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Parsley Energy IncANNUAL REPORTINCORPORATING APPENDIX 4E Annual Report 2021
This Annual Report 2021 is a summary
of Woodside’s operations and activities
for the 12-month period ended
31 December 2021 and financial
position as at 31 December 2021.
Woodside Petroleum Ltd (ABN 55
004 898 962) is the ultimate holding
company of the Woodside group
of companies. In this report, unless
otherwise stated, references to
‘Woodside’, the ‘Group’, the ‘company’,
‘we’, ‘us’ and ‘our’ refer to Woodside
Petroleum Ltd and its controlled
entities, as a whole. The text does not
distinguish between the activities of
the ultimate holding company and
those of its controlled entities.
In this report, references to a year
are to the calendar and financial
year ended 31 December 2021 unless
otherwise stated.
All dollar figures are expressed in
US currency, Woodside share,
unless otherwise stated.
On the cover
Liquefied natural gas (LNG) storage
tank, Karratha Gas Plant.
Forward-looking statements
This report contains forward-looking
statements. Please refer to page 153
which contains a notice in respect of
these statements.
Sustainable Development
Report 2021 and
Climate Report 2021
A summary of Woodside’s
sustainability approach, health and
safety performance and other material
information for the 12-month period
ended 31 December 2021 is included
in our Sustainable Development
Report 2021.
A summary of Woodside's climate
change approach for the 12-month
period ended 31 December 2021 is
included in our Climate Report 2021.
The Annual Report, Sustainable
Development Report and Climate
Report together provide a
complementary review of Woodside’s
business.
ii
Annual Report 2021
Acknowledging Country
Woodside recognises Aboriginal and Torres Strait Islander
peoples as Australia’s first peoples. We acknowledge the
unique connection that Indigenous people have to land,
waters and the environment. We extend this recognition
and respect to Indigenous peoples and communities
around the world.
We are working with Green Reports™ on
an initiative ensuring that communications
minimise environmental impact and
create a more sustainable future for the
community.
APPENDIX 4E
Results for announcement to the market
2021
2020
Revenue from ordinary activities
Increased 93% to US$6,962 million
US$3,600 million
Profit/(loss) from ordinary activities after tax attributable to members
Increased 149% to US$1,983 million
(US$4,028) million
Net profit/(loss) for the period attributable to members
Increased 149% to US$1,983 million
(US$4,028) million
Dividends
Amount
Franked amount per security
Final dividend (US cents per share)
Interim dividend (US cents per share)
None of the dividends are foreign sourced
Previous corresponding period:
Final dividend (US cents per share)
Interim dividend (US cents per share)
Ordinary 105¢
Ordinary 30¢
Ordinary 105¢
Ordinary 30¢
Ordinary 12¢
Ordinary 26¢
Ordinary 12¢
Ordinary 26¢
Ex-dividend date
Record date for determining entitlements to the final dividend
Payment date for the final dividend
24 February 2022
25 February 2022
23 March 2022
Net tangible asset per security1
31 December 2021
31 December 2020
$13.86
$12.55
1 Includes lease assets of $1,080 million and lease liabilities of $1,367 million (2020: $984 million and $1,278 million) as a result of AASB 16 Leases.
Woodside Petroleum Ltd
iii
We provide the energy
the world needs
iv Annual Report 2021
CONTENTS
Overview
About Woodside
202I achievements
202I summary
Chairman's report
Chief Executive Officer's report
Executive management
Focus areas
Merger with BHP Petroleum
Financial Performance and Strategy
Financial summary
Strategy and capital management
Energy markets
Business model and value chain
Operations
Development
Corporate
Climate change
New energy
Carbon
Risk
Reserves and resources
Governance
Woodside Board of Directors
Corporate governance
Directors' report
Remuneration Report
Financial Statements
Shareholder Information
Shareholder statistics
Key announcements 2021
Events calendar 2022
Business directory
Asset facts
Glossary, units of measure and conversion factors
Ten-year comparative data summary
6
6
7
8
10
12
14
16
18
19
20
25
28
29
31
41
47
48
49
50
51
55
60
61
65
66
69
93
149
150
152
152
154
155
156
159
Woodside’s Operating and Financial Review is contained on pages 6-59.
Woodside Petroleum Ltd
v
OVERVIEW
ABOUT WOODSIDE
We provide energy which Australia and the world needs to heat homes,
keep lights on and enable industry. We have a reputation for safe and reliable
operations. Our LNG in particular supports the decarbonisation goals of our
customers, and we are progressing opportunities to commercialise new energy
products and lower-carbon services as part of our broader product mix.
Our proven capabilities as a reliable, low-cost energy
provider combined with a focus on technology to enable
efficiency will drive our long-term success.
We have a portfolio of quality oil and gas assets and more
than 30 years of operating experience. Through our North
West Shelf and Pluto LNG projects we operated 5% of global
LNG supply in 2021. Offshore Australia we operate two
floating production storage and offloading (FPSO) facilities,
the Okha FPSO and Ngujima-Yin FPSO.
Our operations are focused on safety, reliability, efficiency
and environmental performance.
We also have a non-operated participating interest in the
Wheatstone project, which started production in 2017.
In November 2021, we reached agreement with BHP Group
(BHP) for the merger of BHP's petroleum business with
Woodside. The merger will deliver increased scale, diversity
and resilience. Completion of the merger is targeted for the
second quarter of 2022, following receipt of approvals.
The Scarborough and Pluto Train 2 projects have been
approved, with first LNG cargo expected in 2026.
In Senegal, the Sangomar Field Development Phase 1
remains on track targeting first oil in 2023.
Our marketing, trading and shipping activities enable
us to supply a growing base of customers primarily in
the Asia-Pacific region.
We are evolving our business to develop a low-cost, lower-
carbon, profitable, resilient and diversified portfolio to help
us thrive through the global energy transition.
Our climate strategy is to reduce our net equity Scope 1
and 2 greenhouse gas emissions, while investing in the
products and services that our customers need as they
reduce their emissions.
We have set targets to reduce our net equity Scope 1 and
2 greenhouse gas emissions, including a 15% reduction by
2025 and 30% by 2030, towards our aspiration to achieve
net zero by 2050 or sooner.1
Our hydrocarbon business is complemented by a growing
portfolio of hydrogen, ammonia and solar opportunities in
Australia and internationally.
Our new energy opportunities include the proposed
hydrogen and ammonia projects H2Perth and H2TAS
in Australia and the proposed hydrogen project H2OK
in North America.
We take a disciplined and prudent approach to investment
through our capital management framework, ensuring we
manage financial risks and maintain a resilient financial
position. This allows us to optimise the value delivered from
our portfolio of opportunities.
Environmental, social and governance performance is
integral to our success. Our approach to sustainability is
outlined in our Sustainable Development Report.
Enduring, meaningful relationships with communities
are fundamental to our social performance. Woodside is
committed to managing our activities in a sustainable way
that is fundamental to the wellbeing of our workforce,
our communities and our environment.
We recognise that our success is driven by our people and
our culture. We are committed to upholding our values of
respect, ownership, sustainability, working together, integrity
and courage, and we aim to attract, develop and retain a
diverse, high performing workforce.
1 Target is for net equity Scope 1 and 2 greenhouse gas emissions, relative to a starting base of the gross annual average equity Scope 1 and 2 greenhouse gas emissions over 2016-2020 and
may be adjusted (up or down) for potential equity changes in producing or sanctioned assets with an FID prior to 2021. Post-completion of the Woodside and BHP petroleum merger (which
remains subject to conditions including regulatory approvals), the starting base will be adjusted for the then combined Woodside and BHP petroleum portfolio.
6
Annual Report 2021
2021 ACHIEVEMENTS
Net profit after tax
Underlying net profit after tax
million
$1,983
$3,792
Operating cash flow
million
149%
I05%
million
$1,620
135
Full-year dividend
US CPS
262%
255%
STRATEGIC ACHIEVEMENTS
1
2
3
4
Merger agreed with BHP's petroleum
business
Final investment decisions approved
for Scarborough and Pluto Train 2
Sell-down agreed for Pluto Train 2
$5 billion investment target to support
the energy transition1
1 Targeted investment in new energy products and lower-carbon services by 2030. Investment target assumes completion of the proposed merger with BHP’s petroleum business. Individual
investment decisions are subject to Woodside’s investment hurdles. Not guidance.
Woodside Petroleum Ltd
7
2021 SUMMARY
Achieved strong operational performance, delivered highest profit since 2014
and maintained balance sheet strength.
CREATING VALUE
We delivered a reported NPAT of
$1,983 million, the highest since 2014.
Our strong NPAT performance was
underpinned by increased oil and
gas prices, consistent operational
performance and proactive decisions
to manage our sales portfolio.
Earnings per share increased by 149%
to 206 US cps and our full-year fully
franked total dividend increased by
255% to 135 US cps.
FINANCIAL STRENGTH
We continued to prudently manage
our debt portfolio with net debt of
$3,772 million and gearing of 21.9%,
within our target range of 15-35%.
We maintained our investment grade
credit rating and ended the period with
more than $6 billion of liquidity.
CONSISTENT OPERATIONS
Our operations maintained strong LNG
reliability. Total recordable injury rate
(TRIR) increased to 1.74 per million
work hours.
Reported net profit
after tax (NPAT)
1,983
1,364
1,069
343
n
o
i
l
l
i
m
$
Production
100.3
91.4
89.6
91.1
84.4
e
o
b
M
M
(4,028)
2017
2018
2019 2020 2021
2017
2018
2019 2020 2021
Gearing
Liquidity
23.9
24.4
21.9
%
12.1
14.4
3,918
n
o
i
l
l
i
m
$
2,942
6,952
6,704
6,125
2017
2018
2019 2020 2021
2017
2018
2019 2020 2021
LNG reliability
Safety
93.5
97.3
93.7
97.6
97.7
s
e
i
r
u
n
j
i
l
e
b
a
d
r
o
c
e
r
l
a
t
o
T
1.32
1.29
12
5
21
2
1.74 TRIR
0.90 0.88
19
Contractors
11
3
8
3
8
Employees
2017
2018
2019 2020 2021
2017
2018
2019 2020 2021
TRIR is the total recordable injury rate per
million work hours.
Woodside continues to be recognised
for strong sustainability performance.
%
8
Annual Report 2021
Operating revenue
Sales volume
5,240
4,873
3,600
3,975
n
o
i
l
l
i
m
$
6,962
106.8
111.6
89.2
84.1
97.4
e
o
b
M
M
2017
2018
2019 2020 2021
2017
2018
2019 2020 2021
Net debt
4,747
n
o
i
l
l
i
m
$
3,888 3,772
2,791
2,397
2017
2018
2019 2020 2021
Credit ratings
S&P Global
BBB+
Moody'sBaa1
Production cost
5.7
505
5.2
5.1
465
443
4.8
5.3
Unit production
cost ($/boe)
478
481
Morgan Stanley Capital
International1
Total
production cost
($ million)
Sustainalytics2
SHAREHOLDER
OUTCOMES
Full-year dividend
135US CPS
255%
Earnings per share
206.0
US CPS
149%
Return on equity
14.8% 144%
Return on average
capital employed
15.6% 174%
2017
2018
2019 2020 2021
1
2
As of 2021, Woodside received an Morgan Stanley Capital International ESG Rating of AAA. Refer to the disclaimer on page 11 of the Sustainable Development Report 2021.
In December 2021, Woodside Petroleum Ltd received an ESG Risk Rating of 26.7 and was assessed by Sustainalytics to be at medium risk of experiencing material financial impacts from ESG factors. In 2021, Woodside was
recognised by Sustainalytics as an ESG Industry Top Rated company. Copyright ©2021Sustainalytics. All rights reserved. This section contains information developed by Sustainalytics (www.sustainalytics.com). Such information
and data are proprietary of Sustainalytics and/or its third party suppliers (Third Party Data) and are provided for informational purposes only. They do not constitute an endorsement of any product or project, nor an investment
advice and are not warranted to be complete, timely, accurate or suitable for a particular purpose. Their use is subject to conditions available at https://www.sustainalytics.com/legal-disclaimers.
Woodside Petroleum Ltd
9
CHAIRMAN'S REPORT
On behalf of the Board, I am pleased to report that 2021 has delivered
improved financial performance and significant decisions which we think will
set Woodside up to deliver value to all our stakeholders in the years ahead.
With the global economy rebounding during the year,
we were able to capitalise on high oil and gas prices to
report a 2021 net profit after tax of $1,983 million. Strong
operating revenue and prudent management of capital
and expenditure have us very well positioned to deliver our
growth ambitions while returning value to shareholders. We
will pay a full-year total dividend of 135 US cents per share.
As the COVID-19 pandemic continued to evolve around the
world and in Australia, we maintained rigorous controls and
response measures to protect the health of our workforce
and community, and maintain production at our operations.
Our safety performance was disappointing. Our total
recordable injury rate increased, in contrast with a downward
trend in previous years. Improving this performance is a
priority in the year ahead, both in operations and as we
embark on new major projects requiring thousands of
additional workers.
Our announcement of a proposed merger with BHP’s
petroleum business in August, followed by execution of a
binding share sale agreement in November, is a momentous
decision for Woodside’s long-term future.
The case for the proposed merger is compelling, bringing
together the best of both organisations to create a larger
global independent energy company with the scale, diversity,
and resilience to provide value to shareholders and navigate
the energy transition. We are expecting to deliver significant
synergies as we bring both businesses together.
I look forward to seeking our shareholders’ approval
for the merger, with the vote targeted for 19 May 2022.
Announcing final investment decisions on our Scarborough
and Pluto Train 2 projects and the sell-down of 49% of Pluto
Train 2 to Global Infrastructure Partners which completed
in January 2022, were further significant achievements for
Woodside in 2021.
Scarborough is a world-class reservoir containing only 0.1%
carbon dioxide that will be processed through the expanded
Pluto LNG facility. It is targeted to deliver first cargo in 2026
into a market with anticipated robust demand for LNG. It will
10 Annual Report 2021
also deliver significant benefits to Western Australia and the
nation in the form of thousands of jobs during development,
tax revenues and domestic gas supply.
The COP-26 global climate summit in October-November
2021 saw renewed focus on global efforts to address climate
change. Woodside aims to thrive in the energy transition as a
low-cost, lower-carbon energy provider and our approach to
climate strategy is simple.
First, like all firms and consumers, we must reduce our own
greenhouse gas emissions. Secondly, as an energy producer,
we must ensure that we invest in the products and services
that our customers want, as they too reduce their emissions.
