced
through the Code of Conduct and other HR policies. Jadestone’s
management works to achieve a flat organisational structure with
a short and effective chain of command. All of Jadestone’s employees
and managers are expected to listen, take feedback, be accessible and
to work in close cooperation with their colleagues.
Collective Bargaining Agreements
Currently over 80% of Jadestone offshore employees working at the
Stag and Montara facilities are under a collective bargaining agreement
(or Enterprise Bargaining Agreement) (Stag 25/31 (81%) and Montara
50/60 (83%)).
Jun Jun Tan, Aida Bakar and Simon Khor, subsurface team in Kuala Lumpur
Gender Diversity (Onshore), 2018–2019
66%
68%
34%
32%
80
70
60
50
40
30
20
10
0
2018 Average %
2019 Average %
% Gender Male
% Gender Female
Figure S.2 Onshore gender diversity at Jadestone
Age and Gender Diversity, 2018–2019
Age % >50
Age % 30-50
Age % <30
% Gender female
% Gender male
0
10
20
30
40
50
60
70
80
90
100
2019 Average %
2018 Average %
Figure S.3 Age diversity statistics for Jadestone Asia-Pacific
This continues to build on Jadestone’s commitment
to diversity, with women representing 32% of the
total onshore workforce (Figure S.2) and 25% of
leadership positions at the year's end. Onshore
gender diversity at Jadestone (32%) is above the
industry average.
G.1 | Business Ethics and Integrity
The Company shares a set of core values – Respect, Integrity, Safety,
Results-Orientated, Sustainability and Passion. Each employee
is expected to make a commitment to these, and to contribute to
protecting and enhancing the Company’s reputation. Jadestone’s core
values underpin the work the business does, and form the foundation
of the Code of Conduct.
The composition of the Board of Directors is an important aspect of
the business approach to corporate governance. The Board comprises
eight members, including a non-executive Chairman. Five of the
directors are independent non-executive Directors, who exercise
objective judgement in corporate affairs.
Code of Conduct
Jadestone is committed to upholding the highest standards of
responsible social and ethical behaviour. All of its employees, contractors
and consultants are expected to conduct their activities for Jadestone
fairly, ethically, and in a way that protects the Company’s reputation.
Furthermore, employees have an obligation to observe high standards
of integrity and fair dealing.
Jadestone is bound by a Code of Conduct Policy (“the Code”) that applies
to all employees and contractors. This Code provides the framework of
principles for conducting business, dealing with other employees, clients
and suppliers. The Code does not replace legislation and if any part of
it is in conflict, then legislation takes preference. The Code reflects the
Company commitment to a culture of honesty, integrity
and accountability.
All Jadestone onshore and offshore employees undertake an e-learning
programme on the Code of Conduct on the commencement of their
employment. The induction is monitored to ensure a 100% completion
rate. Employees are required to complete a refresher on the Code of
Conduct every 12 months including affirmation of their compliance
with the Code.
Những Ước Mơ Xanh (‘Green Dreams’) Organisation
Corruption
Jadestone is committed to conducting business in accordance with
all applicable laws and regulations and the highest ethical standards
in all jurisdictions in which it operates, including with respect to the
Corruption of Foreign Public Officials Act and the Criminal Code in
Canada and the Bribery Act in the United Kingdom and similar statutes
in other countries. To that end, employees, consultants and agents are
prohibited from offering, paying, promising, authorising or acquiescing
in the giving of any bribe, kick back or other illicit payment, inducement,
benefit or thing of value to any individual, directly or indirectly through
a third party for the purpose of (a) influencing an act or decision,
(b) inducing such individual to do or omit to do any act to affect or
influence any act or decision, or (c) securing any concession, contract
or other improper advantage, in each case, in order to obtain or retain
business or an advantage in the conduct of business in violation
of applicable laws of Canada and the United Kingdom and any other
anti-corruption laws of any jurisdiction in which the Company
does business.
The Company will not authorise, participate in, nor tolerate, any
business practice that does not comply with, or that violates, the
intent of the Policy.
INCIDENTS OF NON-COMPLIANCE
NUMBER
Number of legal actions for anti-competitive
behaviour, anti-trust, and monopoly practices and
their outcomes
Significant fines and non-monetary sanctions for
non-compliance with laws and regulations
Confirmed incidents of corruption
0
0
0
Extractive Sector Transparency Measures Act
In accordance with Canada’s Extractive Sector Transparency Measures
Act, Jadestone prepares a schedule of payments by payee and a schedule
of payments by project, to provide to the Minister of Natural Resources
Canada and to the Directors of the Company, detailing all cash payments
made to a government. The Company reports all payments made by it,
on its own behalf and in its role as operator, directly to any government
on a gross basis. These schedules are available on the Jadesotone
website and are updated annually.
Case Study – Australia
Through Jadestone’s corporate governance, cultural values and
management systems, the operational performance of Montara was
greatly improved in 2019. This was achieved through changes to safety
leadership, operational discipline, and quality assurance. Over a nine
month period, Jadestone was able to address the requirements of seven
enforcement notices issued by the Australian Regulator to the previous
Operator.
2020 ESG Strategic Corporate Goal
•
Excellence in business ethics and transparency
– Target Zero fines for any regulatory breaches for non-
compliance
– Maintain top Quartile Governance Standards
Jadestone Energy 2019 Annual Report
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Sustainability Report
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The GCT will be actively engaged with country level Incident
Management Teams (“IMT”) to address specific country or regional
events that directly affect business operations. For example, within
Jadestone Australia, an Incident Management Team has been
established and is maintained to ensure Jadestone operated assets
are fully supported in emergency management. Upon the activation
of the country level IMT, the GCT is engaged to determine business risks,
exposure and reputational impact.
In 2019, the GCT were engaged to support a mock annual oil spill
exercise for Jadestone’s Stag field operations in Australia managed
by the country level IMT. This allowed the country level IMT to
test its incident management processes and also fulfil regulatory
commitments. The GCT is engaged on a regular basis to exercise its
support to country level IMTs.
2020 ESG Strategic Corporate Goal
•
•
Economic contribution to county economies
Providing energy in the most efficient and sustainable way
– Deliver production at the improved unit cost as agreed in
performance targets
– Deliver capital investment programmes, adding reserves and
extending facility life as agreed in performance targets
References
ANZECC/ ARMCANZ (2000) Australian and New Zealand Environment and
Conservation Council (ANZECC) & Agriculture and Resource Management Council
of Australia and New Zealand (ARMCANZ), Guidelines for Fresh and Marine
Water Quality. Australian Government.
GSSB 2016. Global Reporting Initiative (2016) Reporting Principles and Standard
Disclosures. Global Sustainability Standards Board www.globalreporting.org/
standards.
IPIECA (2015) Oil and gas industry guidance on voluntary sustainability reporting.
UK TCFD (2019) Task Force on Climate-related Financial Disclosures Good Practice
Handbook.
Want to know more:
www.jadestone-energy.com
For further information about our sustainability performance visit our
sustainability pages and follow us on social media.
Feedback
We welcome your feedback.
Please visit us at www.jadestone-energy.com/contact for all our contact details,
or email us directly at contact@jadestone-energy.com
Operations team briefing in the Control Room on the Montara Asset
G.2 | Asset Integrity & Process Safety
G.3 | Critical Incident Risk Management
In our Australian operations, Asset Integrity and Process Safety
Management is described in the Jadestone Australia Business
Management system and is regulated in Australia by the Australian
National Offshore Petroleum Safety and Environmental Management
Authority (NOPSEMA).
Process safety incidents, including near misses, are reported and
performance is reviewed and managed on an ongoing basis. Some key
achievements for the Company in 2019 included:
•
• Upgrade of the Management of Change system;
•
Further development of Inhouse Technical Authorities (previously
heavily reliant on external third parties);
Development of a Process Safety Management Framework;
• No loss of hydrocarbon to environment events; and
•
Independent Competent Person review of asset integrity
management.
Process safety is assured through the delivery of asset integrity
maintenance activities. The results of these activities are regularly
reviewed by Jadestone’s discipline engineers and Technical Authorities
within the business. In addition, process safety performance is reviewed
by an Independent Competent Person on a rolling five-year review cycle.
Safety cases for each of the Company’s Australian assets describe
how Jadestone manages the specific process safety risks for each
asset. Compliance with these requirements are subject to Jadestone’s
assurance and audit processes.
Outside Australia, the same principles are / will be applied even where
Safety Cases are not required by local legislation.
2020 ESG Strategic Corporate Goal
•
Critical incident risk management
– Zero Loss of Primary Containment (Tier 1)
– Perform 1 full emergency exercise and minimum 2 desktop
exercises to test preparedness
Jack Up rig Ensco 107 operating over the Stag Platform
Risk management is a critical component of Jadestone’s business
process. The Jadestone risk management process is aligned with the
requirements of ISO 31000 and addresses risk management at three
levels: Business, Facility and Task. The three risk levels are directly
related and the risk assessments cascade such that Business level risks
set the context for Facility risk assessments, and Facility level risks set
the context for Task risk assessments.
•
•
•
Business level risks are assessed concurrently with the development
of the Annual Value Plan, which details the high-level activities over
a 12 month reporting period;
Facility level risks are assessed concurrently with the requirements
of key regulatory documents and standards, and are continually
reviewed against the context of planned activity over the detailed
plan time horizon (typically 90-120 days); and
Task level risks are assessed ahead of execution of each task,
as required by the Integrated Safe System of Work.
Although formal risk assessments are usually discrete exercises typically
conducted in workshops, the risk management process is a continuous
loop that requires constant dialogue with key stakeholders to ensure
a proactive approach. Continuous improvement is a requirement of the
Jadestone Business Management System and includes consideration
of the effectiveness of the system itself.
Group Crisis Team
Jadestone’s Group Crisis Team are responsible for the development
of strategies and plans to manage reputation, operability, licence to
operate, liabilities and potential financial loss. The Group Crisis Team
(“GCT”) also provide technical, operational and communication advice
to country-level incident management teams or to the wider Jadestone
organisation. The GCT have the overall responsibility to liaise with
each Country Manager and to develop and approve crisis management
strategies and plans.
The GCT also identify, monitor, prioritise and manage domestic and
group issues and developments that may have an impact upon the
business operations of Jadestone. The GCT follow the Jadestone Crisis
Management Plan (“CMP”) that sets out to define process/procedures
to respond effectively to a major crisis event and provide the framework
for the integrated management of a crisis or incident within Jadestone.
Specifically, this plan:
•
Describes the crisis management structure and organisation for
Jadestone;
•
•
•
Lists the roles and responsibilities for Jadestone and its members;
Details the call-out response process linking the GCT with the
country-level incident management response arrangements; and
Describes the framework for integrated crisis and incident
management.
G4-DMA – Emergency Preparedness
The Jadestone Crisis Management System has been established to
address and manage key crisis risks and events with the potential for
business disruption, reputation or financial loss. In the event of a Level
3 incident or crisis, the GCT is engaged to identify risk and manage crisis
action plans. A key component of the action plan is timely and effective
communication to key stakeholders, both internally and externally.
Jadestone Energy 2019 Annual Report
42
Sustainability Report
43
GRI Disclosure / Material Matters
The table below illustrates the data available for each of Jadestone's Material Matters (and GRI Disclosure).
Reporting boundaries include all operating assets and offices across Asia Pacific, as identified in the Annual Report.
Where there was not appropriate data available for the 2018 and 2019 calendar year for an asset or office location (largely due to new ownership
of an asset) this was omitted from the disclosure as shown below.
Jadestone is committed to increased data collection and transparency to support future reports.
L
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R
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S
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D
•
STATUS
Operating
JSE became
operator in
Aug 2019
Office
No operating
assets
No operating
assets
Office /
Regional HQ
Office
Australia
Stag
Australia
Montara
Australia
Perth
Indonesia
Vietnam
Block 46/07 PSC
Philippines
Block SC 56 and
Block SC 57
Singapore
Malaysia
Kuala Lumpur Technical
& Financial Centre
of Excellence
L
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&
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D
L
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K
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G
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•
•
•
•
•
•
•
•
•
•
•
•
•
•
HR data includes both employees and contractors
Data available and reported against GRI standard for 2019
• GRI disclosure relevant and will be reported in future years as asset becomes operational and data becomes available
STANDARD DISCLOSURE
GRI 102: General Disclosures
ORGANISATIONAL PROFILE
102-1
102-2
102-3
102-4
102-5
102-6
102-7
102-8
102-9
102-10
102-11
102-12
102-13
STRATEGY
102-14
ETHICS AND INTEGRITY
102-16
GOVERNANCE
102-18
STAKEHOLDER ENGAGEMENT
102-40
102-41
102-42
102-43
102-44
REPORTING PRACTICE
102-45
102-46
102-47
102-48
102-49
102-50
102-51
102-52
102-54
102-54
102-55
102-56
103-1
DESCRIPTION
REFERENCE
Name of organisation
Activities, brands, products and services
Location of headquarters
Location of operations
Ownership and legal form
Markets served
Scale of the organisation
Information on employees and other workers
Supply chain
Significant changes to the organisation and its supply chain
Precautionary principle or approach
External initiatives endorsed
Membership of associations
Statement from senior decision-maker
Values, principles, standards, and norms of behaviour
Page 25
Page 25
Page 25
Page 25
Page 25
Page 25
Page 25, https://www.jadestone-energy.com/
Page 35, 37, 38
Page 39
Page 39
Page 30
Page 28
Page 28
Page 24
Page 28, 39
Governance structure
Page 44-57, https://www.jadestone-energy.com/annualreport
List of stakeholder groups
Collective bargaining agreements
Identifying and selecting stakeholders
Approach to stakeholder engagement
Key topics and concerns raised
Entities included in the consolidated financial statements
Defining report content and topic boundaries
List of material topics
Restatement of information
Changes in reporting
Reporting period
Date of most recent report
Reporting cycle
Contact point for questions regarding the report
Claims of reporting in accordance with the GRI standards
GRI content index
External assurance
Explanation of the material topic and its boundary
Page 35
Page 38
Page 35
Page 35
Page 29
Page 13, https://www.jadestone-energy.com/annualreport
Page 28, 42
Page 29
N/A
N/A
Page 28
N/A
Page 42
Page 41
Page 28
Page 43
N/A
Page 42
Topic Specific Disclosures
ECONOMIC CONTRIBUTIONS
GRI 203:
203-1
BUSINESS ETHICS AND TRANSPARENCY
GRI 205: Anti-Corruption
205-3
GRI 206: Anti-Competitive Behaviour
206-1
LEADERSHIP AND GOVERNANCE
As per general disclosures
CRITICAL INCIDENT RISK MANAGEMENT
G4-DMA
CLIMATE CHANGE AND GHG EMISSIONS
GRI305: Emissions
305-1
305-2
305-7
ENVIRONMENTAL MANAGEMENT
GRI 306: Effluents and Waste
306-1
306-3
REGULATORY MANAGEMENT
GRI 307: Environmental Compliance
307-1
ASSET INTEGRITY AND PROCESS SAFETY
G4-DMA
OG13
OCCUPATIONAL HEALTH AND SAFETY
GRI 403: Occupational Health and Safety
403-1
403-2
403-3
403-4
403-5
403-9
403-10
WORKFORCE MANAGEMENT
GRI 404: Training and Education
404-1
DIVERSITY
GRI 405: Diversity and Equal Opportunity
405-1
Infrastructure investments and services supported
Confirmed incidents of corruption and actions taken
Legal actions for anti-competitive behaviour, anti-trust, and monopoly practices
Emergency preparedness
Direct (Scope 1) GHG emissions
Energy indirect (Scope 2) GHG emissions
NOx, SOx and other significant air emissions
Water discharge by quality and destination
Significant spills
Non-compliance with environmental laws and regulations
Asset integrity and process safety
Number of process safety events, by business activity
Occupational health and safety management system
Hazard identification, risk assessment, and incident investigation health and safety
Occupational health services
Worker participation, consultation, and communication on occupational health and safety
Worker training on occupational health and safety
Work-related injuries
Work-related ill health
Average hours of training per year per employee
Diversity of governance bodies and employees
Page 10
Page 39
Page 39
Page 40
Page 31
Page 31
Page 32
Page 32
Page 30
Page 30
Page 40
Page 40
Page 34
Page 34
Page 34
Page 34
Page 37
Page 34
Page 34
Page 37
Page 38
Jadestone Energy 2019 Annual Report
44
Jadestone is committed to
upholding the highest standards
of governance and responsible,
social and ethical behaviour.
45
C
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Jadestone Energy 2019 Annual Report
46
Corporate Governance
Board Profiles
47
Paul Blakeley OBE (Appointed as Executive Chairman June 7, 2016/President and
CEO June 15, 2017)
Executive Director, President and Chief Executive Officer
Committee memberships: HSE Committee, Disclosure Committee
Paul commenced at Jadestone in June 2016. Paul holds a BSc. from Bedford College,
University of London.
Paul has over 40 years’ energy experience, including over 20 years at Talisman Energy Inc (‘Talisman’).
As Executive Vice President Asia Pacific & Middle East at Talisman, Paul led the building of
Talisman’s portfolio in Asia Pacific to become the largest upstream independent in the region.
Paul has a long track record of acquiring production and further enhancing value through
follow-on development activity.
Directorships of other reporting issuers: None
Cedric Fontenit (Appointed June 7, 2016)
Non-Executive Director (Independent)
Committee memberships: Compensation and Nominating Committee
Cedric has extensive experience in advising on M&A, financing and structuring investments
gained from his 20-year career in investment banking and hedge fund industries. Cedric is
currently co-founder and managing partner of Amavia Capital, a private investment firm.
He was previously a senior member of the investment team at Tyrus Capital S.A.M. where he
had significant investment experience in the oil and gas and mining industries, among others.
Directorships of other reporting issuers: None
Robert Lambert (Appointed May 5, 2011)
Non-Executive Director, Deputy Chairman (Independent)
Committee memberships: HSE Committee, Audit Committee
Robert has 50 years’ experience in the international exploration and production business
and is formerly CEO and President of TSX-V listed Petra Petroleum Inc.
Robert is MBA-qualified and is a Chartered Geologist (GSL and EFG), having held numerous
operational and management positions (during his long career with Conoco Inc from
1978 to 2004) in the US, Europe, North Africa, West Africa, South East Asia and the
Caspian region.
More recently, Robert was a Non-Executive Director of AIM-listed Eland Oil and Gas plc
from 2012 to 2015 and was Chief Executive Officer of GB Petroleum Ltd. from 2005 to 2010.
Directorships of other reporting issuers: Hillcrest Petroleum Inc.
Iain McLaren (Appointed April 21, 2015)
Non-Executive Director (Independent)
Committee memberships: Compensation and Nominating Committee, Audit Committee
Iain has significant experience in the oil and gas sector and is currently Director, Chair of the Audit
Committee and a member of the Remuneration and Nominations committees for Wentworth
Resources Plc, as well as a director of Ecofin Global Utilities and Infrastructure Trust Plc.
Iain is a past Senior Independent Director for Cairn Energy Plc, past Chairman of BMO UK High
Income Trust Plc (formerly known as F&C UK High Income Trust Plc), past Director of Baillie
Gifford Shin Nippon Plc, Edinburgh Dragon Trust Plc, past President of the Institute of Chartered
Accountants of Scotland, and was a partner in KPMG for 28 years until 2008.
Directorships of other reporting issuers: Ecofin Global Utilities and Infrastructure Trust Plc; and
Wentworth Resources Plc.
Dennis McShane (Appointed December 10, 2017)
Non-Executive Director, Chairman
Committee memberships: Compensation and Nominating Committee
Dennis has over 35 years’ experience in finance, oil and gas, and mining sectors in the US,
Europe, Africa, and Australia.
Dennis has been involved in numerous transformational corporate transactions both as
director or advisor. He was the Executive Director of Strategy for Ophir Energy, plc having
previously served as a Senior Independent Director during its Initial Public Offering and
Director of Finance and Strategy leading the IPO of Ferrexpo, plc.
Dennis was also previously a Managing Director with JP Morgan Chase and Co. He currently
serves as a non-executive director of a private US based service sector company.
Directorships of other reporting issuers: None
David Neuhauser (Appointed June 7, 2016)
Non-Executive Director (Independent)
Committee memberships: None
David has extensive capital markets and M&A experience and is currently founder and
managing director of event-driven hedge fund Livermore Partners in Chicago. He has
invested in and advised global public companies for the past 21 years and has a strong
track record of enhancing intrinsic value through restructuring and strategic initiatives.
Directorships of other reporting issuers: BNK Petroleum Inc.
Lisa Stewart (Appointed December 1, 2019)
Non-Executive Director (Independent)
Committee memberships: HSE Committee, Audit Committee
Lisa has over 30 years of experience in the upstream oil and gas industry in engineering
and senior management positions. Lisa has served as Executive Chairman, President and
Chief Executive Officer of Sheridan Production Company LLC, Executive Vice President of
El Paso Corporation, President of El Paso E&P and Director of Cimarex Energy Co.
Prior to her time at El Paso, Lisa spent 20 years at Apache, including extensive experience
in Asia Pacific, leaving in January 2004 as Executive Vice President with responsibility for
reservoir engineering, business development, land, environmental, health & safety, and
corporate purchasing.
Directorships of other reporting issuers: Cimarex Energy Co.
Dan Young (Appointed as CFO January 18, 2017 / Director August 8, 2018)
Executive Director and Chief Financial Officer
Committee memberships: Disclosure Committee
Dan commenced at Jadestone in 2017. Dan holds a BCom(Hons) from the University of Western
Australia, and an MBA(Hons) from the University of Chicago Booth School of Business.
Dan is a Chartered Accountant and a CFA charterholder. Dan has more than 24 years’
experience in senior oil and gas and natural resources investment banking, advisory
and consulting roles.
Prior to joining Jadestone, Dan was Senior Vice President, and Head of APAC Consulting
for Wood Mackenzie. Dan also worked for 13 years in JP Morgan’s global energy investment
banking coverage and mergers and acquisitions group.
Directorships of other reporting issuers: None
Jadestone Energy 2019 Annual Report 48
Corporate Governance
Management Profiles
49
Paul Blakeley OBE
Executive Director, President and Chief Executive Officer
Paul has over 40 years’ energy experience, including over 20 years at Talisman Energy Inc
(‘Talisman’). As Executive Vice President Asia Pacific & Middle East at Talisman, Paul led the
building of Talisman’s portfolio in Asia Pacific to become the largest upstream independent
in the region.
Paul has a long track record of acquiring production and further enhancing value through
follow-on development activity.
James Borras
General Manager, Vietnam
James has worked in oil and gas for 24 years within the drilling discipline in various technical,
operational, and leadership roles. Prior to Jadestone, James worked for Talisman Energy and
BP. For the past 10 years, James has been working as Well Engineering Team Leader on field
development projects offshore Vietnam. He has a proven track record in successful project
delivery, solid HSE leadership, and excellent interface management within multi-discipline
project teams.
Mark Craig
Group Operations Manager
Mark has worked in the oil and gas industry for 26 years in technical and management
roles. Mark spent the last 12 years working for Talisman Energy in positions including
Senior Operations and Start Up Engineer, Field Manager, Production Manager and General
Operations Manager. Mark has a strong technical understanding of petroleum engineering,
oil, gas and cryogenic production facilities, economics and operations.
Lucy Dean
Group HR Manager
Lucy has over 25 years’ HR experience working in both the Energy Sector and top tier
Financial Institutions. Her experience includes business partnering at an international level
and coordinating HR activities across multiple geographies. Lucy has spent the last 10 years
in Singapore working closely with Asian businesses and prior to that worked in Hong Kong
and London.
Nguyen Thanh Ha
Group Commercial Manager
Ha has spent over 15 years working in the oil and gas industry with both BP and Talisman
Energy. Ha has significant experience in M&A, operational commercial, project evaluation,
strategy and portfolio management. Ha’s last seven years were with Talisman Energy
where she undertook a regional Business Development and Commercial role for the
Company’s Asia Pacific portfolio.
Owen Hobbs
Country Manager, Australia
Owen has over 30 years of experience in the upstream oil and gas industry, including leading
some of Australia and New Zealand’s largest onshore and offshore operations with roles in
Boral Energy, Santos, and Origin Energy. He has managed conventional and unconventional
assets, provided leadership to cross- functional teams, worked closely with regulators, and
been involved in M&A and divestment activities. Prior to Owen’s career in the Oil and Gas
industry he spent five years with the Royal New Zealand Navy as an Executive Branch officer.
Henning Hoeyland
Group Subsurface Manager
Henning has 17 years’ experience with Schlumberger and Talisman Energy Inc. in the North
Sea and Southeast Asia. His strengths include reservoir engineering with special focus on
producing / mature fields.
Michael Horn
Executive Vice President, Corporate and Business Development
Michael has over 26 years’ experience in the oil and gas industry, largely in Asia Pacific, with
assignments in Vietnam, Malaysia and Singapore, the last 12 of which were with Talisman
Energy Inc. He has identified and closed a number of key transactions which were a vital part
of Talisman Energy Inc’s success in Asia, and has a strong reputation as a dealmaker within
Asia amongst industry stakeholders and the investment community.
David Lamb
Country Manager, Indonesia
David has over 36 years’ oil and gas industry experience, mostly in Asia. He has a proven
track record of operational excellence, particularly with HSE matters, and is also fluent in
Bahasa Indonesian. David was previously the country manager of Talisman Energy Inc.
Indonesia where he created and executed Talisman Energy Inc.’s “South Sumatera Strategy” –
successfully building a leading position with highly prospective acreage in partnership with
the national oil company Pertamina.
Neil Prendergast
General Counsel
Neil has significant experience advising on operations, joint venture projects, acquisitions
and divestitures within the energy industry and across various jurisdictions including South
East Asia, the Middle East, North Africa and North America. Neil previously spent six years
as a member of Talisman Energy Inc. Indonesia’s senior management team, setting strategy,
mitigating risk and ensuring safe and profitable production.
Dan Young
Executive Director and Chief Financial Officer
Dan is a Chartered Accountant and a CFA charterholder. Dan has more than 24 years’
experience in senior oil and gas and natural resources investment banking, advisory
and consulting roles.
Prior to joining Jadestone, Dan was Senior Vice President, and Head of APAC Consulting
for Wood Mackenzie. Dan also worked for 13 years in JP Morgan’s global energy investment
banking coverage and mergers and acquisitions group.
Jadestone Energy 2019 Annual Report 50
Corporate Governance
Governance Report
Introduction
Jadestone, as a British Columbia incorporated company, follows Canadian
corporate governance standards. Jadestone believes that an effective corporate
governance framework adds value to its business and enhances stakeholder
confidence in the Company.
Jadestone is committed to upholding the highest standards of governance and
responsible, social and ethical behaviour. Jadestone has implemented a Code of
Conduct Policy (“the Code”) that applies to all employees and contractors and
which provides a framework of principles for conducting business, dealing with
other employees, clients and suppliers, and reflects the Company’s commitment
to a culture of honesty, integrity and accountability.
A copy of the Company’s key governance documents, including the Company’s
Articles of Incorporation, the Code and related policies, are available on the
Company’s website at www.jadestone-energy.com
Preparing for Montara crude oil offload
51
Role of the Board
The Board has adopted a charter which establishes the relationship
between the Board and management and describes their respective
functions and responsibilities.
The Board is responsible for the overall performance of the Company
and accordingly takes accountability for monitoring the Company’s
business and affairs, setting its strategic direction, establishing policies,
and overseeing the Company’s financial position. The Company’s
management team, led by the CEO, is responsible for the day-to-day
management of the operations of the Company.
Board Composition
As at the date of this Report, the Board consists of two executive
directors (the CEO and CFO), and six non-executive directors. The names
of the directors, the year of each directors’ appointment and their status
as independent, non-executive or executive are set out in the Board of
Directors section at pages 46 and 47.
Independence
All directors are expected to bring independent views and judgment
to the Board’s deliberations. The Board has reviewed the position and
associations of all directors in office at the date of this Report and
considers that a majority of the directors are independent non-executive
directors in accordance with Canadian corporate governance standards.
Of the current members of the Board, Iain McLaren, Robert Lambert,
David Neuhauser, Cedric Fontenit and Lisa Stewart are considered
“independent” within the meaning of NI 52-110 and A. Paul Blakeley,
Daniel Young and Dennis McShane are considered not to be
independent. Mr. Blakeley is not considered to be independent, due
to his role as the President and CEO of the Company, Mr. Young is not
considered to be independent, due to his role as the CFO of the Company
and Mr. McShane is not considered to be independent, due to his role as
the Chairman of the Company.
Chairman’s role
The Chairman of Jadestone sets the tone for the Company and is
responsible for:
(a)
(b) setting the agenda for Board meetings in conjunction with the CEO
leadership of the Board;
and Company Secretary;
(c) overseeing the provision by management to directors of accurate,
timely and clear information;
(d) efficient organisation and conduct of the Board’s function,
including by:
(i)
(ii) promoting constructive and respectful relations between
facilitating effective contribution of all directors;
directors and between the Board and senior management; and
(iii) managing the Board to ensure that sufficient time is allowed
for discussion;
(e) chairing meetings of members; and
(f) speaking for the Board between its meetings including engaging
with the CEO and reporting to the Board on decisions and actions
taken between meetings of the Board;
CEO’s role
The CEO, as the leader of the executive management team, is
responsible for:
(g) managing the day to day affairs of the Company;
(h)
leading the Company’s performance and maintaining a dialogue
with the Chairman on key strategic issues;
(i) monitoring the performance of the Company’s executives;
(j)
implementing the Board’s decisions, policies and strategies and
reporting to the Board on the affairs of Jadestone or as directed by
the Board;
(k) developing, implementing and monitoring the strategic, business
and financial plans for the Company; and
(l) ensuring effective communication with shareholders and key
stakeholders.
Non Executive Directors’ role
The non-executive directors bring independent judgement to the Board’s
deliberative processes and constructively challenge the performance
of the Company’s executive management team in the delivery of the
Company’s agreed objectives and targets.
Company Secretary’s role
The Company Secretary is responsible for ensuring that Board
procedures are complied with and that governance matters are
addressed by the Company. All directors have direct access to the
Company Secretary.
Audit Committee
The Audit Committee’s purpose is to ensure that the Company adopts
and follows a policy of proper and timely disclosure of material financial
information and to review the key risks affecting the financial position
of the Company. The Audit Committee’s responsibilities include the
following:
(a) reviewing and reporting to the Board on the Financial Statements
of the Company, and reviewing significant financial reporting
judgments before they are publicly disclosed;
(b) reviewing the Company’s internal financial control system;
(c) monitoring and reviewing the external audit function including
matters concerning appointment and remuneration, independence
and non-audit services;
(d) reviewing and assessing the corporate risk management framework
for identifying, monitoring and managing significant business risks
that could impact financial reporting; and
(e) overseeing the work undertaken by the Company’s independent
third party reserves evaluator.
As at the date of this Report, and in accordance with Canadian corporate
governance standards, the Audit Committee is constituted entirely of
independent non-executive directors, namely, Iain McLaren (Chairman),
Robert Lambert and Lisa Stewart.
Key matters considered by the Audit Committee in 2019
During the Reporting Period, the Committee’s principal focus areas were:
• Quarterly Financial Statements;
•
Full Year Financial Statements;
• Management’s Discussion and Analysis in respect of all Financial
Statements;
Year-end reserves report;
•
• Auditor independence;
•
•
Internal controls and risk management; and
Going concern assessment.
Jadestone Energy 2019 Annual Report
52
Corporate Governance
53
Disclosure Committee
The purpose of the Disclosure Committee is to assist the Board in:
(a) fulfilling its responsibilities in respect of the Company’s disclosure
obligations arising under the Market Abuse Regulation (EU) No.
596/2014, the AIM Rules for Companies, the Disclosure Guidance
and Transparency Rules sourcebook published by the FCA, Canadian
corporate governance standards, including those contained in
National Instrument 51-102, and other applicable law; and
(b) establishing and maintaining adequate procedures, systems
and controls to enable the Group to comply with its disclosure
obligations.
As at the date of this Report, the Disclosure Committee is constituted by
Paul Blakeley and Dan Young.
Key matters considered by the Disclosure Committee in 2019
During the Reporting Period the Committee considered:
•
The Company’s processes for periodic and continuous disclosure;
and
The Company’s Insider Trading Policy and other related policies and
procedures.
•
Gordon Lattimer, a production technician on Montara asset
Compensation and Nomination Committee
The Compensation and Nominating Committee’s purpose is to ensure
that the compensation of directors, employees and officers is set
appropriately based on industry data with the goal of attracting,
retaining and motivating key management personnel to ensure the long-
term success of the Company.
The Compensation and Nominating Committee responsibilities include
the following:
(a) annually reviewing and making recommendations with respect
to executive remuneration including short term and long term
incentives;
identifying individuals qualified to become new Board members;
and
(b)
(c) annually assessing the contribution and effectiveness of each
director, as well as the competencies and characteristics each
director is expected to bring to the Board.
As at the date of this Report, the Compensation and Nominating
Committee is constituted entirely of independent non-executive
directors, namely, Cedric Fontenit (Chairman), Iain McLaren and
Dennis McShane.
Key matters considered by the Compensation and Nomination
Committee in 2019
During the Reporting Period the Committee’s principal focus areas were:
•
Executive remuneration and the award of Short Term Incentives
(“STIs”) and Long Term Incentives (“LTIs”);
• NED remuneration;
•
•
•
The structure of the Company’s LTI plans;
Board composition and succession planning; and
The appointment of Lisa Stewart as an independent non-executive
director.
HSE Committee
The HSE Committee’s purpose is to support the Board’s oversight
of health, safety, community and environmental related matters.
The HSE Committee’s responsibilities include the following:
(a) formulating the Group’s policies and systems for identifying and
managing health, safety, social/communities and environmental
risks within the Group’s operations;
(b) evaluating the effectiveness of the Group’s policies and systems for
identifying and managing health, safety, social/communities and
environmental risks within the Group’s operations;
(c) assessing the policies and systems within the Group for ensuring
compliance with health, safety, social/communities and
environmental regulatory requirements; and
(d) assessing the performance of the Group with regard to the impact
of health, safety, environmental and social/community relations
decisions and actions upon employees, communities and other
third parties.
As at the date of this Report, the HSE Committee is constituted by
a majority of independent non-executive directors. Robert Lambert and
Lisa Stewart are independent and Paul Blakeley is non-independent.
Key matters considered by the HSE Committee in 2019
During the Reporting Period the Committee reviewed:
•
the Company’s safety management system; and
•
the Company’s safety performance against industry benchmarks.
Board and Committee Attendance
The table below shows a summary of directors’ attendance at Board and committee meetings for the period from January 1, 2019 to December 31, 2019.
NAME AND POSITIONS HELD
IN THE COMPANY
A. Paul Blakeley
Director, President and
Chief Executive Officer
Daniel Young
Director and Chief Financial Officer
Dennis McShane
Director and Chairman
Iain McLaren
Director
Eric Schwitzer (1)
Director
Robert Lambert
Director and Deputy Chairman
David Neuhauser
Director
Cedric Fontenit
Director
Lisa Stewart (2)
Director
BOARD
5 of 5
5 of 5
5 of 5
5 of 5
4 of 4
5 of 5
5 of 5
5 of 5
1 of 1
AUDIT COMMITTEE
COMPENSATION
AND NOMINATING
COMMITTEE
HEALTH, SAFETY, SECURITY
& ENVIRONMENT
COMMITTEE
DISCLOSURE COMMITTEE
N/A
N/A
N/A
4 of 4
4 of 4
4 of 4
N/A
N/A
N/A
N/A
N/A
3 of 4
4 of 4
4 of 4
N/A
N/A
4 of 4
N/A
2 of 2
N/A
N/A
N/A
N/A
2 of 2
N/A
N/A
N/A
1 of 1
1 of 1
N/A
N/A
N/A
N/A
N/A
N/A
N/A
Notes:
(1) Mr. Schwitzer stepped down as a director of the Company on November 30, 2019. Mr. Schwitzer attended all Board meetings, Audit Committee meetings and Compensation and
Nominating Committee meetings held prior to his resignation.
(2) Ms. Stewart was appointed as a director of the Company on December 1, 2019 and has attended the one Board meeting since her appointment.
Continuing Education
The Board’s practice is to only recruit persons with extensive experience
in the oil and gas industry or with significant experience in either
managing or advising publicly listed companies. Prospective new
Board members are provided detailed background information on the
Company’s affairs and plans, prior to their appointment as a director.
Board members are encouraged to communicate with management,
auditors and technical consultants to keep themselves abreast of
industry trends and developments and changes in legislation.
Independent Advice
Directors, as a condition of their engagement, have access to
independent advice as required, as well as direct access to the Company
Secretary.
Directors’ and Officers’ Liability Insurance and
Indemnification
The Company has in place deeds of indemnity with all of its directors
and officers under which the Company agrees to indemnify its directors
and officers against all costs, charges, losses and liabilities incurred by
them in the lawful execution of their duties. The Company also has a
Directors’ and Officers’ liability insurance policy.
Ethical Business Conduct
The Board encourages and promotes a culture of ethical business
conduct through communication and supervision as part of its overall
stewardship responsibility. In addition to the Company’s Code of
Conduct, the Board has adopted other policies including an Insider
Trading Policy and a Whistleblower Policy in order to promote a culture
of ethical conduct.
Shareholder Engagement
Shareholders are invited to the Annual General Meeting where Board
members are available to take questions. Beyond the Annual General
Meeting, the Chair, Chief Executive Officer and Chief Financial Officer
and where appropriate, other members of the senior management team
meet regularly with investors (including institutional shareholders)
and analysts through investment conferences, roadshows, webcasts
and conference calls, website and social media engagement, direct
correspondence and investor presentations to actively build the
relationship, provide updates on the Company’s business and to
obtain feedback regarding the market’s expectations for the Company.
Feedback is discussed at every Board meeting.
Number of Directors and Election of Directors
At the Annual General and Special Meeting held on May 15, 2019 the
Company’s Shareholders approved a resolution fixing the number of
directors at eight. The Board intends to recommend to Shareholders
at the upcoming AGM scheduled for June 18, 2020 that this number
of directors be retained.
The Board considers that given the size and scale of the Company’s
operations and the blend of skills and experience of the existing
directors, this is an appropriate number of directors in the Company’s
current context. The Board reviews its composition annually as an
assurance measure to ensure that it is an appropriate size and has
an appropriate mix of skills and experience.
The directors of the Company are elected annually and hold office until
the next annual general meeting of the Shareholders, unless they retire
prior to their re-election. When a casual vacancy arises in the context
of a retirement, the Board is entitled to appoint a director who remains
in office until the next annual general meeting.
Jadestone Energy 2019 Annual Report 54
Corporate Governance
Montara Venture FPSO
Remuneration report
Director and Named Executive Officer Compensation
The following information is presented in accordance with National
Instrument Form 51-102F6V – Statement of Executive Compensation –
Venture Issuers. For the purposes of this Report:
“CEO” of the Company means each individual who acted as Chief
Executive Officer of the Company, or acted in a similar capacity, for any
part of the most recently completed financial year.
“CFO” of the Company means each individual who acted as Chief
Financial Officer of the Company, or acted in a similar capacity, for any
part of the most recently completed financial year.