Natural gas, when used to generate electricity, emits
around half the life cycle emissions of coal. It can also play
an important role in ‘firming up’ intermittent renewable
generation and be used in ‘hard to abate’ industrial sectors.
Major customer countries for Woodside’s LNG, including
Japan, the Republic of Korea and China, have set net zero
targets and identified ongoing use of natural gas in their
energy mix.
Global demand for oil is forecast to continue for decades,
particularly given the challenges in substituting other energy
sources in certain applications. Oil production, as part of
Woodside’s broader diversified portfolio, will help meet
this global demand, contributing margins and cash flow as
Woodside navigates the energy transition.
We are making solid progress against our net equity Scope 1
and 2 greenhouse gas emissions reduction targets. Our 2021
net equity Scope 1 and 2 greenhouse gas emissions were
10% below the 2016 – 2020 gross annual average. These
reductions were achieved by a range of design, operations
and offsetting actions and we are on course to achieve
Woodside’s near-term 2025 target of a 15% reduction. From
there, we have a mid-term target of a 30% reduction by
2030, with a net zero aspiration by 2050.1
We are also pursuing opportunities to commercialise new
energy products and lower-carbon services as part of our
broader product mix. In December 2021 we set ourselves
a new target to invest $5 billion in profitable new energy
products and lower-carbon services by 2030, assuming
the proposed merger with BHP’s petroleum business is
completed.2 These products include hydrogen and ammonia
which produce lower greenhouse gas emissions at the point
of use and can help our customers decarbonise.
We announced new hydrogen and ammonia producing
opportunities including H2Perth near the Kwinana industrial
hub south of Perth, H2TAS located in the Bell Bay area of
northern Tasmania, and H2OK in Oklahoma.
Following the State of Emergency declared on 1 February
2021 in Myanmar, we placed all business decisions under
review and expressed our concern at the deteriorating
human rights situation. Subsequent to the reporting period,
we announced our intention to withdraw from our interests
in Myanmar.
In the second quarter, we also announced a decision to exit
Kitimat LNG in Canada, allowing us to focus on higher value
opportunities in Australia and Senegal, where we are on track
to deliver first oil from the Sangomar development in 2023.
Continued capital discipline is central to our strategy to thrive
through the energy transition by building a low-cost, lower-
carbon, profitable, resilient and diversified portfolio.
On behalf of the Board, I would like to thank the entire
Woodside team, who delivered excellent results in 2021
while continuing to pivot and adapt in a dynamic external
environment.
Peter Coleman retired as Chief Executive Officer and
Managing Director in the second quarter after 10 years in
the role. Peter’s focus on safety and operational excellence,
and his leadership on sustainability, are very valuable
legacies. We thank Peter and Meg O’Neill, who acted as Chief
Executive Officer from April until August, when the Board
formally appointed her to the role.
—
Richard Goyder, AO
Meg has taken on the role with great leadership and energy,
overseeing an incredible second half in which we announced
the proposed merger with BHP’s petroleum business,
Scarborough and Pluto Train 2 final investment decisions, a
number of new energy opportunities, and now an impressive
profit result.
My thanks also go to my Board colleagues who have put
in many hours and enthusiastically participated in all the
transformational decisions taken in 2021.
To all our shareholders, we appreciate your ongoing
support. We are pleased that the significant efforts of the
Woodside team in 2021 have delivered increased financial
returns to you.
Rest assured that we remain focused on delivering value to
all of our stakeholders and building a stronger, more resilient
and diversified company.
Richard Goyder, AO
Chairman
17 February 2022
1 Target is for net equity Scope 1 and 2 greenhouse gas emissions, relative to a starting base of the gross annual average equity Scope 1 and 2 greenhouse gas emissions over 2016-2020 and
may be adjusted (up or down) for potential equity changes in producing or sanctioned assets with an FID prior to 2021. Post-completion of the Woodside and BHP petroleum merger (which
remains subject to conditions including regulatory approvals), the starting base will be adjusted for the then combined Woodside and BHP petroleum portfolio.
2 Investment target assumes completion of the proposed merger with BHP’s petroleum business. Individual investment decisions are subject to Woodside’s investment hurdles. Not guidance.
Woodside Petroleum Ltd
11
CHIEF EXECUTIVE
OFFICER'S REPORT
2021 has been a transformative year for Woodside in which we delivered strong
financial results driven by our low-cost, reliable operations, and announced key
investment decisions and strategies to ensure that Woodside is a resilient and
diversified company in the future.
We achieved a reported net profit after tax of $1,983 million,
underpinned by strengthened oil and LNG pricing, increased
trading activity and the reversal of non-cash impairments
related to Pluto-Scarborough and NWS Gas. We generated
an operating cash flow of $3.8 billion, a 105% increase from
2020, strengthening our balance sheet and financial position.
We announced the proposed merger with BHP’s petroleum
business in August and signed a binding share sale
agreement in November. The merger is transformative and
will deliver increased scale, diversity, and resilience to better
navigate the energy transition. It will provide the financial
strength to fund planned developments in the near term,
investment in future energy opportunities and return value
to shareholders through the cycle. Completion of the merger
is targeted for early June 2022 subject to a shareholder vote
on the transaction which is targeted for 19 May 2022.
Unfortunately, and contrary to the importance we place
on keeping our colleagues safe, our total recordable injury
rate increased to 1.74 per million work hours. The safety of
our employees and contractors is our number one priority.
A focus area for 2022 is to address common root causes
for the 2021 incidents to deliver improvements in overall
safety performance.
We continued to deliver reliable and lower-cost operations,
all while completing our largest ever program of planned
maintenance which included work scopes deferred from
2020 due to the impact of the COVID-19 pandemic.
We established the Operations Transformation program to
support the long-term cost competitiveness of our assets
and business. As part of this program we are streamlining
processes, utilising technology to enable more informed
decision making and automating routine tasks. A key
focus for our team has been improving the efficiency and
effectiveness of maintenance planning and execution.
We had a reserves downgrade on Julimar-Brunello and a
reserves revision on the Greater Pluto region following the
completion of integrated subsurface studies incorporating
4D seismic and well performance data.
We approved final investment decisions on our Scarborough
and Pluto Train 2 projects. These decisions are as significant
for us as the North West Shelf was in the 1980s, and Pluto in
the 2000s. Scarborough is a world-class reservoir containing
only 0.1% carbon dioxide and will be processed through the
expanded Pluto LNG facility. The Scarborough and Pluto
Train 2 projects leverage existing infrastructure at Pluto LNG
and site works for Pluto Train 2 were previously completed
when the original LNG train was built.
Processing Scarborough gas through the efficient and
expanded Pluto LNG facility makes it an attractive option
for major LNG customers seeking reliable, affordable, and
lower-carbon energy to meet demand and support their
decarbonisation goals. The approved FID decisions have
also resulted in an increase to Woodside's overall corporate
Proved plus Probable (2P) Total Reserves by 1,432.7 MMboe.
In addition to achieving FID, we also completed the sell-
down of a 49% non-operated participating interest in
Pluto Train 2 to Global Infrastructure Partners (GIP). This
transaction completed in January 2022.
Construction of our Sangomar project in Senegal continued
on schedule with the first well drilled and completed and
FPSO conversion activities continuing. First oil is targeted
for 2023.
Construction of the Pluto-KGP Interconnector pipeline
between Pluto LNG and the Karratha Gas Plant was completed
and commissioning activities commenced ahead of ready for
start-up (RFSU) targeted for the first quarter of 2022. The
Interconnector will provide opportunities to take advantage
of future excess capacity at KGP. It will also provide potential
12 Annual Report 2021
to accelerate future developments of other offshore Pluto gas
reserves, as well as third-party resources.
In October, the first phase of the Pyxis Hub achieved RFSU,
which will tie-back the Pyxis and Pluto North fields to
existing Pluto infrastructure and support the Pluto-KGP
Interconnector.
We also achieved RFSU of Julimar-Brunello
Phase 2, which involves the tie-back of the Julimar field
to the Wheatstone offshore platform. Both Pyxis Hub and
Julimar-Brunello Phase 2 were delivered ahead of schedule
and under budget.
Woodside recognises that a decarbonising world requires
low-cost and lower-carbon energy. As well as managing
our net equity Scope 1 and 2 greenhouse gas emissions,
our approach includes growing our portfolio of new energy
opportunities and building capability as we develop the
market for lower-carbon products and services.
In December, we built on our net equity Scope 1 and 2
greenhouse gas emissions reduction targets of 15% by 2025
and 30% by 2030, with a net zero aspiration by 2050, by
setting ourselves a new target to invest $5 billion in new
energy products and lower-carbon services by 2030.1,2
Our focus is on hydrogen and ammonia, which produce
lower greenhouse gas emissions at the point of use and
will help our customers decarbonise. We are also looking at
lower-carbon services such as carbon capture and storage,
which Woodside could offer as a service to third parties to
sequester their emissions.
—
Meg O'Neill
In parallel with this Annual Report we have also released our
Climate Report, which articulates how our business will thrive
in the energy transition. The report will be put to a non-
binding advisory vote at our 2022 Annual General Meeting
on 19 May 2022.
Environmental, social and governance performance is
integral to our success. Our Sustainable Development Report
outlines our approach to sustainability which covers inclusion
and diversity.
I am both humbled and honoured to be leading Woodside
during this transformational period for our company.
Our story is already remarkable because of the challenges
we have overcome and the opportunities we have grasped.
I believe we will only emerge stronger as we continue
to create a future in which Woodside provides reliable,
affordable and lower-carbon energy for decades to come.
Meg O'Neill
Chief Executive Officer and Managing Director
17 February 2022
1 Target is for net equity Scope 1 and 2 greenhouse gas emissions, relative to a starting base of the gross annual average equity Scope 1 and 2 greenhouse gas emissions over 2016-2020 and
may be adjusted (up or down) for potential equity changes in producing or sanctioned assets with an FID prior to 2021. Post-completion of the Woodside and BHP petroleum merger (which
remains subject to conditions including regulatory approvals), the starting base will be adjusted for the then combined Woodside and BHP petroleum portfolio.
2 Investment target assumes completion of the proposed merger with BHP’s petroleum business. Individual investment decisions are subject to Woodside’s investment hurdles. Not guidance.
Woodside Petroleum Ltd
13
EXECUTIVE MANAGEMENT
Meg O’Neill
BSc (Ocean Engineering), BSc (Chemical
Engineering), MSc (Ocean Systems
Management)
Chief Executive Officer and
Managing Director
Mark Abbotsford
BEcon (Hons), MBA, MPhil (Finance)
Jacky Connolly
BCom, MOHS
Vice President Marketing, Trading and
Shipping
Vice President People and Global
Capability
» Marketing
» Trading
» Shipping
» People and Global Capability
» Organisational Development
» Remuneration
Fiona Hick
BEng (Materials Engineering), BAppSci
(Energy and Carbon Studies), FIEAust
Daniel Kalms
BEng (Chemical Engineering),
GradCertProjMgt, MBA
Senior Vice President Merger
Integration Planning
» Integration Planning
Executive Vice President Operations
» Producing Business Units
» Production Support
» Maintenance
» Logistics
» Health, Safety and Environment
» Subsea and Pipelines
» Reservoir Management
» Decomissioning
14 Annual Report 2021
Julie Fallon
BEng (Hons) (Chemical Engineering),
FIChemE
Acting Senior Vice President
Corporate and Legal
» Internal Audit
» Business Climate and Energy Outlook
» Corporate Affairs
» Legal and Secretariat
» Governance, Risk and Compliance
» Property, Security and Resilience
Shaun Gregory
BSc (Hons), MBT
Executive Vice President
Sustainability and Chief Technology
Officer
» Exploration
» Digital
» Geoscience
» Technology
» New Energy and Carbon Abatement
opportunities
Dr Tom Ridsdill-Smith
BSc (Hons), PhD (Mathematical Geophysics)
Graham Tiver1
BBus, FCPA
Menno Weustink
MSc (Offshore Technology)
Senior Vice President Climate
» Climate Solutions
» Climate Engagement
Executive Vice President
and Chief Financial Officer
» Finance, Tax, Treasury and Insurance
Acting Vice President Development
» Engineering
» Projects
» Commercial
» Development Planning
» Business Development and Growth
» Drilling and Completions
» Contracting and Procurement
» Investor Relations
» Quality
» Browse
» Strategy, Planning and Analysis
» Sangomar Field Development
» Kitimat
» Sunrise
1 Mr Tiver commenced with Woodside on 1 February 2022 after the resignation of Sherry Duhe as Executive Vice President and Chief Financial Officer.
Woodside Petroleum Ltd
15
FOCUS AREAS
Senegal
Canada
Beijing2
Seoul2
Tokyo2
Houston
Myanmar3
H2OK
Heliogen
Singapore1
Perth
Carbon
origination
projects
H2Perth
H2TAS
Australia
Timor-Leste/Australia
Product type
Phase
Gas
Oil
Producing assets
Developments
Gas or oil
Appraisal and exploration
New energies
Carbon origination projects
Refer to the Asset Facts section on page 155 for full details of Woodside's global interests.
1 Denotes marketing office.
2 Denotes representative and liaison offices.
3 Woodside announced its decision to withdraw from its interests in Myanmar on 27 January 2022.
16 Annual Report 2021
Okha FPSO
North West
Shelf Project
Pluto
Scarborough
Wheatstone
Ngujima-Yin FPSO
Browse
Karratha
Pluto LNG
North West
Shelf Project
Onslow
Wheatstone
Western
Australia
Product share of
2021 annual production
Carbon
origination
projects
Perth
Woodside
headquarters
H2Perth
LNG 78%
Liquids 19%
LPG and domestic gas 3%
Woodside Petroleum Ltd
17
MERGER WITH
BHP PETROLEUM
Woodside and BHP signed a binding share sale agreement in November 2021
for the merger of Woodside and BHP’s petroleum business.
TARGETED KEY DATES
» Early April 2022 – Issue of notice of meeting,
explanatory memorandum and independent
expert’s report
» 19 May 2022 – Shareholder meeting to vote on
the merger
» Early June 2022 – Completion of the merger
The combination of Woodside and BHP’s petroleum business
is expected to deliver:
1
2
3
4
5
6
A long-life, conventional asset portfolio of scale
and diversity of geography, product and end
markets. The recent final investment decisions
for Scarborough and Pluto Train 2 crystallise a
sustained LNG production profile
A stronger balance sheet and resilient operating
cash flows to fund shareholder returns and business
evolution to support the energy transition
Superior returns through continued capital
discipline
An enhanced development portfolio of high-return
growth options
Increased capacity to deliver on the energy
transition
Opportunities to deliver ongoing attractive
synergies
N
O
B
R
WER C A
LO
T
S
O
C
W
O
L
P R OFITABLE
OPTIMISE
VALUE AND
SHAREHOLDER
RETURNS
R
E
S
I
L
I
E
N
T
D
I
V
E
R
S
I
F
I
E
D
On completion, Woodside will be the largest energy
company listed on the ASX and a global top 10 independent
energy company by production.1 The merger supports
Woodside’s strategy to build a low-cost, lower-carbon,
profitable, resilient and diversified portfolio.