“NEO” or “named executive officer” means each of the following
individuals:
(a) a CEO;
(b) a CFO;
(c) each of the three most highly compensated executive officers
of the Company, including any of its subsidiaries, or the three
most highly compensated individuals acting in a similar
capacity, other than the CEO and CFO, at the end of the most
recently completed financial year whose total compensation
was, individually, more than $150,000, as determined in
accordance with subsection 1.3(6) of Form 51-102F6 – Statement
of Executive Compensation, for that financial year; and
(d) each individual who would be a NEO under paragraph (c) but for
the fact that the individual was neither an executive officer
of the Company or its subsidiaries, nor acting in a similar
capacity, at the end of that financial year.
Effective November 30, 2019, Mr. Schwitzer stepped down as a director
of the Company. Lisa Stewart was appointed as a director of the
Company effective December 1, 2019. As at December 31, 2019, the
Company had three NEOs, being A. Paul Blakeley, the President and CEO,
Daniel Young, the CFO and Michael Horn, the Executive Vice-President of
Corporate and Business Development and the former Interim CEO, and
eight directors, being A. Paul Blakeley, Daniel Young, Dennis McShane,
Iain McLaren, Robert Lambert, David Neuhauser, Cedric Fontenit and
Lisa Stewart.
Director and NEO Compensation, Excluding
Compensation Securities
The following table sets out all compensation paid, payable, awarded,
granted, given, or otherwise provided, directly or indirectly, by the
Company and its subsidiaries, excluding compensation securities,
to each NEO and director, in any capacity, for the year ended
December 31, 2019.
Table of Compensation Excluding Compensation Securities
55
SALARY, CONSULTING
FEE, RETAINER OR
COMMISSION
(US$)
BONUS
(US$)
COMMITTEE OR
MEETING FEES
(US$)
VALUE OF
PERQUISITES (1)
(US$)
VALUE OF
ALL OTHER
COMPENSATION
(US$)
TOTAL
COMPENSATION
(US$)
NAME AND POSITION
A. Paul Blakeley
Director, President and CEO
Daniel Young
Director and CFO
Michael Horn
Executive Vice President,
Corporate and Business
Development
Dennis McShane
Director and Chairman
Iain McLaren
Director
Eric Schwitzer (2)
Director
Robert Lambert
Director and Deputy Chairman
David Neuhauser
Director
Cedric Fontenit
Director
Lisa Stewart (3)
Director
Notes:
YEAR
2019
2019
500,000
585,000
320,000
198,400
2019
320,000
217,600
2019
2019
2019
2019
2019
2019
2019
125,000
56,250
56,250
56,250
56,250
56,250
5,000
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
5,000
25,000
10,000
12,500
Nil
10,000
833
566,926
363,538
396,196
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
1,651,926
881,938
933,796
130,000
81,250
1,369
67,619
Nil
Nil
Nil
Nil
68,750
56,250
66,250
5,833
(1)
Includes cost of living differential, foreign service allowance, international talent allowance and pension allowance, as well as education, housing, utilities and wellness subsidies (benefits
in kind).
(2) Mr. Schwitzer stepped down as a director of the Company on November 30, 2019.
(3) Ms. Stewart was appointed as a director of the Company on December 1, 2019.
Jadestone Energy 2019 Annual Report
56
Corporate Governance
57
Compensation Securities
NAME AND POSITION
A. Paul Blakeley (1)
Director, President and CEO
Former Executive Chairman
Daniel Young (3)
Director and CFO
Michael Horn (4)
Executive Vice President,
Corporate and Business Development
Former Interim CEO
Dennis McShane (5)
Director and Chairman
Iain McLaren (6)
Director
Eric Schwitzer (7)
Director
TYPE OF
COMPENSATION
SECURITY
Stock Options
Stock Options
Stock Options
Stock Options
Stock Options
Stock Options
Robert Lambert (8)
Director and Deputy Chairman
Stock Options
David Neuhauser (9)
Director
Cedric Fontenit (10)
Director
Lisa Stewart (11)
Director
Stock Options
Stock Options
Stock Options
NUMBER OF
COMPENSATION SECURITIES,
NUMBER OF UNDERLYING
SECURITIES, AND
PERCENTAGE OF CLASS
1,200,000 Options
representing 1,200,000
underlying Common Shares
0.26%(2)
750,000 Options
representing 750,000
underlying Common Shares
0.16%(2)
750,000 Options
representing 750,000
underlying Common Shares
0.16%(2)
100,000 Options
representing 100,000
underlying Common Shares
0.02%(2)
75,000 Options
representing 75,000
underlying Common Shares
0.02%(2)
75,000 Options
representing 75,000
underlying Common Shares
0.02%(2)
75,000 Options
representing 75,000
underlying Common Shares
0.02%(2)
75,000 Options
representing 75,000
underlying Common Shares
0.02%(2)
75,000 Options
representing 75,000
underlying Common Shares
0.02%(2)
75,000 Options
representing 75,000
underlying Common Shares
0.02%(2)
DATE OF
ISSUE OR
GRANT
ISSUE,
CONVERSION
OR EXERCISE
PRICE
(C$)
CLOSING PRICE OF
SECURITY OR
UNDERLYING SECURITY
AT YEAR END
(C$)
EXPIRY
DATE
March 29, 2019
C$0.85
C$1.59
March 28, 2029
March 29, 2019
C$0.85
C$1.59
March 28, 2029
March 29, 2019
C$0.85
C$1.59
March 28, 2029
March 29, 2019
C$0.85
C$1.59
March 28, 2029
March 29, 2019
C$0.85
C$1.59
March 28, 2029
March 29, 2019
C$0.85
C$1.59
November 29, 2020
March 29, 2019
C$0.85
C$1.59
March 28, 2029
March 29, 2019
C$0.85
C$1.59
March 28, 2029
March 29, 2019
C$0.85
C$1.59
March 28, 2029
December 3, 2019
C$1.17
C$1.59
December 2, 2029
Notes:
(1) As of the last day of the most recently completed financial year end, Mr. Blakeley held a total of 4,700,000 options which were granted on June 7, 2016, March 28, 2017, March 29, 2018, July 29, 2018
and March 29, 2019. Of these options, 500,000 granted on June 7, 2016 vest (or have vested) in four instalments with 125,000 vesting on the date of grant, 125,000 vesting on June 7, 2017, 125,000
vesting on June 7, 2018 and the remainder vesting on June 7, 2019. All other options vest (or have vested) over a period of three years in equal installments from the date of the grant.
(2) Represents the percentage of the issued and outstanding Common Shares of the Company as at December 31, 2019.
(3) As of the last day of the most recently completed financial year end, Mr. Young held a total of 1,950,000 options which were granted on March 28, 2017, March 29, 2018, July 29, 2018 and March 29,
2019. All options vest (or have vested) over a period of three years in equal installments from the date of the grant.
(4) As of the last day of the most recently completed financial year end, Mr. Horn held a total of 2,250,000 options which were granted on June 7, 2016, March 28, 2017, March 29, 2018, July 29, 2018 and
March 29, 2019. Of these options, 250,000 granted on June 7, 2016 vest (or have vested) in four instalments with 62,500 vesting on the date of grant, 62,500 vesting on June 7, 2017, 62,500 vesting
on June 7, 2018 and the remainder vesting on June 7, 2019. All other options vest (or have vested) over a period of three years in equal installments from the date of the grant.
(5) As of the last day of the most recently completed financial year end, Mr. McShane held a total of 345,000 options which were granted on December 10, 2017, March 29, 2018 and March 29, 2019.
All options vest (or have vested) over a period of three years in equal installments from the date of the grant.
(6) As of the last day of the most recently completed financial year end, Mr. McLaren held a total of 475,000 options which were granted on April 21, 2015, March 28, 2017, March 29, 2018 and
March 29, 2019. Of these options, 250,000 granted on April 21, 2015 were not subject to vesting provision and they were immediately exercisable for a period of ten years from the date of grant.
All other options vest (or have vested) over a period of three years in equal installments from the date of the grant.
(7) As of the last day of the most recently completed financial year end, Mr. Schwitzer held a total of 425,000 options which were granted on April 21, 2015, March 28, 2017, March 29, 2018 and March
29, 2019. Mr. Schwitzer stepped down as director of the Company on November 30, 2019 and therefore all options have vested and they were immediately exercisable until November 29, 2020.
(8) As of the last day of the most recently completed financial year end, Mr. Lambert held a total of 375,000 options which were granted on April 21, 2015, March 28, 2017, March 29, 2018 and March 29,
2019. Of these options, 150,000 granted on April 21, 2015 were not subject to vesting provision and they were immediately exercisable for a period of ten years from the date of grant.
All other options vest (or have vested) over a period of three years in equal installments from the date of the grant.
(9) As of the last day of the most recently completed financial year end, Mr. Neuhauser held a total of 225,000 options which were granted on March 28, 2017, March 29, 2018 and March 29, 2019.
All options vest (or have vested) over a period of three years in equal installments from the date of the grant.
(10) On March 28, 2017 Mr. Fontenit was granted 100,000. Mr. Fontenit waived his right to these 100,000 options on April 27, 2017, and the 100,000 options were subsequently cancelled. As of the last
day of the most recently completed financial year end, Mr. Fontenit held a total of 75,000 options which were granted on March 29, 2019. All options vest (or have vested) over a period of three
years in equal installments from the date of the grant.
(11) As of the last day of the most recently completed financial year end, Ms. Stewart held a total of 75,000 options which were granted on December 3, 2019. Such options shall vest upon the third
anniversary of the grant date, i.e. on December 3, 2022.
Exercise of Compensation Securities by NEOs
and Directors
No director or NEO exercised any compensation securities, being solely
comprised of stock options, during the Company’s most recently
completed financial year ended December 31, 2019.
Long-Term Incentive Plans
In order to attract and retain qualified personnel, provide incentives and
rewards to directors, employees and consultants of the Company or
its subsidiaries, and to align the interests of such directors, employees
and consultants with those of the Shareholders, the directors of the
Company have adopted the Stock Option Plan (“Stock Option Plan”),
the Performance Share Plan 2019 (“Performance Share Plan”) and
the Restricted Share Plan 2019 (“Restricted Share Plan”) (the Stock
Option Plan, the Performance Share Plan and the Restricted Share Plan
together, the “LTI Plans”), to allow the Company to grant long-term
incentive, including stock options, performance shares and restricted
shares (together, the “LTI”) to directors, officers, employees and
consultants, as additional compensation, and as an opportunity to
participate in the growth of the Company. The granting of such LTI is
intended to align the interests of such persons with that of the Company
and is common industry practice.
The directors of the Company have adopted “rolling” LTI Plans that allow
the Company to issue up to a maximum of 10% of the Company’s issued
and outstanding Common Shares at any given time. In accordance with
TSX Venture Exchange (the “Exchange”) policies, a plan with a rolling
10% maximum must be confirmed by Shareholders of the Company
at each annual general meeting. The LTI Plans were last approved and
confirmed by the Shareholders of the Company at the annual general
meeting on May 15, 2019.
Starting in 2020, the Company is implementing a three year transition
away from Stock Option Plan awards in favour of Performance Share
Plan awards. The 2020 LTI is expected to be comprised of 75% Stock
Option Plan awards and 25% Performance Share Plan awards.
As specified in the Performance Share Plan, annual performance targets
for the Company are established by the Nominating and Compensation
Committee and are set out in an annual performance contract for the
CEO. The 2020 performance contract is based on a collection of key
metrics intended to represent comprehensive success of the business,
with a weighting of 40% toward achieving operational targets, 20%
toward delivering continuous improvement in ESG performance, 20%
toward delivering per share accretive growth and 20% toward creating
sustainable shareholder value.
NAME AND PRINCIPAL POSITION
TERMINATION AND TERMINATION OR RESIGNATION WITHIN 12 MONTHS OF CHANGE OF CONTROL.
A. Paul Blakeley (2)
Director, President and
Chief Executive Officer
Michael Horn
Executive Vice President,
Corporate and Business Development
Daniel Young (3)
Director and Chief Financial Officer
Twenty-four (24) times the Officer’s monthly salary; two (2) times the Annual Performance Pay Target (the Annual Performance Pay Target Amount in
respect of the year preceding the date of notice, if the date of notice precedes the date upon which such performance pay amount would have been paid
and, a pro-rata portion of the Annual Performance Pay Target Amount in respect of that portion of the current year to the date of notice) and an amount
equivalent to US$500,000 as compensation for the loss of expatriate benefits and all other benefits over the period of twenty-four (24) months
Legal and Taxation counselling services to a maximum of US$30,000
Twelve (12) times the Officer’s monthly salary; two (2) times the Annual Performance Pay Target (the Annual Performance Pay Target Amount in respect
of the year preceding the date of notice, if the date of notice precedes the date upon which such performance pay amount would have been paid and,
a pro-rata portion of the Annual Performance Pay Target Amount in respect of that portion of the current year to the date of notice) and an amount
equivalent to US$100,000 as compensation for the loss of expatriate benefits and all other benefits over the period of twenty-four (24) months
Legal and Taxation counselling services to a maximum of US$20,000
Twelve (12) times the Officer’s monthly salary; two (2) times the Annual Performance Pay Target (the Annual Performance Pay Target Amount in respect
of the year preceding the date of notice, if the date of notice precedes the date upon which such performance pay amount would have been paid and,
a pro-rata portion of the Annual Performance Pay Target Amount in respect of that portion of the current year to the date of notice) and an amount
equivalent to US$100,000 as compensation for the loss of expatriate benefits and all other benefits over the period of twenty-four (24) months
Legal and Taxation counselling services to a maximum of US$20,000
Notes:
(1) The Company may terminate a NEO’s employment and pay the NEO a pro-rated amount equal to the NEO’s basic salary in lieu of the NEO’s notice period or any unexpired portion of it. Notice or
salary in lieu of notice will not apply where the NEO is terminated for misconduct.
(2) The NEOs are entitled to exercise any vested share options as at the Termination or End Date for a period of 90 days following that date. Any unvested options will automatically lapse on the
Termination or End Date.
(3) The NEOs are entitled to their full bonus in respect of the year in which the Change of Control occurs.
(4) The NEOs are entitled to a bonus in the year they cease to be employed by the Company, calculated on a pro-rated basis for that year for the period commencing at the beginning of the year and
ending on their End Date.
Jadestone Energy 2019 Annual Report 58
59
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Montara platform
Jadestone Energy 2019 Annual Report
60
Consolidated Financial Statements
for the years ended December 31, 2019 and December 31, 2018
Management’s Report
The accompanying consolidated financial statements are the
responsibility of management. The consolidated financial
statements were prepared by management, in accordance with
International Financial Reporting Standards (“IFRS”), outlined
in the notes to the consolidated financial statements.
Management maintains appropriate systems of internal controls. Policies and procedures are designed to give reasonable assurance
that transactions are appropriately authorised, assets are safeguarded, and financial records properly maintained, to provide reliable
information for the presentation of consolidated financial statements.
Deloitte & Touche LLP, an independent firm of chartered accountants, was appointed by the shareholders to audit the consolidated
financial statements, and to provide an independent professional opinion.
The Audit Committee reviewed the consolidated financial statements with management. The Board of Directors has approved the
consolidated financial statements, on the recommendation of the Audit Committee.
These financial statements were approved by the directors and authorised for issue on April 23, 2020.
A. Paul Blakeley
Director
April 23, 2020
Daniel Young
Director
April 23, 2020
61
Independent Auditor’s Report
To The Shareholders Of Jadestone Energy Inc.
Opinion
We have audited the accompanying consolidated financial statements
of Jadestone Energy Inc. and its subsidiaries (the “Group”), which
comprise the consolidated statements of financial position as at
December 31, 2019 and 2018, and the consolidated statements of profit
or loss and other comprehensive income, consolidated statement of
changes in equity and consolidated statements of cash flows for the
years ended December 31, 2019 and 2018, and notes to the consolidated
financial statements, including a summary of significant accounting
policies.
In our opinion, the consolidated financial statements present fairly,
in all material respects, the financial positions of Jadestone Energy
Inc. as at December 31, 2019 and 2018, and of its financial performance
and its cash flows for the year ended December 31, 2019 and 2018, in
accordance with International Financial Reporting Standards (“IFRS”)
as issued by International Accountant Standards Board (“IASB”).
Basis for Opinion
We conducted our audit in accordance with Canadian generally accepted
auditing standards (“Canadian GAAS”). Our responsibilities under
those standards are further described in the Auditor’s Responsibilities
for the Audit of the Financial Statements section of our report. We are
independent of the Group in accordance with the ethical requirements
that are relevant to our audit of the consolidated financial statements
in Canada, and we have fulfilled our other ethical responsibilities in
accordance with these requirements. We believe that the audit evidence
we have obtained is sufficient and appropriate to provide a basis for
our opinion.
Key Audit Matters
Key audit matters are those matters that, in our professional judgement,
were of most significance in our audit of the consolidated financial
statements of the current year. These matters were addressed in the
context of our audit of the consolidated financial statements as a whole,
and in forming our opinion thereon, and we do not provide a separate
opinion on these matters.
KEY AUDIT MATTERS
HOW THE MATTER WAS ADDRESSED IN THE AUDIT
Impairment assessment of oil and gas properties
As at December 31, 2019, the Group recorded US$383.0 million of
oil and gas properties and US$59.0 million of right-of-use assets
associated with these properties, which approximate 51% and 8%
respectively relative to the Group’s total assets.
Management performed an assessment of the internal and external
factors of the oil and gas properties’ carrying values to determine
whether there is any indicator of impairment.
Based on management’s assessment, there were no impairment
indicators identified as at 31 December 2019.
Notwithstanding the above, as the oil and gas properties is a
material component of the Group’s total assets, management
further assessed recoverability of its oil and gas properties by looking
at future cash flows from the respective oil and gas properties
(“Financial Model”) at December 31, 2019 and its future plans for
these assets. Management, who is ultimately responsible to the third
party estimates, have also engaged an independent qualified person
to estimate, where appropriate, the proved, probable and possible
reserves for certain of the oil and gas properties, including the future
net cash flows arising from such. The above assessment requires
the exercise of significant judgement about and assumptions on,
amongst others, the discount rate, oil reserves, expected production
volumes and future Brent oil prices.
The Group has made disclosures on the above judgement in Note 3.
Since December 31, 2019, the oil price has fallen sharply in large
part due to the impact of the international spread of COVID-19 and
geopolitical factors. Management has assessed that this is a non-
adjusting post balance sheet event in accordance with IAS 10 Events
after the reporting period and has made disclosures in Note 41.
Our audit procedures focused on evaluating impairment indicators
in accordance with IAS 36 Impairment of assets, and challenging
the judgements and key assumptions used by management in
determining the recoverable amount. Such procedures included,
amongst others:
•
• Reviewing the internal and external factors used by
management to determine impairment indicators;
Checking the Group’s budget to evaluate whether management
has a budget and plan for the assets, including the funding
options for future capital expenditure to be able to realise the
future cash flows;
• Assessing the objectivity, competency and experience of the
•
•
•
•
independent qualified person who prepared the reserve reports;
Checking the reserve reports prepared by the independent
qualified person relating to the Group’s estimated oil price, to
determine whether they indicate there has been a significant
change with an adverse effect on the recoverable amount;
Challenging management’s oil price assumptions against
external data, to determine whether they indicate that there
has been a significant change with an adverse effect on the
recoverable amount;
Comparing field and plant production performance during the
year against budget, to determine whether they indicate that
there has been a significant change with an adverse effect on
the recoverable amount; and
Challenging management’s assumptions on key data used in
their computation of the discount rate.
Based on our procedures, we noted that the carrying amounts of oil
and gas properties are stated appropriately.
As part of our post balance sheet date audit procedures, we
considered whether the COVID-19 pandemic and geopolitical factors
provide evidence of conditions that existed at the balance sheet
date. Based on our procedures covering the facts and circumstances,
we concurred with management that it is a non-adjusting event
and disclosures surrounding the impact of the events had been
appropriately disclosed in Note 41.
Jadestone Energy 2019 Annual Report 62
Consolidated Financial Statements
Independent Auditor’s Report
To The Shareholders Of Jadestone Energy Inc.
KEY AUDIT MATTERS
HOW THE MATTER WAS ADDRESSED IN THE AUDIT
Impairment assessment of intangible
exploration assets
As at December 31, 2019, the Group recorded US$116.1 million of
intangible exploration assets, which approximate 15% of the Group’s
total assets.
Management performed an assessment of the internal and external
factors of the intangible exploration assets properties’ carrying values
to determine whether there is any indicator of impairment.
Based on management’s assessment, there were no impairment
indicators identified as at December 31, 2019.
Notwithstanding the above, as the intangible exploration assets
represent a material component of the Group’s total assets,
management performed an assessment of the technical feasibility
and commercial viability of extracting a mineral resource and whether
there is any adverse information that will affect the final investment
decision to commercialise the asset.
Management, who is ultimately responsible for third party estimates,
have also engaged an independent qualified person to estimate,
where appropriate, the gross contingent resources for all of the
intangible exploration assets.
The Group has made disclosures on the above judgement in Note 3.
Since December 31, 2019, the oil and gas price has fallen sharply in
large part due to the impact of the international spread of COVID-19
and geopolitical factors. Management has assessed that this is a
non-adjusting post balance sheet event in accordance with IAS 10
Events after the reporting period and has made disclosures in
Note 41.
Our audit procedures focused on evaluating and challenging
the judgements and key assumptions used by management in
performing the impairment review under IFRS 6 Exploration for and
evaluation of mineral resources. Such procedures included, amongst
others:
•
• Reviewing the internal and external factors used by
management to determine impairment indicators;
Checking the Group’s budget to evaluate whether management
has a budget and plan for the assets, including the funding
options for future capital expenditure to be able to realise the
future cash flows;
Performing a retrospective review of prior year’s work budget
and current year’s actual activity to determine the reliability of
management’s plan and budget for the purpose of assessing
impairment indicators;
•
• Assessing the objectivity, competency and experience of the
•
independent qualified person who prepared the reserve reports;
and
Checking the reserve reports prepared by the independent
qualified person relating to the Group’s estimated oil reserves, to
determine whether they indicate if there has been a significant
change with an adverse effect on the recoverable amount.
As part of our post balance sheet audit procedures, we have
considered whether the COVID-19 pandemic and geopolitical factors
provide evidence of conditions that existed at the balance sheet date.
Based on our procedures, we concurred with management that it is
a non-adjusting event and disclosures surrounding the impact of the
events had been appropriately disclosed in Note 41.
Based on our procedures, we noted that the carrying amounts of
intangible exploration assets are stated appropriately.
63
Responsibilities of Management and Those Charged with
Governance for the Consolidated Financial Statements
Management is responsible for the preparation and fair presentation
of these consolidated financial statements in accordance with IFRS,
and for such internal control as management determines is necessary
to enable the preparation of financial statements that are free from
material misstatement, whether due to fraud or error.
In preparing the financial statements, management is responsible for
assessing the Group’s ability to continue as a going concern, disclosing,
as applicable, matters related to going concern and using the going
concern basis of accounting unless management either intends to
liquidate the Group or to cease operations, or has no realistic alternative
but to do so.
Those charged with governance are responsible for overseeing the
Group’s financial reporting process.
Other Information
Management is responsible for the other information. The other
information comprises:
• Management’s Discussion and Analysis; and
•
The information, other than the financial statements and our
auditor’s report thereon, in the Annual Report.
Our opinion on the consolidated financial statements does not cover
the other information and we do not and will not express any form
of assurance conclusion thereon. In connection with our audit of the
consolidated financial statements, our responsibility is to read the
other information identified above and, in doing so, consider whether
the other information is materially inconsistent with the consolidated
financial statements or our knowledge obtained in the audit or
otherwise appears to be materially misstated.
We obtained Management’s Discussion and Analysis prior to the date
of this auditor’s report. If, based on the work we have performed on this
other information, we conclude that there is a material misstatement
of this other information, we are required to report that fact in this
auditor’s report. We have nothing to report in this regard.
The information, other than the financial statements and the auditors’
report thereon, in the Annual Report is expected to be made available
to us after the date of this auditor’s report. If, based on the work we will
perform on this other information, we conclude that there is a material
misstatement of this other information, we are required to report that
face to those charged with governance.
Jadestone Energy 2019 Annual Report We communicate with those charged with governance regarding, among
other matters, the planned scope and timing of the audit and significant
audit findings, including any significant deficiencies in internal control
that we identify during our audit.
We also provide those charged with governance with a statement
that we have complied with relevant ethical requirements regarding
independence, and to communicate with them all relationships
and other matters that may reasonably be thought to bear on our
independence, and where applicable, related safeguards.
From the matters communicated with those charged with governance,
we determine those matters that were of most significance in the audit
of the financial statements of the current year and are therefore the key
audit matters. We describe these matters in our auditor’s report unless
law or regulation precludes public disclosure about the matter or when,
in extremely rare circumstances, we determine that a matter should not
be communicated in our report because the adverse consequences of
doing so would reasonably be expected to outweigh the public interest
benefits of such communication.
The engagement partner on the audit resulting in this independent
auditor’s report is Kanagasabai s/o Haridas.
Deloitte & Touche LLP
Public Accountants and
Chartered Accountants
Singapore
April 23, 2020
Consolidated Statement of Profit or Loss and Other Comprehensive Income
for the years ended December 31, 2019 and December 31, 2018
Consolidated statement of profit or loss
Revenue
Production costs
Depletion, depreciation and amortisation
Staff costs
Other expenses
Impairment of assets
Other income
Finance costs
Other financial gains
Profit/(Loss) before tax
Income tax expense
Profit/(Loss) for the year
Earnings/(Loss) per ordinary share
Basic and diluted (US$)
Consolidated statement of comprehensive income
Profit/(loss) for the year
Other comprehensive (loss)/income
Items that may be reclassified subsequently to profit or loss:
(Loss)/Gain on unrealised cash flow hedges
Hedging gain reclassified to profit or loss
Tax income/(expense) relating to components of other
comprehensive (loss)/income
Other comprehensive (loss)/income
Total comprehensive income for the year
NOTES
4
5
6
8
9
10
11
12
13
14
15
26
14
2019
USD’000
325,406
(119,898)
(90,746)
(19,714)
(11,692)
-
2,979
(16,443)
3,389
73,281
(32,776)
40,505
0.09
40,505
(30,542)
(14,874)
(45,416)
13,624
(31,792)
8,713
65
2018
Restated
USD’000
113,423
(90,939)
(13,776)
(13,538)
(10,374)
(11,901)
2,534
(9,240)
12,345
(21,466)
(9,567)
(31,033)
(0.10)
(31,033)
51,775
(1,088)
50,687
(15,207)
35,480
4,447
64
Consolidated Financial Statements
Independent Auditor’s Report
To The Shareholders Of Jadestone Energy Inc.
Auditor’s Responsibility for the Audit of the Financial
Statements
Our objectives are to obtain reasonable assurance about whether the
financial statements as a whole are free from material misstatement,
whether due to fraud or error, and to issue an auditor’s report that
includes our opinion. Reasonable assurance is a high level of assurance,
but is not a guarantee that an audit conducted in accordance with
Canadian GAAS will always detect a material misstatement when it
exists. Misstatements can arise from fraud or error and are considered
material if, individually or in the aggregate, they could reasonably be
expected to influence the economic decisions of users taken on the basis
of these financial statements.
As part of an audit in accordance with Canadian GAAS, we exercise
professional judgement and maintain professional skepticism
throughout the audit. We also:
a)
Identify and assess the risks of material misstatement of the
financial statements, whether due to fraud or error, design and
perform audit procedures responsive to those risks, and obtain
audit evidence that is sufficient and appropriate to provide a basis
for our opinion. The risk of not detecting a material misstatement
resulting from fraud is higher than for one resulting from error,
as fraud may involve collusion, forgery, intentional omissions,
misrepresentations, or the override of internal control.
b) Obtain an understanding of internal control relevant to the audit
in order to design audit procedures that are appropriate in the
circumstances, but not for the purpose of expressing an opinion on
the effectiveness of the Group’s internal control.
c) Evaluate the appropriateness of accounting policies used and the
reasonableness of accounting estimates and related disclosures
made by management.
d) Conclude on the appropriateness of management’s use of
the going concern basis of accounting and, based on the audit
evidence obtained, whether a material uncertainty exists related
to events or conditions that may cast significant doubt on the
Group’s ability to continue as a going concern. If we conclude that
a material uncertainty exists, we are required to draw attention
in our auditor’s report to the related disclosures in the financial
statements or, if such disclosures are inadequate, to modify our
opinion. Our conclusions are based on the audit evidence obtained
up to the date of our auditor’s report. However, future events or
conditions may cause the Group to cease to continue as a going
concern.
e) Evaluate the overall presentation, structure and content of the
financial statements, including the disclosures, and whether the
financial statements represent the underlying transactions and
events in a manner that achieves fair presentation.
f) Obtain sufficient appropriate audit evidence regarding the financial
information of the entities or business activities within the Group
to express an opinion on the consolidated financial statements.
We are responsible for the direction, supervision and performance
of the Group audit. We remain solely responsible for our audit
opinion.
Certain 2018 comparative information has been restated, as a result of reclassifications between line items. Please refer to Note 43.
All comprehensive income is attributable to the equity holders of the parent.
The accompanying notes are an integral part of the consolidated financial statements.
Jadestone Energy 2019 Annual Report 66
Consolidated Financial Statements
67
Consolidated Statement of Financial Position as at December 31, 2019 and December 31, 2018
Consolidated Statement of Changes in Equity for the years ended December 31, 2019 and December 31, 2018
Assets
Non-current assets
Intangible exploration assets
Oil and gas properties *
Plant and equipment
Right-of-use assets
Derivative financial instruments
Restricted cash
Deferred tax assets
Total non-current assets
Current assets
Inventories*
Trade and other receivables
Derivative financial instruments
Restricted cash
Cash and cash equivalents
Total current assets
Total assets
Equity and liabilities
Equity
Capital and reserves
Share capital
Share-based payments reserve
Hedging reserves
Accumulated losses
Total equity
Non-current liabilities
Provisions
Borrowings
Secured convertible bonds
Lease liabilities
Other payable
Deferred tax liabilities
Total non-current liabilities
Current liabilities
Borrowings
Lease liabilities
Trade and other payables *
Tax liabilities
Total current liabilities
Total liabilities
Total equity and liabilities
NOTES
2019
USD’000
16
17
18
19
36
24
21
22
23
36
24
24
25
27
26
28
31
32
29
30
21
31
29
35
116,096
383,018
1,780
59,787
-
17,477
16,012
594,170
31,411
42,283
5,275
6,008
75,934
160,911
755,081
466,573
23,857
3,688
(268,651)
225,467
280,418
7,328
-
42,533
359
64,825
395,463
41,795
19,739
27,962
44,655
134,151
529,614
755,081
2018
Restated
USD’000
95,607
430,193
1,709
-
15,339
23,561
21,287
587,696
15,822
32,800
35,985
5,083
52,981
142,671
730,367
466,562
22,375
35,480
(309,156)
215,261
284,300
49,420
-
-
3,748
92,468
429,936
52,393
-
31,493
1,284
85,170
515,106
730,367
SHARE
CAPITAL
USD’000
SHARE-
BASED
PAYMENTS
RESERVE
USD’000
HEDGING
RESERVES
USD’000
ACCUMULATED
LOSSES
USD’000
TOTAL
USD’000
As at January 1, 2018
364,466
21,855
-
(278,123)
108,198
Loss for the year
Other comprehensive income for the year
Total comprehensive income for the year
Share-based compensation, representing
transaction with owners, recognised
directly in equity
Shares issued, net of transaction costs
(Note 25)
Total transactions with owners,
recognised directly in equity
-
-
-
-
102,096
102,096
-
-
-
520
-
520
-
35,480
35,480
-
-
-
(31,033)
-
(31,033)
35,480
(31,033)
4,447
-
-
-
As at December 31, 2018 / January 1, 2019
466,562
22,375
35,480
(309,156)
Profit for the year
Other comprehensive loss for the year
Total comprehensive income for the year
Share-based compensation, representing
transaction with owners, recognised
directly in equity
Shares issued, net of transaction costs
(Note 25)
Total transactions with owners,
recognised directly in equity
-
-
-
-
11
11
-
-
-
1,482
-
1,482
-
(31,792)
(31,792)
-
-
-
40,505
-
40,505
-
-
-
520
102,096
102,616
215,261
40,505
(31,792)
8,713
1,482
11
1,493
As at December 31, 2019
466,573
23,857
3,688
(268,651)
225,467
* The comparative information has been restated for 2018 as a result of IFRS 3 adjustment to the purchase price allocation of the Montara assets
acquisition, see further in Notes 7 and 43.
Certain 2018 comparative information has been restated, as a result of reclassifications between line items. Please refer to Note 43.
The accompanying notes are an integral part of the consolidated financial statements.
The accompanying notes are an integral part of the consolidated financial statements.
Jadestone Energy 2019 Annual Report
68
Consolidated Financial Statements
69
Consolidated Statement of Cash Flows for the years ended December 31, 2019 and December 31, 2018
Significant Accounting Policies and Explanation Notes to the Financial Statements
for the years ended December 31, 2019 and December 31, 2018
NOTES
2019
USD’000
Operating activities
Profit/(Loss) before tax
Adjustments for:
Depletion, depreciation and amortisation
Depreciation of right-of-use assets
Other finance costs
Interest expense
Share-based payments
Loss/(Gain) on ineffective hedge recycled to profit or loss
Oil and gas properties written off
Change in fair value of contingent payments
Change in Stag FSO provision
Interest income
Unrealised foreign exchange gain
Gain on early repayment of convertible bonds
Impairment of intangible exploration assets
Operating cash flows before movements in working capital
Increase in trade and other receivables
(Increase)/Decrease in inventories
(Decrease)/Increase in trade and other payables
Cash generated from operations
Release of restricted cash for Ogan Komering
Interest paid
Tax refunded/(paid)
Net cash generated from operating activities
Investing activities
Acquisition of Montara
Payment for oil and gas properties
Payment for plant and equipment
Proceeds from disposal of plant and equipment
Payment for intangible exploration assets
Transfer from/(to) debt service reserve account
Interest received
Net cash used in investing activities
Financing activities
Net proceeds from issuance of shares
Net drawdown from borrowings
Repayment of borrowings
Repayment of lease liabilities
Payment of bond facility and stand-by fees
6
6 / 19
12
12
8
9 / 11
17
13
11
11
11
13
10
7
17
18
16
24
11
25
31
33
33
32 / 33
Net cash (used in)/generated from financing activities
Net increase in cash and cash equivalents
Effect of translation on foreign currency cash and cash balances
Cash and cash equivalents at beginning of the year
Cash and cash equivalents at end of the year
24
The accompanying notes are an integral part of the consolidated financial statements.
73,281
75,870
14,876
10,376
6,067
1,482
633
533
(3,389)
(1,717)
(1,260)
(8)
-
-
176,744
(9,483)
(7,346)
(12,431)
147,484
-
(4,698)
1,851
144,637
-
(45,161)
(502)
4
(11,589)
5,159
1,260
(50,829)
11
-
(54,203)
(16,671)
-
(70,863)
22,945
8
52,981
75,934
2018
Restated
USD’000
(21,466)
13,776
-
6,272
2,968
520
(637)
-
(12,057)
(835)
(422)
-
(288)
11,901
(268)
(3,918)
15,752
14,856
26,422
729
(2,263)
(7,125)
17,763
(133,092)
(6,968)
(1,437)
-
(1,635)
(18,644)
422
(161,354)
102,096
118,040
(17,761)
-
(17,514)
184,861
41,270
1,261
10,450
52,981
1 | Corporate Information
Jadestone Energy Inc. (the “Company” or “Jadestone”) is an oil and gas
company incorporated in Canada.
The Company’s ordinary shares are listed on AIM, a market by the
London Stock Exchange. The Company was listed on the TSX-V
throughout 2019 but delisted on March 25, 2020. The Company trades
under the symbol “JSE”.
The financial statements are expressed in United States Dollars (“US$”
or “USD”).
The Company and its subsidiaries (the “Group”) are engaged in
production, development, exploration and appraisal activities in
Australia, Vietnam and the Philippines. The Company’s current
producing assets are in the Carnarvon (Stag) and Vulcan basins
(Montara), offshore Western Australia.
On November 18, 2019, the Group executed a sale and purchase
agreement (“SPA”) with Österreichische Mineralölverwaltungs
Aktiengesellschaft New Zealand (“OMV New Zealand”) to acquire
an operated 69% controlling interest in the Maari project for a total
consideration of US$50.0 million (subject to customary working capital
adjustments). The transaction is subject to regulatory approvals and
joint venture partners’ acceptance. Following these approvals, the
transaction will close and control of the Maari project will transfer to the
Group. The economic benefits from January 1, 2019 until the closing date
will be adjusted in the final consideration price. The Group anticipates
to complete the acquisition in second half of 2020.
The Company’s head office is located at 3 Anson Road, #13-01
Springleaf Tower, Singapore 079909. The registered office of the
Company is 10th Floor, 595 Howe Street, Vancouver, British Columbia
V6C 2T5, Canada.
2 | Summary Of Significant
Accounting Policies
Basis Of Preparation
The financial statements have been prepared on a going concern basis
and in accordance with the historical cost convention basis, except
as disclosed in the accounting policies below, and are drawn up in
accordance with the provisions of International Financial Reporting
Standards (“IFRS”) as issued by International Accounting Standards
Board (“IASB”).
Historical cost is generally based on the fair value of the consideration
given in exchange for goods and services.
Fair value is the price that would be received from selling an asset or
paid to transfer a liability in an orderly transaction between market
participants at the measurement date, regardless of whether that price
is directly observable or estimated using another valuation technique.
In estimating the fair value of an asset or a liability, the Group takes
into account the characteristics of the asset or liability which market
participants would take into account when pricing the asset or liability
at the measurement date. Fair value for measurement and/or disclosure
purposes in these consolidated financial statements is determined on
such a basis, except for share-based payment transactions that are
within the scope of IFRS 2 Share-based Payment, leasing transactions
that are within the scope of IFRS 16 Leases, and measurements that
have some similarities to fair value but are not fair value, such as net
realisable value in IAS 2 Inventories, or value in use in IAS 36 Impairment
of Assets.
In addition, for financial reporting purposes, fair value adjustments are
categorised into level 1, 2 or 3 based on the degree to which the inputs
to the fair value adjustments are observable and the significance of the
inputs to the fair value measurement in its entirety, which are described
as follows:
-
-
Level 1 inputs are quoted prices (unadjusted) in active markets
for identical assets or liabilities that the Group can access at the
measurement date;
Level 2 inputs are inputs, other than quoted prices included within
Level 1, that are observable for the asset or liability, either directly or
indirectly; and
-
Level 3 inputs are unobservable inputs for the asset or liability.
Adoption of new and revised standards
New and amended IFRS standards that are effective for the current
year
In the current year, the Group has applied IFRS 16 Leases (as issued by
the IASB in January 2016) that is effective for annual periods that begin
on or after January 1, 2019.
IFRS 16 introduces new or amended requirements with respect to lease
accounting. It introduces significant changes to lessee accounting
by removing the distinction between operating and finance lease and
requiring the recognition of a right-of-use asset and a lease liability
at commencement for all leases, except for short-term leases and leases
of low value assets when such recognition exemptions are adopted.