Completion of the merger is subject to satisfaction
(or waiver where permitted) of relevant conditions
precedent, which include:
• Approval by regulatory and competition authorities
• Approval by Woodside shareholders at a general meeting
• KPMG, in its capacity as Woodside's independent expert
issuing a report concluding that the merger is in the best
interests of Woodside shareholders
• Registration statements relating to Woodside shares
being declared effective by the United States Securities
and Exchange Commission
• Other conditions customary for a transaction of this nature.
1 Source: Wood Mackenzie Corporate Benchmarking Tool production forecasts as at 31 July 2021. Woodside analysis.
18 Annual Report 2021
FINANCIAL
PERFORMANCE
AND STRATEGY
FINANCIAL SUMMARY
In 2021 we achieved a reported net profit after tax of $1,983 million and an
underlying net profit after tax of $1,620 million, the highest since 2014.
Strong sales revenue resulting from increased market pricing in 2021 was a key
contributor to this. The favourable market conditions also supported a significant
increase in third-party trading activity.
FINANCIAL SUMMARY
$ million
Operating revenue
EBITDA1
EBIT1
NPAT
Underlying NPAT1,2
Net cash from operating activities
Investing expenditure
Capital investment expenditure1,3
Exploration expenditure1,4
Free cashflow1
Dividends distributed
Key ratios
Return on equity
ROACE
Effective income tax rate5
Earnings
Gearing
Sales volumes
Gas
Liquids
Total
%
%
%
US cps
%
MMboe
MMboe
2021
6,962
4,135
3,493
1,983
1,620
3,792
2,727
2,631
96
851
404
14.8
15.6
32.0
206.0
21.9
93.7
17.9
111.6
2020
3,600
1,922
(5,171)
(4,028)
447
1,849
2,013
1,901
112
(263)
766
(33.4)
(21.0)
20.5
(423.5)
24.4
86.5
20.3
106.8
1 These are non-IFRS measures that are unaudited but derived from audited Financial Statements. These measures are presented to provide further insight into Woodside's performance. Refer
to footnote 4 on page 159 for the calculation methodology on EBITDA.
2 2021 NPAT was adjusted for Myanmar exploration and evaluation write-offs ($209 million), various costs relating to Woodside's exit from the Kitimat LNG development ($33 million), one-off
reconciliation of joint venture costs from prior years ($4 million); offset by the impact of impairment reversals of oil and gas properties ($582 million) and prior period impacts of price reviews
($27 million). 2020 NPAT was adjusted for the impact of impairment of oil and gas properties and exploration and evaluation assets ($3,923 million), recognition of provisions for the Corpus
Christi onerous contract ($447 million), a one-off reconciliation of joint operating costs relating to prior years ($41 million), an adjustment to revenue recognised in prior periods relating to price
reviews currently under negotiation ($27 million), redundancy costs ($20 million) and additional costs incurred as a result of COVID-19 ($17 million).
3 Excludes exploration capitalised.
4 Excludes prior period expenditure written off and permit amortisation; includes evaluation expense.
5 Global effective income tax rate. 2020 effective income tax rate was impacted by one-off items including the impairment of foreign assets and onerous contract provision.
20 Annual Report 2021
NPAT reconciliation ($ million)
3,161
165
(2,719)
1,058
(1,284)
5,716
d
n
a
t
n
e
m
r
i
a
p
m
I
0
2
0
2
t
c
a
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n
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o
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h
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v
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p
(4,028)
T
A
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N
0
2
0
2
(86)
1,983
(363)
1,620
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1
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i
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a
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a
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m
t
s
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d
a
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A
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1
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0
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n
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d
n
u
1
2
0
2
Key movements
Sales revenue: price
The recovery in oil and gas prices continued in 2021, leading
to increased sales revenue due to higher realised prices.
Sales revenue: volume
There was an approximately ten-fold increase in the number
of traded LNG cargoes in 2021 in response to favourable
market conditions. There was also an approximately three-
fold increase in the number of Corpus Christi cargoes lifted.
This was partially offset by fewer condensate cargoes sold,
lower facility reliability on Ngujima-Yin as well as weather
events in the first half of 2021. The corresponding trading
costs for the purchase of third-party traded LNG cargoes
and Corpus Christi cargoes are shown in the "trading costs"
line item within "other costs of sales" in note A.1 to the
Financial Statements.
Impairment reversals
Final investment decisions for the Scarborough and Pluto
Train 2 projects supported the reversal of a non-cash
impairment for Pluto, previously recognised in 2020. The
non-cash impairment for NWS Gas recognised in 2020 was
also reversed, supported by updated cost and production
profiles and an improved price environment.
Trading costs
Trading costs increased due to a higher number of traded
cargoes in 2021. The trading revenue is recognised in LNG
revenue, and the corresponding higher trading costs are
shown in the "trading costs" line item within "other costs of
sales" in note A.1 to the Financial Statements.
Income tax and PRRT
Income tax and PRRT expense increased primarily due to the
effect of higher operating revenue in 2021.
Other
Oil and gas properties depreciation expense decreased
primarily due to a reduction in asset bases following the
asset impairments announced in July 2020. It was also
impacted by lower oil production volumes as a result of
lower facility reliability on Ngujima-Yin and weather events
in 2021.
Exploration wells in Myanmar were written-off during the
period as a result of the decision to relinquish the blocks and
withdraw from Myanmar.
Other items decreasing NPAT included higher royalties,
exercise and levies due to higher pricing and revenue, higher
repurchase and cancellation costs for revenue optimisations
and net loss on hedging activities.
Average
annual dated
Brent ($/boe)
71
135
Dividend per share
71
144
54
98
64
91
42
38
2017
2018
2019
2020
2021
Full-year
dividend
(US cps)
Woodside Petroleum Ltd
21
Capital management
Capital allocation
Capital expenditure increased in 2021 due to activity ramp up
on Sangomar and other expenditure on projects such as Pyxis
Hub and Julimar-Brunello Phase 2. Contingent payments
were made to ExxonMobil and BHP following the final
investment decisions taken on Scarborough and Pluto Train 2.
Dividend payments
A 2021 final dividend of US 105 cents per share (cps)
has been declared. The final dividend is based on the
2021 underlying NPAT of $1,620 million and reflects the
performance of our high-reliability and low-cost operations.
The value of the final dividend payment is $1,018 million,
representing a payout ratio of approximately 80% of
underlying NPAT.
Woodside's dividend policy remains unchanged following a
review in 2021. Dividends will continue to be based on NPAT
excluding non-recurring items, with a minimum 50% payout
ratio, and a targeted payout ratio between 50% and 80%.
The dividend reinvestment plan remains active, allowing
eligible shareholders to reinvest their dividends directly into
shares at a 1.5% discount.
Unit production cost
Unit production cost increased by 10% to $5.3/boe. Total
production cost remained stable despite increased planned
turnaround activity but produced volumes decreased,
impacted by the expiry of NWS joint domestic gas contract
obligations, cessation of production from the Angel field in
2020, turnaround activity on NWS Project and Wheatstone
and the impact of weather events in the first half of 2021.
Liquidity
3,792
(2,491)
Cash
Undrawn debt
n
o
i
l
l
i
m
$
6,704
0
0
1
,
3
4
0
6
3
,
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0
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2
w
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h
s
a
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g
n
i
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a
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p
O
(450)
(289)
(700)
(435)
(6)
6,125
0
0
1
,
3
5
2
0
3
,
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R
D
i
f
o
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n
(
d
a
p
s
d
n
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d
v
D
i
i
Production cost
Debt maturity profile
5.2
443
5.1
465
5.7
505
4.8
478
5.3
481
n
o
i
l
l
i
m
$
1,500
1,000
500
0
7
1
0
2
8
1
0
2
9
1
0
2
0
2
0
2
1
2
0
2
2
2
0
2
3
2
0
2
4
2
0
2
5
2
0
2
6
2
0
2
7
2
0
2
8
2
0
2
9
2
0
2
0
3
0
2
1
3
0
2
Total production cost ($ million)
Unit production cost ($/boe)
Drawn debt
Undrawn debt facilities
1 Other funding activities includes repayment of borrowings and lease liabilities, borrowing costs and contributions to NCI.
22 Annual Report 2021
Balance sheet, liquidity, and debt service
During 2021 we generated $3,792 million of cash flow from
operating activities. We ended the period with liquidity of
$6,125 million. Our credit ratings of Baa1 and BBB+ were
both reaffirmed during 2021 by Moody’s and S&P Global
respectively.
We prudently and strategically manage our debt near-term
maturities and maintain a low cost of debt. During the first half
of 2021 we repaid a $700 million bond and during the year we
refinanced $400 million of committed undrawn facilities.
Our gearing ratio decreased from 24.4% at the end of 2020
to 21.9% primarily due to a stronger equity position of the
Group as a result of 2021 profit and our gearing remains
within our target range of 15-35%.
Our weighted average term to maturity decreased from 4.4
to 4.0 years, and our portfolio cost of debt decreased from
2.9% to 2.7%. Our drawn debt at the end of the period was
$5,446 million. We will continue to actively manage our debt
portfolio throughout 2022.
Hedging
The Board regularly reviews the appropriate level of hedging
to protect against downside pricing risk. In December
2021, in anticipation of the merger, the Board approved
hedging of up to 50% of oil-linked exposure from produced
hydrocarbons in any one year.
As at 14 February 2022, Woodside has oil hedges in place for
approximately 17.5 MMboe of 2022 production at an average
price of $74.57 per barrel and approximately 21.9 MMboe of
2023 production at an average price of $74.50 per barrel.1
Hedges were also placed to lock in Title Transfer Facility
(TTF) priced volumes of approximately 0.5 MMboe for the
first quarter of 2022.2
In addition, Woodside has taken hedges on Corpus Christi
volumes to protect against downside pricing risk for
2022 and 2023. As a result of hedging and term sales,
approximately 97% of Corpus Christi volumes in 2022
and 73% in 2023 have reduced pricing risk as at
14 February 2022.3
2022 outlook
Our investment expenditure guidance for 2022 is $3,800
to $4,200 million. The guidance excludes the impact of
any subsequent sell-downs which we are progressing on
Sangomar and Scarborough upstream, and excludes the
benefit of GIP's additional contribution of approximately
$822 million for Pluto Train 2.
We will increase expenditure on Scarborough and Pluto Train
2 following the final investment decisions in 2021 and will
also continue to safely execute Sangomar, which is on track
for first oil in 2023.
2022 guidance excludes the impact from the proposed
merger with BHP’s petroleum business.
2022 Investment expenditure guidance
4,000
3,000
n
o
i
l
l
i
m
$
2,000
1,000
0
Sangomar4
Scarborough5
Pluto Train 26
Other growth7
Exploration
Base business8
2022E
1 As at 31 December 2021, Woodside had oil hedges in place for approximately 13.9 MMboe of 2022 production at an average price of $73.60 per barrel and approximately 15.8 MMboe of 2023
production at an average price of $73.48 per barrel.
2 In place as at 31 December 2021.
3 As a result of hedging and term sales approximately 97% of Corpus Christi volumes in 2022 and 70% in 2023 had reduced pricing risk as at 31 December 2021.
4 Sangomar represents 82% participating interest. Excludes the impact of any subsequent sell-down.
5 Scarborough represents 73.5% participating interest. Excludes the impact of any subsequent sell-down.
6 Pluto Train 2 represents 51% participating interest. Excludes the benefit of GIP's additional contribution of approximately $822 million.
7 Other growth includes New Energy, Pluto-KGP Interconnector, Browse and other spend.
8 Base business includes Pyxis, Pluto LNG, NWS Project, Wheatstone, Australia Oil and Corporate.
Woodside Petroleum Ltd
23
24 Annual Report 2021
STRATEGY AND CAPITAL
MANAGEMENT
We have a strategy to thrive through the energy transition by building a low-cost,
lower-carbon, profitable, resilient and diversified portfolio. This will enable us to
continue to optimise value and shareholder returns.
Woodside has a history of low-cost, high margin operations.
Our customers, investors and other stakeholders are
increasingly demanding low-cost, lower-carbon energy and
Woodside is working on opportunities to develop a resilient
and diversified portfolio.
Strategic framework
Woodside has a portfolio of Tier 1 assets which provides
the foundation to deliver new growth opportunities. Our
disciplined capital allocation approach includes robust
assessment of opportunities, portfolio outcomes and
shareholder returns, while maintaining focus on safe and
reliable operations.
Our investment decisions are informed by energy market
analysis including supply, demand and price outlooks and
we test the robustness of potential investments against
a wide range of climate scenarios to ensure we make the
right investment decisions to remain profitable and resilient
through various commodity cycles and climate outcomes.
Our high performing culture, which includes an engaged,
accountable and diverse workforce with a responsible
environmental, social and governance (ESG) mindset,
is critical to ensuring our effectiveness in delivering our
vision and strategy. Our strategic framework is underpinned
by our safe and reliable operations, a strong balance sheet
and technology to enhance efficiency and deliver low-cost
and improved decision making across the value chain.
COMPETITIVE
ADVANTAGE
Highly valued products
World-class Tier 1 assets
Diversification within known
value chains
HIGH PERFORMING
CULTURE
Responsible environmental, social
and governance (ESG) mindset
Engaged, accountable and diverse
workforce
ENABLERS
Safe and reliable operations
Strong balance sheet
Technology
DISCIPLINED
CAPITAL ALLOCATION
Robust assessment of
opportunities, portfolio outcomes
and shareholder returns
Disciplined capital spend bound
by defined targets
MARKET
ANALYSIS
Energy markets supply, demand
and price outlook
Scenarios inform new energy
trajectory and existing business
Woodside Petroleum Ltd 25
Capital allocation framework
Our capital allocation framework sets target investment criteria for oil, gas and new energy opportunities. We use this capital
allocation framework to create a diversified and flexible portfolio which is responsive to changes in demand and supply
for our products.
OIL
GAS
NEW ENERGY
OFFSHORE
PIPELINE
LNG
DIVERSIFIED
Focus
Generate high returns to
fund diversified growth,
focusing on high quality
resources
Leveraging infrastructure to
monetise undeveloped gas,
including optionality for hydrogen
New energy products and
lower-carbon services to reduce
customers’ emissions; hydrogen,
ammonia, CCUS1
High cash generation
Characteristics
Shorter payback period
Quick to market
Stable long-term
cash flow profile
Resilient to
commodity pricing
Long-term cash flow
Strong forecast
demand
Upside potential
Developing market
Lower capital requirement
Lower risk profile
Opportunity
targets
Emissions
reduction
IRR > 15%
IRR > 12%
IRR > 10%
Payback within 5 years2
Payback within 7 years2
Payback within 10 years2
30% net emissions reduction by 2030, net zero aspiration by 2050 or sooner3
When assessing opportunities, we consider a broad range of portfolio evaluation and opportunity evaluation factors relevant
to the opportunity. These assessments can apply to acquisitions or divestments, and for evaluating the impact of a new project
on the portfolio.
Portfolio and opportunity optimisation
Portfolio evaluation considerations4
Opportunity evaluation considerations4
EPS
Free cash
flow
Funding
capacity
Emissions
profile
Strategic
fit
IRR/NPV
Payback
period
Risk
Breakeven
Growth opportunities are screened against portfolio metrics using price, scenario and climate analysis
1 CCUS refers to carbon capture utilisation and storage.
2 Payback refers to RFSU + X years.
3 Target is for net equity Scope 1 and 2 greenhouse gas emissions, relative to a starting base of the gross annual average equity Scope 1 and 2 greenhouse gas emissions over 2016-2020 and
may be adjusted (up or down) for potential equity changes in producing or sanctioned assets with an FID prior to 2021. Post-completion of the Woodside and BHP petroleum merger (which
remains subject to conditions including regulatory approvals), the starting base will be adjusted for the then combined Woodside and BHP petroleum portfolio.
4 Illustrative of the considerations. Not an exhaustive list.
26 Annual Report 2021
Capital management
Our capital management framework provides us with the
flexibility to maximise the value delivered from our portfolio
of opportunities.
We consider a range of climate and macroeconomic
scenarios to inform our decision making and ensure we
maintain a resilient financial position.
Our capital investment requirements are primarily funded
by our resilient and stable operating cash flows, which
we augment or distribute with a number of capital
management levers:
• Participating interest management, ensuring we balance
capital investment requirements, project execution risk
and long-term value. In 2021 we announced the sell-
down of a 49% non-operating participating interest in the
Pluto Train 2 Joint Venture. This transaction completed
in January 2022. In 2022, we will continue the targeted
sell-down processes for Sangomar and the Scarborough
offshore resource.
• Hedging, to protect the balance sheet against the
commodity cycle.
• Debt management, to ensure that we continue to have
access to premium debt markets at a competitive cost
to support our growth activities. We seek to manage
average debt maturity on our debt portfolio. Our gearing
target is 15-35%. We continue to target maintaining an
investment-grade credit rating.
Optimise value and shareholder returns
2022 PRIORITIES
» Maintain a strong balance sheet through liquidity
and debt portfolio management
» Active balance sheet management including
commodity and foreign exchange hedging
» Sell-down Sangomar and the Scarborough
offshore resource
• Shareholder returns, to ensure we reward our
shareholders appropriately. Our dividend policy is to aim
to pay a minimum of 50% of net profit after tax excluding
non-recurring items. The net profit after tax basis helps
preserve cash and protect the balance sheet in periods
of low commodity pricing. We will target a payout ratio
between 50 and 80% and our dividend reinvestment
plan remains active. We will maintain the flexibility to
consider opportunities to provide additional returns to
shareholders through special dividends and share buy-
backs in periods of excess cash generation.
• Focused expenditure management, to ensure prudent and
efficient deployment of capital to support delivery of base
business and growth opportunities.
Safe, reliable and
low-cost operations
Investment
expenditure
Strong
balance
sheet
Dividend policy
(minimum 50%
payout ratio)
Special
dividends
Share
buy-backs
Future
investment
Excess
cash
Investment grade
credit rating
Maintain dividend based on NPAT
excluding non-recurring items,
targeting 50-80% payout ratio
Targeted
15-35% gearing
Woodside Petroleum Ltd
27
ENERGY MARKETS
The global economy grew strongly in 2021, continuing
its recovery from the COVID-induced lows of 2020,
supported by rising vaccination rates and fiscal and
monetary stimulus measures.
Oil and gas prices recovered, as demand rebounded in line
with the global economic recovery. In 2021, north Asian
LNG prices reached all-time highs in January and again
in October, supported by various factors including colder
winter weather in many key gas-consuming countries and
disruptions experienced by a number of suppliers. Global
LNG demand grew by 6% in 2021, supported by continued
strong demand growth in Asia.1
The World Bank estimates in its Global Economic Prospects
report released in January 2022 that global GDP growth will
continue in 2022 but at a slower rate, expected to be 4.1% in
2022, down from 5.5% estimated for 2021.
Global commitment to take decisive action to address
climate change continues to strengthen. In the lead-up
to the 26th UN Climate Change Conference of the Parties
(COP-26) held in Glasgow during November 2021, many
countries, including Japan, South Korea and China, pledged
to achieve net zero carbon emissions by around the middle of
this century. The International Energy Agency (IEA) estimated
in November 2021 that if all of the climate pledges announced
to date were met in full and on time, global warming could be
limited to below 2 degrees Celsius by 2100.2
The global energy transition is creating uncertainty over
how global energy markets will evolve, but there is broad
consensus that lower-carbon power sources, such as solar,
wind and lower-carbon hydrogen, will play an increasingly
important role in global energy systems.
LNG demand by region - AET-24
Natural gas, which on a lifecycle basis emits half the
carbon dioxide of coal to generate power, is expected
to play a critical role in the energy transition. Gas-fired
power generation is expected to be an important source
of grid stability and flexibility as power systems become
renewables-rich.3
Natural gas can also be used in conjunction with carbon
capture and storage to create lower-carbon hydrogen, which
is likely to become an increasingly significant source of
energy over time. It also has the potential to displace higher-
carbon fuel sources in many applications.
There is a significant opportunity for natural gas to assist with
the decarbonisation goals of developing countries in Asia,
which typically are fast-growing and often coal-dependent.
Wood Mackenzie analysis indicates that growth in global
gas demand is expected to at least 2035 under all of their
scenarios, including their AET-2 scenario, with most growth
coming from developing Asian nations.4
Under Wood Mackenzie’s AET-2 scenario, global LNG
demand grows by 62% between 2021 and 2040. Asian LNG
demand growth over this period is even stronger, at 90%.
Under Energy Transition Outlook, their base case, global LNG
demand increases by 90% between 2021 and 2040.4
In addition to our own Scarborough project, 2021 saw
Qatar’s North Field East (NFE) project, the Darwin LNG
backfill (Barossa) project in Australia, and Russia’s Baltic LNG
(Ust-Luga) project take FID. Scarborough’s competitive cost
of supply, low reservoir carbon content and proximity to key
Asian demand centres makes it ideally placed to supply the
world’s growing LNG needs.
m
c
B
1,200
1,000
800
600
400
200
0
Energy Transition Outlook (base case)
AET-2 Total global LNG demand
Rest of world
Europe
South-Eastern Asia
Southern Asia
Eastern Asia
2021
2025
2030
2035
2040
1 Wood Mackenzie Short Term Demand Tracker, January 2022, pg 2.
2 IEA Commentary: COP26 climate pledges could help limit global warming to 1.8 degrees C, but implementing them will be key, Dr Fatih Birol, 4 November 2021.
3 Grattan Institute 2021: “Go for net zero – a practical plan for reliable, affordable, low-emissions electricity” page 30.
4 AET-2 is Wood Mackenzie's accelerated energy transition 2 degrees Celsius scenario. Wood Mackenzie Commodity Report, Global Gas Demand, October 2021, pg 2.
28 Annual Report 2021
BUSINESS MODEL
AND VALUE CHAIN
Woodside’s business model seeks to optimise returns across the value chain.
We achieve this by prioritising competitive growth opportunities; by utilising
our operational, development and technological capabilities; and by deepening
relationships in energy markets with strong demand growth. We do this with the
objective of delivering superior outcomes for stakeholders.
Acquire and explore
We grow our portfolio through acquisitions and exploration, based on a
disciplined approach to optimising shareholder value and appropriately
managing risk. We look for material positions in world-class assets and
basins that are aligned with our capabilities and existing portfolio. We assess
acquisition opportunities that complement our discovered and undiscovered
resource base. We target exploration opportunities close to existing
infrastructure and with a clear path to commercialisation.
2021 EXAMPLES
Executed binding share sale
agreement for the merger
of Woodside and BHP's
petroleum business.
Develop
We are building on more than 30 years of development expertise from
our assets in Western Australia by investing in opportunities in Australia
and internationally. During the development phase, we maximise value
by selecting the most competitive concept for extracting, processing and
delivering energy to our customers. We are investing in new energy and
lower-carbon solutions to meet the needs of our customers and support the
resilience of our business.
Achieved FID for the
Scarborough and Pluto Train
2 projects, and secured land
for two proposed hydrogen
and ammonia projects in
Australia and the proposed
hydrogen project, H2OK in
North America.
Operate
Our operations are characterised by strong safety, reliability, and
environmental performance in remote and challenging locations. Our
operated assets include the NWS Project and Pluto LNG. We also operate
two FPSO facilities and have a non-operated interest in Wheatstone. By
adopting technology and a continuous improvement mindset we are able to
support operational performance and optimise the value of our assets.
Completed major turnarounds
at NWS Project’s Karratha
Gas Plant, North Rankin
Complex and Goodwyn-A
platform.
Woodside Petroleum Ltd 29
—
Working at Pluto LNG onshore processing facility
Market
Our marketing and trading strategy is to build a diverse customer
portfolio and pursue additional sales agreements, underpinned by
reliable domestic gas, LNG and liquids production, and supplemented
by globally sourced volumes.
Our relationships with customers in Australian and international energy
markets have been maintained through a track record of reliable delivery
and expertise across contracting, marketing and trading. In addition to
long-term LNG sales, we pursue near-term value-accretive arrangements
through short- and mid-term sales and LNG shipping transactions. Our
marketing of crude, condensate and LPG is based on short-term sales,
and may be supplemented by term arrangements to maximise value. We
are collaborating with our customers on innovative lower-carbon energy
solutions, including carbon offset LNG and liquids cargoes.
2021 EXAMPLES
Marketed domestic gas on
a mid- and short-term basis
from Woodside's portfolio.
Decommission
Decommissioning is integrated into project planning, from the earliest
stages of development through to the end of field life. Through working
together with our partners and technical experts, we are able to identity the
most sustainable and beneficial post-closure options that minimise financial,
social and environmental impacts.
Completed plug and
abandonment activities for
the Capella well and two
Yodel wells.
30 Annual Report 2021
OPERATIONS
PLUTO LNG
2021 HIGHLIGHTS
2022 PLANNED ACTIVITIES
» Delivered strong production performance
» Achieve Pluto-KGP Interconnector ready
» Achieved start-up of Pyxis Hub ahead of schedule
for start-up
and under budget
» Achieve Pluto water handling ready for start-up
» Agreed new targets for Pluto LNG greenhouse
gas emissions under the Pluto Greenhouse Gas
Abatement Program
» Commence Xena 2 project execution
Enabling growth
The first phase of the Pyxis Hub project, comprising wells in
the Pyxis and Pluto North fields, achieved ready for start-up
(RFSU) in October 2021, four months ahead of the planned
schedule and under budget. Pyxis Hub ties back the Pyxis and
Pluto fields to existing Pluto infrastructure and will support
the Pluto-KGP Interconnector expected to start-up in Q1 2022.
The second phase of the project targets drilling, completion
and subsea tie-back of the Xena 2 well.
Hook-up and commissioning activities for the Pluto water
handling project continued during the year. Schedule
impacts related to COVID-19 were managed and the project
is on track to achieve RFSU in 2022. Once operational the
water handling unit will enable wet gas production.
Woodside’s Pluto Greenhouse Gas Abatement Program
(GGAP) was approved by the Western Australian Minister
for Environment. The GGAP includes interim and long-term
targets to achieve a 30% emissions reduction from approved
levels by 2030 and net zero by 2050 across the entire
project.2 The targets incorporate emissions associated with
Pluto Train 2 (see Scarborough and Pluto Train 2 on
pages 42-43).
Woodside interest: 90%, operator
Operational performance
Woodside achieved strong production performance at
Pluto LNG in 2021, delivering 44.3 MMboe of production
(Woodside share). This was a decrease of 1% compared to
2020 due to a minor turnaround at Pluto LNG delivered in
August 2021.
High reliability of 97.2% at Pluto LNG was maintained
during the year as a result of our focus on safe, reliable
and efficient operations.
We had no Tier 1 or 2 process safety events at Pluto LNG
in 2021.
We continue to focus on efficiency and emissions reduction
opportunities. In 2021 new controls and piping were
installed at Pluto LNG, enabling low pressure methane
vapour to be captured, and compressed to recycle back into
the LNG train. The estimated emissions savings compared
to venting the uncombusted methane was approximately
2.4 kt CO2-e per annum.1
Woodside commenced construction of the Pluto Operations
Centre at our head office in Perth to remotely operate the
foundation Pluto offshore and onshore assets. The centre will
be known as Moorditj Danjoo, which means 'strong together'
in the local Nyoongar language. Moorditj Danjoo is expected
to commence a phased transition to full operations from the
second quarter of 2022 leveraging Woodside's capability to
integrate innovation and technology to support operational
performance.
Woodside completed a review of the reserves and resource
estimates for the Greater Pluto region in November 2021. The
review followed completion of integrated subsurface studies
incorporating 4D seismic and well performance data. Further
detail is in the Reserves and resource statement on page 55.
1 The estimated GHG savings quoted in each example are based on operated emissions using engineering judgment by appropriately skilled and experienced Woodside engineers.