In contrast to lessee accounting, the requirements for lessor accounting
have remained largely unchanged. Details of these new requirements are
described in the “Leases” policy. The impact of the adoption of IFRS 16
on the Group’s consolidated financial statements is described below.
The date of initial application of IFRS 16 for the Group is January 1, 2019.
The Group has applied IFRS 16 using the cumulative catch-up approach
which measures asset at amount equal to liability (adjusted for accruals
and prepayments). Please refer to (c) for the finance impact on the initial
application of IFRS 16.
Jadestone Energy 2019 Annual Report 70
Significant Accounting Policies and
Explanation Notes to the Financial Statements for the years ended December 31, 2019 and December 31, 2018
71
Impact of the new definition of a lease
(a)
The Group has made use of the practical expedient available on
transition to IFRS 16 not to reassess whether a contract is or contains a
lease. Accordingly, the definition of a lease in accordance with IAS 17 and
IFRIC 4 will continue to be applied to those leases entered or changed
before January 1, 2019.
The change in definition of a lease mainly relates to the concept of
control. IFRS 16 determines whether a contract contains a lease on the
basis of whether the customer has the right to control the use of an
identified asset for a period of time in exchange for consideration. This is
in contrast to the focus on ‘risks and rewards’ in IAS 17 and IFRIC 4.
The Group applies the definition of a lease and related guidance set
out in IFRS 16 to all lease contracts entered into or changed on or after
January 1, 2019 (whether it is a lessor or a lessee in the lease contract).
The Group has reviewed the new definition in IFRS 16, and concluded
that it will not significantly change the scope of contracts that meet the
definition of a lease for the Group.
(b) Impact on lessee accounting
(i) Former operating leases
IFRS 16 changes how the Group accounts for leases previously classified
as operating leases under IAS 17, which were off balance sheet.
Applying IFRS 16, for all leases (except as noted below), the Group:
-
-
-
Recognises right-of-use assets and lease liabilities in the
consolidated statement of financial position, initially measured at
the present value of the future lease payments;
Recognises depreciation of right-of-use assets and interest on lease
liabilities in the consolidated statement of profit and loss; and
Separates the total amount of cash paid into a principal portion
(presented within financing activities) and interest (presented
within operating activities) in the consolidated statement
of cash flows.
Under IFRS 16, right-of-use assets are tested for impairment in
accordance with IAS 36.
For short-term leases (lease term of 12 months or less) and leases of
low-value assets (which includes personal computers, small items of
office furniture and telephones), the Group has opted to recognise a
lease expense on a straight-line basis as permitted by IFRS 16. This
expense is presented within ‘other expenses’ in profit or loss.
The Group has used the following practical expedients when applying
the cumulative catch-up approach to leases previously classified as
operating leases applying IAS 17.
-
-
-
-
The Group has applied a single discount rate to a portfolio of leases
with reasonably similar characteristics.
The Group has elected not to recognise right-of-use assets and
lease liabilities to leases for which the lease term ends within 12
months of the date of initial application.
The Group has excluded initial direct costs from the measurement
of the right-of-use asset at the date of initial application.
The Group has used hindsight when determining the lease term
when the contract contains options to extend or terminate the
lease.
(c) Finance impact of initial application of IFRS 16
The weighted average lessees incremental borrowing rate applied to
lease liabilities recognised in the statement of financial position on
January 1, 2019 is 8.6%.
The following table shows the operating lease commitments disclosed
in Note 34 applying IAS 17 at December 31, 2018, discounted using the
incremental borrowing rate at the date of initial application and the
lease liabilities recognised in the statement of financial position at the
date of initial application.
Operating lease commitments as at December 31, 2018
Short-term leases and leases of low-value assets
Effect of discounting the above amounts
Present value of the lease payments due in periods covered by extension options that are included in the lease term
and not previously included in operating lease commitments
Lease liabilities recognised as at January 1, 2019
USD’000
43,595
(50)
(8,157)
462
35,850
The Group has recognised US$35.9 million of right-of-use assets and US$35.9 million of lease liabilities upon transition to IFRS 16.
In the current year, the Group has applied a number of amendments to IFRS Standards and Interpretations issued by the IASB that are effective for an
annual period that begins on or after January 1, 2019. Their adoption has not had any material impact on the disclosures or on the amounts reported in
these financial statements.
New and revised IFRSs in issue but not yet effective
In the current year, the Group has not applied the following amendments
to IFRS Standards and Interpretations issued by the IASB that are
effective for an annual period that begins on or after January 1, 2020:
-
-
-
Amendments to IFRS 3 Business Combinations;
Amendments to IAS 1 and IAS 8 Definition of Material; and
Amendments to References to the Conceptual Framework in IFRS
Standards.
All amendments are effective for annual periods beginning on or after
January 1, 2020 and generally require prospective application.
The Group is currently performing an assessment of the impact of these
amendments and anticipates potential material impact on the financial
statements of the Group in future periods as described below:
Amendments to IFRS 3 Business Combinations
The amendments clarify that while businesses usually have outputs,
outputs are not required for an integrated set of activities and assets
to qualify as a business. To be considered a business an acquired set
of activities and assets must include, at a minimum, an input and a
substantive process that together significantly contribute to the ability
to create outputs.
Additional guidance is provided that helps to determine whether a
substantive process has been acquired. The amendments introduce an
optional concentration test that permits a simplified assessment of
whether an acquired set of activities and assets is not a business. Under
the optional concentration test, the acquired set of activities and assets
is not a business if substantially all of the fair value of the gross assets
acquired is concentrated in a single identifiable asset or group of similar
assets.
The amendments are applied prospectively to all business combinations
and asset acquisitions for which the acquisition date is on or after the
first annual reporting period beginning on or after January 1, 2020, with
early application permitted.
Amendments to IAS 1 and IAS 8 Definition of Material
The amendments are intended to make the definition of material in
IAS 1 easier to understand and are not intended to alter the underlying
concept of materiality in IFRS Standards. The concept of ‘obscuring’
material information with immaterial information has been included as
part of the new definition.
The threshold for materiality influencing users has been changed from
‘could influence’ to ‘could reasonably be expected to influence’.
The definition of material in IAS 8 has been replaced by a reference to
the definition of material in IAS 1. In addition, the IASB amended other
Standards and the Conceptual Framework that contain a definition of
material or refer to the term ‘material’ to ensure consistency.
The amendments are applied prospectively for annual periods beginning
on or after January 1, 2020, with earlier application permitted.
Amendments to References to the Conceptual Framework in IFRS
Standards
Together with the revised Conceptual Framework, which became
effective upon publication on March 29, 2018, the IASB has also issued
Amendments to References to the Conceptual Framework in IFRS
Standards. The document contains amendments to IFRS 2, IFRS 3, IFRS
6, IFRS 14, IAS 1, IAS 8, IAS 34, IAS 37, IAS 38, IFRIC 12, IFRIC 19, IFRIC 20,
IFRIC 22, and SIC-32.
Not all amendments, however, update those pronouncements with
regard to references to and quotes from the framework so that they
refer to the revised Conceptual Framework. Some pronouncements
are only updated to indicate which version of the Framework they are
referencing to (the IASC Framework adopted by the IASB in 2001, the
IASB Framework of 2010, or the new revised Framework of 2018) or to
indicate that definitions in the Standard have not been updated with the
new definitions developed in the revised Conceptual Framework.
The amendments, where they actually are updates, are effective
for annual periods beginning on or after January 1, 2020, with early
application permitted.
Basis of Consolidation
The consolidated financial statements incorporate the financial
statements of the Company and enterprises controlled by the Company
and its subsidiaries. Control is achieved where the Company:
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Has power over the investee;
Is exposed, or has rights, to variable returns from its involvement
with the investee; and
Has the ability to use its power to affect its returns.
The Company reassesses whether or not it controls an investee if facts
and circumstances indicate that there are changes to one or more of the
three elements of control listed above.
Consolidation of a subsidiary begins when the Company obtains control
over the subsidiary and ceases when the Company loses control of the
subsidiary. Specifically, income and expenses of a subsidiary acquired or
disposed of during the year are included in the consolidated statement
of profit or loss and other comprehensive income from the date the
Company gains control until the date when the Company ceases to
control the subsidiary.
Profit or loss and each component of other comprehensive income are
attributed to the owners of the Company. Total comprehensive income
of subsidiaries is attributed to the owners of the Company and to the
non-controlling interests even if this results in the non-controlling
interests having a deficit balance.
When necessary, adjustments are made to the financial statements of
subsidiaries to bring their accounting policies into line with the Group’s
accounting policies.
All intragroup assets and liabilities, equity, income, expenses and cash
flows relating to transactions between members of the Group are
eliminated in full on consolidation.
Business Combinations
Acquisitions of businesses (including joint operations which are
assessed to be businesses) are accounted for using the acquisition
method. The consideration for each acquisition is measured as the
aggregate of the acquisition date fair values of assets given, liabilities
incurred by the Company to the former owners of the acquiree, and
equity interests issued by the Company in exchange for control of the
acquiree. Acquisition-related costs are recognised in profit or loss as
incurred.
Jadestone Energy 2019 Annual Report 72
Significant Accounting Policies and
Explanation Notes to the Financial Statements for the years ended December 31, 2019 and December 31, 2018
73
The definition of a business in accordance with IFRS 3 is an integrated
set of activities and assets that is capable of being conducted and
managed for the purpose of providing good or services to customers,
generating investment income (such as dividends or interest) or
generating other income from ordinary activities. At the acquisition
date, the identifiable assets acquired and the liabilities assumed are
recognised at their fair value, except that:
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-
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Deferred tax assets or liabilities and liabilities or assets related to
employee benefit arrangements are recognised and measured in
accordance with IAS 12 Income Taxes and IAS 19 Employee Benefits
respectively;
Liabilities or equity instruments related to share-based payment
transactions of the acquiree or the replacement of an acquiree’s
share-based payment awards transactions with share-based
payment awards transactions of the acquirer, in accordance with
the method in IFRS 2 Share-based Payment at the acquisition date;
and
Assets (or disposal groups) that are classified as held for sale
in accordance with IFRS 5 Non-Current Assets Held for Sale and
Discontinued Operations.
Where applicable, the consideration for the acquisition includes any
asset or liability resulting from a contingent consideration arrangement,
measured at its acquisition-date fair value. Subsequent changes in
such fair values are adjusted against the cost of acquisition where they
qualify as measurement period adjustments. Measurement period
adjustments are adjustments that arise from additional information
obtained during the ‘measurement period’ (which cannot exceed one
year from the acquisition date) about facts and circumstances that
existed at the acquisition date. The subsequent accounting for changes
in the fair value of the contingent consideration that do not qualify
as measurement period adjustments depends on how the contingent
consideration is classified.
Contingent consideration that is classified as equity is not re-measured
at subsequent reporting dates and its subsequent settlement is
accounted for within equity. Contingent consideration that is classified
as a liability is re-measured at subsequent reporting dates with the
corresponding gain or loss being recognised in profit or loss.
If the initial accounting for a business combination is incomplete by the
end of the reporting period in which the combination occurs, the Group
reports provisional amounts for the items for which the accounting
is incomplete. Those provisional amounts are adjusted during the
measurement period (see below), or additional assets or liabilities
are recognised, to reflect new information obtained about facts and
circumstances that existed as of the acquisition date that, if known,
would have affected the amounts recognised as at that date.
The measurement period is the period from the date of acquisition
to the date the Group obtains complete information about facts and
circumstances that existed as at the acquisition date and is subject to a
maximum of one year from acquisition date.
Where an interest in a production sharing contract (“PSC”) is acquired
by way of a corporate acquisition, the interest in the PSC is treated as an
asset purchase unless the acquisition of the corporate vehicle meets the
requirements to be treated as a business combination and definition of
a business.
Foreign Currency Transactions
The Group’s consolidated financial statements are presented in USD,
which is the parent’s functional currency and presentation currency.
The functional currencies of subsidiaries are determined based on the
economic environment in which they operate.
In preparing the financial statements of each individual Group entity,
transactions in currencies other than the entity’s functional currency
are recorded at the rates of exchange prevailing on the dates of the
transactions. At the end of each reporting period, monetary items
denominated in foreign currencies are retranslated at the rates prevailing
at the end of the reporting period. Non-monetary items carried at fair
value that are denominated in foreign currencies are retranslated at the
rates prevailing on the date when the fair value was determined. Non-
monetary items that are measured in terms of historical cost in a foreign
currency are not retranslated.
Exchange differences arising on the settlement of monetary items, and
on retranslation of monetary items are included in profit or loss for the
period.
Exchange differences arising on the retranslation of non-monetary items
carried at fair value are included in profit or loss for the period, except
for differences arising on the retranslation of non-monetary items in
respect of which gains or losses are recognised in other comprehensive
income. For such non-monetary items, any exchange component of that
gain or loss is also recognised in other comprehensive income.
Joint Operations
A joint operation is a joint arrangement whereby the parties that
have joint control of the arrangement have rights to the assets, and
obligations for the liabilities, relating to the arrangement. Joint control
is the contractually agreed sharing of control of an arrangement,
which exists only when decisions about the relevant activities require
unanimous consent of the parties sharing control.
When a Group entity undertakes its activities under joint operations, the
Group as a joint operator recognises in relation to its interest in a joint
operation:
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-
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Its assets, including its share of any assets held jointly;
Its liabilities, including its share of any liabilities incurred jointly;
Its revenue from the sale of its share of the output arising from the
joint operation; and
Its expenses, including its share of any expenses incurred jointly.
The Group accounts for the assets, liabilities, revenue and expenses
relating to its interest in a joint operation in accordance with the IFRSs
applicable to the particular assets, liabilities, revenues and expenses.
When a Group entity transacts with a joint operation in which a Group
entity is a joint operator (such as a sale or contribution of assets), the
Group is considered to be conducting the transaction with the other
parties to the joint operation, and gains and losses resulting from
the transactions are recognised in the Group’s consolidated financial
statements only to the extent of other parties’ interests in the joint
operation.
When a Group entity transacts with a joint operation in which a Group
entity is a joint operator (such as a purchase of assets), the Group does
not recognise its share of the gains and losses until it resells those
assets to a third party.
Changes to the Group’s interest in PSCs usually require the approval of
the appropriate regulatory authority. A change in interest is recognised
when:
-
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Approval is considered highly likely; and
All affected parties are effectively operating under the revised
arrangement.
Where this is not the case, no change in interest is recognised and any
funds received or paid are included in the statement of financial position
as contractual deposits.
Pre-Licence Award Costs
Costs incurred prior to the effective award of oil and gas licence,
concessions and other exploration rights are expensed in profit or loss.
Exploration and Evaluation Costs
The costs of exploring for and evaluating oil and gas properties, including
the costs of acquiring rights to explore, geological and geophysical
studies, exploratory drilling and directly related overheads such as
directly attributable employee remuneration, materials, fuel used, rig
costs and payments made to contractors are capitalised and classified
as intangible exploration assets (“E&E assets”).
If no potentially commercial hydrocarbons are discovered, the E&E
assets are written off through profit or loss as a dry hole. If extractable
hydrocarbons are found and, subject to further appraisal activity (e.g. the
drilling of additional wells), it is probable that they can be commercially
developed, the costs continue to be carried as intangible exploration
costs while sufficient/continued progress is made in assessing the
commerciality of the hydrocarbons.
Costs directly associated with appraisal activity undertaken to determine
the size, characteristics and commercial potential of a reservoir following
the initial discovery of hydrocarbons, including the costs of appraisal
wells where hydrocarbons were not found, are initially capitalised as E&E
assets.
All such capitalised costs are subject to technical, commercial and
management review, as well as review for indicators of impairment at
the end of each reporting period. This is to confirm the continued intent
to develop or otherwise extract value from the discovery. When such
intent no longer exists or if there is a change in circumstances signifying
an adverse change in initial judgment, the costs are written off.
When commercial reserves of hydrocarbons are determined and
development is approved by management, the relevant expenditure
is transferred to oil and gas properties. The technical feasibility and
commercial viability of extracting a mineral resource is considered to
be determinable when proved or probable reserves are determined to
exist. The determination of proved or probable reserves is dependent
on reserve evaluations which are subject to significant judgments and
estimates.
Costs related to geological and geophysical studies that relate to blocks
that have not yet been acquired, and costs related to blocks for which no
commercially viable hydrocarbons are expected, are taken direct to the
profit or loss and have been disclosed as expensed exploration costs.
Farm-Outs in The Exploration and Evaluation Phase
The Group does not record any expenditure made by the farmee on its
account. It also does not recognise any gain or loss on its exploration
and evaluation farm-out arrangements, but re-designates any costs
previously capitalised in relation to the whole interest as relating to the
partial interest retained. Any cash consideration received directly from
the farmee is credited against costs previously capitalised in relation to
the whole interest, with any excess accounted for by the farmor as a gain
on disposal.
Oil And Gas Properties
Producing assets
The Group recognises oil and gas properties at cost less accumulated
depletion, depreciation and impairment losses. Directly attributable
costs incurred for the drilling of development wells and for the
construction of production facilities are capitalised together with
the discounted value of estimated future costs of decommissioning
obligations. Workover expenses are recognised in profit or loss in the
period in which they are incurred, unless it generates additional reserves
or prolongs the economic life of the well, in which case it is capitalised.
When components of oil and gas properties are replaced, disposed of, or
no longer in use, they are derecognised.
Depletion and amortisation expense
Depletion of oil and gas properties is calculated using the units of
production method for an asset or group of assets from the date in
which they are available for use. The costs of those assets are depleted
based on proved and probable reserves.
Costs subject to depletion include expenditures to date, together with
approved estimated future expenditure to be incurred in developing
proved and probable reserves. Costs of major development projects are
excluded from the costs subject to depletion until they are available for
use.
The impact of changes in estimated reserves is dealt with prospectively
by depleting the remaining carrying value of the asset over the
remaining expected future production. If reserves estimates are revised
downwards, earnings could be affected by higher depletion expense, or
an immediate write-down of the property’s carrying value.
Asset restoration obligations
The Group estimates the future removal and restoration costs of oil
production facilities, wells, pipelines and related assets at the time of
installation or acquisition of the assets, and based on prevailing legal
requirements and industry practice. In most instances, the removal of
these assets will occur many years in the future. The estimates of future
removal costs are made considering relevant legislation and industry
practice and require management to make judgments regarding the
removal date, the extent of restoration activities required, and future
removal technologies.
Site restoration costs are capitalised within the cost of the associated
assets, and the provision is stated in the statement of financial
position at its total estimated present value. These costs are based on
judgements and assumptions regarding removal dates, technologies,
and industry practice. This estimate is evaluated on a periodic basis and
any adjustment to the estimate is applied prospectively. Changes in the
estimated liability resulting from revisions to estimated timing, amount
of cash flows, or changes in the discount rate are recognised as a change
in the asset restoration liability and related capitalised asset restoration
cost within oil and gas properties.
Jadestone Energy 2019 Annual Report 74
Significant Accounting Policies and
Explanation Notes to the Financial Statements for the years ended December 31, 2019 and December 31, 2018
75
Impairment of Assets
At the end of each reporting period, the Group reviews the carrying
amounts of its assets to determine whether there is any indication that
those assets have suffered an impairment loss. If any such indication
exists, the recoverable amount of the asset is estimated in order to
determine the extent of the impairment loss (if any). Where it is not
possible to estimate the recoverable amount of an individual asset, the
Group estimates the recoverable amount of the cash-generating unit
to which the asset belongs. When a reasonable and consistent basis
of allocation can be identified, corporate assets are also allocated to
individual cash-generating units, or otherwise they are allocated to the
smallest group of cash-generating units for which a reasonable and
consistent allocation basis can be identified.
Intangible assets with indefinite useful lives and intangible assets not
yet available for use, are tested for impairment annually, and whenever
there is an indication that the asset may be impaired.
Recoverable amount is the higher of fair value less costs to sell and
value in use. In assessing value in use, the estimated future cash flows
are discounted to their present value using a pre-tax discount rate that
reflects current market assessments of the time value of money and the
risks specific to the asset for which estimates of future cash flows have
not been adjusted.
If the recoverable amount of an asset (or cash-generating unit) is
estimated to be less than its carrying amount, the carrying amount of
the asset (or cash-generating unit) is reduced to its recoverable amount.
An impairment loss is recognised immediately in profit or loss.
Where an impairment loss subsequently reverses, the carrying amount
of the asset (cash-generating unit) is increased to the revised estimate
of its recoverable amount, but so that the increased carrying amount
does not exceed the carrying amount that would have been determined
had no impairment loss been recognised for the asset (cash-generating
unit) in prior years. A reversal of an impairment loss is recognised
immediately in profit or loss.
Inventories
Inventories are valued at the lower of cost and net realisable value. Cost
is determined as follows:
Petroleum products, comprising primarily of extracted crude oil
-
stored in tanks, pipeline systems and aboard vessels, and natural
gas, are valued using weighted average costing inclusive of depletion
expense; and
- Materials, which include drilling and maintenance stocks, are valued
at the weighted average cost of acquisition.
Net realisable value represents the estimated selling price less
applicable selling expenses. If the carrying value exceeds net realisable
value, a write-down is recognised. The write-down may be reversed in a
subsequent period if the inventory is still on hand but the circumstances
which caused the write-down no longer exist.
The change in net present value of future obligations, due to the
passage of time, is expensed as accretion expense within financing
charges. Actual restoration obligations settled during the period reduce
the decommissioning liability.
The asset restoration costs are depleted using the units of production
method (see above accounting policy).
Borrowing Costs
Finance costs of borrowing are allocated to periods over the term of the
related debt at a constant rate on the carrying amount. Debt is shown
on the consolidated statement of financial position, net of arrangement
fees and issue costs, and amortised through to the income statement
and statement of other comprehensive income as finance costs over the
term of the debt.
Borrowing costs directly attributable to the acquisition, construction or
production of qualifying assets, which are assets that necessarily take
a substantial period of time to get ready for their intended use or sale,
are added to the cost of those assets, until such time as the assets are
substantially ready for their intended use or sale.
All other borrowing costs are recognised in the profit or loss in the period
in which they are incurred.
Investment income earned on the temporary investment of specific
borrowings pending their expenditure on qualifying assets is deducted
from the borrowing costs eligible for capitalisation. All other borrowing
costs are recognised in profit or loss in the period in which they are
incurred and this includes borrowing costs in relation to exploration
activities which are capitalised in intangible exploration assets, as
management is of the view that these do not meet the definition of a
qualifying asset.
Plant and Equipment
Plant and equipment is stated at cost less accumulated depreciation
and any recognised impairment loss.
Depreciation is charged so as to write off the cost of assets evenly over
their estimated useful lives, on the following:
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Computer equipment: 3 years; and
Fixtures and equipment: 3 years.
The estimated useful lives, residual values and depreciation method are
reviewed at each year end, with the effect of any changes in estimate
accounted for on a prospective basis.
Right-of-use assets are depreciated over the shorter period of the lease
term and the useful life of the underlying asset. If a lease transfers
ownership of the underlying asset or the cost of the right-of-use asset
reflects that the Group expects to exercise a purchase option, the related
right-of-use asset is depreciated over the useful life of the underlying
asset.
An item of plant and equipment is derecognised upon disposal or when
no future economic benefits are expected to arise from the continued
use of asset. Any gain or loss arising on the disposal or retirement
of an item of plant and equipment is determined as the difference
between the sales proceeds and the carrying amount of the asset and is
recognised in profit or loss.
Financial Instruments
Financial assets and financial liabilities are recognised in the Group’s
consolidated statement of financial position when the Group becomes a
party to the contractual provisions of the instrument.
Financial assets and financial liabilities are initially measured at fair
value. Transaction costs are directly attributable to the acquisition or
issue of the financial assets and financial liabilities (other than financial
assets and financial liabilities at fair value through the profit or loss)
are added to or deducted from the fair value of the financial assets or
financial liabilities, as appropriate, on initial recognition.
Transaction costs directly attributable to the acquisition of financial
assets or financial liabilities at fair value through profit or loss are
recognised immediately in profit or loss.
Financial assets
All financial assets are recognised and derecognised on a trade date
basis where the purchases or sales of financial assets is under a
contract whose terms require delivery of assets within the time frame
established by the market concerned.
All recognised financial assets are measured subsequently in their
entirety at either amortised cost or fair value, depending on the
classification of the financial assets.
Classification of financial assets
Debt instruments that meet the following conditions are measured
subsequently at amortised cost:
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The financial asset is held within a business model whose objective
is to hold financial assets in order to collect contractual cash flows;
and
The contractual terms of the financial asset give rise on specified
dates to cash flows that are solely payments of principal and
interest on the principal amount outstanding.
Debt instruments that meet the following conditions are subsequently
measured at fair value through other comprehensive income (“FVTOCI”):
-
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the financial asset is held within a business model whose objective
is achieved by both collecting contractual cash flows and selling the
financial assets; and
the contractual terms of the financial asset give rise on specified
dates to cash flows that are solely payments of principal and
interest on the principal amount outstanding.
By default, all other financial assets are subsequently measured at fair
value through profit or loss (“FVTPL”).
Amortised cost and effective interest method
The effective interest method is a method of calculating the amortised
cost of a debt instrument and of allocating interest income over the
relevant period.
For financial assets, the effective interest rate is the rate that exactly
discounts estimated future cash receipts (including all fees and points
paid or received that form an integral part of the effective interest rate,
transaction costs and other premiums or discounts) excluding expected
credit losses, through the expected life of the debt instrument, or, where
appropriate, a shorter period, to the gross carrying amount of the debt
instrument on initial recognition.
The amortised cost of a financial asset is the amount at which the
financial asset is measured at initial recognition minus the principal
repayments, plus the cumulative amortisation using the effective
interest method of any difference between that initial amount and the
maturity amount, adjusted for any loss allowance. The gross carrying
amount of a financial asset is the amortised cost of a financial asset
before adjusting for any loss allowance.
Interest income is recognised using the effective interest method for
debt instruments measured subsequently at amortised cost and at
fair value through other comprehensive income. For financial assets
other than purchased or originated credit impaired financial assets,
interest income is calculated by applying the effective interest rate
to the gross carrying amount of a financial asset, except for financial
assets that have subsequently become credit impaired. For financial
assets that have subsequently become credit impaired, interest income
is recognised by applying the effective interest rate to the amortised
cost of the financial asset. If, in subsequent reporting periods, the credit
risk on the credit impaired financial instrument improves so that the
financial asset is no longer credit impaired, interest income is recognised
by applying the effective interest rate to the gross carrying amount of
the financial asset.
Interest income is recognised in profit or loss and is included in “other
income” (Note 11) line item.
Foreign exchange gains and losses
The carrying amount of financial assets that are denominated in a
foreign currency is determined in that foreign currency and translated
at the spot rate at the end of each reporting period.
All financial assets measured at amortised cost that are not part of a
designated hedging relationship, exchange differences are recognised
in profit or loss in either “other income” (Note 11) or “other expenses”
(Note 9) line item.
Impairment of financial assets
The Group’s financial assets that are subject to the expected credit
loss model comprise trade and other receivables. While cash and bank
balances are also subject to the impairment requirements of IFRS 9
Financial Instruments, the expected credit loss allowances are not
expected to be significant.
The Group’s trade and other receivables are primarily with (i)
counterparties to oil and gas sales and (ii) governments for recoverable
amounts of value added taxes.
The concentration of credit risk relates to the main counterparty to oil
and gas sales in Australia, where the sole customer has an A1 credit
rating (Moody’s). All trade receivables are generally settled 30 days after
sale date. In the event that an invoice is issued on a provisional basis
then the final reconciliation is paid within 3 days of the issuance of the
final invoice, largely mitigating any credit risk.
The Group recognises lifetime expected credit loss (“ECL”) for trade
receivables. The expected credit losses on these financial assets are
estimated based on days past due, applying expected non-recoveries for
each group of receivables.
The Group measures the loss allowance for other receivables at an
amount equal to 12-months ECL, as there is no significant increase in
credit risk since initial recognition.
Jadestone Energy 2019 Annual Report 76
Significant Accounting Policies and
Explanation Notes to the Financial Statements for the years ended December 31, 2019 and December 31, 2018
77
Significant increase in credit risk
In assessing whether the credit risk on a financial instrument has
increased significantly since initial recognition, the Group compares the
risk of a default occurring on the financial instrument as at the reporting
date with the risk of a default occurring on the financial instrument
as at the date of initial recognition. In making this assessment, the
Group considers both quantitative and qualitative information that
is reasonable and supportable, including historical experience and
forward-looking information that is available without undue cost or
effort. Forward-looking information considered includes the future
prospects of the industries in which the Group’s debtors operate, based
on consideration of various external sources of actual and forecast
economic information that relate to the Group’s core operations.
In particular, the following information is taken into account when
assessing whether credit risk has increased significantly since initial
recognition:
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an actual or expected significant deterioration in the financial
instrument’s external (if available) or internal credit rating;
significant deterioration in external market indicators of credit risk
for a particular financial instrument, e.g. a significant increase in
the credit spread, the credit default swap prices for the debtor, or
the length of time or the extent to which the fair value of a financial
asset has been less than its amortised cost;
existing or forecast adverse changes in business, financial or
economic conditions that are expected to cause a significant
decrease in the debtor‘s ability to meet its debt obligations;
an actual or expected significant deterioration in the operating
results of the debtor;
significant increases in credit risk on other financial instruments of
the same debtor; and
an actual or expected significant adverse change in the regulatory,
economic, or technological environment of the debtor that results
in a significant decrease in the debtor’s ability to meet its debt
obligations.
Despite the foregoing, the Group assumes that the credit risk on
a financial instrument has not increased significantly since initial
recognition if the financial instrument is determined to have low credit
risk at the reporting date. A financial instrument is determined to have
low credit risk if i) the financial instrument has a low risk of default, ii)
the borrower has a strong capacity to meet its contractual cash flow
obligations in the near term and iii) adverse changes in economic and
business conditions in the longer term may, but will not necessarily,
reduce the ability of the borrower to fulfil its contractual cash flow
obligations.
The Group regularly monitors the effectiveness of the criteria used to
identify whether there has been a significant increase in credit risk and
revises them as appropriate to ensure that the criteria are capable of
identifying significant increase in credit risk before the amount becomes
past due.
Definition of default
The Group considers the following as constituting an event of default
for internal credit risk management purposes as historical experience
indicates that receivables that meet either of the following criteria are
generally not recoverable:
- when there is a breach of financial covenants by the counterparty;
or
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information developed internally or obtained from external sources
indicates that the debtor is unlikely to pay its creditors, including
the Group, in full (without taking into account any collaterals held
by the Group).
Credit-impaired financial assets
A financial asset is credit-impaired when one or more events that have a
detrimental impact on the estimated future cash flows of that financial
asset have occurred. Evidence that a financial asset is credit-impaired
includes observable data about the following events:
-
-
-
-
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significant financial difficulty of the issuer or the borrower;
a breach of contract, such as a default or past due event;
the lender(s) of the borrower, for economic or contractual reasons
relating to the borrower’s financial difficulty, having granted to the
borrower a concession(s) that the lender(s) would not otherwise
consider;
it is becoming probable that the borrower will enter bankruptcy or
other financial reorganisation; or
the disappearance of an active market for that financial asset
because of financial difficulties.
Write-off policy
The Group writes off a financial asset when there is information
indicating that the counterparty is in severe financial difficulty and there
is no realistic prospect of recovery, e.g. when the counterparty has been
placed under liquidation or has entered into bankruptcy proceedings,
or in the case of trade receivables, when the amounts are over one year
past due, whichever occurs sooner. Financial assets written off may
still be subject to enforcement activities under the Group’s recovery
procedures, taking into account legal advice where appropriate. Any
recoveries made are recognised in profit or loss.
Measurement and recognition of expected credit losses
The measurement of ECL is a function of the probability of default, loss
given default (i.e. the magnitude of the loss if there is a default) and the
exposure at default. The assessment of the probability of default and
loss given default is based on historical data adjusted by forward looking
information as described above.
As for the exposure at default, for financial assets, this is represented
by the assets’ gross carrying amount at the reporting date together
with any additional amounts expected to be drawn down in the future
by default date determined based on historical trend, the Group’s
understanding of the specific future financing needs of the debtors, and
other relevant forward looking information.
For financial assets, the expected credit loss is estimated as the
difference between all contractual cash flows that are due to the Group
in accordance with the contract and all the cash flows that the Group
expects to receive, discounted at the original effective interest rate.
If the Group has measured the loss allowance for a financial instrument
at an amount equal to lifetime ECL in the previous reporting period, but
determines at the current reporting date that the conditions for lifetime
ECL are no longer met, the Group measures the loss allowance at an
amount equal to 12-month ECL at the current reporting date, except for
assets for which the simplified approach was used.
Derecognition of financial assets
The Group derecognises a financial asset only when the contractual
rights to the cash flows from the asset expire, or it transfers the
financial asset and substantially all the risks and rewards of ownership
of the asset to another entity. If the Group neither transfers nor retains
substantially all the risks and rewards of ownership, and continues to
control the transferred asset, the Group recognises its retained interest
in the asset and an associated liability for amounts it may have to pay. If
the Group retains substantially all of the risks and rewards of ownership
of a transferred financial asset, the Group continues to recognise the
financial asset and also recognises a collaterialised borrowing for the
proceeds received.
On derecognition of a financial asset measured at amortised cost, the
difference between the asset’s carrying amount and the sum of the
consideration received and receivables is recognised in the profit or loss.
Financial liabilities
All financial liabilities are measured subsequently at amortised cost
using the effective interest method or at FVTPL.
However, financial liabilities that arise when a transfer of a financial
asset does not qualify for derecognition or when the continuing
involvement approach applies, are measured in accordance with the
specific accounting policies set out below.
Financial liabilities at FVTPL
Financial liabilities are classified as at FVTPL when the financial liability
is (i) contingent consideration of an acquirer in a business combination,
(ii) held for trading or (iii) it is designated as at FVTPL.
A financial liability other than a contingent consideration of an acquirer
in a business combination may be designated as at FVTPL upon initial
recognition if:
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such designation eliminates or significantly reduces a measurement
or recognition inconsistency that would otherwise arise; or
the financial liability forms part of a group of financial assets or
financial liabilities or both, which is managed and its performance
is evaluated on a fair value basis, in accordance with the Group’s
documented risk management or investment strategy, and
information about the grouping is provided internally on that basis;
or
it forms part of a contract containing one or more embedded
derivatives, and IFRS 9 permits the entire combined contract to be
designated as at FVTPL.
Financial liabilities at FVTPL are measured at fair value, with any gains
or losses arising on changes in fair value recognised in profit or loss to
the extent that they are not part of a designated hedging relationship
(see hedge accounting policy). The net gain or loss recognised in profit
or loss incorporates any interest paid on the financial liability and is
included in either “other financial gains” (Note 13) or “finance costs”
(Note 12) line item in profit or loss.
Financial liabilities measured subsequently at amortised cost
Other financial liabilities are measured subsequently at amortised cost
using the effective interest method.
The effective interest method is a method of calculating the amortised
cost of a financial liability and of allocating interest expense over the
relevant period. The effective interest rate is the rate that exactly
discounts estimated future cash payments (including all fees and points
paid or received that form an integral part of the effective interest
rate, transaction costs and other premiums or discounts) through the
expected life of the financial liability, or (where appropriate) a shorter
period, to the amortised cost of a financial liability.
Foreign exchange gain or loss
For financial liabilities that are denominated in a foreign currency and
are measured at amortised cost at the end of each reporting period,
the foreign exchange gains and losses are determined based on the
amortised cost of the instruments. These foreign exchange gains and
losses are recognised in the “other income” (Note 11) or “other expenses”
(Note 9) line item in profit or loss for financial liabilities that are not part
of a designated hedging relationship. For those which are designated
as a hedging instrument for a hedge of foreign currency risk, foreign
exchange gains and losses are recognised in other comprehensive
income and accumulated in a separate component of equity.
Equity instruments
Equity instruments issued by the Group are recorded at the fair value
of the proceeds received, net of direct issue costs, except where the
accounting treatment is defined by a separate accounting standard,
as in the case of share-based payments.
Convertible bonds
Convertible bonds are regarded as compound instruments, consisting
of a debt host component and an equity conversion option upon
maturity, which are classified separately as financial liabilities at
amortised cost and financial liabilities at FVTPL respectively, in
accordance with the substance of the contractual arrangement on initial
recognition. The conversion option that will be settled by the exchange
of a fixed amount of cash or another financial asset for a number of
the Company’s own equity instruments, is classified as a derivative
financial liability.
On initial recognition, the fair value of the liability host component is
determined using the prevailing market interest rate of similar non-
convertible debts. The difference between the gross proceeds of the
issue of the convertible loans and the fair value assigned to the liability
host component, representing the conversion option for the holder to
convert the loans into equity, is recognised separately as a derivative
financial liability.
In subsequent periods, the derivative financial liability which represents
the equity conversion option is measured at its fair value, and with
fair value changes recognised in the profit or loss. The liability host
component is carried at amortised cost using the effective interest
method until the liability is extinguished on conversion or redemption.
Upon conversion, the derivative financial liability and the carrying
amount of the liability host component will be transferred to share
capital.
Transaction costs
Transaction costs that relate to the issue of the convertible bonds
are allocated to the liability host and equity or derivative liability
components in proportion to the allocation of the gross proceeds.
Transaction costs relating to the equity component are charged directly
to equity. Transaction costs relating to the liability component are
included in the carrying amount of the liability, and amortised over the
period of the convertible loan using the effective interest method.
Transaction costs incurred prior to any issue of the convertible bond are
capitalised as prepayments.
Jadestone Energy 2019 Annual Report 78
Significant Accounting Policies and
Explanation Notes to the Financial Statements for the years ended December 31, 2019 and December 31, 2018
79
Derecognition of financial liabilities
The Group derecognises financial liabilities when, and only when,
the Group’s obligations are discharged, cancelled or they expire.
The difference between the carrying amount of the financial liability
decognised, and the consideration paid and payable is recognised in
profit or loss.
Derivative financial instruments
The Group enters into derivative financial instruments to manage its
exposure to commodity price risks.
Derivatives are initially recognised at fair value on the date the contract
is entered into, and is subsequently remeasured to fair value as at
each reporting date. The resulting gain or loss is recognised in profit or
loss immediately unless the derivative is designated and effective as
a hedging instrument, in which event the timing of the recognition in
profit or loss depends on the nature of the hedge relationship.
Hedge accounting
All hedges are classified as cash flow hedges, which hedges exposure
to variability in cash flows that is either attributable to a particular
risk associated with a recognised asset or liability, or a component of a
recognised asset or liability, or a highly probable forecasted transaction.
At the inception of the hedge relationship, the Group documents
the relationship between the hedging instrument and the hedged
item, along with its risk management objectives and its strategy for
undertaking various hedge transactions. Furthermore, at the inception
of the hedge and on an ongoing basis, the Group documents whether
the hedging instrument is effective in offsetting changes in fair values
or cash flows of the hedged item attributable to the hedged risk, which
is when the hedging relationships meet all of the following hedge
effectiveness requirements:
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there is an economic relationship between the hedged item and the
hedging instrument;
the effect of credit risk does not dominate the value changes that
result from that economic relationship; and
the hedge ratio of the hedging relationship is the same as that
resulting from the quantity of the hedged item that the Group
actually hedges and the quantity of the hedging instrument that
the Group actually uses to hedge that quantity of hedged item.