2 Pluto LNG Development Public Environmental Review (2006) emissions estimate of 4.1 Mtpa CO2-e for two LNG trains.
32 Annual Report 2021
Production
44.3
MMboe
LNG reliability
97.2%
Sales revenue
$2,649
million
Unit production cost
$4.3
per boe
—
Pluto LNG onshore processing facility
Woodside Petroleum Ltd 33
NWS PROJECT
2021 HIGHLIGHTS
2022 PLANNED ACTIVITIES
» Successfully delivered major turnaround activities
» Commence processing other resource owner
» Delivered 14% reduction in underlying
operating costs
» Established a marketing entity to engage with
other resource owners for processing gas through
the Karratha Gas Plant
» Re-engaged with the Browse Joint Venture
on potential supply of gas to KGP
gas through Karratha Gas Plant
» Commence production from Greater Western
Flank Phase 3
» Target further improvement in underlying
operating cost performance
Operational performance
The NWS Project delivered full-year production of
24.7 MMboe in 2021 (Woodside share). This was a decrease
of 20% compared to 2020, due to significant planned
turnaround activity in 2021 and offshore gas supply
constraints.
We achieved high reliability of 98.3% during the year and
we had no Tier 1 or 2 process safety events at NWS in 2021.
We continue to focus on efficiency and emissions reduction
opportunities to support Woodside's corporate targets.
In 2021, KGP used advanced process controls to prioritise
in real time the most modern and efficient gas turbines.
This resulted in increased energy efficiency compared to
a non-prioritised approach. Estimated savings are
approximately 55-150 kt CO2-e per annum.1
The NWS Project successfully executed its largest scope
of planned shutdown maintenance in 2021 and included
work deferred from 2020 due to the impact of the COVID-19
pandemic. The turnarounds were completed at Karratha
Gas Plant (KGP), North Rankin Complex and Goodwyn A
platform.
Our people demonstrated resilience to maintain safe,
reliable production at NWS, despite constraints presented by
COVID-19 border restrictions. This required careful workforce
management to ensure compliance with government
requirements.
Enabling growth
With emerging processing capacity, the NWS Project is
preparing to process third-party gas from 2022 and has
created a marketing entity to market available processing
capacity at KGP.
Arrangements were finalised with the Western Australian
Government for the processing of gas from Pluto from 2022
and the Waitsia Joint Venture from 2023. Woodside also
agreed with the Western Australian Government to market
and make available from 2025 an additional 45.6 PJ of
domestic gas from its existing NWS equity production.
The four-well development drilling campaign for Greater
Western Flank Phase 3 (GWF-3) completed in January
2022. GWF-3 (including Lambert Deep) is a subsea tie-back
opportunity to further commercialise NWS reserves.
The NWS Project re-engaged with the Browse Joint Venture
on a commercial proposal and joint technical studies to
support processing Browse gas at KGP.
A revised Greenhouse Gas Management Plan was
submitted to the Environmental Protection Authority in
December 2021 by the NWS Project participants to support
long-term operations and processing of future third-party
gas resources.
Woodside interest: 16.67%, operator
1 The estimated GHG savings quoted in each example are based on operated emissions using engineering judgment by appropriately skilled and experienced Woodside engineers.
34 Annual Report 2021
Production
24.7
MMboe
LNG reliability
98.3%
Sales revenue
$I,530
million
Unit production cost
$4.7
per boe
—
Working at Karratha Gas Plant
Woodside Petroleum Ltd 35
WHEATSTONE AND
JULIMAR-BRUNELLO
202I HIGHLIGHTS
2022 PLANNED ACTIVITIES
» Achieved start-up of Julimar-Brunello Phase 2
» Safely execute Phase 2 of the Wheatstone major
ahead of schedule and under budget
turnaround
» Completed Phase 1 of the Wheatstone major
turnaround
Operational performance
Woodside's share of annual production in 2021 was
13.5 MMboe, a decrease from 15.2 MMboe in 2020 due to
the Wheatstone major turnaround and Brunello reservoir
performance.
Wheatstone executed the first phase of a multi-year major
turnaround throughout September and October 2021 and
will complete the second phase during 2022.1
Woodside completed a review of the reserves and resource
estimates for Julimar-Brunello in October 2021. The review
followed completion of integrated subsurface studies
incorporating 4D seismic, well performance and well drilling
results. Further detail is in the Reserves and resource
statement on page 55.
Julimar-Brunello Phase 2
Julimar-Brunello Phase 2 involves the tie-back of the Julimar
field to the Wheatstone offshore platform. Strong progress
was made on the development throughout 2021, with
installation of subsea equipment completed. Completion
of cold commissioning activities and RFSU was achieved in
December 2021.
Woodside interest: 13%, non-operator (Wheatstone);
65%, operator (Julimar-Brunello)
—
Subsea 7 vessel, Seven Oceans
installing 18" flow line for
Julimar-Brunello Phase 2
Production
Sales revenue
I3.5
MMboe
$772
million
1 Wheatstone LNG processes gas from two separate developments, the Wheatstone Iago
Project (80%) and the Julimar-Brunello Project (20%). Woodside is the operator of the
Julimar-Brunello project with 65% equity. Woodside’s 13% non-operated interest in the
Wheatstone facilities includes the offshore platform, the pipeline to shore and the onshore
plant, but excludes the Wheatstone Iago fields and infrastructure.
36 Annual Report 2021
AUSTRALIA OIL
202I HIGHLIGHTS
2022 PLANNED ACTIVITIES
» Successful execution of Okha FPSO major
» Commencement of Enfield subsea wells
turnaround
plug and abandonment
» Delivered revenue optimisation activities
» Start-up of Cimatti production and water
injection wells to Ngujima-Yin FPSO
» Preparation for Ngujima-Yin major
turnaround in 2023
Ngujima-Yin FPSO
The Ngujima-Yin FPSO produces oil from the Vincent and
Greater Enfield resources. The facility delivered full-year
production of 7.1 MMboe in 2021 (Woodside share), down
from 8.3 MMboe in 2020 due to weather impacts and lower
facility reliability, including the FPSO disconnection during
Tropical Cyclone Seroja in April 2021. In addition, Woodside
temporarily shut-in production from the Cimatti field to
capitalise on the continued increased price premium for low
sulphur fuel oil.
Woodside completed engineering studies to enable
additional production through increased water injection
without the need for large capital expenditure.
Woodside interest: 60%, operator
Okha FPSO
The Okha FPSO produces oil from the Cossack, Wanaea,
Lambert and Hermes fields.
Woodside successfully completed a series of significant
maintenance activities including a major turnaround and
a five-yearly survey to establish the technical condition of
the facility.
Woodside's share of annual production in 2021 was
1.5 MMboe, an increase from 1.4 MMboe in 2020 due to the
installation of a replacement subsea flowline increasing
production rates at the Okha FPSO by approximately
1,000 bbl/d.
Woodside interest: 33.33%, operator
—
Okha FPSO
Woodside Petroleum Ltd
37
EXPLORATION
2021 HIGHLIGHTS
2022 PLANNED ACTIVITIES
» Completed three offshore exploration wells in
» Continue to prioritise infrastructure-led activities
Myanmar in Q1 2021
» Completed ‘Ojingeo’ 3D marine seismic offshore
Republic of Korea in May 2021
» Senegal SNE North-2 appraisal well planning and
PSC licence extension
» Drill SNE North-2 well in Senegal
» Evaluate 3D seismic data from offshore Republic
of Korea to identify prospectivity close to the
Korean market
» Relinquish remaining interests in Myanmar
Woodside is focused on maturing exploration activities
near existing infrastructure, exiting low value licences and
planning for future exploration wells.
Australia
Interpretation of datasets focused primarily on exploration
opportunities in Western Australia close to existing
infrastructure. An infrastructure-led portfolio approach
during 2021 identified opportunities which are notionally
planned for the 2023-2024 period.
The Gemtree exploration prospect in permit WA-49-L has
received Environment Plan approval and is planned to be
drilled in 2023 for tie-back to Wheatstone infrastructure.
Additional subsurface studies facilitated Woodside’s bid
and award of WA-550-P gazettal permit, which provides
highly prospective tie-back options for Woodside’s Pluto
infrastructure.
A 2D seismic survey acquisition in NT-P86 offshore the
Northern Territory is targeted for 2022.
Global activities
A 3D seismic survey covering approximately 2,575km² was
successfully acquired in H1 2021 for Blocks 8 and 6-1N in
offshore the Republic of Korea. This data will support the
continued subsurface assessment and identification of
prospects.
Woodside progressed and approved the Senegal SNE
North-2 well location. This well targets both appraisal and
exploration oil intervals to enable tie-back into the under
construction Sangomar FPSO. The well is planned to be drilled
in the second half of 2022, in conjunction with the ongoing
Sangomar Field Development Phase 1 drilling campaign.
An extension to the RSSD Exploration Licence was supported.
38 Annual Report 2021
In March 2021 Woodside completed a three well exploration
campaign in Myanmar blocks A-7, AD-1 and AD-8. All three
wells were safely drilled, evaluated, and abandoned, and
while AD-8 and A-7 found hydrocarbons, none of the wells
were considered a commercial discovery.
Notice to terminate the Production Sharing Contract for
Myanmar Block A-7 was accepted by Myanma Oil and Gas
Enterprise on 23 November 2021. The effective date is
30 September 2021 with the formal relinquishment process
on-going.
On 27 January 2022 Woodside announced its decision to
withdraw from its interests in Myanmar.
Location of SNE North-2 offshore Senegal.
MARKETING, TRADING
AND SHIPPING
LNG portfolio
Woodside supplies LNG to major gas and electricity utilities,
trading houses and industrial buyers around the world. We
manage our LNG portfolio through a mix of short-, mid- and
long-term contracts, supplied by Woodside and cargoes
purchased from third parties. This combination of different
arrangements within our LNG portfolio enables operational
flexibility to capitalise on changing market conditions as
they occur. In 2021 Woodside supplied 8.6 million tonnes of
LNG from both produced volumes and purchased Corpus
Christi volumes.
Our trading and optimisation activity significantly increased
in 2021 reaching its highest level, driven by favourable
commodity price levels and volatile market conditions.
Our LNG portfolio approach enables sales commitments
to be met from produced and purchased offtake, allowing
optimisation of both our portfolio offtake and our shipping
fleet to maximise value. Portfolio optimisation activities
include the purchase and on-sale of third-party cargoes to
extract additional value, which has enabled Woodside to
increase exposure to gas hub indices at higher price levels.
Gas hub exposure is the proportion of produced equity
LNG volumes expected to be sold on gas hub indices such
as JKM, TTF and UK National Balancing Point. Henry Hub
is excluded from the calculation. In 2021 our produced LNG
sold on gas hub indices was approximately 16% and we
expect approximately 20-25% of our produced LNG to be
sold on gas hub indices in 2022.
Liquids marketing
Woodside has built its liquids marketing capability to
optimise value from its oil portfolio. The marketing of crude,
condensate and LPG is based on short-term sales, and may
be supplemented by term arrangements.
Woodside achieved record premiums to Dated Brent for
three cargoes in 2021; a Vincent crude cargo produced
from the Ngujima-Yin FPSO, which targeted low sulphur
fuel oil blenders as opposed to traditional refineries,
and two Wheatstone condensate cargoes resulting from
strengthening regional condensate demand.
—
Karratha Gas Plant
Woodside Petroleum Ltd 39
Growth
The long-term sale and purchase agreement executed in
January 2021 with Uniper Global Commodities included an
approved Scarborough FID condition which was satisfied in
November 2021. The Scarborough FID also provides a strong
foundation to undertake future mid-term and long-term LNG
sales, targeting traditional and growth markets principally in
the Asia region.
Woodside signed a memorandum of understanding with
Viva Energy to progress discussions on capacity usage
at Viva Energy’s proposed LNG regasification terminal in
Geelong, Australia, potentially enabling Woodside to supply
LNG to the east coast Australia market.
Woodside signed a non-binding heads of agreement with
Commonwealth LNG, to negotiate a sale and purchase
agreement for the supply of LNG from the proposed
Commonwealth LNG development in Cameron, Louisiana.
Woodside executed joint venture agreements with the
RSSD joint venture participants to enable the lifting and
marketing of oil production from the Sangomar Field
Development Phase 1.
Domestic gas
Woodside continues to meet customer requirements
for domestic gas through a mix of short-, mid- and long-
term contracts.
Our domestic gas sources include the NWS Project, Pluto
LNG and Wheatstone. Our portfolio sales approach enables
us to develop our base of customers and trading capabilities.
Woodside and joint venture participant EDL LNG Fuel to
Power executed three sale and purchase agreements (SPA)
for the supply of domestic LNG from the Pluto LNG truck
loading facility for a period of five to ten years. Woodside is
continuing discussions with various mining companies for
the potential delivery of LNG to their mine sites.
Integrated shipping and operations
Woodside has a proven track record across integrated
shipping, operations, marketing and trading which delivered
308 LNG, condensate, crude and LPG cargoes with
Woodside equity interest in 2021.
Woodside maintains an LNG shipping fleet of six vessels
under long-term contracts, and one vessel on short-term
charter. Control of shipping capacity protects value from
producing assets, ensures reliable cargo delivery to meet
contractual sales arrangements and enables portfolio and
shipping optimisation.
Woodside actively engaged with customers on inclusion
of carbon offsets as part of structuring sales transactions,
building its carbon offset marketing capability and supporting
the decarbonisation goals of our customers. In March 2021,
Woodside and the Pluto LNG joint venture participants sold
their first carbon offset condensate cargo to Trafigura Pte Ltd.
In November 2021, Woodside sold its first carbon offset LNG
cargo to Uniper Global Commodities SE, and its first carbon
offset LPG cargo to Vitol Asia Pte Ltd.1
1 The term “carbon offset” indicates that the seller and the buyer have committed to reduce or offset the amount of carbon dioxide equivalent associated with their respective operated
emissions (including the extraction, processing, storage, and shipping) through a combination of demonstrated emissions reductions and carbon offsets certified by Verra or Gold Standard.
—
LNG jetty, Karratha Gas Plant.
40 Annual Report 2021
DEVELOPMENT
SCARBOROUGH
AND PLUTO TRAIN 2
2021 HIGHLIGHTS
2022 PLANNED ACTIVITIES
» Approved final investment decisions in
» Commence site civil works and module
November 2021
fabrication for Pluto Train 2
» Executed commercial agreements to enable
processing of Scarborough gas at the
Pluto LNG site
» Progress Scarborough engineering, procurement
and manufacturing activities across all major
contracts
» Agreed sell-down of a 49% non-operating
» Commence fabrication yard activities for the
interest in Pluto Train 2 to Global Infrastructure
Partners (GIP)1
floating production unit
» Complete front-end engineering design (FEED)
» Issued full notice to proceed to Scarborough
for Pluto Train 1 modifications
contractors
» Target sell-down of Scarborough offshore resource
Final investment decisions were approved for the Scarborough and Pluto
Train 2 projects, including the construction of new domestic gas facilities.
The Scarborough field is located approximately 375 km off
the coast of Western Australia and is estimated to contain
11.1 trillion cubic feet (100%) of dry gas. Development
of Scarborough will include the installation of a floating
production unit with eight wells drilled in the initial phase
and thirteen wells drilled over the life of the Scarborough
field. The gas will be transported to the existing Pluto LNG
facility through a new approximately 430 km trunkline.
Expansion of Pluto LNG will include the construction of a
second LNG train, associated domestic gas processing facilities,
supporting infrastructure and modifications to Pluto Train 1 to
allow it to process Scarborough gas. The composition of gas
from the Scarborough field is well suited to Pluto LNG which
is designed for lean gas and nitrogen removal. An area for a
second train was pre-prepared when the foundation project
was built, with minimal earthworks required for Pluto Train 2.
During 2021, Woodside completed key activities to support
the final investment decisions. This included entering into
a sale and purchase agreement with Global Infrastructure
Partners (GIP) for the sale of a 49% non-operating
participating interest in the Pluto Train 2 Joint Venture. The
transaction included a number of other related agreements
between Woodside and GIP, including a project commitment
agreement. The transaction completed on 18 January 2022.
Woodside is continuing the sell-down process for
Scarborough, targeting an operating equity interest of 51% or
greater in the Scarborough Joint Venture.
Woodside continues to work with Traditional Custodians
to identify, manage and protect heritage. In 2021
an independent ethnographic assessment found no
ethnographic sites within the proposed Scarborough
development area. This, coupled with an archaeological
assessment that did not find any prospective submerged
archaeological locations likely to be impacted by the project,
supports there being a nil to low likelihood of submerged
heritage in the development area.
All key primary environmental approvals to support the
final investment decisions are in place, with secondary
environmental approvals progressing to support project
execution activities.
Woodside’s Pluto Greenhouse Gas Abatement Program
(GGAP) was approved by the Western Australian Minister
for Environment. The GGAP includes interim and long-term
1 This transaction completed in January 2022.
42 Annual Report 2021
—
Illustration of the approved
Scarborough and Pluto Train 2
projects at the existing Pluto LNG
onshore facility
targets to achieve a 30% emissions reduction from approved
levels by 2030 and net zero by 2050 across the entire
project.1 The targets incorporate emissions associated with
Pluto Train 2.
Woodside was also granted environmental approval of the
State waters (nearshore) component for the Scarborough
project by the Western Australian Minister for
Environment. This is the primary environmental approval
required for activities in State waters. It authorises the
installation of an approximately 32 km section of the
Scarborough trunkline within State waters, together with
associated activities required to construct the trunkline.
Bechtel has proven Australian LNG project experience and
has been selected as the EPC contractor for Pluto Train 2 and
integration into the existing Pluto LNG facilities. Woodside
issued a limited notice to proceed to Bechtel in October
2021, enabling Bechtel to progress engineering, and order
materials and equipment for Pluto Train 2 and commence
early works for construction of the accommodation village
in Karratha. Bechtel was issued full notice to proceed in
January 2022.
Concept definition studies were completed in Q4 2021 for
modifications to Pluto Train 1 to enable processing of up to
3 Mtpa of Scarborough gas. Front-end engineering design
commenced in Q1 2022 and is expected to be completed in
the second half of 2022.
Woodside has engaged a range of specialist contractors
in the offshore, subsea and pipelines sectors to deliver the
Scarborough project and has secured access to the Valaris
DPS-1 mobile offshore drilling unit to undertake drilling of
the initial eight wells. The detailed design activities are well
progressed and in Q4 2021 the project took delivery of five
subsea production trees which will be stored and preserved
in readiness for drilling operations in 2023.
Woodside has commitments in place with our contractors
to deliver skills development and training, employment,
contracting and Indigenous participation during the four-
year construction phase.
The Scarborough Field Development Plan and pipeline licence
applications were submitted to regulators and are currently
under assessment. Retention lease renewals in respect of
the WA-61-R and WA-63-R titles for the Jupiter and Thebe
fields respectively were granted by the Commonwealth and
Western Australian Joint Authority.
Woodside is targeting the first LNG cargo in 2026.
Woodside interest: 73.5%, operator (Scarborough);
51%, operator (Pluto Train 2)2
1 Pluto LNG Development Public Environmental Review (2006) emissions estimate of 4.1 Mtpa CO2-e for two LNG trains.
2 Following sell-down of a 49% non-operating participating interest to GIP which completed on 18 January 2022.
Woodside Petroleum Ltd 43
PLUTO-KGP
INTERCONNECTOR
The Pluto-KGP Interconnector will allow the transfer of gas between Pluto LNG
and the NWS Project’s Karratha Gas Plant to optimise production across both
facilities, enabling accelerated production of Pluto gas reserves as well as
third-party resources.
Gas from Pluto will be processed using new equipment at
Pluto LNG before being transported by the 3.2 km, 30-inch
pipeline to Karratha Gas Plant (KGP). The pipeline has been
constructed within the existing Dampier to Bunbury Natural
Gas Pipeline corridor.
In January 2021, domestic gas arrangements with the
Western Australian Government were finalised to allow
Woodside to supply Pluto gas through the Interconnector
pipeline, for processing at KGP.
Throughout the year, construction activities progressed for
the processing facilities and piping at Pluto LNG and KGP.
The primary module of the Interconnector project, fabricated
and supplied by a Western Australian based contractor was
installed at Pluto LNG in Q3 2021.
The pipeline construction between Pluto LNG and KGP was
completed in Q4 2021. Traditional Custodians were consulted
and engaged during clearing and other key activities to
ensure culturally significant areas were clearly demarcated
and avoided, and pipeline construction activities were
undertaken in a culturally appropriate manner.
Commissioning activities are underway and Woodside is
targeting ready for start-up in Q1 2022.
Woodside interest: 100%
—
Pluto-KGP Interconnector
under construction
44 Annual Report 2021
SANGOMAR FIELD
DEVELOPMENT
2021 HIGHLIGHTS
2022 PLANNED ACTIVITIES
» Drilled and completed the first development well
» Commence subsea installation
» Commenced FPSO conversion activities
» Arrival of second drillship in Senegal
» Progressed subsea infrastructure fabrication
» Progress FPSO conversion activities
The Sangomar Field Development Phase 1 is Senegal’s first oil project
and is on track for first oil in 2023.
Phase 1 is developing the less complex reservoirs in the
Sangomar field and testing other reservoirs to support
potential future phases. This phase of the development
targets production of an estimated 231 million barrels of oil
resources (100%) with 2P Reserves of 149 MMbbl Woodside
economic share. Oil will be produced through a stand-alone
floating production storage and offloading (FPSO) facility
with supporting subsea infrastructure. It is designed to allow
the tie-in of subsequent phases.
In February 2021, the VLCC oil tanker arrived at a shipyard in
China and FPSO conversion activities commenced. The FPSO
will be named FPSO Léopold Sédar Senghor, after the first
President of the Republic of Senegal. The FPSO conversion
activities continued throughout the year, with construction
work scopes for the turret, mooring system and topside
modules progressing. The conversion remains on schedule.
In July 2021, the Ocean BlackRhino drillship arrived in Senegal
and subsequently the first development well was drilled and
completed, including installation of the xmas tree. It was
the first horizontal production well to be drilled in Senegal.
Overall, the drilling campaign will include up to 23 production,
gas and water injections wells and will be undertaken using
two drill ships using a batch drilling approach.
Subsea equipment fabrication is on schedule across multiple
international locations and equipment continues to arrive
in Senegal, including wellhead systems and xmas trees.
Preparation activities are ongoing for the subsea installation
campaign, expected to commence in 2022.
Woodside is working with the Government of Senegal to
develop local capabilities, support training initiatives, offer
employment opportunities and organise capacity building
sessions with Senegalese administrations.
Woodside has local content commitments with our key
contractors to ensure opportunities are maximised for
Senegalese people and suppliers. In 2021, Woodside awarded
contracts to Senegalese local businesses for major services
to support in-country development activities.
In 2021 Woodside Energy (Senegal) B.V. completed the
acquisition of the entire participating interest of FAR Senegal
RSSD S.A. in the Rufisque Offshore, Sangomar Offshore and
Sangomar Deep Offshore (RSSD) joint venture. Woodside’s
participating interest increased to 82% for the Sangomar
exploitation area (with Petrosen's participating interest
18%) and 90% for the remaining RSSD evaluation area (with
Petrosen's participating interest 10%).
Woodside commenced engagement with interested parties
to sell down its participating interest in the RSSD joint
venture to a targeted 40-50%.
Woodside interest: 82%, operator
Woodside Petroleum Ltd 45
BROWSE
SUNRISE
The Sunrise development comprises the Sunrise and
Troubadour gas and condensate fields. The fields contain an
estimated contingent resource (2C) of 1.7 Tcf of dry gas and
76 MMbbl of condensate Woodside share (5.1 Tcf of dry gas
and 226 MMbbl of condensate, 100%).
The Sunrise Joint Venture participants continue to engage
the Australian and Timor-Leste Governments on a new
Greater Sunrise Production Sharing Contract (PSC), which is
required under the 2019 Maritime Boundary Treaty.
Woodside is meeting its relevant title commitments (JPDA
03-19 and JPDA 03-20 and Retention Lease NT/ RL2 and NT/
RL4) and maintains a social investment program.
Woodside interest: 33.44%, operator
CANADA
In 2021 Woodside announced its decision to exit its 50% non-
operated participating interest in the proposed Kitimat LNG
(KLNG) development, located in British Columbia, Canada.
Exit activities progressed as planned with commercial
agreement terminations, lease relinquishments and
remediation planning well underway. The sale of the Pacific
Trail Pipeline route to Enbridge Inc. was completed in
December 2021.
Woodside is retaining an upstream position in the Liard
Basin by assuming full equity in 28 non-infrastructure
related Liard Basin leases from Chevron Canada, to study
low-cost natural gas, ammonia and hydrogen opportunities
in Canada. More information is available in the Reserves and
resources statement on page 55.
The Browse Joint Venture (BJV) is proposing to develop the
Brecknock, Calliance and Torosa fields located approximately
425 km north of Broome in the offshore Browse basin. The
Browse resource contains an estimated contingent resource
(2C) of 4.3 Tcf of dry gas and 119 MMbbl of condensate
Woodside share (13.9 Tcf of dry gas and 390 MMbbl of
condensate, 100%).
Activities during 2021 focused on key commercial, regulatory
and technical work streams to enable greater certainty
for the development to progress towards FEED entry. This
included recommencing commercial discussions and joint
technical studies with the North West Shelf Project regarding
an agreement to process Browse gas at KGP.
Woodside continues to work with both Commonwealth and
State regulators and engage relevant stakeholders to finalise
the supplement to the proposed Browse to NWS Project
Draft Environmental Impact Statement (EIS) and Response to
Submissions on the Environmental Review Document (ERD).
The BJV is evaluating a range of options to manage
greenhouse gas emissions and is progressing a feasibility
assessment for a carbon capture and storage solution and
opportunities to improve energy efficiency.
Applications for production licences for the Calliance and
Torosa Fields and a retention lease renewal in relation to
Brecknock were submitted in April 2020. Commonwealth
and State title regulators are continuing their assessment of
these applications.
Woodside interest: 30.6%, operator
MYANMAR
Following the State of Emergency declared on 1 February
2021, Woodside placed all business decisions under
continuous review.
Woodside announced its decision to withdraw from its
interests in Myanmar on 27 January 2022.
46 Annual Report 2021
CORPORATE
CLIMATE CHANGE
Woodside aims to thrive through the energy transition by building a low-cost,
lower-carbon, profitable, resilient and diversified portfolio. Our climate strategy
is an integral part of our company strategy. It has two key elements: reducing our
net equity Scope 1 and 2 greenhouse gas emissions, and investing in the products
and services that our customers need as they reduce their emissions.
Our Climate Report includes a detailed description of
Woodside's approach to climate change. This Annual Report
should be read in conjunction with Woodside's Climate
Report 2021 and the Sustainable Development Report 2021.
In 2021, Woodside’s net equity Scope 1 and 2 greenhouse gas
emissions were 3,235 kt CO2-e, 10% below the 2016-2020
gross annual average and is on track to achieve Woodside’s
target of a 15% reduction by 2025.
We plan to achieve this by avoiding emissions in the way
we design our facilities, reducing emissions in the way we
operate our facilities and offsetting the remainder.
Woodside is focused on reducing methane emissions and is a
signatory to the Methane Guiding Principles.
Woodside has also published its approach to Scope 3
greenhouse gas emissions. This includes a new investment
target of $5 billion by 2030 in new energy products and
lower-carbon services which are expected to support
customer and supplier emissions reduction, together with
promoting global emissions measurement and reporting.1
Woodside's climate reporting has been structured to align
with the Task Force on Climate-related Financial Disclosures
(TCFD) recommendations framework, and is a supporter of
TCFD. This year we have issued a separate Climate Report
and will put it to a non-binding, advisory shareholder vote at
our 2022 Annual General Meeting.
THE CLIMATE REPORT DESCRIBES OUR:
STRATEGY
including emissions reduction
plans and portfolio scenario
analysis
TARGETS AND METRICS
including our progress against
emissions reduction objectives
GOVERNANCE
RISK MANAGEMENT
including the respective roles of
Board and Management
including short-, medium- and
long-term risks and opportunities
1 Investment target assumes completion of the proposed merger with BHP’s petroleum business. Individual investment decisions are subject to Woodside’s investment hurdles. Not guidance.
48 Annual Report 2021
NEW ENERGY
Woodside's strategy is to invest in the new energy products and the lower-
carbon services our customers need as they decarbonise. We are progressing
opportunities for producing products such as hydrogen and ammonia.
In 2021, we made significant progress by securing land for
three proposed projects:
• H2Perth, a world-scale liquid hydrogen and ammonia
production facility to be located on 130 hectares of
industrial land in southern metropolitan Perth
• H2TAS, a 100% renewable ammonia project to be located
in Tasmania’s Bell Bay region, allowing expansion of the
previous concept to export scale while also providing
local supply
• H2OK, a 290 MW liquid hydrogen project in the
Westport Industrial Park, Ardmore, Oklahoma. Front-end
engineering design has commenced.
A key component of this strategy is to work with potential
customers to develop demand for new sources of energy.