If a hedging relationship ceases to meet the hedge effectiveness
requirement relating to the hedge ratio but the risk management
objective for that designated hedging relationship remains the same,
the Group adjusts the hedge ratio of the hedging relationship (i.e.
rebalances the hedge) so that it meets the qualifying criteria again.
The Group designates the full change in the fair value of a forward
contract (i.e. including the forward elements) as the hedging instrument
for all of its hedging relationships involving forward contracts. The
Group designates only the intrinsic value of option contracts as a hedged
item, i.e. excluding the time value of the option. The changes in the fair
value of the aligned time value of the option are recognised in other
comprehensive income and accumulated in the cost of hedging reserve.
If the hedged item is transaction related, the time value is reclassified
to profit or loss when the hedged item affects profit or loss. If the
hedged item is time period related, then the amount accumulated in
the cost of hedging reserve is reclassified to profit or loss on a rational
basis - the Group applies straight line amortisation. Those reclassified
amounts are recognised in profit or loss in the same line as the hedged
item. If the hedged item is a non financial item, then the amount
accumulated in the cost of hedging reserve is removed directly from
equity and included in the initial carrying amount of the recognised non
financial item. Furthermore, if the Group expects that some or all of the
loss accumulated in cost of hedging reserve will not be recovered in the
future, that amount is immediately reclassified to profit or loss.
Note 36 sets out details of the fair values of the derivative instruments
used for hedging purposes.
Movements in the hedging reserve in equity are detailed in Note 26.
Cash flow hedges
The effective portion of changes in the fair value of derivatives and
other qualifying hedging instruments that are designated and qualify
as cash flow hedges is recognised in other comprehensive income and
accumulated under the heading of cash flow hedging reserve, limited to
the cumulative change in fair value of the hedged item from inception
of the hedge. The gain or loss relating to the ineffective portion is
recognised immediately in profit or loss in either “other financial gains”
(Note 13) or “finance costs” (Note 12) line item.
Amounts previously recognised in other comprehensive income and
accumulated in equity are reclassified to profit or loss in the periods
when the hedged item affects profit or loss, in the same line as
the recognised hedged item. However, when the hedged forecast
transaction results in the recognition of a non financial asset or a non
financial liability, the gains and losses previously recognised in other
comprehensive income and accumulated in equity are removed from
equity and included in the initial measurement of the cost of the non-
financial asset or non-financial liability. This transfer does not affect
other comprehensive income. Furthermore, if the Group expects that
some or all of the loss accumulated in the cash flow hedging reserve will
not be recovered in the future, that amount is immediately reclassified
to profit or loss.
The Group discontinues hedge accounting only when the hedging
relationship (or a part thereof) ceases to meet the qualifying criteria
(after rebalancing, if applicable). This includes instances when the
hedging instrument expires or is sold, terminated or exercised. The
discontinuation is accounted for prospectively. Any gain or loss
recognised in other comprehensive income and accumulated in cash
flow hedge reserve at that time remains in equity and is reclassified
to profit or loss when the forecast transaction occurs. When a forecast
transaction is no longer expected to occur, the gain or loss accumulated
in cash flow hedge reserve is reclassified immediately to profit or loss.
Equity and Listing Costs
Ordinary shares are classified as equity and recorded at the value of
consideration received. The cost of issuing shares is shown in share
capital as a deduction, net of tax, from the proceeds.
Incremental and direct attributable costs that specifically relate to the
admission of the Company into AIM and the issuance of new shares
are recorded in profit or loss. Remaining costs that relate jointly to both
the AIM admission and the new shares issuance are allocated on a
proportionate basis in accordance with IAS 32.
Fair Value Estimation of Financial Assets and Liabilities
The fair value of current financial assets and liabilities carried at
amortised cost, approximate their carrying amounts, as the effect of
discounting is immaterial.
Share-Based Payments
Share-based incentive arrangements are provided to employees which
allow them to acquire shares of the Company.
The fair value of options granted is recognised as an employee expense
with a corresponding increase in equity.
Share options are valued at the date of grant using the Black-Scholes
pricing model, and are charged to operating costs over the vesting period
of the award. The charge is modified to take account of options granted
to employees who leave the Group during the vesting period and forfeit
their rights to the share options, and in the case of non-market related
performance conditions, where it becomes unlikely they will vest. At
the end of the reporting period, the Group revises its estimates of the
number of equity instruments expected to vest. The impact of the
revision of the original estimates, if any, is recognised in profit or loss
such that the cumulative expense reflects the revised estimate, with a
corresponding adjustment to the share options reserve.
Equity-settled share-based payment transactions with parties other
than employees are measured at the fair value of goods or services
received, except where that fair value cannot be estimated reliably, in
which case they are measured at the fair value of the equity instruments
granted, measured at the date at which the entity obtains the goods or
the counterparty renders the service.
Leases
The Group has applied IFRS 16 using the cumulative catch-up approach
and therefore comparative information has not been restated and is
presented under IAS 17. The details of accounting policies under both IAS
17 and IFRS 16 are presented separately below.
Policies applicable from January 1, 2019
The Group as lessee
The Group assesses whether a contract is or contains a lease, at
inception of the contract. The Group recognises a right-of-use asset and
a corresponding lease liability with respect to all lease arrangements in
which it is the lessee, except for short-term leases (defined as leases
with a lease term of 12 months or less) and leases of low value assets
(such as personal computers, small items of office furniture and
telephones). For these leases, the Group recognises the lease payments
as an operating expense on a straight-line basis over the term of the
lease unless another systematic basis is more representative of the
time pattern in which economic benefits from the leased assets are
consumed.
The lease liability is initially measured at the present value of the lease
payments that are not paid at the commencement date, discounted
by using the rate implicit in the lease. If this rate cannot be readily
determined, the lessee uses its incremental borrowing rate.
Lease payments included in the measurement of the lease liability
comprise fixed lease payments (including in-substance fixed payments).
The lease liability is presented as a separate line in the consolidated
statement of financial position.
The lease liability is subsequently measured by increasing the carrying
amount to reflect interest on the lease liability (using the effective
interest method) and by reducing the carrying amount to reflect the
lease payments made.
The Group remeasures the lease liability (and makes a corresponding
adjustment to the related right-of-use asset) whenever:
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The lease term has changed or there is a significant event or change
in circumstances resulting in a change in the assessment of exercise
of a purchase option, in which case the lease liability is remeasured
by discounting the revised lease payments using a revised discount
rate.
The lease payments change due to changes in an index or rate or
a change in expected payment under a guaranteed residual value,
in which cases the lease liability is remeasured by discounting the
revised lease payments using an unchanged discount rate (unless
the lease payments change is due to a change in a floating interest
rate, in which case a revised discount rate is used).
A lease contract is modified and the lease modification is not
accounted for as a separate lease, in which case the lease liability
is remeasured based on the lease term of the modified lease by
discounting the revised lease payments using a revised discount
rate at the effective date of the modification.
The Group did not make any such adjustments during the periods
presented.
The right-of-use assets comprise the initial measurement of the
corresponding lease liability, lease payments made at or before the
commencement day, less any lease incentives received and any initial
direct costs. They are subsequently measured at cost less accumulated
depreciation and impairment losses.
Whenever the Group incurs an obligation for costs to dismantle and
remove a leased asset, restore the site on which it is located or restore
the underlying asset to the condition required by the terms and
conditions of the lease, a provision is recognised and measured under
IAS 37. To the extent that the costs relate to a right-of-use asset, the
costs are included in the related right-of-use asset, unless those costs
are incurred to produce inventories.
Right-of-use assets are depreciated over the shorter period of lease term
and useful life of the underlying asset. If a lease transfers ownership of
the underlying asset or the cost of the right-of-use asset reflects that
the Group expects to exercise a purchase option, the related right-of-
use asset is depreciated over the useful life of the underlying asset. The
depreciation starts at the commencement date of the lease.
The right-of-use assets are presented as a separate line in the
consolidated statement of financial position.
The Group applies IAS 36 to determine whether a right-of-use asset
is impaired and accounts for any identified impairment loss as described
in the “Impairment of Assets” policy.
As a practical expedient, IFRS 16 permits a lessee not to separate non-
lease components, and instead account for any lease and associated
non-lease components as a single arrangement. The Group has not used
this practical expedient. For contracts that contain a lease component
and one or more additional lease or non-lease components, the Group
allocates the consideration in the contract to each lease component on
the basis of the relative stand-alone price of the lease component and
the aggregate stand-alone price of the non-lease components.
Policies applicable prior to January 1, 2019
Leases are classified as finance leases whenever the terms of the lease
transfer substantially all the risks and rewards of ownership to the
lessee. All other leases are classified as operating leases.
Jadestone Energy 2019 Annual Report
80
Significant Accounting Policies and
Explanation Notes to the Financial Statements for the years ended December 31, 2019 and December 31, 2018
81
The Group as lessee
Rentals payable under operating leases are charged to profit or loss on
a straight-line basis over the term of the relevant lease unless another
systematic basis is more representative of the time pattern in which
economic benefits from the leased asset are consumed. Contingent
rentals arising under operating leases are recognised as an expense in
the period in which they are incurred.
In the event that lease incentives are received to enter into operating
leases, such incentives are recognised as a liability. The aggregate
benefit of incentives is recognised as a reduction of rental expense on
a straight-line basis, except where another systematic basis is more
representative of the time pattern in which economic benefits from the
leased assets are consumed.
Provisions
Provisions are recognised when the Group has a present obligation (legal
or constructive) as a result of a past event, it is probable that the Group
will be required to settle the obligation, and a reliable estimate can be
made of the amount of the obligation.
The amount recognised as a provision is the best estimate of the
consideration required to settle the present obligation at the end of
the reporting period, taking into account the risks and uncertainties
surrounding the obligation. Where a provision is measured using the
cash flows estimated to settle the present obligation, its carrying
amount is the present value of those cash flows (when the effect of the
time value of money is material).
When some or all of the economic benefits required to settle a provision
are expected to be recovered from a third party, the receivable is
recognised as an asset if it is virtually certain that reimbursement will be
received and the amount of the receivable can be measured reliably.
Gas revenue is meter measured based on the hydrocarbon volumes
delivered. The volumes delivered over a calendar month are invoiced
based on meter readings monthly. The price is either fixed (gas) or
linked to an agreed benchmark (Brent Crude) in advance and premium or
discounts are set based on commercial negotiations at arms-length. This
methodology is considered appropriate as it is normal business practice
under such arrangements. In line with the aforementioned, revenue is
recognised at a point in time when deliveries of the gas are transferred
to the customers.
A receivable is recognised once transfer has occurred as this represents
the point in time at which the right to consideration becomes
unconditional, and only the passage of time is required before the
payment is due.
Royalties
Royalty arrangements that are based on production are recognised by
reference to the underlying arrangement.
The Group’s oil and gas operations are reflected in the profit or
loss, based on the Group’s working interest in such production.
All government stakes, other than income taxes, and including
government’s share of production, are considered to be royalties.
Royalties to government on production from these joint operations
represent the entitlement of the respective governments to a portion
of the Group’s share of oil and gas and are recorded using rates in effect
under the terms of contracts at the time of production and net of
revenue.
Income Tax
Income tax expense represents the sum of the tax currently payable and
deferred tax.
Retirement Benefit Obligations
Payments to defined contribution retirement benefit plans are charged
as an expense as and when employees have tendered the services
entitling them to the contributions. Payments made to state-managed
retirement benefit schemes, such as Malaysia’s Employees Provident
Fund, are dealt with as payments to defined contribution plans where
the Group’s obligations under the plans are equivalent to those arising in
a defined contribution retirement benefit plan. The Group does not have
any defined benefit plans.
Current tax
The tax currently payable is based on taxable profit for the year. Taxable
profit differs from profit as reported in the statement of profit or loss
and other comprehensive income, because it excludes items of income
or expense that are taxable or deductible in other years and it further
excludes items that are not taxable or tax deductible. The Group’s
liability for current tax (and tax laws) is calculated using tax rates that
have been enacted or substantively enacted, in countries where the
Company and its subsidiaries operate, by the end of the reporting period.
Revenue
Revenue from contracts with customers is recognised in the income
statement when performance obligations are considered met, which is
when control of the hydrocarbons are transferred to the customer.
Revenue from the production of oil and gas, in which the Group has
an interest with other producers, is recognised based on the Group’s
working interest and the terms of the relevant production sharing
contracts.
Production revenue (liquids revenue) is recognised when the Group
gives up control of the unit of production at the delivery point agreed
under the terms of the contract. This generally occurs when the
product is physically transferred into a vessel, pipe or other delivery
mechanism. The amount of production revenue recognised is based
on the agreed transaction price and volumes delivered. In line with the
aforementioned, revenue is recognised at a point in time when deliveries
of the liquids are transferred to the customers.
Petroleum resource rent tax (PRRT)
PRRT incurred in Australia is considered for accounting purposes to be a
tax based on income. Accordingly, current and deferred PRRT expense is
measured and disclosed on the same basis as income tax.
Deferred tax
Deferred tax is recognised on temporary differences between the
carrying amounts of assets and liabilities in the financial statements
and the corresponding tax bases used in the computation of taxable
profit. Deferred tax liabilities are generally recognised for all taxable
temporary differences and deferred tax assets are recognised to the
extent that it is probable that taxable profits will be available, against
which deductible temporary differences can be utilised. Such deferred
tax assets and liabilities are not utilised if the temporary difference
arises from goodwill or from the initial recognition (other than in a
business combination) of other assets and liabilities in a transaction
that affects neither the taxable profit nor the accounting profit.
Deferred tax liabilities are recognised for taxable temporary differences
arising on investments in subsidiaries, except where the Group is able to
control the reversal of the temporary difference and it is probable that
the temporary difference will not reverse in the foreseeable future.
Deferred tax assets arising from deductible temporary differences
associated with such investments and interests, are only recognised to
the extent that it is probable that there will be sufficient taxable profits
against which to utilise the benefits of the temporary differences and
they are expected to reverse in the foreseeable future.
The carrying amount of deferred tax assets is reviewed at the end of
each reporting period and reduced to the extent that it is no longer
probable that sufficient taxable profits will be available to allow all or
part of the asset to be recovered.
Deferred tax is calculated at the tax rates that are expected to apply in
the period when the liability is settled, or the asset realised, based on
the tax rates (and tax laws) that have been enacted or substantively
enacted, by the end of the reporting period. The measurement of
deferred tax liabilities and assets reflects the tax consequences that
would follow from the manner in which the Group expects, at the end
of the reporting period, to recover or settle the carrying amount of its
assets and liabilities.
Deferred tax assets and liabilities are offset when there is a legally
enforceable right to set off current tax assets against current tax
liabilities and when they relate to income taxes levied by the same
taxation authority and the Group intends to settle its current tax assets
and liabilities on a net basis.
Current and deferred tax for the year
Current and deferred tax are recognised as an expense or income in profit
or loss, except when they relate to items credited or debited outside
profit or loss (either in other comprehensive income or directly in equity),
in which case the tax is also recognised outside profit or loss (either in
other comprehensive income or directly in equity, respectively).
Cash And Bank Balances In The Statement Of Cash Flows
Cash and bank balances comprise cash in hand and at bank and other
short-term deposits held by the Group with maturities of less than
three months.
3 | Critical Accounting Judgments and
Key Sources of Estimation Uncertainty
In the application of the Group’s accounting policies, management is
required to make judgments, estimates and assumptions about the
carrying amounts of assets and liabilities that are not readily apparent
from other sources. The estimates and associated assumptions are
based on historical experience and other factors that are considered to
be relevant. Actual results may differ from these estimates.
The estimates and underlying assumptions are reviewed on an ongoing
basis. Revisions to accounting estimates are recognised in the period
in which the estimate is revised, if the revision affects only that period,
or in the period of the revision and future periods if the revision affects
both current and future periods.
The following are the critical judgements, apart from those involving
estimates (see below), that management has made on the process of
applying the Group’s accounting policies that have the most significant
effect on the amounts recognised in the financial statements.
a) Acquisitions, divestitures, farm-in arrangements and/or
assignment of interests
The Group accounts for acquisitions, divestitures, and farm-in
arrangements by considering if the acquired or transferred interest
relates to that of an asset, or of a business as defined in IFRS 3
Business Combinations. Accordingly, the Group considers if there
is the existence of business elements (e.g., inputs, processes and
outputs) or a group of assets that includes inputs, outputs and
processes that are capable of being managed together for providing
a return to investors or other economic benefits.
The Group considers farm-in arrangements that pertain to
exploration interests, with no production license, and no proved
reserves, to be assets, rather than a business, and would account
for such farm-ins based on the consideration paid, which would
be capitalised as an intangible exploration asset and subject to
impairment reviews.
Key sources of estimation uncertainty
The key assumptions concerning the future, and other key sources of
estimation uncertainty at the end of the reporting period, that have
a significant risk of causing a material adjustment to the carrying
amounts of assets and liabilities within the next financial year, are
discussed below.
a) Contingent consideration
The determination of the contingent liability components
requires significant management judgement and assumptions.
The contingent payments are based on multiple future triggering
events that may or may not occur. The Group assesses these
factors independently taking into account probabilities and future
circumstances. Where management deems necessary, independent
valuation models and advisors will be requested to determine the
fair value of such commitments. All contingent payments are set
out in Note 7.4.
Jadestone Energy 2019 Annual Report
82
Significant Accounting Policies and
Explanation Notes to the Financial Statements for the years ended December 31, 2019 and December 31, 2018
Impairment of assets
The Group undertakes a regular review of asset carrying values
to determine whether there is any indication of impairment. For
intangible exploration assets impairment assessment, the Group
takes into consideration the technical feasibility and commercial
viability of extracting a mineral resource and whether there is any
adverse information that will affect the final investment decision.
For oil and gas properties, expected future cash flow estimation
is based on reserves, future production profiles, commodity prices
and costs. For right-of-use assets, the Group applies IAS 36 to
determine whether a right-of-use asset is impaired and accounts
for any identified impairment loss as described in the ‘Impairment
of Assets’ policy. The carrying amounts of intangible exploration
assets, oil and gas properties and right-of-use assets are disclosed
in Notes 16, 17 and 19, respectively.
f) Asset restoration obligations
The Group estimates the future removal and restoration costs of oil
production facilities, wells, pipelines and related assets at the time
of installation of the assets and reviewed subsequently at the end
of each reporting period. In most instances the removal of these
assets will occur many years in the future.
The estimate of future removal costs is made considering relevant
legislation and industry practice and requires management to make
judgments regarding the removal date, the extent of restoration
activities required and future removal technologies. The carrying
amounts of the Group’s asset restoration obligations is disclosed
in Note 28 to the financial statements.
b) Depletion of oil and gas properties
e)
Oil and gas properties are depleted using the units of production
method.
Estimates of the Group’s oil and gas reserves are inherently
uncertain. Proved plus probable reserves are the estimated volumes
of crude oil and natural gas which geological and engineering data
demonstrate that are most likely to be economically producible,
from known reservoir under existing economic conditions and
operating method. Changes in proved plus probable oil and gas
reserves, and the associated expected development capital, will
affect units of production depletion in the Group’s consolidated
financial statements for oil and gas properties. Proved plus oil and
gas reserves are subject to revision, based on new information,
such as from development drilling and production activities, or from
changes in economic factors, including product prices, contract
terms, evolution of technology or development plans, etc.
The carrying amount and depletion amount of oil and gas properties
are disclosed in Note 17 and Note 6, respectively.
c) Taxes
The Group recognises the net future economic benefit of deferred
tax assets to the extent that it is probable that the deductible
temporary differences will reverse in the foreseeable future and
the carry forward of unutilised tax credits and unutilised tax losses
can be utilised accordingly. Assessing the recoverability of deferred
income tax and PRRT assets requires the Group to make significant
estimates related to expectations of future taxable income.
Estimates of future taxable income are based on forecast cash
flows from operations and the application of existing tax laws in
each jurisdiction. To the extent that future cash flows and taxable
income differ significantly from estimates, the ability of the Group
to realise the net deferred tax assets as recorded in the statement
of financial position, could be impacted. The carrying amounts
of the Group’s deferred tax assets are disclosed in Note 21 to the
financial statements.
d) Reserves estimates
The estimated reserves are management assessments, and take
into consideration reviews by an independent third party, under the
Group’s reserves audit programme, as well as other assumptions,
interpretations and assessments. These include assumptions
regarding commodity prices, exchange rates, discount rates,
future production and transportation costs, and interpretations
of geological and geophysical models to make assessments of the
quality of reservoirs and their anticipated recoveries. Changes in
reported reserves can impact asset carrying values, the provision
for restoration and the recognition of deferred tax assets, due to
changes in expected future cash flows. Reserves are integral to the
amount of depreciation, depletion and amortisation charged to the
statement of profit or loss and other comprehensive income, and
the calculation of inventory.
4 | Revenue
The Group derives its revenue from contracts with customers for the sale of oil and gas products. Revenue is presented net of royalties.
In line with the revenue accounting policies set out in Note 2, all revenue is recognised at a point in time.
Liquids revenue, after hedging
Stag
Montara
Ogan Komering
Gas revenue
Ogan Komering
Royalties
Total revenue derived from contracts with customers, after hedging and
net of royalties
2019
USD’000
65,181
260,225
-
-
325,406
-
325,406
83
2018
USD’000
74,772
31,198
8,520
2,482
116,972
(3,549)
113,423
Royalties in 2018 related to production entitlement in Indonesia. The Ogan Komering PSC expired on May 20, 2018 and hence no revenue and no
production royalty entitlement is recognised in the current year.
5 | Production Costs
Operating costs
Workovers
Logistics
Repairs and maintenance
Movement in inventories
2019
USD’000
52,527
30,331
20,635
23,742
(7,337)
119,898
2018
USD’000
48,887
10,577
9,034
5,117
17,324
90,939
The cost of inventories recognised in production costs is US$92.4 million
(2018: US$61.0 million). In 2018, the Group had written down crude oil
amounting to US$3.4 million to its net realisable value. The write down
amount was recognised in production costs. There were no inventories
write-down in FY2019.
The Group has adopted IFRS 16, effective January 1, 2019. The Group has
recognised depreciation of right-of-use assets in 2019, as disclosed in
Note 6. The lease payments paid were offset against lease liabilities.
The Group has applied the cumulative catch-up approach and did not
restate comparatives. The lease payments included in 2018 operating
costs were US$6.8 million.
The Montara assets were acquired on September 28, 2018. The
production costs for 2018 include Montara’s production costs of US$42.7
million from the date of acquisition until the year end, compared to a full
year for 2019 of US$84.4 million.
The Ogan Komering PSC expired on February 28, 2018 and a temporary
co-operation contract was entered into, continuing the terms of the PSC.
A new PSC was issued on May 20, 2018 to Pertamina, at which point
Jadestone no longer held an interest in the PSC. Included in the total
production cost of US$90.9 million in 2018 is US$2.8 million related
to Ogan Komering (Note 38).
Jadestone Energy 2019 Annual Report 84
Significant Accounting Policies and
Explanation Notes to the Financial Statements for the years ended December 31, 2019 and December 31, 2018
6 | Depletion, Depreciation and Amortisation (“DD&A”)
Depletion and amortisation (Note 17):
Stag
Montara
Ogan Komering
Depreciation:
Plant and equipment (Note 18)
Right-of-use assets (Note 19)
Movement in inventories
2019
USD’000
10,237
73,449
-
83,686
427
14,876
(8,243)
90,746
2018
USD’000
8,614
4,768
618
14,000
376
-
(600)
13,776
The Montara assets were acquired on September 28, 2018 and were shut down to address a maintenance and inspection backlog from November 1, 2018
to January 11, 2019. The depletion charge for the oil and gas properties for the comparative period related to the production from September 28
to October 31, 2018, compared to a full year for 2019.
The Ogan Komering DD&A charge in 2018 related to the production from January 1 to May 19, 2018, after which the Group no longer held an interest
in the PSC.
7 | Acquisition of Montara Assets
7.1 Effective date and acquisition date
In 2018, Jadestone Energy (Eagle) Ltd, a wholly owned subsidiary of the Company, closed the acquisition of the Montara Assets from PTTEP Australia,
obtaining control and 100% of legal ownership.
The transaction had an economic effective date of January 1, 2018, at which point the economic benefits of owning the Montara Assets passed to
the Group. The transaction closed on September 28, 2018 (the Acquisition Date) at which point the Group obtained ownership and control of the
Montara assets. On May 30, 2019 the regulator approved the transfer of 99% of the legal title in the license. On August 6, 2019, the transfer of
operatorship was completed and on October 1, 2019, the final 1% of legal title of the license was approved and the transaction was completed.
As the Group took control of the operating decisions of the Montara assets on September 28, 2018, this is the date used for the purpose of calculating
the purchase price allocation and the fair value of the assets and liabilities recorded in the statement of financial position.
7.2 Fair value of consideration transferred and purchase price allocation adjustments
On September 28, 2018, the consideration for the Montara Assets reflected a cash payment of US$133.1 million as set out below:
Asset purchase price
Crude inventory value
Capital charge
Net cash adjustment (from January 1, 2018 to the date of acquisition)
Cash payment on acquisition date
USD’000
195,000
6,657
6,982
(75,547)
133,092
85
The crude inventory value relates to the inventory on hand at the effective date of January 1, 2018. The capital charge reflects interest on the asset
purchase price of US$195.0 million calculated on a daily basis at a rate of 3% above LIBOR from (and including) the effective date to (but excluding) the
date of completion. The net cash adjustment reflects the net of the interim period receipts and expenses incurred, invoiced or paid by PTTEP Australia
in the period from the effective date to the date of completion.
In addition, there were deferred contingent payments payable, in addition to the upfront cash consideration set out above, depending on the outcome
of a number of trigger events. The trigger events are linked to 2018 production volumes, future Dated Brent oil prices in 2019 and 2020, production
from the infill well drilling scheduled for 2020 and final investment decision for developments with significant 2P reserves. The Group reviewed all the
contingent payments, and at the date of acquisition recorded an amount of US$15.8 million at fair value for the following two contingent events:
-
-
Annual average Dated Brent crude price exceeding US$80/bbl in 2019: US$20.0 million; and
Annual average Dated Brent crude price exceeding US$80/bbl in 2020: US$10.0 million.
Management has assessed the fair value of the above contingent consideration using a Monte Carlo option simulation model, which considered inputs
such as the spot Dated Brent oil price at completion date, the risk-free rate, volatility of Dated Brent oil price, and the length of time the contingent
payment will apply. This implies the fair value of the contingent consideration to be US$10.8 million and US$5.0 million for the 2019 and 2020 deferred
payments, respectively, totalling US$15.8 million in 2018. This reflected a discount of 46% and 50% for the respective 2019 and 2020 contingent
consideration payments arising from the time value of money and the likelihood of the trigger event occurring. During the year, the Group has
derecognised the 2019 deferred contingent payment as the annual average Dated Brent crude price in 2019 fell below US$80/bbl. Please refer to
Note 7.4 for the full disclosure of all the other contingent payments and management’s assessment therein. As at December 31, 2019, the fair value
of the 2020 contingent payment has been reduced to US$0.4 million (2018: US$3.7 million) (Note 30) as a result of the declining forward curve Dated
Brent crude oil price.
The voluntary shutdown that occurred at Montara from November 1, 2018 to January 11, 2019 resulted in a loss of production and revenue during the
period, as well as an increase in costs due to overheads still being incurred and additional maintenance work required to rectify historic maintenance and
inspection issues. As a result, on January 7, 2019, PTTEP Australia and the Group agreed that PTTEP Australia would fund cash calls capped at US$22.0
million. Management believes that the shutdown was a result of facts and circumstances that existed as at the acquisition date. As such, the US$22.0
million has been adjusted against the consideration transferred for the Montara Assets.
During the year, the Group has completed the purchase price allocation (“PPA”) exercise to determine the fair values of the net assets acquired within
the stipulated time period of 12 months from the acquisition date of September 28, 2018, in accordance with IFRS 3 Business Combinations. Following
the transfer of operatorship on August 6, 2019, the Group was able to confirm an inventory adjustment of US$14.0 million in order to align with the
Group’s accounting policies. The adjusted fair values of identifiable assets and liabilities have been reflected in the consolidated statement of financial
position as at December 31, 2018.
Below are the effects of the final PPA adjustments in accordance with IFRS 3:
FAIR VALUE OF PURCHASE CONSIDERATION
PROVISIONAL PPA
USD’000
ADJUSTMENTS
USD’000
FINAL PPA
USD’000
Asset purchase price
Crude inventory value
Capital charge
Net cash adjustment
Cash payment on acquisition date
Deferred contingent consideration
Prepaid asset for future cash calls
Working capital adjustment
Total
195,000
6,657
6,982
(75,547)
133,092
15,805
(22,000)
997
127,894
-
-
-
-
-
-
-
819
819
195,000
6,657
6,982
(75,547)
133,092
15,805
(22,000)
1,816
128,713
Jadestone Energy 2019 Annual Report
86
Significant Accounting Policies and
Explanation Notes to the Financial Statements for the years ended December 31, 2019 and December 31, 2018
Assets acquired and liabilities assumed at the date of acquisition:
Asset
Non-current assets
Oil & gas properties
Current assets
Inventories
Prepayments
Total assets
Liabilities
Current liabilities
Trade and other payables
Non-current liabilities
Provision for asset restoration obligations
Deferred tax liabilities
Other provisions
Total liabilities
Net identifiable assets acquired
PROVISIONAL PPA
USD’000
ADJUSTMENTS
USD’000
FINAL PPA
USD’000
353,806
35,373
4,917
394,096
(4,314)
(183,020)
(78,437)
(431)
(266,202)
127,894
14,828
(14,009)
-
819
-
-
-
-
-
819
368,634
21,364
4,917
394,915
(4,314)
(183,020)
(78,437)
(431)
(266,202)
128,713
Please refer to Note 43 for a summary of the adjustment of comparative figures.
7.3 Impact of acquisition on the results of the Group
Included in 2018 revenue for the year and 2018 loss after tax for the year, were US$31.2 million and US$4.2 million, respectively, that were both
attributable from the Montara Assets.
Acquisition-related costs amounting to US$1.8 million have been excluded from the consideration transferred and have been recognised as an expense
in the comparable period, within “other expenses” (Note 9) in the consolidated statement of profit or loss and other comprehensive income.
Had the business combination been effected as at January 1, 2018, and based on the performance of the business during 2018 under PPTEP Australia’s
operatorship, the Group would have generated revenues of US$257.2 million and an estimated net loss after tax of US$4.8 million in 2018.
Management of the Group considers these “pro-forma” numbers to represent an approximate measure of the performance of the combined Group on
an annualised basis and to provide a reference point for comparison in future periods.
7.4 Contingent consideration
NO.
TRIGGER EVENT
CONSIDERATION
MANAGEMENT’S RATIONALE
8 | Staff Costs
Wages, salaries and fees
Staff benefits in kind
Share-based compensation
87
2019
USD’000
13,764
4,468
1,482
19,714
2018
USD’000
10,555
2,463
520
13,538
The above staff cost includes director’s and non-executive directors’ salaries and fees.
Headcount has increased during the year from 80 people to 197 people at the end of the year predominantly due to additional headcount required in
Australia and in Vietnam as the Group prepared for project sanction of Nam Du and U Minh.
9 | Other Expenses
Professional fees/consultancies
Office costs
Travel and entertainment
Net loss on ineffective oil derivatives
Oil and gas properties written off
Net foreign exchange loss
Other expenses
2019
USD’000
6,510
2,194
834
633
533
173
815
11,692
2018
USD’000
6,568
2,774
811
-
-
-
221
10,374
The Group has adopted IFRS 16, effective January 1, 2019. The Group has recognised depreciation for right-of-use assets in 2019 as disclosed in
Note 6. The lease payments paid were offset against lease liabilities. The Group has applied the cumulative catch-up approach and did not restate
comparatives. Lease payments included in 2018 office costs were US$0.9 million.
10 | Impairment of Assets
2019
USD’000
-
2018
USD’000
11,901
1.
2.
3.
4.
5.
The average Dated Brent price in the calendar
year 2019 is US$80/bbl or higher
US$20 million
Reversed during the year as the event was not triggered.
Impairment of intangible exploration assets (Note 16)
The average Dated Brent price in the calendar
year 2020 is US$80/bbl or higher
US$10 million
Montara infill well production is equal to
or greater than 1.5mm bbls in the first 12
months after start of commercial production
First commercial gas
FID of development of new wells within
Montara titles with 2P reserves greater than
15.0mm bbls
US$20 million
US$20 million
US$60 million
The fair value has been reduced to US$0.4 million as a result
of declining Dated Brent crude oil price and the likelihood of
the trigger event occurring.
It is unlikely that the infill well production will be equal or
greater than 1.5mm bbls in the first 12 months based on
current projections. As such, fair value is assessed to be nil.
The Group has no plans to produce gas from Montara as at
the date of these financial statements.
The Group has no substantive plans to drill new wells, aside
from infill well drilling as at the date of these financial
statements.
In 2018, a review of exploration assets resulted in management deciding to impair and relinquish Block 127 in Vietnam at the end of its exploration
phase, in May 2018. All minimum work commitments had been completed and the Group returned the license and officially relinquished the block
in October 2018. The total capitalised exploration expenditure in respect of Block 127 of US$11.9 million was charged to profit or loss as an
impairment expense.
Jadestone Energy 2019 Annual Report 88
Significant Accounting Policies and
Explanation Notes to the Financial Statements for the years ended December 31, 2019 and December 31, 2018
11 | Other Income
Interest income
Change in Stag FSO provision
Net foreign exchange gain
Net gain on ineffective oil derivatives
12 | Finance Costs
Interest expense
Accretion expense for asset retirement obligations (Note 28)
Interest expense on lease liabilities
Accretion expense for Stag FSO provision
Convertible bond facility fees (Note 32)
Bond accretion (Note 32)
Fair value loss on derivative liability (Note 32)
Other finance costs
2019
USD’000
1,260
1,717
2
-
2,979
2019
USD’000
6,067
5,842
4,280
110
-
-
-
144
16,443
2018
USD’000
422
835
640
637
2,534
2018
USD’000
2,968
3,632
-
179
560
706
1,195
-
9,240
14 | Income Tax Expense
Current tax
Corporate tax
Petroleum resource rent tax (“PRRT”)
Deferred tax
Tax depreciation
Tax losses
PRRT
89
2018
USD’000
(2,188)
(6,221)
(8,409)
(3,196)
2,812
(774)
(1,158)
(9,567)
2019
USD’000
(43,370)
1,850
(41,520)
20,285
(5,257)
(6,284)
8,744
(32,776)
The Australian corporate income tax rate is applied at 30%. PRRT is calculated at 40% of sales revenue less certain permitted deductions and is tax
deductible for Australian corporate income tax purposes. The Indonesian corporate income tax rate is applied at 35%. Indonesian branch profit tax
is applied at 20%.
The above movement in deferred tax balances relates to temporary differences between the tax base of an asset or liability, and its carrying amount
in the statement of financial position.
During the year, Stag utilised PRRT carried forward credits of US$1.1 million (2018: US$5.8 million) and incurred a net expense of US$ 4.4 million
(2018: US$7.0 million). The Montara field has utilised PRRT carried forward credits of US$21.5 million and currently has US$3.1 billion (2018: US$2.9
billion) based on the Montara field’s latest forecasted augmentation by management which is available for offset against future PRRT taxable profit,
and so it is not anticipated to incur any liability for the foreseeable future.
The accretion expense for asset retirement obligations for the Stag field and the Montara field recognised in 2019 has increased to US$5.8 million from
US$3.6 million in 2018, reflecting a full year charge at Montara for 2019, as compared to 2018 for the period from September 28, 2018 to year end.
The Company is a resident in the Province of British Columbia and pays no Canadian tax; the Group has no operating business in Canada. Subsidiaries
are resident for tax purposes in the territories in which they operate.
The Group has adopted IFRS 16, effective from January 1, 2019. Consequently, the Group has recognised interest expense on lease liabilities in 2019.
The Group has applied the cumulative catch-up approach and did not restate comparatives. Lease payments made in 2018 were included in Note 5
and Note 9.
Interest expense includes interest incurred on the reserve based lending facility of US$6.1 million (2018: US$2.4 million), reflecting a full year charge
in 2019 as compared to 2018 for the period from September 28, 2018 to year end. Interest expense in 2018 also included interest incurred on the Tyrus
bond, which was repaid in August 2018, of US$0.6 million.
13 | Other Financial Gains
Change in provisions - Montara contingent payments
Gain on early repayment of convertible bonds
2019
USD’000
3,389
-
3,389
2018
USD’000
12,057
288
12,345
The change in provisions represents the reduction in the fair value of the Montara contingent payments. The consideration to PTTEP Australia included
two potential contingent payments which at the date of acquisition had a fair value of US$15.8 million (see Note 7.4). The Group has derecognised the
2019 contingent payment as the average Dated Brent crude oil price in 2019 fell below US$80/bbl. The fair value of the remaining contingent payment
has been reduced to US$0.4 million (2018: US$3.7 million), reflecting the lower forward curve for Dated Brent crude oil prices, and hence the lower
likelihood of exceeding US$80/bbl in 2020.
The tax expense on Group’s profit/(loss) differ from the amount that would arise using the standard rate of income tax applicable in the countries
of operation as explained below:
Profit/(Loss) before tax
Tax calculated at the domestic tax rates applicable to the profit/loss in
the respective countries (Australia 30%, Indonesia 48%*, Canada 27%
and Singapore 17%)
Effects of non-deductible expenses
PRRT tax benefit/(expense)
Effect of PRRT tax (expense)/benefit
Tax expense for the year
2019
USD’000
73,281
(23,190)
(5,152)
6,284
(10,718)
(32,776)
2018
USD’000
(21,446)
2,364
(7,013)
(6,995)
2,077
(9,567)
* The Indonesian tax rate is based on the effective rate after taking into account the corporate tax rate of 35% and the branch profit tax of 20%.
In addition to the amount charged to the profit or loss, the following amounts relating to tax have been recognised in other comprehensive income.
Other comprehensive income - deferred tax
Income tax (credit)/expense related to carrying amount of hedged item
2019
USD’000
(13,624)
2018
USD’000
15,207
Jadestone Energy 2019 Annual Report 90
Significant Accounting Policies and
Explanation Notes to the Financial Statements for the years ended December 31, 2019 and December 31, 2018
15 | Earnings/(Loss) Per Ordinary Share
The calculation of the basic and diluted profit/(loss) per share is based on the following data:
16 | Intangible Exploration Assets
Profit/(Loss) for the purposes of basic and diluted per share, being the
net profit/(loss) for the year attributable to equity holders of the Company
2019
USD’000
40,505
2018
USD’000
(31,033)
Cost
As at January 1, 2018
Additions
Disposals
2019
NUMBER OF SHARES
2018
NUMBER OF SHARES
As at December 31, 2018/January 1, 2019
Additions
Weighted average number of ordinary shares for the purposes of basic EPS
Effect of diluted potential ordinary shares - share options
461,040,802
2,512,719
316,525,850
-
Weighted average number of ordinary shares for the purposes
of dilutive EPS
463,553,521
316,525,850
The calculation of diluted EPS for 2019 includes 2,512,719 of weighted average dilutive ordinary shares available for exercise from in-the-money vested
options (2018: 400,264 of weighted average potential ordinary shares available for exercise from in-the-money vested options are excluded, as they
are non-dilutive given the Group’s loss from operations). Additionally, 607,821 of weighted average potential ordinary shares available for exercise are
excluded, as they are out-of-the-money (2018: 546,973).
In 2018, the calculation of diluted EPS excludes 74,668,968 of potential ordinary shares eligible for conversion under the secured convertible bond as
they are non-dilutive given the interest and other costs on the bond per share exceed basic loss per share. The secured convertible bond was fully repaid
on August 15, 2018. Additionally, 2,631,982 of weighted potential ordinary shares available for exercise under vested options are not included given the
Group’s loss from continuing operations in 2018.
EARNINGS PER SHARE (US$)
- Basic
- Diluted
2019
0.09
0.09
2018
(0.10)
(0.10)
As at December 31, 2019
Impairments
As at January 1, 2018
Additions
Disposals
As at December 31, 2018/January 1, 2019/December 31, 2019
Net book value
As at December 31, 2018
As at December 31, 2019
For the purpose of the consolidated statement of cash flows, intangible exploration assets of US$8.9 million remained unpaid as at December 31, 2019
(2018: US$0.7 million).
91
TOTAL
USD’000
193,294
1,835
(99,522)
95,607
20,489
116,096
87,621
11,901
(99,522)
-
95,607
116,096
Jadestone Energy 2019 Annual Report 92
Significant Accounting Policies and
Explanation Notes to the Financial Statements for the years ended December 31, 2019 and December 31, 2018
93
17 | Oil and Gas Properties
19 | Right-of-Use Assets
Cost
As at January 1, 2019
Additions
As at December 31, 2019
Accumulated depreciation
As at January 1, 2019
Charge for the year
As at December 31, 2019
Net book value
As at December 31, 2019
PRODUCTION
ASSETS
USD’000
TRANSPORTATION
AND LOGISTICS
USD’000
BUILDINGS
USD’000
TOTAL
USD’000
29,339
-
29,339
-
5,334
5,334
3,507
38,813
42,320
-
8,519
8,519
24,005
33,801
3,004
-
3,004
-
1,023
1,023
1,981
35,850
38,813
74,663
-
14,876
14,876
59,787
The Group leases several assets including the Stag FSO, helicopters, a supply boat, logistic facilities for Montara field, and buildings. The average lease
term is 4 years.
The maturity analysis of lease liabilities is presented in Note 29.
Amount recognised in profit or loss
Depreciation expense on right-of-use assets
Interest expense on lease liabilities
Expenses relating to short-term leases
Expense relating to leases of low value assets
2019
USD’000
14,876
4,280
11,748
15
Cost
As at January 1, 2018
Arising from the acquisition of businesses (Note 7)
Fair value adjustment (Note 7)
Changes in asset restoration obligations (Note 28)
Additions
As at December 31, 2018/January 1, 2019
Changes in asset restoration obligations (Note 28)
Additions
Written off
As at December 31, 2019
Accumulated depletion and amortisation
As at January 1, 2018
Charge for the year
As at December 31, 2018/January 1, 2019
Charge for the year
Written off
As at December 31, 2019
Net book value
As at December 31, 2018
As at December 31, 2019
18 | Plant and Equipment
Cost
As at January 1, 2018
Additions
As at December 31, 2018/January 1, 2019
Additions
Disposal
As at December 31, 2019
Accumulated depreciation
As at January 1, 2018
Charge for the year
As at December 31, 2018/January 1, 2019
Charge for the year
Disposal
As at December 31, 2019
Net book value
As at December 31, 2018
As at December 31, 2019
* Due to figures rounded to nearest thousand.
TOTAL
USD’000
75,863
353,806
14,828
6,353
6,968
457,818
(8,117)
45,161
(533)
494,329
13,625
14,000
27,625
83,686
-
111,311
430,193
383,018
TOTAL
USD’000
2,204
1,437
3,641
502
(4)
4,139
1,556
376
1,932
427
-*
2,359
1,709
1,780
COMPUTER
EQUIPMENT
USD’000
FIXTURES AND
FITTINGS
USD’000
1,180
1,192
2,372
452
-
2,824
665
310
975
359
-
1,334
1,397
1,490
1,024
245
1,269
50
(4)
1,315
891
66
957
68
-*
1,025
312
290
Jadestone Energy 2019 Annual Report 94
Significant Accounting Policies and
Explanation Notes to the Financial Statements for the years ended December 31, 2019 and December 31, 2018
95
20 | Investments in Subsidiaries and Interests in Joint Operations
21 | Deferred Tax
The succeeding sections of this Note present the details of the principal subsidiaries and joint operations of the Group.
The following are the deferred tax liabilities and assets recognised by the Group and movements thereon during the current and prior reporting year.
Details of the investments in which the Group holds 20% or more of the nominal value of any class of share capital are as follows:
NAME OF THE COMPANY
Jadestone Energy (Eagle) Pty Ltd
Jadestone Energy (Australia Holdings) Pty Ltd
Jadestone Energy (Australia) Pty Ltd
Jadestone Energy (New Zealand Holdings) Ltd*
Jadestone Energy (New Zealand) Ltd*
Jadestone Energy (Ogan Komering) Ltd
Jadestone Energy (Singapore) Pte Ltd
Jadestone Energy International Holdings Inc.
Jadestone Energy Ltd
Jadestone Energy Sdn Bhd
Mitra Energy (Philippines SC- 56) Ltd
Mitra Energy (Philippines SC- 57) Ltd
Mitra Energy (Vietnam 05-1) Pte Ltd
Mitra Energy (Vietnam Nam Du) Pte Ltd
Mitra Energy (Vietnam Tho Chu) Pte Ltd
PLACE OF
INCORPORATION
% VOTING
RIGHTS AND
SHARES
HELD 2019
% VOTING
RIGHTS AND
SHARES
HELD2018
Australia
Australia
Australia
New Zealand
New Zealand
Canada
Singapore
Canada
Bermuda
Malaysia
Bermuda
BVI
Singapore
Singapore
Singapore
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
-
-
100
100
100
100
100
100
100
100
100
100
NATURE OF BUSINESS
Production oil & gas
Investment holdings
Production oil & gas
Investment holdings
Exploration
Production oil & gas
Investment holdings
Investment holdings
Investment holdings
Administration
Exploration
Exploration
Exploration
Exploration
Exploration
* Jadestone Energy (New Zealand Holdings) Ltd and Jadestone Energy (New Zealand) Ltd were incorporated on October 25, 2019 as part of the
Maari acquisition.
Details of the operations, of which all are in exploration stage except for Stag, Montara and Ogan Komering (ceased on May 20, 2018) which are in the
production stage, are as follows:
CONTRACT AREA
DATE OF EXPIRY
HELD BY
Montara Oilfield
Stag Oilfield
46/07
51
SC56
SC57
Indefinite
Aug 25, 2039
Jun 29, 2035
Jun 10, 2040
Aug 4, 2055
Sept 14, 2055
Jadestone Energy (Eagle) Pty Ltd
Jadestone Energy (Australia) Pty Ltd
Mitra Energy (Vietnam Nam Du) Pte Ltd
Mitra Energy (Vietnam Tho Chu) Pte Ltd
Mitra Energy (Philippines SC-56) Ltd
Mitra Energy (Philippines SC-57) Ltd
PLACE OF
OPERATIONS
Australia
Australia
Vietnam
Vietnam
Philippines
Philippines
2019
100
100
100
100
25
21
2018
100
100
100
100
25
21
GROUP EFFECTIVE WORKING
INTEREST % AS AT DECEMBER 31,
AUSTRALIAN
PRRT
USD’000
TAX
DEPRECIATION
USD’000
DERIVATIVES
FINANCIAL
INSTRUMENTS
USD’000
TAX LOSSES
USD’000
As at January 1, 2018
(Charged)/Credited to profit or loss
Charged to OCI
Acquisition of Montara assets
As at December 31, 2018/ January 1, 2019
(Charged)/Credited to profit or loss
Credited to OCI
As at December 31, 2019
20,273
(774)
-
-
19,499
(6,284)
-
13,215
903
(3,196)
-
(78,437)
(80,730)
20,285
-
(60,445)
-
-
(15,207)
-
(15,207)
-
13,624
(1,583)
TOTAL
USD’000
23,621
(1,158)
(15,207)
(78,437)
(71,181)
8,744
13,624
2,445
2,812
-
-
5,257
(5,257)
-
-
(48,813)
Deferred tax assets and liabilities are offset when there is a legally enforceable right to set off current tax assets against current tax liabilities and when
they relate to income taxes levied by the same taxation authority and the Group intends to settle its current tax assets and liabilities on a net basis. The
following is the analysis of the deferred tax balances (after offset) for financial reporting purposes:
Deferred tax liabilities
Deferred tax assets
2019
USD’000
(64,825)
16,012
(48,813)
2018
USD’000
(92,468)
21,287
(71,181)
At the reporting date, the Group has unutilised tax losses of US$ Nil (2018: US$17.5 million) available for offset against future profits. The Group has
unutilised PRRT credits of approximately US$3.1 billion (2018: US$2.9 billion) available for offset against future PRRT taxable profits in respect of the
Montara field. No deferred tax asset has been recognised in respect of these PRRT credits, due to management’s projections that there will continue
to be current augmentation of PRRT credits that are more than sufficient to offset against any PRRT tax to be paid. Accordingly, as PRRT credits are
utilised based on a last-in-first-out basis, the unutilised PRRT credits of approximately US$ 3.1 billion (2018: US$2.9 billion) will not be utilised given
the forecasted augmentation, and are therefore not recognised as a deferred tax asset.
22 | Inventories
Materials and spares
Crude oil inventories
2019
USD’000
8,964
22,447
31,411
2018
Restated
USD’000
8,955
6,867
15,822
Jadestone Energy 2019 Annual Report 96
Significant Accounting Policies and
Explanation Notes to the Financial Statements for the years ended December 31, 2019 and December 31, 2018
97
23 | Trade and Other Receivables
Trade receivables
Prepayments
Other receivables and deposits
PRRT receivables
GST/VAT receivables
2019
USD’000
34,007
4,754
2,311
-
1,211
42,283
2018
USD’000
57
26,831
4,857
700
355
32,800
Trade receivables represent revenues generated in Australia. The average credit period is 30 days (2018: 30 days). All outstanding receivables as at
December 31, 2019 and December 31, 2018 have been fully recovered in 2020 and 2019, respectively.
25 | Share Capital
Authorised ordinary shares
Unlimited number of ordinary voting shares with no par value.
Issued and fully paid
As at January 1, 2018
Issued during the year
As at December 31, 2018 / January 1, 2019
Issued during the year
As at December 31, 2019
NO. OF SHARES
USD’000
221,298,004
239,711,474
461,009,478
33,333
461,042,811
364,466
102,096
466,562
11
466,573
Prepayments in 2018 includes US$22.0 million from PTTEP Australia (Note 7) relating to the Montara acquisition. The amount was fully recovered via
cash calls in 2019.
In 2018, the Company was listed on AIM, a market by the London Stock Exchange. Pursuant to the listing on AIM, the Company issued 239,711,474 new
ordinary shares, raising gross proceeds of approximately £83.9 million at a price of 35 pence per share.
The Group has derivative receivables of US$0.5 million (2018: US$3.4 million) within other receivables, which have been received in full in January 2020
(2018: January 2019). There is no significant increase in credit risk since initial recognition
The costs arising from the issuance of the new shares and charged to profit or loss and equity amounted to US$2.0 million and US$5.8 million
respectively.
In 2018, Australian PRRT paid amounted to US$6.9 million, while the PRRT expense was US$6.2 million. The difference of US$0.7 million was
recognised as a PRRT receivable and was fully recovered during 2019.
No interest is charged on outstanding receivables. There are no trade receivables older than 30 days.
During the year, employee share options of 33,333 were exercised and issued at a price of CAD0.47 per share.
The Company has one class of ordinary share. Fully paid ordinary shares carry one vote per share without restriction, and carry a right to dividends
as and when declared by the Company.
24 | Cash and Bank Balances
26 | Hedging Reserves
Current assets
Cash and bank balances
Less: restricted cash
Cash and cash equivalents
Non-current assets
Cash and bank balances
Less: restricted cash
Cash and cash equivalents
Cash and cash equivalents in the consolidated statement of cash flows
2019
USD’000
81,942
(6,008)
75,934
17,477
(17,477)
-
75,934
2018
USD’000
58,064
(5,083)
52,981
23,561
(23,561)
-
52,981
At beginning of the year
Loss/(Gain) arising on changes in fair value of hedging instruments during the year
Income tax related to (loss)/gain recognised in other comprehensive income
Net gain reclassified to profit and loss
Income tax related to amounts reclassified to profit or loss
At end of the year
2019
USD’000
(35,480)
30,542
(9,162)
14,874
(4,462)
(3,688)
2018
USD’000
-
(51,775)
15,534
1,088
(327)
(35,480)
The cash flow hedge reserve represents the cumulative amount of gains and losses on hedging instruments deemed effective in cash flow hedges.
The cumulative deferred gain or loss on the hedging instrument is recognised in profit or loss only when the hedged transaction impacts the
profit or loss.
As part of the reserve based lending agreement (Note 31), the Group must retain an aggregate amount of principal, interest, fees and costs payable
at each quarter-end in the debt service reserve account (“DSRA”). An amount of US$13.5 million (2018: US$18.6 million) is deposited in the DSRA as
at December 31, 2019. In addition, the Group is required to maintain a minimum cash balance in the Montara cash operating account of US$15.0 million
(2018: US$15.0 million). The DSRA has been classified as restricted cash given certain restrictions under the loan agreement to withdraw amounts
from the DSRA. The scheduled amounts of quarterly principal repayment under the loan, are sculpted, and decline over time, and hence the quantum
required under the DSRA will fall, in line with reductions in the principal repayment, all other things being equal. During the year, US$6.0 million (2018:
US$5.1 million) has been recognised as current/able to be released within 12 months, with the remaining US$7.5 million (2018: US$13.6 million) treated
as non-current/able to be released in 2021 (2018: 2020/2021).
The Group retains US$10.0 million of cash (2018: US$10.0 million) in support of a bank guarantee to a key supplier in respect of Stag’s FSO vessel.
It is kept in a specific bank account that has in place restrictions that does not allow for the cash to be used for normal operations.
Jadestone Energy 2019 Annual Report 98
Significant Accounting Policies and
Explanation Notes to the Financial Statements for the years ended December 31, 2019 and December 31, 2018
99
27 | Share-Based Payments Reserve
The total expense arising from share-based payments recognised for the period ended December 31, 2019 was US$1.5 million (2018: US$0.5 million)
(Note 8).
On August 19, 2015, the Company adopted, as approved by shareholders, a stock incentive plan (the “Plan”) which establishes a rolling number of
shares issuable under the Plan in the amount of 10% of the Company’s issued shares at the date of grant. Under the terms of the Plan, the exercise
price of each option granted cannot be less than the market price at the date of grant, or such other price as may be required by TSX-V. Options under
the Plan can have a term of up to 10 years, with vesting provisions determined by the directors in accordance with TSX-V policies for Tier 2 Issuers.
The Black-Scholes option-pricing model, with the following assumptions, was used to estimate the fair value of the options at the date of grant:
The provision for Stag FSO represents the fair value of amounts payable to the crew of the FSO on termination of the lease.
The Group’s asset restoration obligations (“ARO”) result from the future estimated costs to decommission each of the Stag and Montara assets.
The carrying value of the provision comprises the discounted present value of the estimated future costs. Current estimated costs of the ARO for
each of the Stag and Montara assets have been escalated to the estimated date at which the expenditure would be incurred, at an assumed blended
inflation rate of 2.06% and 2.10% respectively (2018: Stag - 2.27%; Montara - 2.13%). The estimates are a blend of assumed US and Australian inflation
rates to reflect the underlying mix of US dollar and Australian dollar denominated expenditures. The present value of the future estimated ARO for
each of the Stag and Montara assets has then been calculated based on blended risk-free rates of 2.24% and 2.31% respectively (2018: Stag - 2.49%;
Montara - 2.60%). The Stag estimated ARO has been revised upward, as at year end, due to an increase in facilities abandonment, as a result of higher
construction vessel costs amidst tightening market conditions. The Montara estimated ARO has been revised downward, due to a decrease in well
abandonment costs arising from decreasing rig and other equipment rates.
OPTIONS GRANTED ON
Management expects decommissioning expenditures to be incurred from 2033 and 2036 onwards for Montara and Stag, respectively.
Risk-free rate
Expected life
Expected volatility
Share price
Exercise price
Expected dividends
DECEMBER 3, 2019
MARCH 28, 2019
JULY 29, 2018
MARCH 29, 2018
1.46% to 1.47%
5.5 to 6.5 years
40.1% to 42.8%
C$1.17
C$1.17
Nil
1.46% to 1.47%
5.5 to 6.5 years
39.9% to 42.3%
C$0.85
C$0.85
Nil
2.23% to 2.26%
5.5 to 6.5 years
43.2% to 44.7%
C$0.61
C$0.61
Nil
1.99% to 2.04%
5.5 to 6.5 years
43.1% to 44.1%
C$0.43
C$0.43
Nil
The following table summarises the share options outstanding and exercisable as at December 31, 2019:
On May 30, 2019, Jadestone Energy (Eagle) Pty Ltd, a wholly owned subsidiary of the Company entered into a deed poll with the Australian Government
with regard to the requirements of maintaining sufficient financial capacity to ensure Montara’s asset restoration obligations can be met when due.
The deed states that the Group is required to provide a financial security in favour of the Australian Government when the aggregate remaining net after
tax cash flow of the Group is 1.25 times or below the Group’s estimated future decommissioning costs.
29 | Lease Liabilities
SHARE OPTIONS
NUMBER OF
OPTIONS
WEIGHTED
AVERAGE EXERCISE
PRICE C$
WEIGHTED AVERAGE
REMAINING
CONTRACT LIFE
NUMBER
OF OPTIONS
EXERCISABLE
Analysed as:
Non-current
Current
As at January 1, 2018
Previously issued share options
New share options issued
Cancelled during the year
As at December 31, 2018/ January 1, 2019
New share options issued
Vested during the year
Exercised during the year
Cancelled during the year
As at December 31, 2019
28 | Provisions
8,102,842
4,500,000
(470,000)
12,132,842
8,075,000
-
(33,333)
(306,667)
19,867,842
0.58
0.54
1.03
0.56
0.85
0.50
0.47
0.48
0.68
9.03
8.04
9.36
-
8.50
9,25
7.63
-
-
8.21
As at January 1, 2018
Acquisition of Montara (Note 7)
Accretion expense (Note 12)
Changes in discount rate and FX assumptions and estimates (Note 17/Note 11)
Other
As at December 31, 2018/January 1, 2019
Accretion expense (Note 12)
Changes in discount rate assumptions and estimates (Note 17/Note 11)
As at December 31, 2019
PROVISION FOR
ASSET RESTORATION
OBLIGATIONS
USD’000
STAG FSO
PROVISION
USD’000
84,728
183,020
3,632
6,353
(36)
277,697
5,842
(8,117)
275,422
7,259
-
179
(835)
-
6,603
110
(1,717)
4,996
927,822
2,475,008
-
(170,000)
3,232,830
75,000
3,858,316
(33,333)
(113,333)
7,019,480
TOTAL
USD’000
91,987
183,020
3,811
5,518
(36)
284,300
5,952
(9,834)
280,418
2019
USD’000
42,533
19,739
62,272
20,228
19,881
17,934
9,547
3,145
(8,463)
62,272
Maturity analysis of lease liabilities based on undiscounted gross cash flows:
Year 1
Year 2
Year 3
Year 4
Year 5
Unearned interest
The Group does not face a significant liquidity risk with regards to its lease liabilities. Lease liabilities are monitored within the Group’s treasury
function.
30 | Other Payable
Montara contingent payments (Note 7.4)
2019
USD’000
359
2018
USD’000
3,748
The contingent payment of US$0.4 million relates to one remaining potential contingent payment to PTTEP for the Montara acquisition (see Note 7.4).
The 2019 contingent payment has been derecognised during the year as the liability has failed to materialise as Dated Brent price averaged below US$80
bbl. The 2020 contingent payment will be payable if the average Dated Brent price is above US$80/bbl in 2020. Based on the forward curve and the
likelihood of occurrence, the fair value of the contingent payment was valued at US$0.4 million. The 2020 contingent payment is payable in January 2021
and accordingly it has been classified as a non-current liability on the consolidated statement of financial position.
Jadestone Energy 2019 Annual Report 100
Significant Accounting Policies and
Explanation Notes to the Financial Statements for the years ended December 31, 2019 and December 31, 2018
31 | Borrowings
Non-current secured borrowings
Reserve based lending facility
Current secured borrowings
Reserve based lending facility
Current unsecured borrowings
Other
2019
USD’000
7,328
41,795
-
41,795
49,123
2018
USD’000
49,420
51,114
1,279
52,393
101,813
Balances related to the secured convertible bond are:
Nominal value of the convertible bonds issued
Derivative financial instruments at the date of issuance
Liability component at the date of issuance
Less: convertible bond issue costs
Liability recognised at inception, net of costs
Cumulative accretion expense
Less: bond settlement adjustments
101
2018
USD’000
15,000
(2,390)
12,610
(378)
12,232
1,244
13,476
(13,476)
-
2019
USD’000
-
-
-
-
-
-
-
-
-
On August 2, 2018, the Group entered into a reserve based lending agreement to borrow US$120.0 million to partly fund the Montara acquisition (Note
7). The loan is secured against the Montara assets and repayable in quarterly tranches from December 31, 2018 until March 31, 2021. The loan was fully
drawn down on September 28, 2018. The loan incurred costs of US$3.2 million and the fair value of the loan at drawdown had an amortised carrying
value of US$116.8 million. During the year, the Group made principal repayment and interest service costs of US$52.9 million and US$4.5 million (2018:
US$16.9 million; US$ 1.7 million) respectively, leaving a balance of US$49.1 million (2018: US$100.5 million).
The loan incurs interest at 3% above LIBOR.
32 | Secured Convertible Bond
On November 8, 2016 the Group entered into a convertible bond with Tyrus Capital Event S.à r.l and incurred a structuring fee of 2% of the facility, and a
1% per annum standby fee on the undrawn portion of the facility until maturity on October 31, 2019.
On August 1, 2018, the Group and Tyrus Capital Event S.à r.l. conditionally agreed, upon admission and listing on AIM, that the Group would redeem the
convertible bond facility by paying US$17.5 million to Tyrus and all associated security released. At June 30, 2018, the balance on the bond was drawn to
US$15.0 million. Repayment subsequently occurred on August 15, 2018 and all associated security was released.
Interest expense (Note 12)
Standby fee (Note 12)
Bond accretion (Note 12)
Fair value of associated financial derivative (Note 12)
Amortisation of prepaid structuring fee (Note 12)
Gain on early repayment of convertible bonds (Note 13)
2019
USD’000
-
-
-
-
-
-
-
2018
USD’000
558
64
706
1,195
496
(288)
2,731
33 | Reconciliation of Liabilities Arising From Financing Activities
The table below details changes in the Group’s liabilities arising from financing activities, including both cash and non-cash changes. Liabilities arising
from financing activities are those for which cash flows were, or future cash flows will be, classified in the Group’s consolidated statement of cash
flows, as cash flows from financing activities.
The cash flows represent the repayment of the convertible bond, drawdown on borrowings and repayment of borrowings in the consolidated statement
of cash flows.
RESERVED BASED
LENDING FACILITY
USD’000
LEASE LIABILITIES
USD’000
SECURED
CONVERTIBLE BOND
USD’000
OTHER
BORROWINGS
USD’000
As at January 1, 2018
Financing cash flows
Others
As at December 31, 2018/January 1, 2019
Adoption of IFRS 16
Financing cash flows
New lease liabilities
Interest expense
As at December 31, 2019
-
99,829
705
100,534
-
(52,924)
-
1,513
49,123
-
-
-
-
35,850
(16,671)
38,813
4,280
62,272
12,770
(17,514)
4,744
-
-
-
-
-
-
829
450
-
1,279
-
(1,279)
-
-
-
Jadestone Energy 2019 Annual Report 102
Significant Accounting Policies and
Explanation Notes to the Financial Statements for the years ended December 31, 2019 and December 31, 2018
103
34 | Commitments Under Operating Leases
The following is a summary of the Group’s outstanding derivative contracts:
As at December 31, 2019, the Group is committed to US$4,000 for short-term leases (out of scope under IFRS 16).
Contracts designated as hedges
The Group rents equipment under operating leases. The leases are for an average period of 3 years, with fixed rentals over the same period.
Operating lease payments recognised as an expense
As at December 31, 2018, the Group has outstanding commitments under non-cancellable operating leases that fall due as follows:
Within one year
Later than one year but within five years
Later than five years
35 | Trade and Other Payables
Trade payables
Other payables
Provision for long service leave
Other provisions
GST/VAT payables
2019
USD’000
9,192
14,355
851
3,460
104
27,962
2018
USD’000
7,630
2018
USD’000
9,125
31,325
3,145
43,595
2018
Restated
USD’000
7,178
14,476
722
9,117
-
31,493
These amounts are non-interest bearing and repayable on demand. The Group believes that the carrying amount of trade payables approximates their
fair value.
Trade payables and accruals principally comprise amounts outstanding for trade purchases and ongoing costs. The average credit period taken for trade
purchases is less than 30 days. For most suppliers no interest is charged on the trade payables in the first 30 days from the date of invoice. Thereafter,
interest is charged on the outstanding balances at various interest rates. The Group has financial risk management policies in place to ensure that all
payables are settled within the pre-agreed credit terms.
36 | Derivative Financial Instruments
The Group uses derivatives to manage its exposure to oil and gas fluctuations. Oil hedges are undertaken using swaps and call options, all contracts are
based on Dated Brent oil price options. In the current year, the Group has designated its capped swap as a cash flow hedge of highly probable sales.
Derivative financial assets
Designated as cash flow hedges
Commodity capped swap
Analysed as:
Current
Non-current
2019
USD’000
2018
USD’000
5,275
5,275
-
5,275
51,324
35,985
15,339
51,324
CONTRACT
QUANTITY
TYPE OF
CONTRACTS
TERMS
CONTRACT PRICE
HEDGE
CLASSIFICATION
32% (2018:
50%) of Group’s
anticipated
planned 2PD
production
67% of swapped
barrels in 2019
and in the nine
months to
September 30,
2020
Commodity
capped
swap: swap
component
Oct 2018 -
Sep 2020
US$78.26/bbl for Q4 2018,
US$71.72/bbl for 2019
and US$68.45/bbl for
the nine months to
September 30, 2020
Commodity
capped
swap: call
component
Jan 2019 -
Sep 2020
US$80.00/bbl for the nine
months to September 30,
2019, then US$85.00/bbl
to September 2020
Cash flow
FAIR VALUE
ASSET AT
DECEMBER 31,
2019
USD’000
FAIR VALUE
ASSET AT
DECEMBER 31,
2018
USD’000
5,203
50,477
72
847
As critical terms (i.e., the notional amount, life and underlying oil price benchmark) of the capped swap and the corresponding Montara hedged sales are
highly similar, the Group performed a qualitative assessment of effectiveness and has concluded that the value of the capped swap and the value of the
corresponding hedged items will systematically change in opposite direction in response to movements in the underlying commodity prices.
There is however, a source of ineffectiveness in the capped swap arrangement, arising from the slight difference in the timing of Montara’s production
and the settlement of the capped swap arrangement versus the crude sales. The overall change in value used for calculating hedge ineffectiveness on
the capped swap hedge transaction amounted to net loss of US$0.6 million (2018: net gain of US$0.6 million) and have been included in the statement
of profit or loss within “other expenses” (Note 9) and “other income” (Note 11), respectively.
The following tables detail the commodity swap contracts outstanding at the end of the reporting year, as well as information regarding their related
hedged items. Commodity swap contract assets are included in the “derivative financial instruments” line item in the consolidated statement of
financial position.
Hedging instruments - outstanding contracts
2019
Cash flow hedges
Commodity swap component
Commodity call component
2018
Cash flow hedges
Commodity swap component
Commodity call component
OIL VOLUMES
BBLS
NOTIONAL VALUE
USD’000
CHANGE IN FAIR
VALUE USED FOR
CALCULATING HEDGE
INEFFECTIVENESS
USD’000
FAIR VALUE
ASSETS
USD’000
1,136,940
568,470
77,829
48,320
3,157,050
2,107,962
222,718
172,613
633
-
633
637
-
637
5,203
72
5,275
50,477
847
51,324
Jadestone Energy 2019 Annual Report 104
Significant Accounting Policies and
Explanation Notes to the Financial Statements for the years ended December 31, 2019 and December 31, 2018
105
Hedged items
2019
Cash flow hedges
Forecast sales
2018
Cash flow hedges
Forecast sales
CHANGE IN VALUE USED
FOR CALCULATING HEDGE
INEFFECTIVENESS
USD’000
BALANCE IN CASH FLOW
HEDGE RESERVE FOR
CONTINUING HEDGES
USD’000
BALANCE IN CASH FLOW HEDGE
RESERVE ARISING FROM HEDGING
RELATIONSHIPS FOR WHICH HEDGE
ACCOUNTING IS NO LONGER APPLIED
USD’000
633
637
3,688
35,480
-
-
The following table details the effectiveness of the hedging relationships and the amounts reclassified from hedging reserve to profit or loss:
CURRENT
PERIOD HEDGING
(LOSS)/GAIN
RECOGNISED
IN OCI
USD’000
AMOUNT
OF HEDGE
INEFFECTIVENESS
RECOGNISED IN
PROFIT OR LOSS
USD’000
LINE ITEM IN
PROFIT OR LOSS
IN WHICH HEDGE
INEFFECTIVENESS
IS INCLUDED
USD’000
AMOUNT
RECLASSIFIED TO
PROFIT OR LOSS
DUE TO HEDGED
ITEM AFFECTING
PROFIT OR LOSS
USD’000
LINE ITEM IN
PROFIT OR
LOSS IN WHICH
RECLASSIFICATION
ADJUSTMENT IS
INCLUDED
2019
Cash flow hedges
Forecast sales
2018
Cash flow hedges
Forecast sales
(21,380)
36,241
633
637
Other expenses
14,241
Revenue
Other income
451
Revenue
37 | Financial Instruments, Financial Risks and Capital Managements
Financial assets and liabilities
Current assets and liabilities
Management considers that due to the short-term nature of the Group’s current assets and liabilities, the carrying values equate to their fair value.
Non-current assets and liabilities
All non-current assets and liabilities are reflected at fair value.
Financial assets
At amortised cost
Derivative instruments designated in hedge accounting relationships
Financial liabilities
At amortised cost
Contingent consideration for a business combination
2019
USD’000
135,737
5,275
141,012
419,671
359
420,030
2018
Restated
USD’000
86,539
51,324
137,863
417,606
3,748
421,354
Fair values are based on management’s best estimates after consideration of current market conditions. The estimates are subjective and involve
judgment, and as such are not necessarily indicative of the amount that the Group may incur in actual market transactions.
Commodity price risk
The Group’s earnings are affected by changes in oil and gas prices. The Group manages this risk by monitoring oil and gas prices and entering into
commodity hedges against fluctuations in oil prices if considered appropriate.
The Group entered into hedge contracts for sales based upon planned production at Montara (Note 36).
Montara
The Group hedged 50% of its planned production volumes for the 24 months to September 30, 2020. The hedge is a capped swap, providing downside
price protection while allowing for participation in higher commodity prices via purchased call options. The call strike is set at US$80/bbl for the
nine months to September 31, 2019 and US$85/bbl for the twelve months to September 2020. The swap price was set at US$78.26/bbl for Q4 2018,
US$71.72/bbl for 2019 and US$68.45/bbl for the nine months to September 2020. Approximately two thirds of the swapped barrels in 2019 and 2020
have upside price participation via purchased calls. The effective date of the hedge contracts is October 1, 2018.
Commodity price sensitivity
The results of operations and cash flows from oil and gas production can vary significantly with fluctuations in the market prices of oil and/or natural
gas. These are affected by factors outside the Group’s control, including the market forces of supply and demand, regulatory and political actions of
governments, and attempts of international cartels to control or influence prices, among a range of other factors.
The table below summarises the impact on profit/(loss) before tax, and on equity, from changes in commodity prices on the fair value of derivative
financial instruments. The analysis is based on the assumption that the crude oil price moves 10%, with all other variables held constant. Reasonably
possible movements in commodity prices were determined based on a review of recent historical prices and current economic forecasters’ estimates.
EFFECT ON THE RESULT
BEFORE TAX FOR
THE YEAR ENDED
DECEMBER 31, 2019
USD’000
EFFECT ON OTHER
COMPREHENSIVE
INCOME BEFORE TAX
FOR THE YEAR ENDED
DECEMBER 31, 2019
USD’000
EFFECT ON THE RESULT
BEFORE TAX FOR THE
YEAR ENDED
DECEMBER 31, 2018
USD’000
EFFECT ON OTHER
COMPREHENSIVE
INCOME BEFORE TAX
FOR THE YEAR ENDED
DECEMBER 31, 2018
USD’000
-
-
(7,266)
7,266
(1)
1
(16,729)
16,729
GAIN OR LOSS
Increase by 10%
Decrease by 10%
Foreign currency risk
Foreign currency risk is the risk that a variation in exchange rates between United States Dollars (“US Dollar”) and foreign currencies will affect the fair
value or future cash flows of the Group’s financial assets or liabilities.
Cash and bank balances are generally held in the currency of likely future expenditures to minimise the impact of currency fluctuations. It is the Group’s
normal practice to hold the majority of funds in US Dollar in order to match the Group’s revenue and expenditures. The Group’s US$120.0 million reserve
based loan facility is a US Dollar denominated instrument.
In addition to US Dollars, the Group transacts in various currencies, including Australian Dollars, Singapore Dollars, Vietnamese Dong, Malaysian Ringgit,
Canadian Dollars and Indonesian Rupiah.
Material foreign denominated balances were as follows:
Cash and bank balances
Australian Dollars
Trade and other receivables
Australian Dollars
Trade and other payables
Australian Dollars
2019
USD’000
7,088
5,853
21,231
2018
Restated
USD’000
4,923
5,237
1,974
If the Australian dollar weakens/strengthens by 10% against the functional currency of the Group, profit or loss will increase/decrease by US$0.8 million
(2018: decrease/increase by US$0.8 million).
Jadestone Energy 2019 Annual Report 106
Significant Accounting Policies and
Explanation Notes to the Financial Statements for the years ended December 31, 2019 and December 31, 2018
107
Interest rate risk
The Group’s interest rate exposure arises from some of its cash and bank balances and borrowings. The Group’s other financial instruments are non-
interest bearing or fixed rate, and are therefore not subject to interest rate risk.
Jadestone holds some of its cash in interest bearing accounts and short-term deposits. Interest rates currently received are at historically relatively low
levels. Accordingly, a downward interest rate movement would not cause significant exposure to the Group.
On August 2, 2018, the Group entered into a reserve based lending agreement with the Commonwealth Bank of Australia and Société Générale to
borrow US$120.0 million, repayable quarterly to March 31, 2021. The loan was fully drawn down on September 28, 2018 and incurs interest at LIBOR plus
3%. The loan incurred costs of US$3.2 million, which were offset against the proceeds received.
Based on the carrying value of the reserve based loan as at December 31, 2019, if interest rates had increased or decreased by 1% and all other variables
remained constant, the Group’s quarterly net income/(loss) before tax would have decreased or increased by US$0.1 million (2018: US$0.3 million).
Credit risk
Credit risk represents the financial loss that the Group would suffer if a counterparty in a transaction fails to meet its obligations in accordance with the
agreed terms.
The Group actively manages its exposure to credit risk, granting credit limits consistent with the financial strength of the Group’s counterparties and
customers, requiring financial assurances as deemed necessary, reducing the amount and duration of credit exposures, and close monitoring of relevant
accounts.
The Group trades only with recognised, creditworthy third parties.
The Group’s current credit risk grading framework comprises the following categories:
CATEGORY
DESCRIPTION
BASIS FOR RECOGNISING EXPECTED
CREDIT LOSSES (“ECL”)
Performing
The counterparty has a low risk of default and does not have any past-due
amounts.
12-month ECL
Doubtful
In default
Write-off
Amount is > 30 days past due or there has been a significant increase in
credit risk since initial recognition.
Lifetime ECL - not credit-impaired
Amount is > 90 days past due or there is evidence indicating the asset is
credit-impaired.
Lifetime ECL - credit-impaired
There is evidence indicating that the debtor is in severe financial difficulty
and the Group has no realistic prospect of recovery.
Amount is written off
The table below details the credit quality of the Group’s financial assets and other items, as well as maximum exposure to credit risk by credit risk
rating grades:
EXTERNAL
CREDIT
RATING
INTERNAL
CREDIT
RATING
12-MONTH (“12M”)
OR
LIFETIME ECL
NOTE
GROSS
CARRYING
AMOUNT (I)
USD’000
LOSS
ALLOWANCE
USD’000
NET
CARRYING
AMOUNT
USD’000
2019
Cash and bank balances
Trade receivables
Other receivables
2018
Cash and bank balances
Trade receivables
Other receivables
24
23
23
24
23
23
n.a
n.a
n.a
n.a
n.a
n.a
Performing
(i)
Performing
Performing
(i)
Performing
12m ECL
Lifetime ECL
12m ECL
12m ECL
Lifetime ECL
12m ECL
99,419
34,007
2,311
81,625
57
4,857
-
-
-
-
-
-
99,419
34,007
2,311
81,625
57
4,857
(i) For trade receivables, the Group has applied the simplified approach
in IFRS 9 to measure the loss allowance at lifetime ECL. The Group
determines the expected credit losses on these items by using specific
identification, estimated based on historical credit loss experience
based on the past due status of the debtors, adjusted as appropriate to
reflect current conditions and estimates of future economic conditions.
Accordingly, the credit risk profile of these assets is presented based on
their past due status in terms of specific identification.
As at December 31, 2019, total trade receivables amounted to US$34.0
million (2018: US$0.1 million). The balance in in 2019 and 2018 had been
fully recovered in 2020 and 2019, respectively. The Group has derivative
receivables of US$0.5 million and US$3.4 million within other receivables
in 2019 and 2018 and was received in full in January 2020 and 2019,
respectively.
The concentration of credit risk relates to the main counterparty to oil
and gas sales in Australia, where the sole customer has an A1 credit
rating (Moody’s). All trade receivables are generally settled 30 days after
sale date. In the event that an invoice is issued on a provisional basis
then the final reconciliation is paid within 3 days of the issuance of the
final invoice, largely mitigating any credit risk.
The Group manages it liquidity risk by optimising the positive free cash
flow from its producing assets, on-going cost reduction initiatives,
merger and acquisition strategies, and bank balance on hand.