Customer collaboration highlights in 2021 include:
• A new export project consortium with Japan’s IHI
Corporation and Marubeni Corporation in connection
with H2TAS
• A joint feasibility study to establish a clean fuel ammonia
supply chain from Australia to Japan with Japan Oil, Gas
and Metals National Corporation, Marubeni Corporation,
Hokuriku Electric Power Company and The Kansai Electric
Power Co., Inc.
• Forming the HyStation company alongside five other
parties in September 2021 to drive hydrogen bus adoption
in the Republic of Korea
• Agreeing a memorandum of understanding (MOU)
with Hyzon Motor Company to explore collaboration
opportunities in the US and Australia
• Agreeing a MOU with Keppel Data Centres, City Energy,
Osaka Gas Singapore and City-OG Gas Energy Services
to study the feasibility of a liquid hydrogen supply chain
to Singapore and potentially Japan from Woodside’s
proposed H2Perth project.
Our new energy technology focus is on hydrogen
production, renewables and carbon management. In
October 2021 we announced a collaboration with Heliogen,
Inc. including a proposed commercial-scale pilot facility
in California. Heliogen is a leading provider of artificial
intelligence enabled concentrated solar technology.
Woodside is also progressing the Woodside Solar Project,
a proposed solar facility that could supply 100 MW of solar
energy to Pluto LNG and other customers located near
Karratha in Western Australia, with potential expansion to a
maximum of 500 MW.
Woodside announced plans in November 2021 to target
$5 billion investment by 2030 in new energy products and
lower-carbon services.1
Refer to the capital allocation framework on page 26 for
investment criteria.
1 Investment target assumes completion of the proposed merger with BHP’s petroleum business. Individual investment decisions are subject to Woodside’s investment hurdles. Not guidance.
Illustration of the proposed hydrogen project H2OK in Oklahoma, North America.
Woodside Petroleum Ltd 49
CARBON
Woodside has built a portfolio of offsets and carbon origination projects
sufficient to meet our net equity Scope 1 and 2 greenhouse gas emissions
reduction target of 15% by 2025.1
Woodside established a carbon business in 2018 to develop
a sustainable offset portfolio in support of our base business
and new energy projects. We acquire offsets on carbon
markets and also originate our own, managing them on
a portfolio basis to optimise the cost of meeting both
regulatory and corporate targets.2
This approach is intended to manage the risk of future
changes in the costs, availability and regulatory framework
for offsets, by developing a diverse portfolio differentiated
by vintage, methodology and geography.
We retire offsets annually to meet our emissions
reduction targets. Further details can be found in our
Climate Report 2021.
Woodside has a program aimed at utilising land in Western
Australia for biodiverse carbon plantings.
The Woodside Native Reforestation Project planted
3,000 hectares in Western Australia across 2020 and 2021,
which is estimated to sequester about 700,000 tonnes of
CO2-e over 25 years. In 2021, we purchased two properties
in the Wheatbelt region of Western Australia, with planting
targeted for 2022.
Woodside entered into an agreement with the Northern
Territory Government, Commonwealth Scientific and
Industrial Research Organisation and industry to develop
a business case assessing the viability of a large-scale, low
emission carbon capture utilisation and storage hub based in
the Northern Territory. The hub has the potential to reduce
emissions, acting as a catalyst to new net zero industries that
can continue throughout the energy transition.
In November, Woodside, bp and Japan Australia LNG (MIMI)
Pty Ltd agreed to form a consortium to progress feasibility
studies for a large-scale, multi-user carbon capture and
storage (CCS) project near Karratha in Western Australia.
The consortium will assess the technical, regulatory and
commercial feasibility of capturing carbon emitted by
multiple industries located near Karratha and storing it
in offshore reservoirs in the Northern Carnarvon Basin.
The study represents an important step towards the
development of one of Australia’s first multi-user CCS
projects, ideally located to aggregate emissions from
various existing sources.
1 Target is for net equity Scope 1 and 2 greenhouse gas emissions, relative to a starting base of the gross annual average equity Scope 1 and 2 greenhouse gas emissions over 2016-2020 and
may be adjusted (up or down) for potential equity changes in producing or sanctioned assets with an FID prior to 2021. Post-completion of the Woodside and BHP petroleum merger (which
remains subject to conditions including regulatory approvals), the starting base will be adjusted for the then combined Woodside and BHP petroleum portfolio. Assumes equity Scope 1 and 2
greenhouse gas emissions are as currently forecast in Woodside's business plan.
2 Further information on the cost of offsets is available in our Climate Report 2021.
50 Annual Report 2021
—
Tree planting site at near Cranbrook,
Great Southern region, Western Australia
RISK
Our approach to risk management enables us to take risk for reward, protects
against negative impacts and improves our resilience to emerging risks.
Woodside recognises that risk is inherent in our business
and the effective management of risk is vital to deliver our
strategic objectives, continued growth and success. We are
committed to managing risks in a proactive and effective
manner as a source of competitive advantage.
We apply a structured and comprehensive approach to the
identification, assessment and treatment of current risks
and in response to emerging risks. Our risk management
framework provides a single consolidated view of risks
across the company to quantify our full risk exposure and
prioritise risk management and governance.
The framework is aligned with the intent of the International
Standard ISO31000 for risk management, providing line
of sight of risk at appropriate levels of the organisation,
including the executive team and the Board, based on
defined materiality thresholds. Our assessment of risk
considers both financial and non-financial exposures,
including health and safety, environment, finance, reputation
and brand, legal and compliance, social and culture.
A twice yearly review by the executive team and the Board
evaluates the strategic risk profile, and the effectiveness of
material current risks being managed across the business.
Uncertainty in the external environment has increased
in 2021 such as growing geopolitical concerns and
nationalism, increasing sophistication and frequency of
cyber and digital related attacks, continuing global and
domestic impacts of the COVID-19 pandemic, and higher
and evolving societal and stakeholder expectations
(notably on environmental, social and governance (ESG)
topics). We continually monitor external signals to ensure
we are able to adapt our strategies, or review and improve
the controls we rely on, to effectively and efficiently
manage our exposure to risk.
Refer to Woodside’s Corporate Governance Statement
for more information (woodside.com.au/about-us/
corporate-governance).
The Board reviewed and confirmed in 2021 that the risk
management framework is sound, and that Woodside is
operating with due regard to the risk appetite endorsed by
the Board.
Social Licence to Operate
Stakeholders have higher and evolving expectations
of Woodside’s social responsibility, with a focus on
transparency and ethical decision making. In 2021 the release
of ‘Our Risk and Compliance Behaviours’ framework helped
our leaders at all levels of the organisation, by reinforcing the
positive behaviours and actions to influence decision making,
realise opportunity and support sustainable long-term
performance consistent with our Vision and Compass values.
Refer to our Sustainable Development Report 2021 for
more information on ESG.
Climate Change
Climate change and the transition to a lower-carbon
economy influences Woodside’s strategy, presenting both
risk and opportunity in the operation of our existing assets or
commercialisation of our growth portfolio.
We leverage our risk management framework to ensure an
integrated and coordinated approach to the management of
climate change across the business. The risks posed by the
transition to a lower-carbon economy are recognised given
changes in policy, regulation or social expectations in current
or future markets.
Refer to our Climate Report 2021 for more information.
Woodside Petroleum Ltd
51
Overview of our strategic and material risks
TITLE
CONTEXT
RISK
MITIGATION
Climate
change
Climate change is impacting
the way that the world
produces and consumes
energy, and this is expected
to accelerate over time.
Climate change also requires
adaptation to physical
change.
Social
licence to
operate
Our business performance
is underpinned by our
social licence to operate,
which requires compliance
with legislation and the
maintenance of a high level of
ethical behaviour and social
responsibility.
Our business activities
are subject to extensive
regulation and government
policy in each of the
countries where we do
business. Failure to comply
may impact our licence to
operate.
Stakeholders have evolving
expectations of social
responsibility and ethical
decision making. These are
changing at a rate faster than
governments can introduce or
amend regulation.
This will impact the transition to a
lower-carbon economy and may
impact demand (and pricing) for
oil, gas and its substitutes, the
policy and legal environment for
its production, our reputation,
and our operating environment.
Further, the availability and cost
of emission allowances or carbon
offsets could adversely impact
costs of operations.
Woodside contributes to solving climate change
challenges by supplying LNG, improving our energy
efficiency, focusing on reducing our emissions (and
potentially those of our customers or value chain
participants), and developing innovative new energy
technologies and markets for the efficient delivery of
lower-carbon energy to grow a longer-term resilient
portfolio.
We have near- and mid-term emissions reduction targets
with plans to meet them.1 We engage and advocate
with key industry and governance stakeholders. Further
information is in our Climate Report 2021.
Failure to meet stakeholder
expectations can lead to
opposition and a decline in support
for both our base business and
future growth opportunities.
Woodside proactively maintains and builds our social
licence to operate through the application of our
Compass values, effective stakeholder engagement
strategies, our regulatory compliance framework and our
anti-fraud and corruption program.
A significant or continuous
departure from national or local
laws, regulations or approvals
may result in negative social
and cultural impacts, reputation
and brand, and loss of licence to
operate.
Violation of international anti-
bribery and corruption laws may
expose Woodside to fines, criminal
sanctions and civil suits, and
negatively impact our international
reputation.
Our regulatory compliance framework assists Woodside
to proactively maintain relationships with governments
and regulators within countries that support base
business and future growth opportunities.
Woodside maintains meaningful relationships with
stakeholders, seeking proactive engagement to inform
decisions and gain support for changes.
Our fraud and corruption framework aims to prevent,
detect and respond to unethical behaviour. It incorporates
policies, standards, guidelines and training to ensure
activities are conducted ethically and to a high standard.
Scarborough Scarborough extends the
economic life of Pluto LNG,
enables future tiebacks from
adjacent resources, and will
generate significant long-
term cashflow to underpin
Woodside’s future growth
strategy
Failure to commercialise and
deliver Scarborough could result
in a loss of shareholder value and
impact our growth strategy.
Growth
Growth opportunities can be
captured through exploration,
mergers, acquisitions or
expansions. Each may incur
risks that impact our ability to
realise the expected value.
The inability to identify
and commercialise growth
opportunities, or realise their
full value, may result in a loss of
shareholder value.
Failure to complete the merger
with BHP's petroleum business
may also result in a loss of
shareholder value.
We employ a number of measures to ensure Scarborough
is delivered to the approved business case including:
• Effectively managing execution contractors ensuring
they deliver to or better than promised
• Securing execution-related environmental and
regulatory approvals and ensuring compliance through
execution and operations
• Continue to pursue funding opportunities such as the
equity sell down of Scarborough
• Delivering safe and reliable operations that meet
production commitments.
See pages 42-43 for more information on the
Scarborough project.
Our opportunity management framework is flexible and
adaptable with the primary objective to realise the value
of an opportunity while mitigating the risk of a sub-
optimal outcome.
We aim to identify and progress a suite of commercially
attractive and sustainable opportunities that complement
our existing assets, enable portfolio diversity and optimise
our commercial position.
We continue to monitor and assess growth opportunities
through mergers and acquisitions on a case-by-case basis.
1 Target is for net equity Scope 1 and 2 greenhouse gas emissions, relative to a starting base of the gross annual average equity Scope 1 and 2 greenhouse gas emissions over 2016-2020 and
may be adjusted (up or down) for potential equity changes in producing or sanctioned assets with an FID prior to 2021. Post-completion of the Woodside and BHP petroleum merger (which
remains subject to conditions including regulatory approvals), the starting base will be adjusted for the then combined Woodside and BHP petroleum portfolio.
52 Annual Report 2021
TITLE
CONTEXT
RISK
MITIGATION
Operations
Maintaining the technical
integrity and operational
performance of our assets is
essential to protecting our
people, the environment, our
licence to operate and the
financial capacity to support
existing business and growth
opportunities.
Finance
Woodside’s financial
performance and resilience
may be impacted by key
factors such as:
• Disruption in market
dynamics
• Ability to maintain
competitive advantage
• Access to capital
• Management of financial
risks
Safe operation is fundamentally embedded through
an extensive framework of controls that deliver strong
operational performance in our base business. We have a
track record of operating discipline and excellence.
The framework includes production processes, drilling
and completions and well integrity management
processes, inspection and maintenance procedures and
performance standards. The framework is supported and
inspected on an ongoing basis by our regulators.
Decommissioning is integrated into project planning. We
work with our partners and technical experts to identify
sustainable and beneficial post-closure options that
minimise financial, social and environmental impacts.
The framework is adaptable to ensure we are able
to maintain and improve our operating model and
performance, target reliability, cost discipline, emissions
reductions and strong safety and environmental
performance for both our existing business and future
growth opportunities.
The delivery of our strategic portfolio objectives requires
significant capital expenditure, supported by strong
underlying cashflows.
• Uncertainty associated with product demand is
mitigated by selling LNG in a portfolio manner and
under long-term ‘take or pay’ sale agreements,
in addition to the spot market. Our low-cost of
production and prudent approach to balance sheet risk
management further mitigates this exposure.
• A flexible approach to capital management enables
this overall level of investment in the different areas
of our business and the mix to be adjusted to reflect
the external environment. Our capital management
strategy focuses on capital allocation, capital discipline
and efficiency, and active balance sheet management
including commodity and foreign exchange hedging.
• We maintain insurance in line with industry practice
and sufficient to cover normal operational risks.
However, Woodside is not insured against all potential
risks because not all risks can be insured and because
of constraints on the availability of commercial
insurance in global markets.
Insurance coverage is determined by the availability of
commercial options and cost/benefit analysis, taking
into account Woodside’s risk management program.
Losses that are not insured could impact Woodside’s
financial performance. For example, Woodside does
not purchase insurance for the loss of revenue arising
from an operational interruption. Our extensive
framework of financial controls, including monitoring of
counterparties, enables the management of these risks.
• The US dollar reflects the majority of Woodside’s
underlying cashflows and is used in our financial
reporting, reducing our exposure to currency
fluctuations.
Failure to deliver safe, reliable
and efficient operations could
result in a sustained, unplanned
interruption to production, and
a failure to meet production
forecasts, deliver base business
and provide revenue to support
growth.
Our operating assets are subject
to operating hazards associated
with major accident events, cyber
attacks, extreme weather events
and disruptions within global
supply chains that may ultimately
lead to a loss of hydrocarbon
containment or additional costs.
An inability to fund the delivery of
strategic portfolio objectives could
prevent Woodside from unlocking
value, weaken financial resilience
and result in a loss of shareholder
value. Risk factors include:
• Commodity prices are variable
and are impacted by global
economic factors beyond
Woodside’s control.