The Group net profit after tax for the year was US$40.5 million
(2018: loss after tax of US$31.0 million). Operating cash flows before
movements in working capital and net cash generated from operating
activities for the year ended December 31, 2019 was positive of US$176.7
million and US$144.6 million, respectively (2018: negative of US$0.3
million; net cash generated of US$17.8 million). The Group’s net current
assets remained positive at US$26.8 million as at December 31, 2019
(2018: US$57.5 million).
The Group’s reserve based loan is sized on a borrowing base drawn from
projected cash flows from the Montara Assets, and based on proved and
probable producing reserves but including certain infill wells (2PD). This
borrowing base is subject to scheduled semi-annual redeterminations
and as such, and in the event of a significant reduction in the borrowing
base, there is a risk that scheduled repayments may increase to offset
any such borrowing base deficiency. The existing borrowing base, as
assessed by the lenders as at December 2019, is significantly above
aggregate commitments.
The Group recognises lifetime ECL for trade receivables. The ECL on
these financial assets are estimated based on days past due by applying
a percentage of expected non-recoveries for each group of receivables.
As at financial period end, ECL from trade and other receivables are
expected to be insignificant.
The Group believes it has sufficient liquidity to meet all reasonable
scenarios of operating and financial performance for the next 18 months.
Please refer to Note 41 for subsequent events disclosure surrounding the
impact of COVID-19 pandemic on the Group and the Group’s assessment
on the use of the going concern assumption.
Cash and bank balances are placed with reputable banks and financial
institutions, which are regulated, and with no history of default.
The maximum credit risk exposure relating to financial assets is
represented by their carrying value as at the reporting date.
Liquidity risk
Liquidity risk is the risk that the Group will not be able to meet all of its
financial obligations as they become due. This includes the risk that the
Group cannot generate sufficient cash flow from producing assets or is
unable to raise further capital in order to meet its obligations.
Non-derivative financial liabilities
The following table details the expected maturity for non-derivative
liabilities. The table below has been drawn up based on the
undiscounted contractual maturities of the financial liabilities, including
interest, that will be earned on those liabilities, except where the
Group anticipates that the cash flow will occur in a different period.
The adjustment column represents the estimated future cash flows
attributable to the instrument included in the maturity analysis, which
are not included in the carrying amount of the financial liability on the
consolidated statement of financial position, namely interest expense.
2019
Non-interest bearing
Variable interest rate instruments
2018 (Restated)
Non-interest bearing
Variable interest rate instruments
WEIGHTED
AVERAGE
EFFECTIVE
INTEREST
RATE %
ON DEMAND
OR WITHIN
1 YEAR
USD’000
WITHIN 2 TO 5
YEARS
USD’000
MORE THAN
5 YEARS
USD’000
ADJUSTMENTS
USD’000
TOTAL
USD’000
-
7.735
-
8.071
48,086
44,425
92,511
31,493
58,907
90,400
55,503
7,477
62,980
6,603
52,182
58,785
275,422
-
275,422
277,697
-
277,697
(8,463)
(2,779)
370,548
49,123
(11,242)
419,671
-
(9,276)
315,793
101,813
(9,276)
417,606
Jadestone Energy 2019 Annual Report
108
Significant Accounting Policies and
Explanation Notes to the Financial Statements for the years ended December 31, 2019 and December 31, 2018
109
Non-derivative financial assets
The following table details the expected maturity for non-derivative financial assets. The inclusion of information on non-derivative financial assets
is necessary in order to understand the Group’s liquidity risk management, as the Group’s liquidity risk is managed on a net asset and liability basis.
The table has been drawn up based on the undiscounted contractual maturities of the financial assets, including interest that will be earned on those
assets, except where the Group anticipates that the cash flow will occur in a different period. The adjustment column represents the estimated future
cash flows attributable to the instrument included in the maturity analysis, which are not included in the carrying amount of the financial asset on the
consolidated statement of financial position, namely interest income.
WEIGHTED AVERAGE
EFFECTIVE
INTEREST RATE %
ON DEMAND OR
WITHIN 1 YEAR
USD’000
WITHIN 2 TO 5
YEARS
USD’000
ADJUSTMENTS
USD’000
TOTAL
USD’000
Fair value measurements
The Group discloses fair value measurements by level of the following fair value measurement hierarchy:
i. Quoted prices (unadjusted) in active markets for identical assets or liabilities (Level 1);
ii.
Inputs, other than quoted prices included within Level 1, that are observable for the asset or liability, either directly or indirectly (Level 2); and
iii.
Inputs for the asset or liability that are not based on observable market data (unobservable inputs) (Level 3).
FINANCIAL
ASSETS/
FINANCIAL
LIABILITIES
FAIR VALUE (USD’000) AS AT
2019
2018
ASSETS
LIABILITIES
ASSETS
LIABILITIES
FAIR
VALUE
HIERARCHY
VALUATION
TECHNIQUE(S)
AND KEY INPUT(S)
SIGNIFICANT
UNOBSERVABLE
INPUT(S)
RELATIONSHIP
OF
UNOBSERVABLE
INPUTS TO FAIR
VALUE
2019
Non-interest bearing
Variable interest rate instruments
2018 (Restated)
Non-interest bearing
Variable interest rate instruments
* The effect of interest is not material.
-
-*
-
-*
36,318
89,419
125,737
4,914
58,064
62,978
-
10,000
10,000
-
23,561
23,561
-
-*
-*
-
-*
-*
36,318
99,419
135,737
4,914
81,625
86,539
Capital management
The Group manages its capital structure and makes adjustments to it, based on the funds available to the Group, in order to support the acquisition,
exploration and development of resource properties and the ongoing operations of its producing assets. Given the nature of the Group’s activities, the
Board of Directors works with management to ensure that capital is managed effectively and the business has a sustainable future.
To carry-out planned asset acquisitions, exploration and development, and to pay for administrative costs, the Group may utilise excess cash generated
from its ongoing operations and may utilise its existing working capital, and will work to raise additional funds should that be necessary.
Management reviews its capital management approach on an ongoing basis and believes that this approach, given the relative size of the Group, is
reasonable. There were no changes in the Group’s approach to capital management during the financial year ended December 31, 2019. The Group is not
subject to externally imposed capital requirements.
Gearing ratio
Debt
Cash and cash equivalents
Restricted cash
Net (cash)/debt
Equity
Net debt to equity ratio
2019
USD’000
49,123
(75,934)
(13,485)
(40,296)
225,467
N/M
2018
USD’000
101,813
(52,981)
(18,644)
30,188
215,261
14%
Debt is defined as long and short-term borrowings (excluding derivatives) as detailed in Note 31 and 32. Cash and cash equivalents includes the Montara
Assets’ minimum working capital cash balance of US$15.0 million required under the RBL, while restricted cash comprises the US$13.5 million in the
RBL debt service reserve account (2018: US$18.6 million). Restricted cash, as shown here, excludes the US$10.0 million deposited in support of a bank
guarantee to a key supplier in respect of the Stag FSO. Equity includes all capital and reserves of the Group that are managed as capital.
The Group’s overall strategy remains unchanged from 2018.
Derivative financial instruments
1) Commodity
capped swap
contracts
(Note 36)
5,275
-
51,324
-
Level 2
Others - contingent consideration in a business combination
2) Contingent
consideration
(Note 7 and
30)
359
-
-
3,748
Level 3
Third party valuations
based on market
comparable information.
Based on the nature
and the likelihood
of occurrence of the
trigger event. Fair value
is estimated using
future Dated Brent price
forecasts at the end of
the reporting period,
taking into account the
time value of money and
volatility of oil prices.
n.a.
n.a.
Expected future
oil price volatility
of 25% is based
on an analysis of
Brent oil price
movement prior
to acquisition
date.
A slight increase
in Brent oil prices
would result in a
significant increase
in the fair value
and vice versa.
38 | Segment Information
Information reported to the Group’s Chief Executive Officer (the Chief Operating Decision Maker) for the purposes of resource allocation is focused on
two reportable/business segments driven by different types of activities within the upstream oil and gas value chain, namely producing assets and
secondly development and exploration assets. The geographic focus of the business is on SEA and Australia.
Revenue and non-current assets information based on the geographical location of assets respectively are as follows:
PRODUCING ASSETS
AUSTRALIA
USD’000
SEA
USD’000
EXPLORATION
SEA
USD’000
CORPORATE
USD’000
2019
Revenue
Liquids revenue
Production cost
DD&A
Staff costs
Other expenses
Other income
Finance costs
Other financial gain
Profit/(Loss) before tax
Additions to non-current assets
Non-current assets
325,406
325,406
(119,898)
(90,277)
(7,282)
(7,012)
2,971
(16,387)
3,389
90,910
84,444
461,053
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
(113)
(3,543)
(278)
2
(7)
-
(3,939)
20,456
116,162
-
-
-
(356)
(8,889)
(4,402)
6
(49)
-
(13,690)
65
943
TOTAL
USD’000
325,406
325,406
(119,898)
(90,746)
(19,714)
(11,692)
2,979
(16,443)
3,389
73,281
104,965
578,158
Jadestone Energy 2019 Annual Report 110
Significant Accounting Policies and
Explanation Notes to the Financial Statements for the years ended December 31, 2019 and December 31, 2018
111
Revenue
Liquids revenue
Gas revenue
Royalties
Production cost
DD&A
Staff costs
Other expenses
Impairment of assets
Other income
Finance costs
Other financial gain
Profit/(Loss) before tax
Additions to non-current assets
Non-current assets
2018 (RESTATED)
PRODUCING ASSETS
AUSTRALIA
USD’000
SEA
USD’000
EXPLORATION
SEA
USD’000
CORPORATE
USD’000
105,970
-
-
105,970
(88,159)
(13,066)
(3,489)
(5,022)
-
2,345
(6,219)
12,057
4,417
376,856
470,522
8,520
2,482
(3,549)
7,453
(2,780)
(618)
(1,834)
(146)
-
-
-
-
2,075
-
-
-
-
-
-
-
-
(816)
(434)
(11,901)
-
(80)
-
-
-
-
-
-
(92)
(7,399)
(4,772)
-
189
(2,941)
288
(13,231)
(14,727)
1,835
95,607
183
280
TOTAL
USD’000
114,490
2,482
(3,549)
113,423
(90,939)
(13,776)
(13,538)
(10,374)
(11,901)
2,534
(9,240)
12,345
(21,466)
378,874
566,409
Non-current assets include oil and gas properties, intangible exploration assets, right-of-use assets, restricted cash and plant and equipment used in
corporate offices.
Included in revenues arising from producing assets in 2019 are revenues of approximately US$325.4 million (2018: US$106.0 million) which arose from
sales to the Group’s largest customer.
39 | Financial Capital Commitments
Certain PSC’s and service concessions’ have firm capital commitments. The Group has the following outstanding minimum exploration commitments:
SEA portfolio PSC operational commitments
Not later than one year
2019
USD’000
10,000
2018
USD’000
10,000
The SEA portfolio PSC operational commitments as at December 31, 2019 amounted to US$10.0 million (2018: US$ 10.0 million), and relates to the
minimum work commitment outstanding in exploration phase two of the Block 46/07 PSC, for the drilling of a further well.
Under the terms of the Block 46/07 PSC, Jadestone is committed to drill one more appraisal well on the block. The Company plans to drill an appraisal
well on the Nam Du field to facilitate transition of 3C resource to 2C status. This well would be retained for future use as a Nam Du gas producer. On
July 9, 2019, the Company submitted a request to the Vietnam Government, for a further one-year extension to the Block 46/07 PSC exploration phase
two period to June 29, 2021 and this was approved on February 26, 2020. Following the Group’s announcement on March 19, 2020 to delay the project,
the Group will seek Vietnam Government approval for a further extension in order to align drilling of the appraisal well with development of Nam Du/U
Minh. The Group is committed to the project and expects to receive approval for the extension request.
Capital commitments
The Group has the following capital commitments for expenditure that were contracted for at the end of the reporting year but not recognised as
liabilities for Montara:
Not later than one year
40 | Contingent Liabilities
2019
USD’000
19,441
2018
USD’000
17,417
Stag
The Group may be responsible for certain contingent payments after 2018 of up to US$10.0 million linked to future expansion of the Stag Oilfield.
At this time, Jadestone’s management does not consider it probable that the conditions necessary to trigger the contingent payments will occur.
Accordingly, as at December 31, 2019, no provision has been recognised in the financial statements.
Montara
The Group may be responsible for certain contingent payments after 2019 of up to US$110.0 million linked to oil price appreciation, and/or volumes
of production from the first infill well in its first year, and/or future expansion of the Montara Assets (see also Note 7.4). At this time, Jadestone’s
management only considers the contingent payments of up to US$10.0 million (fair value of US$0.4 million) linked to oil price appreciation above
US$80/bbl in 2020 as possible, while also noting the uncertain nature of future changes in oil prices; in this case future prices of Dated Brent.
Accordingly, the fair value of the oil price linked contingent payments of US$10.0 million is recognised as a payable (see Note 30) and the remaining
US$100.0 million of contingent payments has not been recognised in the financial statements.
41 | Events After The End of The Reporting Period
Award of damages in relation to Philippines arbitration
In December 2017, the Group commenced arbitration action against Total E&P Philippines BV (“Total”), with the Singapore International Arbitration
Center, in response to a breach of the 2012 farm out agreement (“the FOA”), claiming that Total failed to drill an exploration well on the deepwater
Halcon prospect, located within the block covered by Service Contract 56 (“SC56”) in the Sulu Sea, offshore the Philippines. The FOA required Total to
drill one exploration well and pay their 75% interest along with the Group’s 25% interest.
On January 3, 2020, the tribunal found in favour of the Group, concluding that Total breached the FOA, awarding (i) monetary damages to the Group
of US$11.1 million, less specific expenditures incurred prior to the breach to be agreed or determined if the parties cannot agree; and (ii) legal costs of
approximately US$4.3 million. The tribunal’s costs will be borne by the Group and Total 25:75.
The parties were unable to agree the specific expenditures and, on March 24, 2020, the tribunal issued a final award in which it determined such
expenditures to be US$0.7 million. The net award to the Group was US$10.4 million.
After the payment of all legal fees, funding costs, and the Company’s share of the tribunal costs, net proceeds to the Group are expected to be
approximately US$2.2 million. This will be recognised in FY2020.
Following the award of monetary damages to the Group, Total would be released from bearing the Group’s 25% interest for the drilling of one
exploration well, its share estimated at US$18.8 million. Consequently, the Group is potentially liable to pay US$2.5 million, being the penalty payable
to the Department of Energy in Philippines if both Total and the Group fail to drill an exploration well prior the licence expiration on September 1, 2020.
However, no final decision has been reached between the Group and Total on the future plan for SC56, the discussion will take place during the next
operator committee meeting, tentatively scheduled in second quarter of 2020.
At the end of the reporting period, no contingent assets nor contingent liabilities were recorded as the outcome of the arbitration was not finalised till
after year end.
The total carrying value within intangible exploration assets in respect of SC56 as at December 31, 2019 was US$50.4 million (2018: US$50.4 million).
The Group has reviewed, pursuant to IFRS 6 Exploration for and evaluation of mineral resources, whether there are any impairment indicators for
SC56 as at year end, and no change has been made to the SC56 carrying value within intangible exploration assets.
Jadestone Energy 2019 Annual Report
112
Significant Accounting Policies and
Explanation Notes to the Financial Statements for the years ended December 31, 2019 and December 31, 2018
113
Vietnam Block 51 and 46/07
The Group holds a 100% operated working interest in the Block 51 PSC and the Block 46/07 PSC, both in the shallow water Malay-Tho Chu Basin,
offshore southwest Vietnam. The Group has made three gas/condensate discoveries: the U Minh and Tho Chu fields in Block 51, and the Nam Du gas
field in Block 46/07.
On October 17, 2019, the Group made the formal declaration of commercial discovery for the Nam Du and U Minh fields and submitted to the Vietnam
Government the combined formal field development plan for the Nam Du and U Minh development, thus initiating the formal government approval
process.
Following delays in the Vietnamese Government approval processes and the drop in the oil price in Q1 2020, the Company announced on March 19, 2020
that it would delay the sanction and development of Nam Du/U Minh and the first gas would not occur before Q4 2022 at the earliest.
As at year end, the Group has recognised US$65.6 million of intangible exploration assets in relation to Nam Du and U Minh fields.
TSX Venture Exchange de-listing
On March 12, 2020, Jadestone has announced and submitted an application to de-list from the TSX-V. The final day of trading for Jadestone’s common
shares on the TSX-V was on March 24, 2020. The Company’s shares will continue to trade on AIM.
42 | Related Party Transactions
During the year, the Group entities did not enter into any transactions with related parties other than the following:
Compensation of key management personnel
Short-term benefits
Other benefits
Share-based payments
2019
USD’000
6,746
1,052
1,038
8,836
2018
USD’000
2,656
326
234
3,216
Upon de-listing from the TSX-V, the Company will remain a Canadian domiciled corporation and will continue as a reporting issuer under Canadian
rules in the near term, but the Company has requested an order from the applicable securities commissions, to grant an exemption from certain of its
Canadian reporting requirements, in a matter to similar to a designated foreign issuer.
Compensation of directors
The total remuneration of members of key management in 2019 (including salaries and benefits) was US$8.8 million (2018: US$3.2 million).
Impact of Coronavirus outbreak (“COVID-19”)
On January 30, 2020, the World Health Organisation declared the COVID-19 outbreak a “Public Health Emergency of International Concern” and on
March 10, 2020, declared it to be a pandemic. Actions taken around the world to help mitigate the spread of COVID-19 include restrictions on travel, and
quarantines in certain areas, and forced closures for certain types of public places and businesses. The COVID-19 and actions taken to mitigate it have
had and are expected to continue to have an adverse impact on the economies and financial markets of many countries, including the geographical area
in which the Group operates.
On April 12, 2020, members of Organisation of the Petroleum Exporting Countries and certain other countries including the Russian Federation, have
agreed to cut global daily oil production by approximately 10%, representing an estimated 9.7mm bbls/d effectively from May 2020.
The decline in Dated Brent oil price due to factors set out above has been assessed to be a non-adjusting post balance sheet event in accordance with
IAS 10.
The depressed Dated Brent oil price will reduce the Group’s revenue in 2020, but the Group has no plan to reduce its crude oil production as the Group
has significant downside protection in place, including via its capped swap and a relatively competitive cash operating cost base. The Group has hedged
about a third of its planned production for the first nine months of 2020. Plus, the crude at both Stag and Montara has generated a premium above the
benchmark crude oil prices.
In the absence of Vietnamese Government approvals for the Nam Du/U Minh field development plan in Q1 2020, and the decline in oil prices, the Group
announced on March 19, 2020 to defer the Nam Du/U Minh gas field development. In respect of the Block 46/07 PSC appraisal well commitment, the
Group will seek Vietnam Government approval for a further extension to the existing June 29, 2021 deadline, in order to align drilling of the appraisal well
with development of Nam Du/U Minh. The Group is committed to the project and expects to receive approval for the extension request.
At the time the Group undertook the impairment review of its non-financial assets, as at December 31, 2019, the spot price for Dated Brent was
US$66.8/bbl. Since that time, Dated Brent oil prices have fallen to around US$19.10/bbl as at April 20, 2020, due to the impact of Coronavirus
(“COVID-19”) on oil demand.
The Group will reflect updated oil price data during its next impairment review, including spot oil prices, but will also give due consideration to both the
medium- and long-term outlook for crude oil prices.
The Group will closely monitor the development of the COVID-19 outbreak and related oil price outlook, and continue to evaluate its impact on the
business, the Group’s financial position and operating results. As part of the preparation of the current financial statements, a forward looking going
concern analysis was undertaken at some of the lower current third party downside Brent crude oil price outlooks, including US$22/bbl in Q2 2020
and US$30/bbl in H2 2020. The Group was able to generate positive operating cashflow without resorting to significant cuts in operating costs, and
comfortably continue as a going concern.
2019
A. Paul Blakeley
Daniel Young
Dennis McShane
Iain McLaren
Eric Schwitzer
Robert Lambert
Cedric Fontenit
David Neuhauser
Lisa Stewart
2018
A. Paul Blakeley
Daniel Young
Dennis McShane
Iain McLaren
Eric Schwitzer
Robert Lambert
David Neuhauser
Cedric Fontenit
SHORT-TERM
BENEFITS (a)
USD’000
OTHER
BENEFITS (a)
USD’000
SHARE-BASED
PAYMENTS
USD’000
TOTAL
COMPENSATION
USD’000
1,302
707
130
81
68
69
66
56
6
2,485
1,035
546
130
70
58
50
45
18
1,952
350
174
-
-
-
-
-
-
-
524
422
149
-
-
-
-
-
-
571
233
139
21
13
25
13
9
12
-
465
164
74
19
9
9
9
9
-
293
1,885
1,020
151
94
93
82
75
68
6
3,474
1,621
769
149
79
67
59
54
18
2,816
(a) Short-term benefits comprise salary, director fee as applicable, performance pay, pension and other allowances. Other benefits comprise
benefits-in-kind.
Jadestone Energy 2019 Annual Report
114
Significant Accounting Policies and
Explanation Notes to the Financial Statements for the years ended December 31, 2019 and December 31, 2018
Director participation in AIM equity raise
Certain directors and members of the management team of the Company (“Insiders”) subscribed for new shares pursuant to the AIM equity raise and
listing completed in August 2018. The issuance of new shares to these Insiders, pursuant to the AIM equity raise, and listing, is considered to be a
related party transaction within the meaning of TSX Venture exchange policy 5.9 and multilateral instrument 61-101 (“MI 61-101”), and disclosable in
the December 31, 2018 year-end financial statements under AIM rule 19. The Company has relied on the exemptions from the valuation and minority
shareholder approval requirements of MI 61-101, contained in sections 5.5(b) and 5.7(1)(b) of MI 61-101, in respect of the Insider participation. Certain
directors subscribed for a total of 1,961,271 new shares at 35 pence per share (or £688,545) as follows.
115
43 | Reclassification Of Comparative Figures
Certain comparative figures in the financial statements of the Group have been reclassified to conform to the presentation in the current financial
year. These reclassifications were made to better reflect the nature of the expenses in the respective lines in the statement of profit or loss and other
comprehensive income. These relate to the following:
AS PREVIOUSLY REPORTED
USD’000
RECLASSIFICATION
USD’000
AS RECLASSIFIED
USD’000
A. Paul Blakeley
David Neuhauser*
Daniel Young
Dennis McShane
Robert Lambert
Eric Schwitzer
Iain McLaren
NUMBER OF NEW SHARES
544,798
544,798
217,919
217,919
217,919
108,959
108,959
1,961,271
Statement of profit or loss and other comprehensive
income for the year ended December 31, 2018
Production costs
Depletion, depreciation and amortisation
Other income
Finance costs
Other financial gains
Statement of financial position as at December 31, 2018
Provision for asset restoration obligations
Provisions
Other payable
(90,339)
(14,376)
1,718
(9,061)
12,982
277,697
-
10,351
(600)
600
816
(179)
(637)
(277,697)
284,300
(6,603)
(90,939)
(13,776)
2,534
(9,240)
12,345
-
284,300
3,748
* These relate to ordinary shares that Mr. Neuhauser is deemed to have an interest in, through Livermore Strategic Opportunities LP. Mr. Neuhauser
is the Managing Director of Livermore Strategic Opportunities LP and hence has the power and authority to direct its activities.
Repayment of secured convertible bond
Tyrus Capital Event S.à r.l., an entity controlled by Tyrus Capital S.A.M., entered into a secured convertible bond facility agreement with the Company in
November 2016. Tyrus Capital S.A.M. controls entities that hold approximately 25.6% of the Company’s ordinary share capital, as at December 31, 2019.
On August 1, 2018, the Company and Tyrus Capital Event S.à r.l. conditionally agreed, upon the Company’s admission and listing on AIM, that the
Company would redeem the secured convertible bond facility by paying US$17.4 million to Tyrus Capital Event S.à r.l., and all associated security
released. At June 30, 2018, the balance on the bond was drawn to US$15.0 million. Repayment subsequently occurred on August 15, 2018.
The reclassifications of comparative figures have been reflected in the statement of cash flows.
As a result of the finalisation of the PPA during the financial year ended December 31, 2019, certain line items have been amended in the statement of
financial position and related notes to the financial statements.
The items were adjusted as follow:
Oil and gas properties
Inventories
Trade and other payables
PROVISIONAL PPA
USD’000
Adjustments
USD’000
415,365
29,831
(30,674)
14,828
(14,009)
(819)
FINAL PPA
USD’000
430,193
15,822
(31,493)
Jadestone Energy 2019 Annual Report 116
117
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Montara Venture
Jadestone Energy 2019 Annual Report
118
Management’s Discussion and Analysis
for the years ended December 31, 2019 and December 31, 2018
119
The following management’s discussion and analysis (“MD&A”)
of the operational and financial results and position of Jadestone
Energy Inc. (the “Company”, or “Jadestone”) is prepared as at April
23, 2020, and should be read in conjunction with the Company’s
consolidated audited financial statements (the “Financial
Statements”) as at, and for the years ended December 31, 2019
and December 31, 2018.
The MD&A was reviewed by the Company’s Audit Committee and
approved by the Board of Directors on April 23, 2020. Any events
subsequent to December 31, 2019, which could materially alter the
reliability and usefulness of the information disclosed, have been
considered and disclosed as appropriate.
The consolidated financial statements for the years ended
December 31, 2019 and December 31, 2018, and comparative
information presented therein, have been prepared in accordance
with International Financial Reporting Standards (“IFRS”) and
are expressed in United States Dollars (“US$” or “USD”). Unless
otherwise stated, comparisons of results are for the years ended
December 31, 2019 and 2018, and the Company’s financial
position as at December 31, 2019 and 2018.
Forward Looking Statements
Producing Assets
This MD&A contains forward-looking statements which are based
on management assumptions, taking into account all known risks,
uncertainties and any other factors which could cause the actual results,
performance and achievements to be materially different. Management
considers these assumptions to be reasonable, but they may prove
to be incorrect, so readers are cautioned not to place reliance on these
forward-looking statements.
Non-Gaap Measures
The Company uses measures primarily based on IFRS, but also uses
some secondary non-GAAP measures. The non-GAAP measures
included in this MD&A and related disclosures are: earnings before
interest, tax, depreciation and exploration (“EBITDAX’), total debt
and net debt. Neither of these measures is used to enhance the
Company’s reported financial performance or position. There are no
comparable measures in accordance with IFRS for EBITDAX, total debt
and net debt. These are useful complimentary measures that are used
by management in assessing the performance and liquidity of the
Company. The non-GAAP measures do not have standardised meanings
prescribed in IFRS, and are therefore unlikely to be comparable to similar
measures presented by other issuers. They are common in the reports
of other companies, but may differ by definition and application.
Corporate Overview & Strategy
Jadestone is an upstream oil and gas company incorporated in Canada.
The Company’s ordinary shares are listed on the Alternative Investment
Market (“AIM”), a sub-market of the London Stock Exchange, and were
listed on the TSX Ventures Exchange (“TSX-V”) until March 24, 2020,
when the Company delisted from the TSX-V. The Company remains
a Canadian domiciled corporation, and has applied to the applicable
securities commissions for designated foreign issuer reporting
treatment. The Company trades under the symbol “JSE”.
The Company and its subsidiaries (the “Group”) are engaged in
production, development, and exploration and appraisal activities
in Australia, Vietnam, Philippines, and, once the Company closes its
acquisition of the Maari asset described below, New Zealand.
On November 18, 2019, the Company executed a sale and purchase
agreement (“SPA”) with Österreichische Mineralölverwaltungs
Aktiengesellschaft New Zealand (“OMV New Zealand”), to acquire an
operated 69% interest in the Maari project, for a total consideration
of US$50.0 million, subject to customary working capital adjustments.
The transaction is subject to regulatory approvals, and joint venture
partner acceptance. When the necessary approvals and acceptance
have been received, the transaction will close, and operatorship of
the Maari project will transfer to the Company. The economic benefits
from January 1, 2019 until the closing date will be adjusted in the final
consideration paid to OMV New Zealand. The Company anticipates
to complete the acquisition in the second half of 2020.
Australia
Stag Oilfield
The Stag Oilfield, in block WA-15-L, is located 60km offshore Western
Australia in a water depth of approximately 47 meters. As at December
31, 2019, the field contained total proved plus probable reserves of
14.8 million barrels of oil (100% net to Jadestone), compared to
16.2 million barrels at the end of 2018.
During 2019, the Group drilled and successfully completed the 49H
infill well, which targeted 1.2mm bbls of 2P reserves. First oil from the
well was achieved on May 21, 2019, at a rate of 1,400 bbls/d, meeting
expectations. The average production for 49H over the period between
May 22, 2019 to the year-end averaged 838 bbls/d.
Montara Oilfield
On September 28, 2018, the Group acquired the Montara Assets, located
in shallow water offshore Australia, from PTTEP Australasia (Ashmore
Cartier) Pty Ltd (“PTTEP Australasia”). The Group reports the first full
year of results for the Montara Assets in calendar year 2019.
The Montara project is located in production licenses AC/L7 and AC/L8,
in the Timor Sea, in a water depth of approximately 77 meters.
The Montara Assets, comprising the three separate fields being
Montara, Skua and Swift/Swallow, are produced through a centralised
FPSO. As at December 31, 2019, the Montara Assets had proven plus
probable reserves of 27.0 million barrels of oil (100% net to Jadestone),
compared to 26.6 million barrels at the end of 2018.
During 2019, the Group successfully installed the replacement subsea
umbilical cables at Montara. The umbilical cables are an essential part
of the control system providing electrical power and control signals to
the subsea well-heads.
On January 11, 2019, production at Montara restarted following a
voluntary shut down initiated on November 1, 2018, to rectify an
inspection and maintenance backlog. As a result of the shutdown,
on January 7, 2019, the seller (PTTEP Australasia) agreed to fund future
cash calls to a cap of US$22.0 million. Management believed that the
shutdown was the result of facts and circumstances that existed at the
acquisition date, and so adjusted the purchase price allocation.
During calendar 2019, the Company completed the Montara purchase
price allocation (“PPA”) exercise to determine the fair values of the net
assets acquired within the stipulated time period of 12 months from the
acquisition date of September 28, 2018, and in accordance with IFRS3
Business Combinations. The adjusted fair values of identifiable assets
and liabilities have been reflected in the consolidated statement of
financial position, as at December 31, 2018.
New Zealand
Maari Oilfield
On November 18, 2019, the Group executed a SPA with OMV New
Zealand, to acquire an operated 69% interest in the Maari project, for a
total cash consideration of US$50.0 million, and subject to customary
closing adjustments. The field holds 2P reserves of 13.9 million bbls
of oil, net to Jadestone’s 69% interest, and current production is
approximately 4,000 bbls/d, again, on a net 69% basis. The transaction
is expected to close in the second half of 2020
Jadestone Energy 2019 Annual Report 120
Management’s Discussion and Analysis
for the years ended December 31, 2019 and December 31, 2018
121
Block 127 PSC
Jadestone operated Block 127 PSC, with a 100% working interest, a legacy
asset inherited from the prior management team. This predominantly
deep water block covers an area of 9,000 km2 and is located at the
southern end of the Phu Khanh Basin, off the east coast of Vietnam.
During the quarter ended March 31, 2018, the Group performed a review
of its asset base, and as a result of that review, decided to relinquish
Block 127 at the end of the current exploration phase on May 24, 2018.
Having completed all minimum work commitments, Jadestone informed
PVN of its relinquishment decision on April 4, 2018, the license was
returned in October 2018, and the Group has officially relinquished the
PSC. The Group recorded an impairment charge of US$11.9 million during
the three months ended March 31, 2018, reducing the book value to nil.
Block 05-1 PSC
On August 9, 2016, the Group, as buyer, signed a definitive agreement
with Teikoku, a wholly-owned subsidiary of Inpex Corporation, as seller,
for the acquisition of a 30% working interest in the Block 05-1 PSC, for
a total cash consideration of US$14.3 million, and subject to normal
closing adjustments.
On February 22, 2018, Teikoku delivered to Jadestone a purported notice
of termination of the SPA, despite Teikoku having just received on
February 9, 2018, the waiver by PVN, of PVN’s statutory pre-emption
rights, held under Vietnamese law. The Group has not accepted Inpex’s
alleged termination, and views the obligations of both parties under the
SPA as continuing. The Group maintains its rights under the SPA, and is
assessing its options, including remedies through legal action.
Philippines
Service Contract 56 (“SC56”)
Jadestone holds a 25% interest in SC56 in partnership with operator
Total E&P Philippines B.V. (“Total”). Four wells have previously been
drilled on SC56, resulting in the Dabakan and Palendag discoveries.
The current exploration period on the block runs until September 1, 2020.
In September 2012, Total farmed into SC56 and assumed a 75%
interest, and in August 2014 formally confirmed its intention to drill
an exploration well on the Halcon prospect. As a result of the Halcon
confirmation, operatorship was transferred to Total, effective October
25, 2014. The Group views Halcon as an economically viable prospect
with significant resource potential.
Total subsequently informed Jadestone that it did not intend to drill an
exploration well on the Halcon prospect. In December 2017, the Group
commenced an arbitration action against Total, claiming failure by Total
to drill the well and resultant damages. On January 3, 2020, the tribunal
found in favour of Jadestone and awarded monetary damages of US$11.1
million, plus legal fees of approximately US$4.3 million, less expenditure
incurred prior to the breach.
On March 26, 2020, the Company received notification of the final award
from the SIAC. The final award confirmed the appropriate deduction
of US$0.7 million, which generated a net award of US$2.2 million after
including all legal fees and the Company’s share of the SIAC costs, and
the deduction of litigation funding fees.
Under the terms of SC56, Total and Jadestone are committed to drill
one more exploration well on the block prior to expiry. The Company
continues to assess all available options in advance of the licence
expiration on September 1, 2020. The Company’s net share of the
penalty in the event the well is not drilled is approximately US$2.4
million.
Service Contract 57 (“SC57”)
The Group holds a 21% working interest in SC57, but it has been under
force majeure since 2011, and these conditions are expected to continue
for the next 12 to 24 months.
Exploration, appraisal and
pre-development assets
The current Southeast Asia (“SEA”) exploration and pre-development
asset portfolio comprises approximately 4.6 million acres of awarded
acreage, and comprises two production sharing contracts (“PSC”) in
Vietnam (Block 51 and Block 46/07), and two service contracts (“SC”) in
the Philippines (SC56 and SC57).
Vietnam
Block 51 PSC and Block 46/07 PSC
Jadestone holds a 100% operated working interest in the Block 51 PSC
and the Block 46/07 PSC, both in shallow waters in the Malay Basin,
offshore Southwest Vietnam. The two blocks hold three discoveries: the
U Minh and Tho Chu gas/condensate fields in Block 51, and the Nam Du
gas field in Block 46/07.
Prior to May 1, 2017, both blocks were held jointly with Petrovietnam
Exploration and Production (“PVEP”), on a 70:30 Jadestone/PVEP
working interest basis. Effective May 1, 2017, PVEP relinquished its
working interests in both blocks, leaving Jadestone as operator with a
100% working interest. The amended investment licenses for the Block
51 PSC and Block 46/07 PSC, showing Jadestone as operator with a
100% working interest in both licenses, was approved by the Vietnam
Government on October 14 and 15, 2019 respectively.
Jadestone’s priority is to develop the Nam Du and U Minh fields with a
view to selling gas into the Vietnamese domestic market. Accordingly,
on May 21, 2018, the outline development plan (“ODP”), proposing a
standalone joint development of these two fields, was approved by
the Vietnamese Ministry of Industry and Trade. On October 17, 2019,
Jadestone made the formal declaration of commercial discovery for the
Nam Du and U Minh fields, and submitted the formal field development
plan (“FDP”) for the combined Nam Du/U Minh development project to
Vietnam Oil and Gas Group (“PVN”) for approval.
On March 19, 2020, the Company announced that in light of changing
market conditions, and in the absence of government approvals of the
FDP, the Company has decided to delay the project. It is now anticipated
that first gas will be no earlier than late 2022.
Block 51 is currently held in a suspended development area (“SDA”)
status. The portion of the block containing the U Minh field will be
converted to a development/production area upon approval of the FDP.
The remainder of the block, including the Tho Chu field, will remain in
SDA status until June 11, 2021. The Tho Chu field will be subject to a later
development plan.
Under the terms of the Block 46/07 PSC, Jadestone is committed to
drill one more appraisal well on the block. The Group plans to drill the
appraisal well on the Nam Du field to prove up additional resource.
This well is planned to be retained for future use as a Nam Du gas
producer. On November 13, 2018, the Vietnam Government approved a
request by the Group to extend the Block 46/07 exploration phase two
period by a further two years to June 29, 2020. Jadestone submitted a
request to PVN seeking Government approval for a further one-year
extension to exploration phase two to June 29, 2021, and this was
approved on February 26, 2020.
Jadestone Energy 2019 Annual Report
122
Management’s Discussion and Analysis
for the years ended December 31, 2019 and December 31, 2018
123
Operational Activities
Selected Financial Information
Montara Oilfield
Production for 2019, the first full calendar year for Montara under Jadestone ownership, averaged 10,483 bbls/d1, compared to 7,585 bbls/d for the post
acquisition period September 28, 2018 to October 31, 2018 in the prior year. The facility was shut in from November 1, 2018 to January 11, 2019 to address
an inspection and maintenance backlog. The 2018 full year production for Montara was 7,637 bbls/d, based on 304 days of production (i.e. excluding the
voluntary shutdown during November and December, and including the period prior to the closing of the transaction on September 28, 2018).
During the three-month period ended December 31, 2019, Montara production averaged 10,894 bbls/d, compared to fourth quarter 2018 production of
2,570 bbls/d based on October production averaged across the whole quarter, as the field was voluntarily shut-in during November and December 2018.
There was a total of six liftings in 2019, resulting in total sales of 3,577,204 bbls, compared to the year ended December 31, 2018 of one lifting and total
sales of 451,291 bbls from the date of closing the Montara acquisition on September 28, 2018 and the shut down between November 1, 2018 to January
11, 2019.
Stag Oilfield
Production for the 2019 calendar year averaged 3,049 bbls/d, compared to 2,799 bbls/d for the year ended December 31, 2018. The increase was due to
the Stag 49H infill well which came online with an initial rate of 1,400 bbls/d upon completion on May 21, 2019, partially offset by downtime associated
with cyclones in 2019, and delays to workovers in the first half of 2019, during the period that the 49H infill well was being drilled.
During the three-month period ended December 31, 2019, production was 3,808 bbls/d, compared to fourth quarter 2018 of 2,644 bbls/d, due to the
impact of the additional production after completion of the 49H well on May 21, 2019, and also production optimisation for other wells.
There was a total of four liftings in 2019, resulting in total sales of 918,961 bbls, compared to the year ended December 31, 2018 of five liftings and total
sales of 1,031,763 bbls.
Ogan Komering PSC
The Ogan Komering PSC expired on February 28, 2018, and a temporary co-operation contract was entered into, continuing the terms of the PSC which
ended on May 19, 2018.
There was no production in 2019, compared to 1,439 bbls/d for the period January 1, 2018 to May 19, 2018. There was no production in the fourth quarter
of 2019 or 2018.
1 Montara total production averaged across the full 365 days was 10,483bbl/d. Actual production for 2019 was 10,778 bbl/d averaged across 355 days of
production from the start of Montara following the voluntary inspection and maintenance shutdown.
The following table provides selected financial information of the Group, which was derived from, and should be read in conjunction with, the
consolidated financial statements for the years ended December 31, 2019 and December 31, 2018.
USD’000 EXCEPT
WHERE INDICATED
DEC 31,
2019
SEP 30,
2019
JUNE 30,
2019
THREE MONTHS ENDED
DEC 31,
2018
MAR 31,
2019
SEP 31,
2018
JUNE 31,
2018
MAR 31,
2018
Production (boe/day)
Revenues 1
Net earnings/(loss)
- Per share: basic & diluted
Funds from/(used in) operating
activities
- Per share: basic & diluted
14,702
91,200
10,364
0.02
45,846
0.10
13,036
62,500
19
0.00
37,114
0.08
13,315
115,341
21,762
0.05
33,013
0.07
13,059
56,366
8,360
0.02
28,664
0.06
5,215
44,972
(6,573)
(0.01)
32,495
0.07
3,080
32,669
(2,955)
(0.01)
(12,224)
(0.03)
4,239
17,496
(4,912)
(0.02)
(2,583)
(0.01)
4,101
18,287
(16,593)
(0.07)
77
0.00
1 Revenue was restated during Q4 2018, including prior periods, from a gross to net basis after deducting royalties, but including realised effective hedging gains/losses. This restatement has
been undertaken pursuant to IFRS15 and implemented in the consolidated financial statements for the year ended December 31, 2018.
Quarter ended: Dec 31, 2019
The average production for the period was 14,702 bbls/d. The Group lifted 1,266,318 bbls during the quarter, which generated US$87.7 million in revenues,
before hedging income of US$3.5 million, and US$45.8 million in operational cashflows after changes in working capital, interest and taxes.
Quarter ended: Sep 30, 2019
The average production for the period was 13,036 bbls/d. Three workovers at Stag were completed during the period, which had been delayed from the
prior period, due to the drilling of 49H infill well. The Group lifted 891,644 bbls during the quarter, which generated US$58.3 million in revenues, before
hedging income of US$4.2 million, and US$37.1 million in operational cashflows after changes in working capital, interest and taxes.
Quarter ended: Jun 30, 2019
The average production for the period was 13,315 bbls/d. The completion of the 49H infill well at Stag on May 21 generated initial production of over
1,400 bbls/d. The additional production was offset by three wells requiring workovers (subsequently undertaken in Q3 2019). The Group lifted
1,589,352 bbls during the quarter, which generated US$114.0 million in revenues, before hedging income of US$1.4 million, and US$33.0 million
in operational cashflows.
Quarter ended: Mar 31, 2019
The average production for the period was 13,059 bbls/d, with Montara restarting production on January 11, 2019 (averaged across the whole quarter).
The Group lifted 748,851 bbls during the quarter, which generated US$50.6 million in revenues, before hedging revenue of US$5.7 million, and US$28.7
million in operational cashflows
Quarter ended: Dec 31, 2018
Montara production averaged 7,628 bbls/d during October 2018, but was shut in to address an inspection and maintenance backlog during November
and December. The average quarter production at Stag was 2,644 bbls/d, or a total of 5,215 bbls/d for the quarter including Montara October production
averaged across the whole quarter. The period was impacted by an additional US$4.0 million charge for the safety inspection and maintenance work.
Quarter ended: Sep 30, 2018
Stag reported production for the quarter to September 30, 2018 of 3,080 bbls/d. The Montara Assets were acquired on September 28, 2018 and
averaged 7,585 bbls/d for the three days to September 30, 2018, which is excluded from the production shown in the quarterly summary above. Funds
used in operations include a net investment (i.e. funds outflow) in working capital of US$12.2 million.
Quarter ended: Jun 30, 2018
Production was 4,239 boe/d for the quarter, reflecting improved uptime at Stag, despite planned maintenance activities which caused the deferral of
38,000 bbls of production, or 417 bbls/d, for the quarter. Revenue was US$17.5 million, due to higher benchmark prices offset by lower production, with
the expiry of the Ogan Komering PSC on May 19, 2018.
Quarter ended: Mar 31, 2018
Stag production was impacted by marine breakaway coupling and electric submersible pump issues, plus poor weather conditions.
Ogan Komering maintained steady production. Net earnings were impacted by an US$11.9 million exploration write-off, with respect to Block 127.
Jadestone Energy 2019 Annual Report
124
Management’s Discussion and Analysis
for the years ended December 31, 2019 and December 31, 2018
125
Production
Reclassification of Comparative Figures
USD’000
DEC 31, 2019
DEC 31, 2018
DEC 31, 2019
DEC 31, 2018
THREE MONTHS ENDED
YEAR ENDED
Certain comparative figures in the financial statements of the Group have been reclassified, to conform to the presentation in the current financial year.
These relate to the following:
Montara crude oil (bbls/d)
Stag crude oil (bbls/d)
Ogan Komering oil and gas (boe/d)
Total (boe/d)
10,894
3,808
-
14,702
2,571
2,644
-
5,215
10,4831
3,049
-
13,8261
710
2,799
548
4,057
Production averaged 13,8261 bbls/d during 2019, compared to 4,057 boe/d for the twelve months ended December 31, 2018 due to:
•
•
First full year of Montara production generated an average annual increase of 10,068 bbls/d (2018 production: 710 bbls/d);
Increased production at Stag by 250 bbls/d, due to additional production generated after completion of the 49H infill well on May 21, 2019, partially
offset with higher than anticipated downtime due to cyclones and delayed workovers while drilling 49H; and
•
The Ogan Komering PSC expired in 2018, which resulted in a fall in production of 548 boe/d averaged across 365 days. Average production based on
the 139 days of production from January 1, 2018 to May 19, 2018 was 1,439boe/d.
Fourth quarter 2019 production of 14,702 bbls/d compares with 5,215 boe/d for the same quarter a year ago, largely due to the impact of the Montara
shutdown during November and December 2018, and higher production at Stag in Q4 2019 in part due to the contribution from 49H.
Benchmark Commodity Price and Realised Price
The average annual benchmark Brent crude oil price decreased to US$64.27/bbl in calendar 2019, compared to US$71.31/bbl, in the twelve months ended
December 31, 2018. The benchmark price for Q4 2019 was US$63.08/bbl, compared to US$68.81/bbl for the same quarter in 2018.
The average annual realised price in calendar 2019 was US$69.07/bbl, compared to US$69.39/bbl in the twelve months ended December 31, 2018.
Realised prices were able to be maintained during the year, despite declining benchmark oil prices, as sales premiums on Stag and Montara increased
from an average of US$3.65/bbl in Q1 2019, to US$6.22/bbl by the end of 2019. The demand for sweet crude oil has increased, and in particular in
the case of Stag, for heavy sweet crude oil, given the International Maritime Organization (“IMO”) 2020 regulations, which came into effect from
January 1, 2020, reducing marine sector sulphur emissions in international waters.
The Brent benchmark price in Q4 2019 was US$63.08/bbl (Q4 2018: US$68.81/bbl), compared to realised prices of US$69.24/bbl (Q4 2018: US$67.51/bbl).
Realised prices in Q4 2019 included an average premium of US$6.22/bbl (Q4 2018: US$2.78/bbl), due to the increased demand for sweet heavy crudes
caused by the IMO 2020 regulations.
Implementation of New Accounting Standards
IFRS16 Leases
The Group has applied IFRS16 Leases (as issued by the IASB in January 2016) from January 1, 2019. The Company adopted the cumulative catch-up
approach under IFRS16, which permits Jadestone to elect not to restate comparatives.
On adoption, IFRS16 changed how the Group accounts for leases previously classified as operating leases.
IFRS16 has the following impacts on the Group accounts:
• Recognises right-of-use assets, and lease liabilities, in the consolidated statement of financial position, initially measured at the present value of
future lease payments;
• Recognises depreciation of right of use assets, and interest on lease liabilities, in the consolidated statement of profit or loss; and
•
Separates the total amount of cash paid into a principal portion (presented within financing activities), and interest (presented within operating
activities), in the consolidated statement of cash flows.
1 Total Group (Montara) production averaged across the full 365 days of 2019 was 13,531 bbls/d (10,483 bbls/d). Total Group (Montara) actual
production for 2019 was 13,826bbls/d (10,778 bbls/d), averaged across 355 days of production from the restart of Montara, following the voluntary
inspection and maintenance shutdown.
Montara - Restatement of purchase price adjustments in accordance with IFRS3 Business Combinations
During the year, the Group has completed the purchase price allocation (“PPA”) exercise to determine the fair values of the net assets acquired within
the stipulated time period of 12 months from the acquisition date of September 28, 2018, in accordance with IFRS3 Business Combinations. Following
the transfer of operatorship on August 6, 2019, the Group was able to confirm an inventory adjustment of US$14.0 million in order to align with the
Group’s accounting policies. The adjusted fair values of identifiable assets and liabilities have been reflected in the consolidated statement of financial
position as at December 31, 2018.
Below are the effects of the final PPA adjustments in accordance with IFRS3:
FAIR VALUE OF PURCHASE CONSIDERATION
PROVISIONAL PPA
USD’000
ADJUSTMENTS
USD’000
FINAL PPA
USD’000
Asset purchase price
Crude inventory value
Capital charge
Net cash adjustment
Cash payment on acquisition date
Deferred contingent consideration
Prepaid Asset for future cash calls
Working capital adjustment
Total
195,000
6,657
6,982
(75,547)
133,092
15,805
(22,000)
997
127,894
-
-
-
-
-
-
-
819
819
195,000
6,657
6,982
(75,547)
133,092
15,805
(22,000)
1,816
128,713
Assets acquired and liabilities assumed at the date of acquisition, September 28, 2018:
PROVISIONAL PPA
USD’000
ADJUSTMENTS
USD’000
FINAL PPA
USD’000
Asset
Non-current assets
Oil & gas properties
Current assets
Inventories
Prepayments
Total assets
Liabilities
Current liabilities
Trade and other payables
Non-current liabilities
Provision for asset restoration obligations
Deferred tax liabilities
Other provisions
Total liabilities
Net identifiable assets acquired
353,806
35,373
4,917
394,096
(4,314)
(183,020)
(78,437)
(431)
(266,202)
127,894
14,828
(14,009)
-
819
-
-
-
-
-
819
368,634
21,364
4,917
394,915
(4,314)
(183,020)
(78,437)
(431)
(266,202)
128,713
Jadestone Energy 2019 Annual Report
126
Management’s Discussion and Analysis
for the years ended December 31, 2019 and December 31, 2018
Results of Operations
CONSOLIDATED STATEMENT OF PROFIT & LOSS
THREE MONTHS ENDED DECEMBER 31,
2018
USD’000
2019
USD’000
Revenue
Production costs
Depletion, depreciation and amortisation
Staff costs
Other expenses
Impairment of assets
Other income
Finance costs
Other financial gains
Profit/(Loss) before tax
Income tax expense
Profit/(Loss) for the quarter/year
Earnings/(Loss) per ordinary share
Basic and diluted (US$)
91,200
(25,876)
(27,331)
(6,328)
(2,471)
-
553
(3,267)
582
27,062
(16,698)
10,364
44,972
(50,602)
(5,932)
(3,921)
(3,276)
-
6,665
(5,186)
12,345
(4,935)
(1,638)
(6,573)
YEAR ENDED DECEMBER 31,
2019
USD’000
325,406
(119,898)
(90,746)
(19,714)
(11,692)
-
2,979
(16,443)
3,389
73,281
(32,776)
40,505
2018
USD’000
113,423
(90,939)
(13,776)
(13,538)
(10,374)
(11,901)
2,534
(9,240)
12,345
(21,466)
(9,567)
(31,033)
0.02
(0.01)
0.09
(0.10)
Consolidated statement of comprehensive income
Profit/(Loss) for the quarter/year
10,364
(6,573)
40,505
(31,033)
Other comprehensive income
Items that may be reclassified subsequently to profit or loss:
(Loss)/Gain on unrealised cash flow hedges
Hedging gain reclassified to profit & loss
Tax income/(expense) relating to components of other
comprehensive income
Other comprehensive (loss)/income
Total comprehensive income for the quarter/year
(9,688)
(3,520)
(13,208)
3,962
(9,246)
1,118
51,775
(1,088)
50,687
(15,207)
35,480
28,907
(30,542)
(14,874)
(45,416)
13,624
(31,792)
8,713
51,775
(1,088)
50,687
(15,207)
35,480
4,447
127
Revenue
Revenue for the year was US$325.4 million, compared to US$113.4
million for the twelve month period ended December 31, 2018. The
variance of US$212.0 million was largely due to:
•
Sales volumes of 4.5mm bbls in calendar 2019, compared to 1.7mm
bbls in calendar 2018, or an additional US$195.2 million;
• An increase in hedging income of US$14.5 million, or income
of US$14.9 million earned in 2019, compared to US$0.4 million
incurred in 2018;
• An increase of US$3.5 million due to a royalty deduction in 2018
related to Ogan Komering not incurred in 2019; and
• A slight reduction in the annual net realised price to US$69.07/bbl
in 2019, compared to US$69.39/boe in 2018, or a reduction of
US$1.4 million.
Revenue for the three months ended December 31, 2019 was US$91.2
million, compared to US$45.0 million for the same quarter in 2018, or an
increase of US$46.2 million, largely due to:
•
Group liftings of 1.3mm bbls in Q4 2019, compared to 0.6mm bbls in
Q4 2018, or an additional US$41.1 million;
• An increase in hedging income of US$3.1 million, or income of
US$3.5 million earned in Q4 2019, compared to US$0.4 million in Q4
2018; and
• An increase in realised prices to US$69.24/bbl in Q4 2019, compared
to US$67.51/bbl in Q4 2018, or an additional US$2.2 million.
Production costs
Production costs in 2019 were US$119.9 million, compared to US$90.9
million. The variance of US$29.0 million was due to:
• Montara’s production costs increased by US$41.7 million, due to
a full calendar year of ownership in 2019, compared to the period
September 28, 2018 to December 31, 2018;
•
•
Partly offset by a decrease in Stag’s production costs of US$10.1
million, due in part to the adoption of IFRS16 Leases which
transferred US$7.7 million to DD&A and finance costs. The
remaining US$2.4 million year-on-year differential at Stag relates
largely to movements in closing inventory. There were 581,128 bbls
at December 31, 2019, compared to 138,425 bbls as at December 31,
2018; and
Further partly offset by a decrease in Ogan Komering’s production
costs by US$2.6 million due to the expiry of the Ogan Komering PSC
in 2018.
Production costs decreased to US$25.9 million during Q4 2019, compared
to US$50.6 million for the same quarter in 2018, predominately due to:
• A decrease of US$15.6 million due to movements in crude oil
inventories due to a significantly larger closing inventory balance for
Q4 2019, compared to Q4 2018;
• A decrease of US$4.0 million in repairs and maintenance associated
with the Montara shutdown between November 1, 2018 to January
10, 2019 incurred in 2018;
• A decrease of US$1.9 million due to the adoption of IFRS16, which
transferred lease payments related to the Stag floating storage and
offloading facility (“FSO”) to DD&A and finance costs in Q4 2019,
compared to Q4 2018 when they were recorded as production costs;
and
• A decrease of US$3.4 million of inventory write down incurred at
Montara in October 2018.
Depletion, depreciation and amortisation (“DD&A”)
DD&A charge in 2019 was US$90.7 million, compared to US$13.8 million
in 2018, with the increase predominately due to:
• An increase of US$68.7 million for the Montara depletion charge,
largely due to a full year’s operations in 2019, compared to one
month in 2018. The Montara assets were acquired on September
28, 2018 and were shut down to address an inspection and
maintenance backlog from November 1, 2018 to January 10, 2019.
Montara’s DD&A per unit of production increased from US$18.39/
bbl in 2018 to US$19.20/bbl in 2019, due to the subsea umbilical
project and other capex projects completed in 2019, which resulted
in higher annual charges of US$3.3 million over the year;
• An additional US$14.9 million in calendar 2019 due to the
recognition of right-of-use assets, pursuant to the adoption of
IFRS16 Leases. In 2018, the operating leases were included in
production costs and other expenses;
•
Stag’s DD&A increased by US$1.6 million, or from US$8.43/bbl in
2018 to US$9.20/bbl in 2019, due to the capital costs associated
with the 49H infill well;
• A decrease of US$0.6 million related to the end of the PSC at Ogan
Komering during 2018; and
• A decrease in inventory movements generated a negative variance
of US$7.6 million, reflecting higher inventory balances at December
31, 2019 of 581,128 bbls, compared to 138,425 bbls held in inventory
at December 31, 2018.
DD&A charge for the three-month period ended December 31, 2019 was
US$27.3 million, compared to US$5.9 million in 2018, with the increase
predominately due to:
• Montara depletion charges increased US$14.5 million due to
additional production volumes in Q4 2019 of 1,002,224 bbls
compared to 236,481 bbls in Q4 2018, as a result of the inspection
and maintenance shutdown in November and December 2018;
• An additional US$4.1 million in Q4 2019, due to the recognition of
right-of-use assets pursuant to the adoption of IFRS16 Leases from
January 1, 2019;
• Montara unit DD&A increased from US$18.87/bbl in Q4 2018 to
US$20.00/bbl in Q4 2019, generating an additional US$1.1 million
expense, reflecting the capex projects brough on stream during the
year including the subsea umbilical project;
•
•
Stag produced higher volumes in Q4 2019 of 350,381 bbls, compared
to 243,268 in Q4 2018, resulting in an increase of US$0.9 million in
depletion charges; and
The Stag unit DD&A increased from US$8.31/bbl in Q4 2018 to
$9.24/bbl in Q4 2019, reflecting the additional capital expenditure
associated with the 49H infill well, brought on-stream in Q2 2019.
This generated a variance of US$0.3 million.
Staff costs
Staff costs in 2019 have increased to US$19.7 million in 2019, compared
to US$13.5 million in 2018, predominately due to an increase in the
number of staff in Australia since the Group took over the operatorship
of Montara in August 2019, and in Vietnam in preparation for project
sanction of Nam Du/U Minh.
As at December 31, 2019, there were 197 full time equivalent personnel
(“FTE”), compared to 80 FTE’s as at December 31, 2018.
Staff costs have increased to US$6.3 million during Q4 2019, compared
to US$3.9 million for the same quarter in 2018, which reflected the
annual trend in increased FTE’s.
Jadestone Energy 2019 Annual Report 128
Management’s Discussion and Analysis
for the years ended December 31, 2019 and December 31, 2018
129
Other expenses
Other expenses for the full year 2019 were US$11.7 million (2018: US$10.4
million), with the variance predominately due to:
• An increase of US$1.6 million in one off projects (Maari US$0.7
million, Montara transition team US$3.1 million) and other
consultancy services (US$1.1 million), compared to Montara
acquisition costs of US$1.4 million and AIM listing expenses of
US$1.9 million in 2018;
• An increase of US$0.8 million associated with ineffective cashflow
hedge movements and foreign exchange losses, compared to US$
nil in 2018, due to ineffective hedge and foreign exchange gains
recognised in other Income; and
Finance costs for the quarter ended December 31, 2019 were US$3.3
million, a decrease of US$1.9 million from the same period in 2018,
predominately due to:
• An increase of US$1.0 million for finance charges on lease liabilities
pursuant to the adoption of IFRS16 effective January 1, 2019 (2018:
US$ Nil);
• A decrease of US$2.1 million associated with lease RBL interest
decreased from US$3.0 million in Q4 2018 to US$0.9 million in Q4
2019, as the Group paid down the loan from US$120.0 million since
the draw down date of September 28, 2019, to US$49.1 million as at
December 31, 2019; and
• A decrease of US$0.7 million in office costs associated with the
change in accounting policies under IFRS16 as office leases are now
recognised in depreciation and finance costs.
• A decrease of US$0.8 million of accretion expense on ARO in Q4
2019 to US$1.2 million (2018: US$2.0 million), due to the annual
review and changes in assumptions supporting the calculation.
Taxation
USD’000
Current tax
Corporate
Petroleum resource rent tax (“PRRT”)
Deferred tax
Tax depreciation
Tax losses
PRRT
THREE MONTHS ENDED
YEAR ENDED
DEC 31, 2019
DEC 31, 2018
DEC 31, 2019
DEC 31, 2018
(11,953)
(1,509)
(13,462)
2,689
-
(5,925)
(3,236)
(16,698)
(483)
(2,757)
(3,240)
(4,014)
4,972
644
1,602
(1,638)
(43,370)
1,850
(41,520)
20,285
(5,257)
(6,284)
8,744
(32,776)
(2,188)
(6,221)
8,409
(3,196)
2,812
(774)
(1,158)
(9,567)
Other financial gains
Other financial gains decreased by US$9.0 million to US$3.4 million in
2019, compared to US$12.3 million in 2018, due to a change in the fair
value of contingent payments associated with Montara.
Management deemed two Montara contingent payments as probable
at the acquisition date closing date of September 28, 2018. The two
contingent payments are US$20.0 million and US$10.0 million and are
triggered if the average Dated Brent oil price is above US$80/bbl in each
of 2019 and 2020 respectively. The fair value of the contingent payments
as at the end of 2018 was US$3.7 million, having been revised down from
US$15.8 million at acquisition closing date, generating a gain of US$12.1
million in 2018.
During 2019, the Group has derecognised the 2019 deferred contingent
payment as the annual average Dated Brent oil price in 2019 fell below
US$80/bbl. As at December 31, 2019, the fair value of the remaining
US$10.0 million contingent payment has been re-assessed at
US$0.4million, resulting in a gain of US$3.4 million.
The quarterly movement between Q4 2019 and Q4 2018 is US$11.8
million, this was predominately due to the assessed fair value of the
Montara contingent payments of US$0.6 million (2018: $12.1 million).
During the quarter ended December 31, 2019, the Group incurred US$2.5
million of other expenses compared to US$3.3 million in Q4 2018,
predominately due to:
•
Professional fees incurred associated with the acquisition of Maari
project of US$0.6 million in Q4 2019, compared US$1.1 million of
fees in Q4 2018; and
• A decrease in rental expenses of US$0.3 million pursuant to the
adoption of IFRS16.
Impairment of assets
The Group has conducted an impairment review in 2019 and concluded
no impairment is required.
In 2018, the Group decided to relinquish block 127 in Vietnam after all
work programme commitments had been performed, and wrote off all
capitalised balances.
Finance costs
Finance costs have increased by US$7.2 million to US$16.4 million in
2019, compared to US$9.2 million 2018, predominately due to:
• An increase of US$3.1 million in interest expenses with US$6.1
million associated with a full year of interest in 2019 on the Group’s
reserve based loan (“RBL”) (2018: US$3.0 million), compared to
three months in 2018;
• An additional US$4.3 million of finance charges on lease liabilities
pursuant to the adoption of IFRS16 effective January 1, 2019 (2018:
US$ Nil);
• An increase of US$2.2 million of accretion expense for Montara and
Stag’s asset retirement obligations (“ARO”) increased to US$5.8
million (2018: US$3.6 million), this was attributable to the annual
update of changes in assumptions used in the calculation; and
• A decrease of US$ 2.5 million due to no convertible bond related
expenses incurred in 2019, compared to US$2.5 million incurred in
2018 (convertible bond facility fees: US$0.6 million, bond accretion
expense: US$0.7 million and fair value loss: US$1.2 million), as the
bond was repaid in August 2018.
The overall tax charge in 2019 increased by US$23.2 million, largely due to:
•
Current corporate income tax increased by US$41.2 million predominately due to:
— Montara generating an income tax charge of US$38.7 million (2018: US$ Nil). There was no income tax charge generated by Montara in 2018 due
to losses incurred for the period between acquisition closing (September 28, 2019), to the financial year end. The comparable period tax losses
arose largely due to to the assets being shut down for an inspection and maintenance backlog between November 1, 2018 to January 10, 2019;
— Stag generating an income tax charge of US$4.7 million (2018: US$1.3 million) reflecting the increase in profitability during the year due to
higher production and revenues, and lower production costs; and
— No income tax charge for Ogan Komering in 2019, compared to US$0.9 million in 2018, following expiry of the Ogan Komering PSC in Q2 2018.
•
Current period PRRT decreased by US$8.1 million as the Group paid US$6.2 million in 2018 but generated a PRRT tax credit of US$1.9 million in
2019; the latter a result of the drilling of the 49H infill well at Stag in Q2 2019 . Montara has PRRT carried forward credits of US$3.1 billion as at
December 31, 2019, the utilisation of credits was exceeded by the augmentation of the existing balance;
• A reduction in deferred tax liabilities, associated with oil & gas properties depletion charges, resulted in a deferred tax credit of US$20.3 million
for the current year (2018: increased tax expense by US$3.2 million). This portion of deferred tax liabilities relates to the larger accounting basis
for Montara’s oil & gas properties, relative to its tax basis, and the deferred tax liability reduces in line with depletion charges;
• Utilisation of Montara carry forward tax losses from 2018 in the course of 2019 gave rise to a charge of US$5.3 million (2018: income of
US$2.8 million); and
•
Deferred PRRT expense of US$6.3 million arose due to an increase in deferred tax liabilities associated with Stag PRRT (2018: US$0.8million),
mostly attributable to the capitalised cost of the 49H infill well for book purposes.
The overall tax charge during Q4 2019 increased by US$15.1 million, largely due to:
•
Current corporate income tax increased US$11.5 million predominately due to:
— Montara generating an income tax charge of US$7.5 million (2018: (US$ Nil)). There was no income tax charge generated by Montara in 2018; and
— Stag generating a charge of US$4.5 million (2018: US$0.5 million) reflecting the increase in profitability.
•
Current PRRT expense for Q4 2019 was US$1.5 million, down US$1.2 million from PRRT expense in Q4 2018 of US$2.8 million, due to higher PRRT
deductibles in 2019, including the costs of the 49 infill well;
• A reduction in deferred tax liabilities, associated with oil & gas properties depletion charges, resulted in a deferred tax credit of US$2.7 million
(Q4 2018: increased tax expense by US$4.4 million). This portion of deferred tax liabilities relates to the larger accounting basis for Montara’s oil
& gas properties, relative to its tax basis, and the deferred tax liability reduces in line with depletion charges;
•
Deferred taxes, in respect of historic carry forward tax losses, was unchanged in Q4 2019, whereas in Q4 2018 there was a tax credit of US$5.0
million arising from the creation of a deferred tax asset due to tax losses at Montara during Q4 2018, largely a result of the inspection and
maintenance shutdown; and
• Deferred PRRT expense at US$5.9 million as a result of an increase in deferred tax liabilities associated with Stag PRRT (2018: tax credit of
US$0.6million), mostly attributable to the capitalised cost of the 49H infill well for book purposes.
Jadestone Energy 2019 Annual Report
130
Management’s Discussion and Analysis
for the years ended December 31, 2019 and December 31, 2018
131
Other comprehensive income
USD’000
DEC 31, 2019
DEC 31, 2018
DEC 31, 2019
DEC 31, 2018
THREE MONTHS ENDED
YEAR ENDED
Profit/(Loss) for the quarter/year
Other comprehensive income
Items that may be reclassified subsequently to profit or loss:
(Loss)/Gain on unrealised cash flow hedges
Hedging gain reclassified to profit & loss
Tax income/(expense) relating to components of other
comprehensive income
Other comprehensive (loss)/income
10,364
(6,573)
40,505
(31,033)
(9,688)
(3,520)
(13,208)
3,962
(9,246)
1,118
51,775
(1,088)
50,687
(15,207)
35,480
28,907
(30,542)
(14,874)
(45,416)
13,624
(31,792)
8,713
51,775
(1,088)
50,687
(15,207)
35,480
4,447
Loss on cash flow hedges
During Q3 2018, the Group entered into a capped swap to hedge approximately 50% of planned production from the existing wells at Montara over the
period October 1, 2018 through to September 30, 2020, at swap rates commencing at US$74.22/bbl, through to US$66.62/bbl, by September 2020. Calls
for a portion of the swapped barrels were bought at a US$80/bbl strike price to September 30, 2019, and at US$85/bbl thereafter.
The swap contracts settle monthly, based on the average Dated Brent oil price in the prevailing month.
The capped swap has been designated as a cash flow hedge, and assessed to be effective with a fair value of US$5.3 million, as at December 31, 2019
(December 31, 2018: US$51.3 million). The fair value is based on third-party valuations for similar products on relevant markets.
The Group recognised a fair value loss on unrealised cashflow hedges for the year ended December 31, 2019 of US$30.5 million (year to December 31,
2018: gain of US$51.8 million), and a fair value loss on unrealised cashflow hedges of US$9.7 million in the three month period ended December 31, 2019
(Q4 2018: gain of US$51.8 million), reflecting the movements in fair value of the remaining hedge contracts on the balance sheet.
Hedging gain reclassified to profit and loss
Following swap settlements, the reclassification of hedge contracts for the year ended December 31, 2019 gave rise to a transfer from other
comprehensive income to revenue of US$14.9 million (year to December 31, 2018: US$1.1 million), and for the three-month period ended December 31,
2019, a transfer to revenue of US$3.5 million (Q4 2018: US$1.1 million). The movement relates to the settlement of hedge contracts associated with the
Montara capped swap throughout 2019, and the ineffective mark-to-market revaluation of the remaining open Montara capped swap contracts.
Tax relating to components of other comprehensive income
The tax components of other comprehensive income for the year ended and three months ended December 31, 2019 are a tax credit of US$13.6 million
and US$4.0 million, respectively, which reflects the deferred tax impact on the net income or expense for the periods.
Financial Position
The following provides selected financial information of the Group, which was derived from, and should be read in conjunction with, the audited
consolidated financial statements for the years December 31, 2019 and December 31, 2018.
USD’000
Non-current assets
Current assets
Non-current liabilities
Current liabilities
Shareholders’ equity
Non-current assets
USD’000
Intangible exploration assets
Oil and gas properties
Plant and equipment
Right-of-use assets
Derivative financial instruments
Restricted cash
Deferred tax assets
Total non-current assets
AS AT DECEMBER 31,
2019
AS AT DECEMBER 31,
2018
594,170
160,911
395,463
134,151
225,467
587,696
142,671
429,936
85,170
215,261
DECEMBER 31,
2019
DECEMBER 31,
2018
116,096
383,018
1,780
59,787
-
17,477
16,012
594,170
95,607
430,193
1,709
-
15,339
23,561
21,287
587,696
Non-current assets as at December 31, 2019 are US$594.2 million (2018: US$587.7 million), an increase of US$6.5 million, predominately due to:
•
Intangible exploration assets - increased by US$20.5 million largely due to the increased expenditure in Vietnam, in preparation of project sanction
of Nam Du/U Minh;
•
Oil and gas properties - decreased by US$47.2 million due to depletion charges for the year, partly offset by costs associated with the Stag 49H infill
well, changes in ARO assumption at Montara and Stag, and pipeline maintenance, among other factors;
• Right-of-use assets - increased by US$59.8 million, pursuant to the adoption of IFRS16;
•
Derivative financial instruments - reduced to nil as at December 31, 2019, from US$15.3 million in 2018, as the swap contracts expire on September
30, 2020 and the balance has been transferred to current assets;
• Restricted cash - decreased by US$6.1 million to US$ 17.5 million, reflecting the declining debt service reserve account balance under the RBL; and
•
Deferred tax assets - decreased by US$5.3 million due to the utilisation of PRRT credits brought forward from the prior year at Stag.
Jadestone Energy 2019 Annual Report 132
Management’s Discussion and Analysis
for the years ended December 31, 2019 and December 31, 2018
Current assets
USD’000
Inventories
Trade and other receivables
Derivative financial instruments
Restricted cash
Cash and cash equivalents
Total current assets
DECEMBER 31,
2019
DECEMBER 31,
2018
31,411
42,283
5,275
6,008
75,934
160,911
15,822
32,800
35,985
5,083
52,981
142,671
Current liabilities
USD’000
Borrowings
Lease liabilities
Trade and other payables
Tax liabilities
Total current liabilities
133
DECEMBER 31,
2019
DECEMBER 31,
2018
41,795
19,739
27,962
44,655
134,151
52,393
-
31,493
1,284
85,170
Inventories - increased by US$15.6 million due to higher closing crude oil inventories at Stag and Montara;
Current assets as at December 31, 2019 were US$160.9 million, compared to US$142.7 million as at December 31, 2018, the increase of US$18.2 million
predominately due to:
•
•
Trade and other receivables - increased by US$9.5 million due to the timing of liftings and invoice settlements at Montara. The last lifting for
Montara was completed on December 17, 2019 with 30 days settlement terms; the cash receipt for this lifting of US$33.9 million was received in
January 2020;
Lease liabilities - increased by US$19.7 million pursuant to the adoption of IFRS16;
Borrowings - decreased by US$10.6 million due to repayments of the RBL by the Group during 2019;
Current liabilities as at December 31, 2019 were US$134.2 million, an increase of US$49.0 million from December 31, 2018, predominately due to:
•
•
•
•
Tax liabilities - increased by US$43.4 million mainly due to the increase in tax liabilities from Montara of US$38.7 million, as a result of profit
before tax achieved by Montara in 2019, compared to a loss before tax in 2018.
Trade and other payables - decreased by US$3.5 million due to differences in settlement dates of standard payables amounts; and
•
Derivative financial instruments - decreased by US$30.7 million to reflect the changes in fair value of the remaining swap contracts that expire on
September 30, 2020; and
• Restricted cash, plus cash and cash equivalents - increased by US$23.9 million, due to organic cash generation in the business in 2019.
Share Capital
The share capital consists of fully paid ordinary shares with a nil par value. All shares are equally eligible to receive dividends and the repayment of
capital, and each share is entitled one vote at the shareholders’ meeting.
Non-current liabilities
USD’000
Provisions
Borrowings
Lease liabilities
Other payable
Deferred tax liabilities
Total non-current liabilities
DECEMBER 31,
2019
DECEMBER 31,
2018
280,418
7,328
42,533
359
64,825
395,463
284,300
49,420
-
3,748
92,468
429,936
Non-current liabilities as at December 31, 2019 were US$395.5 million, a decrease of US$34.5 million from December 31, 2018, predominately due to:
•
Provisions - decreased by US$3.9 million, due to a decrease in the ARO provision of US$2.3 million, reflecting the impact of changes in discount
rate assumptions and estimates, and a reduction in the provision for Stag FSO of US$1.6 million due to changes in estimates;
•
•
•
•
Borrowings - decreased by US$42.1 million due to the reclassification of non-current to current liabilities as at December 31, 2019 year end,
following RBL repayments made by the Group during 2019;
Lease liabilities - increased by US$42.5 million pursuant to the adoption of IFRS16;
Other payable - decreased by US$3.4 million due to the reduction in fair values of the contingent payments to PTTEP, the vendor of the Montara
assets; and
Deferred tax liabilities - decreased by US$27.6 million due to changes in taxable timing differences from Montara.
Number of issued ordinary shares
461,042,811
461,009,478
AS AT DECEMBER 31,
2019
AS AT DECEMBER 31,
2018
At beginning of the year
Issued during the year
At end of the year
USD’000
466,562
11
466,573
USD’000
364,466
102,096
466,562
Shareholders’ equity
Shareholders’ equity increased by US$10.2 million compared to 2018, due to the profit after tax of US$40.5 million generated in the current year, and
transactions with owners of US$1.4 million, partly offset by other comprehensive loss of US$31.8 million arising from Montara hedging instruments.
Jadestone Energy 2019 Annual Report 134
Management’s Discussion and Analysis
for the years ended December 31, 2019 and December 31, 2018
135
Liquidity And Capital Resources
Non-Gaap Measures
Cash at bank
As at December 31, 2019, cash and bank balances were US$75.9 million, excluding restricted cash and the debt service reserve account established
in support of the RBL, compared with US$53.0 million as at December 31, 2018. The following table provides select cashflow information for the
12 month periods indicated:
Net (cash)/debt
Net (cash)/debt is a non-GAAP measure which does not have a standardised meaning prescribed by IFRS. This non-GAAP finance measure is included
because management uses the information to analyse financial strength of the Group. The measure is used to ensure capital is managed effectively in
order to support its ongoing operations, and to raise additional funds if required.
USD’000
Net cash generated from operating activities
Net cash used in investing activities
Net cash (used in)/generated from financing activities
Net increase in cash and cash equivalents
Cash and cash equivalents at beginning of the year
Cash and cash equivalents at end of the year
DECEMBER 31,
2019
DECEMBER 31,
2018
144,637
(50,829)
(70,863)
22,945
52,981
75,934
17,763
(161,354)
184,861
41,270
10,450
52,981
The cash balances improved as at December 31, 2019, compared to 2018, due to organic operating cash generation during the year. The increase in cash
balances was partly used for acquisition of oil and gas properties of US$45.2 million and repayment of the RBL of US$54.2 million during the year,
hence the net cash used in each of investing and financing activities in 2019.
Gearing ratio
Debt
Cash and cash equivalents
Restricted cash
Net (cash)/debt
Equity
Net debt to equity ratio
2019
USD’000
49,123
(75,934)
(13,485)
(40,296)
225,467
N/M
2019
USD’000
101,813
(52,981)
(18,644)
30,188
215,261
14%
Working capital
Working capital is the amount by which current assets exceed current liabilities. As at December 31, 2019, the Group’s working capital remains positive
at US$26.8 million, a decrease of US$30.7 million compared to December 31, 2018. A breakdown of the Group’s working capital is as follows:
Debt is defined as long and short-term interest bearing debt, and excludes derivatives. Cash and cash equivalents includes the Montara Assets’
minimum working capital cash balance of US$15.0 million required under the RBL, while restricted cash comprises US$13.5 million in the RBL debt
service reserve account (2018: US$18.6 million). Restricted cash, as shown here, excludes the US$10.0 million deposited in support of a bank guarantee
to a key supplier in respect of the Stag FSO. Equity includes all capital and reserves of the Group that are managed as capital.
EBITDAX
EBITDAX is a non-GAAP measure which does not have a standardised meaning prescribed by IFRS. This non-GAAP finance measure is included because
management uses the information to analyse financial performance of the Group.
YEAR ENDED DECEMBER 31,
2019
YEAR ENDED DECEMBER 31,
2018
USD’000
Current assets
Current liabilities
Net working capital
AS AT DECEMBER 31,
2019
AS AT DECEMBER 31,
2018
160,911
134,151
26,760
142,671
85,170
57,501
CHANGE
18,240
48,981
(30,741)
The reduction in working capital is predominately due to the recognition of current lease liabilities of US$19.7 million pursuant to the adoption of
IFRS16 effective January 1, 2019. Additionally, there was reduction in the carrying amount of derivative financial assets by US$30.7 million, based on the
redetermination of its fair value as at December 31, 2019. The reduction is partially offset by the increase in inventories of US$15.6 million with higher
unsold crude oil stocks as at December 31, 2019, relative to December 31, 2018.
Contractual obligations and commitments
At year-end, the Group has outstanding commitments under operational and capital commitments that fall due as follows:
Revenue
Production cost
Staff cost
Impairment
Other expenses
Other financial gains
TOTAL
USD’000
LESS THAN 1 YEAR
2019
1-5 YEARS
USD’000
AFTER 5 YEARS
USD’000
Reported EBITDAX
Depletion, depreciation and amortisation
Montara operational and capital commitments
SEA portfolio PSC operational commitments
Total
19,441
10,000
29,441
19,441
10,000
29,441
-
-
-
-
-
-
The SEA portfolio PSC operational commitments as at December 31, 2019 amounting to US$10.0 million (2018: US$ 10.0 million), relates to the
minimum work commitment outstanding in exploration phase two of the Block 46/07 PSC, for the drilling of a further well.
Under the terms of the Block 46/07 PSC, Jadestone is committed to drill one more appraisal well on the block. The Company plans to drill an appraisal
well on the Nam Du field to facilitate transition of 3C resource to 2C status. This well would be retained for future use as a Nam Du gas producer. On
July 9, 2019, the Company submitted a request to the Vietnam Government, for a further one-year extension to the Block 46/07 PSC exploration phase
two period to June 29, 2021, and this was approved on February 26, 2020. Following the Group’s announcement on March 19, 2020 to delay the project,
the Group will seek Vietnam Government approval for a further extension in order to align drilling of the appraisal well with development of Nam Du/U
Minh. The Group is committed to the project and expects to receive approval for the extension request.
Non-recurring
Hedge gain
Riserless light well intervention
Other well workovers
Impairment of assets
Montara shutdown costs
Others
Gain on contingent considerations
Adjusted EBITDAX
325,406
(119,898)
(19,714)
-
(11,692)
3,389
177,491
(90,746)
86,745
14,242
(18,720)
(5,065)
-
-
(3,860)
3,389
(10,014)
187,505
113,423
(90,939)
(13,538)
(11,901)
(10,374)
12,345
(984)
(13,776)
(14,760)
(996)
-
(2,220)
(11,901)
(4,043)
(6,354)
12,345
(11,177)
10,193
Jadestone Energy 2019 Annual Report 136
Management’s Discussion and Analysis
for the years ended December 31, 2019 and December 31, 2018
137
Financial Instruments, Financial Risks And Capital Management
For a detailed analysis of how the Group manages its financial instruments, financial risks and capital management, see the audited consolidated
financial statements for the years ended December 31, 2019 and December 31, 2018. The financial risks, instruments and capital market strategies
have not materially changed since the year end.
Financial assets and liabilities
Current assets and liabilities
Management considers that due to the short-term nature of the Group’s current assets and liabilities, the carrying values equate to their fair value.
Non-current assets and liabilities
All non-current assets and liabilities are reflected at fair value.
USD’000
Financial assets
At amortised cost
Derivative instruments designated in hedge accounting relationships
Financial liabilities
At amortised cost
Contingent consideration for a business combination
DECEMBER 31,
2019
DECEMBER 31,
2018
135,737
5,275
141,012
419,671
359
420,030
86,539
51,324
137,863
417,606
3,748
421,354
Fair values are based on management’s best estimates, after consideration of current market conditions. The estimates are subjective and involve
judgment, and as such are not necessarily indicative of the amount that the Group may incur in actual market transactions.
Commodity price risk
The Group’s earnings are affected by changes in oil and gas prices. The Group manages this risk by monitoring oil and gas prices, and entering into
commodity hedges against fluctuations in oil prices, if considered appropriate.
The Group has entered into hedge contracts for sales based upon planned production at Montara.
Montara
The Group hedged 50% of its planned production volumes at Montara for the 24 months to September 30, 2020 from its existing well stock.
The hedge is a capped swap, providing downside price protection while allowing for participation in higher commodity prices via purchased call options.
The call strike is set at US$80/bbl for the nine months to September 31, 2019 and US$85/bbl for the twelve months to September 2020. The swap price
was set at US$78.26/bbl for Q4 2018, US$71.72/bbl for 2019 and US$68.45/bbl for the nine months to September 2020. Approximately two thirds of the
swapped barrels in 2019 and 2020 have upside price participation via purchased calls. The effective date of the hedge contracts is October 1, 2018.
Commodity price sensitivity
The results of operations and cash flows from oil and gas production can vary significantly with fluctuations in the market prices of oil and/or natural
gas. These prices are affected by factors outside the Group’s control, including the market forces of supply and demand, regulatory and political actions
of governments, and attempts by the OPEC cartel to control or influence prices, among a range of other factors.
The table below summarises the impact on profit/(loss) before tax, and on equity, from changes in commodity prices on the fair value of derivative
financial instruments. The analysis is based on the assumption that the crude oil price moves 10%, with all other variables held constant. Reasonably
possible movements in commodity prices were determined based on a review of recent historical prices and current economic forecasters’ estimates.
EFFECT ON THE
RESULT BEFORE TAX
FOR THE YEAR ENDED
DECEMBER 31, 2019
USD’000
EFFECT ON OTHER
COMPREHENSIVE
INCOME BEFORE TAX
FOR THE YEAR ENDED
DECEMBER 31, 2019
USD’000
EFFECT ON THE
RESULT BEFORE TAX
FOR THE YEAR ENDED
DECEMBER 31, 2018
USD’000
EFFECT ON OTHER
COMPREHENSIVE
INCOME BEFORE TAX
FOR THE YEAR ENDED
DECEMBER 31, 2018
USD’000
-
-
(7,266)
7,266
(1)
1
(16,729)
16,729
GAIN OR LOSS
Increase by 10%
Decrease by 10%
Foreign currency risk
Foreign currency risk is the risk that a variation in exchange rates between United States Dollars (“US Dollar”) and foreign currencies will affect the fair
value or future cash flows of the Group’s financial assets or liabilities.
Cash and bank balances are generally held in the currency of likely future expenditures to minimise the impact of currency fluctuations. It is the Group’s
normal practice to hold the majority of funds in US Dollars in order to match the Group’s revenue and expenditures. The Group’s US$120.0 million
reserve based loan facility is a US Dollar denominated instrument.
In addition to US Dollars, the Group transacts in various currencies, including Australian Dollars, Singapore Dollars, Vietnamese Dong, Malaysian Ringgit,
Canadian Dollars, Indonesian Rupiah and Great British Pounds.
Material foreign denominated balances were as follows:
Cash and bank balances
Australian Dollars
Trade and other receivables
Australian Dollars
Trade and other payables
Australian Dollars
2019
USD’000
7,088
5,853
21,231
2018
USD’000
4,923
5,237
1,974
If the Australian dollar weakens/strengthens by 10% against the functional currency of the Group, profit or loss will increase/decrease by US$0.8 million
(2018: decrease/increase by US$0.8 million).
Jadestone Energy 2019 Annual Report 138
Management’s Discussion and Analysis
for the years ended December 31, 2019 and December 31, 2018
139
Interest rate risk
The Group’s interest rate exposure arises from some of its cash and bank balances and borrowings. The Group’s other financial instruments are non-
interest bearing or fixed rate, and are therefore not subject to interest rate risk.
Jadestone holds some of its cash in interest bearing accounts and short-term deposits. Interest rates currently received are at historically relatively low
levels. Accordingly, a downward interest rate movement would not cause significant exposure to the Group.
On August 2, 2018, the Group entered into an RBL agreement with the Commonwealth Bank of Australia and Société Générale to borrow US$120.0
million, repayable quarterly to March 31, 2021. The loan was fully drawn down on September 28, 2018, and incurs interest at LIBOR plus 3%.
The loan incurred initial costs of US$3.2 million, which were offset against the proceeds received.
Based on the carrying value of the RBL as at December 31, 2019, if interest rates had increased or decreased by 1% and all other variables remained
constant, the Group’s quarterly net income/(loss) before tax would have decreased or increased by US$0.1 million (2018: US$0.3 million).
Credit risk
Credit risk represents the financial loss that the Group would suffer if a counterparty in a transaction fails to meet its obligations in accordance with
the agreed terms.
The Group actively manages its exposure to credit risk, granting credit limits consistent with the financial strength of the Group’s counterparties
and customers, requiring financial assurances as deemed necessary, reducing the amount and duration of credit exposures, and close monitoring
of relevant accounts.
The Group trades only with recognised, creditworthy third parties.
The Group’s current credit risk grading framework comprises the following categories:
CATEGORY
Performing
Doubtful
In default
Write-off
DESCRIPTION
BASIS FOR RECOGNISING EXPECTED
CREDIT LOSSES (“ECL”)
The counterparty has a low risk of default and does not have any
past-due amounts.
12-month ECL
Amount is > 30 days past due or there has been a significant
increase in credit risk since initial recognition.
Lifetime ECL - not credit-impaired
Amount is > 90 days past due or there is evidence indicating the
asset is credit-impaired.
Lifetime ECL - credit-impaired
There is evidence indicating that the debtor is in severe financial
difficulty and the Group has no realistic prospect of recovery.
Amount is written off
The table below details the credit quality of the Group’s financial assets and other items, as well as maximum exposure to credit risk by credit risk
rating grades:
EXTERNAL
CREDIT
RATING
INTERNAL
CREDIT
RATING
12-MONTH
(“12M”) OR
LIFETIME ECL
GROSS CARRYING
AMOUNT (i)
USD’000
LOSS
ALLOWANCE
USD’000
NET CARRYING
AMOUNT
USD’000
2019
Cash and bank balances
Trade receivables
Other receivables
2018
Cash and bank balances
Trade receivables
Other receivables
n.a
n.a
n.a
n.a
n.a
n.a
Performing
(i)
Performing
12m ECL
Lifetime ECL
12m ECL
Performing
(i)
Performing
12m ECL
Lifetime ECL
12m ECL
99,419
34,007
2,311
81,625
57
4,857
-
-
-
-
-
-
99,419
34,007
2,311
81,625
57
4,857
(i) For trade receivables, the Group has applied the simplified approach in IFRS9 to measure the loss allowance at lifetime ECL. The Group determines
the expected credit losses on these items by using specific identification, estimated based on historical credit loss experience based on the past due
status of the debtors, adjusted as appropriate to reflect current conditions and estimates of future economic conditions. Accordingly, the credit risk
profile of these assets is presented based on their past due status in terms of specific identification.
As at December 31, 2019, total trade receivables amounted to US$34.0 million (2018: US$0.1 million). The balance in both 2019 and 2018 had been fully
recovered in 2020 and 2019, respectively. The Group has derivative receivables of US$0.5 million and US$3.4 million within other receivables in 2019 and
2018, respectively, and these balances were received in full in January 2020 and 2019, respectively.
The concentration of credit risk relates to the main counterparty to oil and gas sales in Australia, where the sole customer has an A1 credit rating
(Moody’s). All trade receivables are generally settled 30 days after sale date. In the event that an invoice is issued on a provisional basis then the final
reconciliation is paid within 3 days of the issuance of the final invoice, largely mitigating any credit risk.
The Group recognises lifetime ECL for trade receivables. The ECL on these financial assets are estimated based on days past due, by applying a
percentage of expected non-recoveries for each group of receivables. As at financial period end, ECL from trade and other receivables are expected to be
insignificant.
Cash and bank balances are placed with reputable banks and financial institutions, which are regulated, and with no history of default.
The maximum credit risk exposure relating to financial assets is represented by their carrying value as at the reporting date.
Liquidity risk
Liquidity risk is the risk that the Group will not be able to meet all of its financial obligations, as they become due. This includes the risk that the Group
cannot generate sufficient cash flow from producing assets or is unable to raise further capital in order to meet its obligations.
The Group manages it liquidity risk by optimising positive free cash flow from its producing assets, on-going cost reduction initiatives, bank balance on
hand, and merger and acquisition strategies.
The Group net profit after tax for the year was US$40.5 million (2018: loss after tax US$31.0 million). Operating cash flows before movements in working
capital and net cash generated from operating activities for the year ended December 31, 2019 was positive of US$176.7 million and US$144.6 million,
respectively (year ended December 31, 2018: negative of US$0.3 million; net cash generated of US$17.8 million). The Group’s net current assets remained
positive at US$34.2 million as at December 31, 2019 (December 31, 2018: US$57.5 million).
The Group’s RBL is sized on a borrowing base drawn from projected cash flows from the Montara Assets, and based on proved and probable producing
reserves (2PD) but including certain infill wells. This borrowing base is subject to scheduled semi-annual redeterminations and as such, and in the event
of a significant reduction in the borrowing base, there is a risk that scheduled repayments may increase to offset any such borrowing base deficiency.
The existing borrowing base, as assessed by the lenders as at December 2019, is significantly above aggregate commitments.
The Group believes it has sufficient liquidity to meet all reasonable scenarios of operating and financial performance for the next 12 months.
Non-derivative financial liabilities
The following table details the expected maturity for non-derivative financial liabilities. The table below has been drawn up based on the undiscounted
contractual maturities of the financial liabilities, including interest that will be accrue on those liabilities, except where the Group anticipates that the
cash flow will occur in a different period. The adjustment column represents the estimated future cash flows attributable to the instrument included
in the maturity analysis, which are not included in the carrying amount of the financial liability on the consolidated statement of financial position,
namely interest expense.
2019
Non-interest bearing
Variable interest rate instruments
2018
Non-interest bearing
Variable interest rate instruments
WEIGHTED
AVERAGE
EFFECTIVE
INTEREST RATE
%
ON DEMAND
OR WITHIN
1 YEAR
USD’000
WITHIN
2 TO 5
YEARS
USD’000
-
7.735
-
8.071
48,086
44,425
92,511
31,493
58,907
90,400
55,503
7,477
62,980
6,603
52,182
58,785
MORE
THAN
5 YEARS
USD’000
275,422
-
275,422
277,697
-
277,697
ADJUSTMENTS
USD’000
TOTAL
USD’000
(8,463)
(2,779)
370,548
49,123
(11,242 )
419,671
-
(9,276)
315,793
101,813
(9,276)
417,606
Jadestone Energy 2019 Annual Report 140
Management’s Discussion and Analysis
for the years ended December 31, 2019 and December 31, 2018
141
Non-derivative financial assets
The following table details the expected maturity for non-derivative financial assets. The inclusion of information on non-derivative financial assets
is necessary in order to understand the Group’s liquidity risk management, as the Group’s liquidity risk is managed on a net asset and liability basis.
The table has been drawn up based on the undiscounted contractual maturities of the financial assets, including interest that will be earned on those
assets, except where the Group anticipates that the cash flow will occur in a different period. The adjustment column represents the estimated future
cash flows attributable to the instrument included in the maturity analysis, which are not included in the carrying amount of the financial asset on the
consolidated statement of financial position, namely interest income.
WEIGHTED AVERAGE
EFFECTIVE
INTEREST RATE
%
ON DEMAND
OR WITHIN
1 YEAR
USD’000
WITHIN
2 TO 5
YEARS
USD’000
ADJUSTMENTS
USD’000
TOTAL
USD’000
-
-*
-
-*
36,318
89,419
125,737
4,914
58,064
62,978
-
10,000
10,000
-
23,561
23,561
-
-*
-*
-
-*
-*
36,318
99,419
135,737
4,914
81,625
86,539
2019
Non-interest bearing
Variable interest rate instruments
2018 (Restated)
Non-interest bearing
Variable interest rate instruments
* The effect of interest is not material.
Capital management
The Group manages its capital structure and makes adjustments to it, based on the funds available to the Group, in order to support the acquisition,
exploration and development of resource properties and the ongoing operations of its producing assets. Given the nature of the Group’s activities, the
Board of Directors works with management to ensure that capital is managed effectively and the business has a sustainable future.
To carry-out planned asset acquisitions, exploration and development, and to pay for administrative costs, the Group may utilise excess cash generated
from its ongoing operations and may utilise its existing working capital, and will work to raise additional funds should that be necessary.
Management reviews its capital management approach on an ongoing basis and believes that this approach, given the relative size of the Group, is
reasonable. There were no changes in the Group’s approach to capital management during the financial year ended December 31, 2019. The Group is not
subject to externally imposed capital requirements.
The Group’s overall strategy remains unchanged from 2018.
Fair value measurements
The Group discloses fair value measurements by level of the following fair value measurement hierarchy:
i. Quoted prices (unadjusted) in active markets for identical assets or liabilities (Level 1);
ii.
Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (Level 2); and
iii.
Inputs for the asset or liability that are not based on observable market data (unobservable inputs) (Level 3).
FINANCIAL
ASSETS/
FINANCIAL
LIABILITIES
FAIR VALUE (USD’000) AS AT
2019
2018
ASSETS
LIABILITIES
ASSETS
LIABILITIES
FAIR
VALUE
HIERARCHY
VALUATION
TECHNIQUE(S)
AND KEY INPUT(S)
SIGNIFICANT
UNOBSERVABLE
INPUT(S)
RELATIONSHIP
OF
UNOBSERVABLE
INPUTS TO FAIR
VALUE
Derivative financial instruments
1) Commodity
capped swap
contracts
(Note 36)
5,275
-
51,324
-
Level 2
Third party valuations based
on market comparable
information.
n.a.
n.a.
Others - contingent consideration in a business combination
2) Contingent
consideration
(Note 7 and
30)
359
-
-
3,748
Level 3
Based on the nature and the
likelihood of occurrence of
the trigger event. Fair value is
estimated using future Dated
Brent price forecasts at the
end of the reporting period,
taking into account the time
value of money and volatility
of oil prices.
Expected future
oil price volatility
of 25% is based
on an analysis of
Brent oil price
movement prior
to acquisition
date.
A slight increase
in Brent oil prices
would result in a
significant increase
in the fair value
and vice versa.
Business Risks and Uncertainties
Jadestone, like all companies in the oil and gas industry, operates in an environment subject to inherent risks. Many of these risks are beyond the
ability of a company to control, including those associated with exploring for, developing, and producing economic quantities of hydrocarbons, volatile
commodity prices, governmental regulations, and environmental matters.
Impact of Coronavirus outbreak (“COVID-19”)
On January 30, 2020, the World Health Organisation declared the COVID-19 outbreak a “Public Health Emergency of International Concern” and on
March 10, 2020, declared it to be a pandemic. Actions taken around the world to help mitigate the spread of COVID-19 include restrictions on travel, and
quarantines in certain areas, and forced closures for certain types of public places and businesses. The COVID-19 and actions taken to mitigate it have
had and are expected to continue to have an adverse impact on the economies and financial markets of many countries, including the geographical area
in which the Group operates.
On April 12, 2020, members of Organisation of the Petroleum Exporting Countries and certain other countries including the Russian Federation, have
agreed to cut global daily oil production by almost 10%, representing 9.7 mm bbls/d effectively from May 2020.
The decline in Dated Brent oil price due to factors set out above has been assessed to be a non-adjusting post balance sheet event in accordance with
IAS 10.
The depressed Dated Brent oil price will reduce the Group’s revenue in 2020, but the Group has no plan to reduce its crude oil production as the Group
has significant downside protection in place, including via its capped swap and a relatively competitive cash operating cost base. The Group has hedged
about a third of its planned production for the first nine months of 2020. Plus, the crude at both Stag and Montara has generated a premium above the
benchmark crude oil prices.
In the absence of Vietnamese Government approvals for the Nam Du/U Minh field development plan in Q1 2020, and the decline in oil prices, the Group
announced on March 19, 2020 to defer the Nam Du/U Minh gas field development. In respect of the Block 46/07 PSC appraisal well commitment, the
Group will seek Vietnam Government approval for a further extension to the existing June 29, 2021 deadline, in order to align drilling of the appraisal well
with development of Nam Du/U Minh. The Group is committed to the project and expects to receive approval for the extension request.
Jadestone Energy 2019 Annual Report 142
Management’s Discussion and Analysis
for the years ended December 31, 2019 and December 31, 2018
143
At the time the Group undertook the impairment review of its non-financial assets, as at December 31, 2019, the spot price for Dated Brent was
US$66.8/bbl. Since that time, Dated Brent oil prices have fallen to around US$19.10/bbl as at April 20, 2020, due to the impact of Coronavirus
(“COVID-19”) on oil demand.
Information reported to the Group’s Chief Executive Officer (the Chief Operating Decision Maker) for the purposes of resource allocation is focused on
two reportable/business segments driven by different types of activities within the upstream oil and gas value chain, namely producing assets and
secondly development and exploration assets. The geographic focus of the business is on SEA and Australia.
Segment Information
The Group will reflect updated oil price data during its next impairment review, including spot oil prices, but will also give due consideration to both the
medium- and long-term outlook for crude oil prices.
The Group will closely monitor the development of the COVID-19 outbreak and related oil price outlook, and continue to evaluate its impact on the
business, the Group’s financial position and operating results. As part of the preparation of the current financial statements, a forward looking going
concern analysis was undertaken at some of the lower current third party downside Brent crude oil price outlooks, including US$22/bbl in Q2 2020
and US$30/bbl in H2 2020. The Group was able to generate positive operating cashflow without resorting to significant cuts in operating costs, and
comfortably continue as a going concern.
Operational
Key risks at an operational level include, but are not limited to: operational and safety considerations, risks from operating in an offshore environment,
shipping and pipeline transportation and interruptions, reservoir performance and technical challenges, partner risks, competition, technology, the
Company’s ability to hire and retain necessary skilled personnel, the availability of drilling and related equipment, information systems, seasonality
and disruptions from severe weather and met-ocean restrictions, timing and success of integrating the business and operations of acquired assets and
companies, phased growth execution, risk of litigation, regulatory issues, increases in government taxes and other fiscal changes, and risk to reputation
resulting from operational activities that may cause personal injury, property damage or environmental damage.
Environmental
Jadestone is currently subject to environmental regulations arising from a variety of federal, regional and/or state legislation, all of which is subject to
governmental review and revision from time to time. Such legislation provides for restrictions and prohibitions on the release or emission of various
substances produced in association with certain oil and gas industry operations. In addition, such legislation sets out the requirements with respect to
oilfield waste handling and storage, habitat protection and the satisfactory operation, maintenance, abandonment and reclamation of well and facility
sites.
Compliance with such legislation can require significant expenditures and a breach of such requirements may result in suspension or revocation of
necessary licenses and authorisations, civil liability for pollution damage and the imposition of material fines and penalties. Further, environmental
legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital
expenditures and operating costs. Jadestone believes that it is, and will be, in material compliance with current applicable environmental legislation,
however no assurance can be given that environmental laws will not result in a curtailment of production or a material increase in the costs of
production, development or exploration activities or otherwise have a material adverse effect on Jadestone’s business, financial, result of operations
and prospects.
To mitigate these risks, the Group’s HSE policy is reinforced at every stage of each operational contract. As part of all contract tendering, the Group may
request, and may subsequently audit, the HSE procedures of relevant sub-contractors, to ensure they are in line with standard industry practice, local
regulatory and Group’s requirements.
In accordance with industry practice, the Group maintains insurance coverage against losses from certain of these risks. Nonetheless, insurance
proceeds may not be sufficient to cover all losses, and insurance coverage may not be available for all types of operational risks.
The ability of the Group to meet its obligations is dependent upon there being sufficient financial resources. External financing, from the farm-out of
equity in assets and potentially through the issuance of common shares may be required to fund future activities. There can be no assurance that the
Group will be able to successfully raise funds in the future.
The forgoing list of risks and uncertainties is not exhaustive.
Revenue and non-current assets information based on the geographical location of assets respectively are as follows:
PRODUCING ASSETS
AUSTRALIA
USD’000
SEA
USD’000
EXPLORATION
SEA
USD’000
CORPORATE
USD’000
2019
Revenue
Liquids revenue
Production cost
DD&A
Staff costs
Other expenses
Other income
Finance costs
Other financial gain
Profit/(Loss) before tax
Additions to non-current assets
Non-current assets
2018
Revenue
Liquids revenue
Gas revenue
Royalties
Production cost
DD&A
Staff costs
Other expenses
Impairment of assets
Other income
Finance costs
Other financial gain
Profit/(Loss) before tax
Additions to non-current assets
Non-current assets
325,406
325,406
(119,898)
(90,277)
(7,282)
(7,012)
2,971
(16,387)
3,389
90,910
84,444
461,053
105,970
-
-
105,970
(88,159)
(13,066)
(3,489)
(5,022)
-
2,345
(6,219)
12,057
4,417
376,856
470,522
-
-
-
-
-
-
-
-
-
-
-
-
8,520
2,482
(3,549)
7,453
(2,780)
(618)
(1,834)
(146)
-
-
-
-
2,075
-
-
-
-
-
(113)
(3,543)
(278)
2
(7)
-
(3,939)
20,456
116,162
-
-
-
-
-
-
(816)
(434)
(11,901)
-
(80)
-
-
-
-
(356)
(8,889)
(4,402)
6
(49)
-
(13,690)
65
943
-
-
-
-
-
(92)
(7,399)
(4,772)
-
189
(2,941)
288
(13,231)
(14,727)
1,835
95,607
183
280
TOTAL
USD’000
325,406
325,406
(119,898)
(90,746)
(19,714)
(11,692)
2,979
(16,443)
3,389
73,281
104,965
578,158
114,490
2,482
(3,549)
113,423
(90,939)
(13,776)
(13,538)
(10,374)
(11,901)
2,534
(9,240)
12,345
(21,466)
378,874
566,409
Non-current assets include oil and gas properties, intangible exploration assets, right-of-use assets, restricted cash and plant and equipment used
in corporate offices.
Included in revenues arising from producing assets are revenues of approximately US$325.4 million (2018: US$106.0 million) which arose from sales
to the Group’s largest customer.
Jadestone Energy 2019 Annual Report 144
Management’s Discussion and Analysis
for the years ended December 31, 2019 and December 31, 2018
Off Balance Sheet Arrangements
The Group has no off-balance sheet arrangements.
Related Party Transactions
145
Director participation in AIM equity raise
Certain directors and members of the management team of the Company (“Insiders”) subscribed for new shares pursuant to the AIM equity raise
and listing completed in August 2018. The issuance of new shares to these Insiders, pursuant to the AIM equity raise and listing, is considered to be a
related party transaction within the meaning of TSX Venture exchange policy 5.9 and multilateral instrument 61-101 (“MI 61-101”), and disclosable in
the December 31, 2018 year end financial statements under AIM rule 19. The Company has relied on the exemptions from the valuation and minority
shareholder approval requirements of MI 61-101, contained in sections 5.5(b) and 5.7(1)(b) of MI 61-101, in respect of the Insider participation. Certain
directors subscribed for a total of 1,961,271 new shares at 35 pence per share (or £688,545) as follows.
During the year, the Group entities did not enter into any transactions with related parties other than the following:
Compensation of key management personnel
Short-term benefits
Other benefits
Share-based payments
2019
USD’000
6,746
1,052
1,038
8,836
2018
USD’000
2,656
326
234
3,216
A. Paul Blakeley
David Neuhauser*
Daniel Young
Dennis McShane
Robert Lambert
Eric Schwitzer
Iain McLaren
NUMBER OF NEW SHARES
544,798
544,798
217,919
217,919
217,919
108,959
108,959
1,961,271
The total remuneration of members of key management in 2019 (including salaries and benefits) was US$8.8 million (2018: US$3.2 million).
* These relate to ordinary shares that Mr. Neuhauser is deemed to have an interest in, through Livermore Strategic Opportunities LP. Mr. Neuhauser
is the Managing Director of Livermore Strategic Opportunities LP and hence has the power and authority to direct its activities.
Repayment of secured convertible bond
Tyrus Capital Event S.à r.l., an entity controlled by Tyrus Capital S.A.M., entered into a secured convertible bond facility agreement with the Company in
November 2016. Tyrus Capital S.A.M. controls entities that hold approximately 25.6% of the Company’s ordinary share capital, as at December 31, 2019.
On August 1, 2018, the Company and Tyrus Capital Event S.à r.l. conditionally agreed, upon the Company’s admission and listing on AIM, that the
Company would redeem the secured convertible bond facility by paying US$17.4 million to Tyrus Capital Event S.à r.l., and all associated security
released. At June 30, 2018, the balance on the bond was drawn to US$15.0 million. Repayment subsequently occurred on August 15, 2018.
Compensation of directors
SHORT-TERM
BENEFITS (a)
USD’000
OTHER
BENEFITS (a)
USD’000
SHARE-BASED
PAYMENTS
USD’000
TOTAL
COMPENSATION
USD’000
2019
A. Paul Blakeley
Daniel Young
Dennis McShane
Iain McLaren
Eric Schwitzer
Robert Lambert
Cedric Fontenit
David Neuhauser
Lisa Stewart
2018
A. Paul Blakeley
Daniel Young
Dennis McShane
Iain McLaren
Eric Schwitzer
Robert Lambert
David Neuhauser
Cedric Fontenit
1,302
707
130
81
68
69
66
56
6
2,485
1,035
546
130
70
58
50
45
18
1,952
350
174
-
-
-
-
-
-
-
524
422
149
-
-
-
-
-
-
571
233
139
21
13
25
13
9
12
-
465
164
74
19
9
9
9
9
-
293
1,885
1,020
151
94
93
82
75
68
6
3,474
1,621
769
149
79
67
59
54
18
2,816
(a) Short-term benefits comprise salary, director fees as applicable, performance pay, pension and other allowances. Other benefits comprise
benefits-in-kind.
Jadestone Energy 2019 Annual Report
147
Additional Information
Additional information relating to the Company, including Management Information Circulars, NI 51-101 oil and gas disclosures, material change reports,
and other important items of disclosure, and previous interim and annual consolidated financial statements are available on the System for Electronic
Document Analysis and Retrieval (“SEDAR”) at www.sedar.com.
146
Management’s Discussion and Analysis
for the years ended December 31, 2019 and December 31, 2018
Events After the Reporting Period
Award of damages in relation to Philippines arbitration
In December 2017, the Group commenced arbitration action against Total E&P Philippines BV (“Total”), with the Singapore International Arbitration
Center, in response to a breach of the 2012 farm out agreement (“the FOA”), claiming that Total failed to drill an exploration well on the deepwater
Halcon prospect, located within the block covered by SC56 in the Sulu Sea, offshore the Philippines. The FOA required Total to drill one exploration well
and pay their 75% interest, along with the Group’s 25% interest.
On January 3, 2020, the tribunal found in favour of the Group, concluding that Total breached the FOA, awarding (i) monetary damages to the Group
of US$11.1 million, less specific expenditures incurred prior to the breach to be agreed or determined if the parties cannot agree; and (ii) legal costs
of approximately US$4.3 million. The tribunal’s costs will be borne by the Group and Total 25:75.
The parties were unable to agree the specific expenditures and, on March 24, 2020, the tribunal issued a final award in which it determined such
expenditures to be US$0.7 million. The net award to the Group was US$10.4 million.
After the payment of all legal fees, funding costs, and the Company’s share of the tribunal costs, net proceeds to the Group are expected to be
approximately US$2.2 million. This will be recognised in FY2020.
Following the award of monetary damages to the Group, Total would be released from bearing the Group’s 25% interest for the drilling of one
exploration well, estimated at US$18.8 million. Consequently, the Group is potentially liable to pay US$2.4 million, being the penalty payable to the
Department of Energy in Philippines if both Total and the Group fail to drill an exploration well prior the license expiration on September 1, 2020.
However, no final decision has been reached between the Group and Total on the future plan for SC56. A discussion will take place during the next
operator committee meeting, tentatively scheduled in second quarter of 2020.
At the end of the reporting period, no contingent assets nor contingent liabilities were recorded as the outcome of the arbitration was not finalised till
after year end.
The total carrying value within intangible exploration assets in respect of SC56 as at December 31, 2019 was US$50.4 million (2018: US$50.4 million).
The Group has reviewed, pursuant to IFRS6 Exploration for and evaluation of mineral resources, whether there are any impairment indicators for SC56 as
at year end, and no change has been made to the SC56 carrying value within intangible exploration assets.
Vietnam Block 51 and 46/07
The Group holds a 100% operated working interest in the Block 51 PSC and the Block 46/07 PSC, both in the shallow water Malay-Tho Chu Basin,
offshore southwest Vietnam. The Group has made three gas/condensate discoveries: the U Minh and Tho Chu fields in Block 51, and the Nam Du gas
field in Block 46/07.
On October 17, 2019, the Group made the formal declaration of commercial discovery for the Nam Du and U Minh fields and submitted to the Vietnam
Government the combined formal field development plan for the Nam Du and U Minh development, thus initiating the formal government approval
process.
Following delays in the Vietnamese Government approval processes and the drop in the oil price in Q1 2020, the Group announced on March 19, 2020
that it would delay the sanction and development of Nam Du/U Minh and the first gas would not occur before Q4 2022 at the earliest.
As at year end, the Group has recognised US$65.6 million of intangible exploration assets in relation to Nam Du and U Minh fields.
TSX Venture Exchange de-listing
On February 25, 2020, Jadestone announced its intention to de-list from the TSX-V, and a formal application to the TSX-V was subsequently made
by the Company on March 12, 2020. The final day of trading of Jadestone’s common shares on the TSX-V was on March 24, 2020. The Company’s shares
continue to trade on AIM.
Upon de-listing from the TSX-V, the Company remains a Canadian domiciled corporation, and will continue as a reporting issuer under Canadian rules
in the near term, although the Company has requested an order from the applicable securities commissions, to be granted an exemption from certain
of its Canadian reporting requirements, in a manner similar to a designated foreign issuer.
Jadestone Energy 2019 Annual Report
148
Reserves Summary
149
Jadestone replaced 96% of the volume it produced in 2019 through
technical revisions and economic factors affecting proved reserves.
As of year-end 2019, the Company had 25.1 mm bbls of proved reserves
(after additions of 4.8 mm bbls), and 41.8 mm bbls on a 2P basis (after
additions of 4.0 mm bbls).
Reserve estimates have been calculated in compliance with
National Instrument 51-101 Standards of Disclosure (“NI 51-101”).
Under NI 51- 101, proved reserves are defined as reserves that can
be estimated with a high degree of certainty to be recoverable with
a target of a 90% probability that the actual reserves recovered over
time will equal or exceed proved reserve estimates, while proved plus
probable reserves are defined as having an equal (50%) probability
that the actual reserves recovered will equal or exceed the proved plus
probable reserve estimates.
In accordance with NI 51-101, proved undeveloped reserves have been
recognised in cases where plans are in place to bring the reserves
on production within a short, well defined time frame. Proved
undeveloped reserves often involve infill drilling into existing pools.
The Company’s Montara reserves were audited (and Stag reviewed)
by an independent third-party reserves evaluator, ERCE as of
December 31, 2019 and detailed in their report dated April 23, 2020.
Reconciliation of gross reserves as at December 31, 2019
LIGHT AND MEDIUM CRUDE OIL (mm bbl)
Gross Proved (2)
Gross Probable (2)
Gross Proved
Plus Probable (2)
Gross Possible (2)
Gross Proved
Plus Probable
Plus Possible (2)
25.3
-
2.9
-
-
-
1.9
-5.0
25.1
17.6
-
0.4
-
-
-
-1.2
-
16.7
42.8
16.5
59.3
-
3.3
-
-
-
0.7
-5.0
41.8
-
-1.7
-
-
-
3.6
-
18.4
-
1.6
-
-
-
4.3
-5.0
60.2
Opening balance (1)
December 31, 2018
Plus:
Extension & Improved Recovery
Technical Revisions
Discoveries
Acquisitions
Less:
Dispositions
Economic Factors
Production
Ending balance December 31, 2019
(1) Opening balances are from the ERCE reserve report as of December 31, 2018
(2) Gross reserves are based on the Company working interest share of the property gross reserves
(3) Totals may not sum due to rounding
Summary of oil and gas reserves at December 31, 2019
COMPANY’S INTEREST IN RESERVES (1) (2) (3)
Light & Medium Oil (mm bbl)
Australia
Proved developed producing
Proved developed non-producing
Proved undeveloped
Total Proved Reserves
Probable
Total Proved Plus Probable Reserves
Possible
Total Proved Plus Probable Plus Possible Reserves
Gross (4)
18.2
0.0
6.9
25.1
16.7
41.8
18.4
60.2
Net (5)
18.2
0.0
6.9
25.1
16.7
41.8
18.4
60.2
Includes Montara and Stag, excludes Maari.
(1)
(2) Totals may not add due to rounding.
(3) The definitions of the various categories of reserves and expenditures are those set out in NI 51-101.
(4)
(5)
“Gross” reserves represent a 100% total of the estimated technically recoverable oil up to the economic limit.
“Net” reserves are the Gross reserves multiplied by Jadestone’s working interest in the field/asset.
Summary of net present values of future net revenues as of December 31, 2019
Forecast prices and costs (in US$ millions)
NET PRESENT VALUES OF FUTURE NET REVENUE (1) (2) (3) (4) (5)
After income taxes discounted at
Reserve category
0%
5%
10%
15%
20%
(US$ millions)
(US$ millions)
(US$ millions)
(US$ millions)
(US$ millions)
Australia
Proved Producing Reserves
Proved Developed Reserves
Proved Undeveloped Reserves
Total Proved Reserves
Total Proved Plus Probable Reserves
72
-
62
134
520
172
-
53
224
579
Total Proved Plus Probable Plus Possible Reserves
1,209
1,089
217
-
38
253
549
929
230
-
26
256
497
789
232
-
14
246
445
677
(1) Based on the Company working interest.
(2) Totals may not add due to rounding
(3) The definitions of the various categories of reserves and expenditures are those set out in NI 51-101. Based on forecast prices and costs at January 1, 2020.
(4)
(5) The net present values may not necessarily represent the fair market value for reserves.
Interest expenses and corporate overhead, etc. were not included.
Reserves outlook
Jadestone anticipates adding material reserves in the coming years,
relating to both organic and inorganic developments.
The Company expects to close the acquisition of an operated 69%
interest in the Maari project, offshore New Zealand in the second half
of 2020. In addition to acquiring an interest in offshore production
infrastructure and ongoing oil production, as of the deal’s economic
effective date of January 1, 2019 the fields contained 2P reserves of
13.9 mm bbls, net to the 69% interest being acquired, based on a
reserves audit prepared for the Company by ERCE.
In addition, upon formal approval of its Field Development Plan for
the Nam Du and U Minh gas development in Vietnam, the Company
anticipates adding 2P reserves reflecting the final commercial terms
of the project. As of December 31, 2017, a Competent Persons Report
conducted by ERCE on behalf of the Company indicated 2C resources
for the fields totalling 30.2 mm boe, most of which is gas.
Jadestone Energy 2019 Annual Report 150
Glossary
2C resources
2P reserves
2PD
bbls
bbls/d
boe
boe/d
bcf
bscf
unrisked best estimate scenario of contingent resources
the sum of proved and probable reserves, denotes the best estimate scenario of reserves
proved and probable developed reserves
barrels of oil
barrels of oil per day
barrels of oil equivalent
barrels of oil equivalent per day
billion cubic feet
billion standard cubic feet
contingent resources (2C)
best estimate scenario of contingent resources
EBITDAX
earnings before interest, tax, depreciation, amortisation and exploration expenses
FEED
FPSO
FSO
GW
LTI
mbbls
mboe
mm bbls
mm boe
mmcf/d
mmscf/d
PVEP
Reserves
front end engineering and design
floating production, storage and offloading vessel
floating storage and offloading vessel
gigawatt
lost-time injury
thousands of barrels of oil
thousands of barrels of oil equivalent
millions of barrels of oil
millions of barrels of oil equivalent
millions of cubic feet per day
millions of standard cubic feet per day
Petrovietnam Exploration Production Corporation
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 categorised in accordance with the level of certainty
associated with the estimates and may be sub-classified based on project maturity and/or
characterised by development and production status.