• Demand for and pricing of our
products remain sensitive to
external economic and political
factors, weather, natural
disasters, introduction of new
and competing supply, changes
in buyer preferences for differing
products and price regimes.
• We are exposed to treasury and
financial risks, including liquidity,
changes in interest rates,
fluctuations in foreign exchange
rates and credit risk.
• Insufficient liquidity to meet
financial commitments and fund
growth opportunities could
have a material adverse effect
on our operations and financial
performance.
• Our financing costs could
be affected by interest rate
fluctuations or deterioration in
our long-term investment grade
credit rating.
• We are exposed to credit risk;
our counterparties could fail
or could be unable to meet
their payment or performance
obligations under contractual
arrangements.
Woodside Petroleum Ltd
53
TITLE
CONTEXT
RISK
MITIGATION
People and
culture
Innovation
Digital and
cybersecurity
Woodside must maintain
sufficient talent, capability
and capacity and a strong
organisational culture.
An engaged and enabled
workforce underpins our
ability to deliver base
business, future growth and
new energy opportunities.
This may impact our
operating model and create
the need for a new or co-
existing culture at Woodside.
We focus on maintaining
our competitive advantage
by delivering value through
new ideas, technologies or
diversified products.
The practical application
of innovation delivers
near-term value to our base
business and in the longer
term, transforms and creates
opportunities to thrive in a
lower-carbon economy.
Woodside continues to invest
in and rely on sustainable and
secure digital technologies
to deliver a cost competitive
base business, to enhance
our growth opportunities and
pace of innovation.
Cyber risks continue to
evolve with greater levels of
sophistication.
Regulatory and compliance
obligations are increasing for
data protection and security
of critical infrastructure.
Failure to establish and maintain
sufficient workforce capability and
capacity may impact achievement
of our base business or future
growth objectives and inhibit new
energy opportunities
An ineffective operating model
could inhibit the energy transition
of our base business and new
energy opportunities.
Woodside has a set of resourcing frameworks to attract,
retain and develop our workforce to support both base
business and growth opportunities. We recognise and
value the benefits of creating an inclusive and diverse
working environment.
We employ a direct engagement model to maintain
effective employee and industrial relations. We
proactively engage our major contractors and suppliers
to strengthen alignment with expectations, securing
capability and pricing to meet future business needs.
Inability to deliver an
organisational model may
undermine value following
completion of the merger with
BHP's petroleum business.
Failure to build, embed, leverage
and support innovation may
result in a significant threat to
the competitive advantage of our
base business and our longer-term
sustainability.
In anticipation of the merger with BHP's petroleum
business we are reviewing our current and future
operating models to support both base business and
growth opportunities.
We drive the practical application of innovation through
an entrepreneurial, opportunity-focused, agile approach.
We seek and leverage world-class knowledge and
innovation communities, platforms and tools to reduce
unit costs for both our base business and future growth
opportunities.
We are creating a portfolio of new energy opportunities
to form new strategic relationships or capture market
in response to emerging trends, and disruptive and
complementary technologies.
Failure to safeguard the
confidentiality, integrity and
availability of digital data
and information. Woodside’s
technology systems may be
subject to both unintentional and
intentional disruption, for example
cybersecurity attack.
We are committed to the protection of our people, assets,
reputation and brand through securely enabled digital
technologies.
Digital risks are identified, assessed and managed based
on the business criticality of our people and systems, and
may be required to be segregated and isolated. Digital
risks include third parties, including suppliers and service
providers, within our supply chain.
Our operating model aims to continuously assess and
determine access permissions to critical information or
data, while consolidating, simplifying and automating
security controls.
Our exposure to cyber risk is managed by a control
framework that ensures cyber events are identified,
contained and recovered in a timely manner, and embeds
a cyber-safe culture across the company, with our joint
venture participants and in our supply chain.
54 Annual Report 2021
RESERVES AND
RESOURCES
Woodside delivered Reserves production of 93 MMboe in 2021.18 Approval of the Scarborough development contributed 1,433
MMboe of Proved plus Probable (2P) Undeveloped Reserves. Start-up of the Pyxis, Pluto North and Julimar-Brunello Phase 2
wells contributed Proved plus Probable (2P) Developed Reserves of 45 MMboe, 25 MMboe and 62 MMboe, respectively.
Increased equity interest in the Sangomar Field Development resulted in a net increase of 16 MMboe Proved (1P) Undeveloped
Reserves, 25 MMboe Proved plus Probable (2P) Undeveloped Reserves and 46 MMboe Best Estimate (2C) Contingent
Resources. Increased equity interest in the upstream Liard Basin contributed a net increase of 2,106 MMboe Best Estimate (2C)
Contingent Resources.
Completion of the Greater Pluto and Julimar-Brunello integrated subsurface studies resulted in updated reserves positions for
these regions. The Greater Pluto Proved (1P) Developed and Undeveloped Reserves and Proved plus Probable (2P) Developed
and Undeveloped Reserves decreased by 17 MMboe and 92 MMboe, respectively.34 Julimar-Brunello Proved (1P) Developed and
Undeveloped Reserves and Proved plus Probable (2P) Developed and Undeveloped Reserves decreased by 45 MMboe and
65 MMboe, respectively.34 These changes include 2021 net Reserves production of 46 MMboe for Greater Pluto and 13 MMboe
for Julimar-Brunello.18
Following Woodside’s decision to withdraw from its interests in Myanmar announced on 27 January 2022, the Best Estimate
Contingent Resources (2C) will no longer include 109.5 MMboe for the Myanmar region.
Table 1: Woodside's Reserves1,3,4,5 and Contingent Resources2 overview* (Woodside share, as at 31 December 2021)
Proved11 Developed13 and Undeveloped14
Proved Developed
Proved Undeveloped
Proved plus Probable12 Developed and Undeveloped
Proved plus Probable Developed
Proved plus Probable Undeveloped
Contingent Resources
* Small differences are due to rounding.
Table 2: Key Metrics
2021 reserves replacement ratio15
Organic 2021 reserves replacement ratio16
Three-year reserves replacement ratio
Organic three-year reserves replacement ratio
Reserves life17
Annual production18
Net acquisitions and divestments
Dry Gas6
Bcf8
Condensate7
MMbbl9
Oil
MMbbl
Total
MMboe10
8,090.7
1,952.9
6,137.8
11,669.4
2,634.9
9,034.6
34,768.0
44.8
33.5
11.3
60.2
45.4
14.8
230.1
128.1
30.0
98.0
184.2
35.5
148.7
269.7
1,592.3
406.1
1,186.2
2,291.7
543.1
1,748.5
6,599.4
Units
Proved
Proved plus
Probable
%
%
%
%
Years
MMboe
MMboe
1,044
1,027
336
314
17.1
92.9
16.0
1,446
1,419
467
434
24.7
92.9
24.9
Woodside Petroleum Ltd 55
1P Reserves
2P Reserves
2C Contingent Resources
2
9
5
,
1
2
9
2
2
,
5
1
9
1
7
8
4
1
7
8
0
5
,
1
2
4
4
,
1
4
3
3
,
1
e
o
b
M
M
8
3
2
,
1
3
1
2
,
1
1
4
0
,
1
e
o
b
M
M
9
9
5
6
,
9
7
9
5
,
5
2
9
5
,
7
1
5
2 5
1
0
5
,
,
4
1
0
8 5
9
3
4
,
,
1
1
0
,
1
0
5
1
,
1
0
8
0
,
1
e
o
b
M
M
2015 2016 2017 2018 2019 2020 2021
2015 2016 2017 2018 2019 2020 2021
2015 2016 2017 2018 2019 2020 2021
Table 3: Proved (1P) and Proved plus Probable (2P) Developed and Undeveloped Reserves annual reconciliation by product*
(Woodside share, as at 31 December 2021)
Dry Gas
Bcf
Condensate
MMbbl
Oil
MMbbl
Total
MMboe
)
P
1
(
d
e
v
o
r
P
)
P
2
(
e
l
b
a
b
o
r
P
l
s
u
p
d
e
v
o
r
P
Reserves at 31 December 2020
3,118.3
4,502.6
Revision of Previous Estimates19
-26.8
-520.2
Transfer to/from Reserves20
5,425.0
8,111.3
Extensions and Discoveries21
Acquisitions and Divestments22
9.8
-
11.3
-
Annual Production
-435.5
-435.5
)
P
1
(
d
e
v
o
r
P
51.1
1.6
-0.3
0.3
-
-7.9
)
P
2
(
e
l
b
a
b
o
r
P
l
s
u
p
d
e
v
o
r
P
)
P
1
(
d
e
v
o
r
P
)
P
2
(
e
l
b
a
b
o
r
P
l
s
u
p
d
e
v
o
r
P
)
P
1
(
d
e
v
o
r
P
)
P
2
(
e
l
b
a
b
o
r
P
l
s
u
p
d
e
v
o
r
P
72.9
116.3
177.8
714.5
1,040.6
-4.5
-0.7
0.4
-
-7.9
4.4
-9.9
1.3
-105.6
-
-
16.0
-8.6
-
-
24.9
-8.6
951.4
1,422.4
2.0
16.0
2.3
24.9
-92.9
-92.9
Reserves at 31 December 2021
8,090.7
11,669.4
44.8
60.2
128.1
184.2
1,592.3
2,291.7
* Small differences are due to rounding.
Table 4: Best Estimate Contingent Resources (2C) annual reconciliation by product*
(Woodside share, as at 31 December 2021)
Contingent Resources at 31 December 2020
Revision of Previous Estimates
Transfer to/from Reserves
Extensions and Discoveries
Acquisitions and Divestments
Dry Gas
Bcf
Condensate
MMbbl
31,113.5
-160.1
-8,230.1
-
12,044.6
231.4
-0.6
-0.7
-
-
Oil
MMbbl
234.9
-4.7
-
-
Total
MMboe
5,924.8
-33.4
-1,444.6
-
39.4
2,152.5
Contingent Resources at 31 December 2021
34,768.0
230.1
269.7
6,599.4
* Small differences are due to rounding.
56 Annual Report 2021
Table 5: Best Estimate Contingent Resources (2C) summary by region* (Woodside share, as at 31 December 2021)
Greater Browse29
Greater Sunrise31
Greater Pluto24
Greater Exmouth26
North West Shelf25
Julimar-Brunello27
Canada33
Senegal28
Greater Scarborough30
Myanmar32
Total
* Small differences are due to rounding.
Dry Gas
Bcf
Condensate
MMbbl
Oil
MMbbl
Total
MMboe
4,257.8
1,716.8
1,116.5
307.4
282.4
37.4
25,373.3
232.2
820.2
624.0
119.4
75.6
22.5
2.2
9.7
0.7
-
-
-
-
-
-
-
26.7
11.7
-
-
231.2
-
-
866.4
376.7
218.3
82.9
71.0
7.3
4,451.5
271.9
143.9
109.5
34,768.0
230.1
269.7
6,599.4
1P Reserves by region
(Developed and Undeveloped)
2P Reserves by region
(Developed and Undeveloped)
2C Contingent Resource
by region
I,592
MMboe
2,292
MMboe
6,599
MMboe
Greater Pluto
North West Shelf
Greater Exmouth
Julimar-Brunello
Senegal
%
17%
9%
1%
7%
6%
Greater Pluto
North West Shelf
Greater Exmouth
Julimar-Brunello
Senegal
Greater Scarborough
60%
Greater Scarborough
%
15%
7%
1%
7%
6%
63%
Greater Pluto
North West Shelf
Greater Exmouth
Julimar-Brunello*
Senegal
Greater Scarborough
Greater Browse
Greater Sunrise
Canada
Myanmar
%
3%
1%
1%
0.1%
4%
2%
13%
6%
67%
2%
* Small differences are due to rounding.
Woodside Petroleum Ltd
57
Table 6: Proved (1P) Developed and Undeveloped23 Reserves by region*
Dry Gas
Bcf
Condensate
MMbbl
Oil
MMbbl
Total
MMboe
d
e
p
o
e
v
e
D
l
l
d
e
p
o
e
v
e
d
n
U
l
a
t
o
T
Greater Pluto24
1,123.1
309.2
1,432.3
North West Shelf25
550.5
Greater Exmouth26
-
91.1
-
641.6
-
Julimar-Brunello27
279.3
284.7
564.0
Senegal28
Greater Scarborough30
-
-
-
-
5,452.8
5,452.8
d
e
p
o
e
v
e
D
l
15.8
12.3
-
5.4
-
-
l
d
e
p
o
e
v
e
d
n
U
4.0
2.1
-
5.3
-
-
d
e
p
o
e
v
e
D
l
-
8.4
21.6
-
-
-
l
d
e
p
o
e
v
e
d
n
U
-
-
-
-
l
a
t
o
T
-
8.4
21.6
-
98.0
98.0
-
-
d
e
p
o
e
v
e
D
l
212.8
117.3
21.6
54.4
-
-
l
d
e
p
o
e
v
e
d
n
U
58.2
18.1
-
55.2
98.0
l
a
t
o
T
271.0
135.4
21.6
109.6
98.0
956.6
956.6
l
a
t
o
T
19.7
14.4
-
10.6
-
-
Reserves
1,952.9
6,137.8
8,090.7
33.5
11.3
44.8
30.0
98.0
128.1
406.1
1,186.2
1,592.3
* Small differences are due to rounding.
Table 7: Proved plus Probable (2P) Developed and Undeveloped23 Reserves by region*
Dry Gas
Bcf
Condensate
MMbbl
Oil
MMbbl
Total
MMboe
d
e
p
o
e
v
e
D
l
l
d
e
p
o
e
v
e
d
n
U
l
a
t
o
T
Greater Pluto
1,511.6
333.6
1,845.2
North West Shelf
689.0
118.6
807.6
Greater Exmouth
-
-
-
Julimar-Brunello
434.3
415.7
849.9
Senegal
Greater Scarborough
-
-
-
-
8,166.6
8,166.6
d
e
p
o
e
v
e
D
l
20.7
15.8
-
8.9
-
-
l
d
e
p
o
e
v
e
d
n
U
4.3
2.8
-
7.7
-
-
l
a
t
o
T
25.0
18.5
-
16.7
-
-
d
e
p
o
e
v
e
D
l
-
10.1
25.3
-
-
-
l
d
e
p
o
e
v
e
d
n
U
-
-
-
-
l
a
t
o
T
-
10.1
25.3
-
148.7
148.7
-
-
d
e
p
o
e
v
e
D
l
285.9
146.7
25.3
85.1
-
-
l
d
e
p
o
e
v
e
d
n
U
62.8
23.6
-
80.6
148.7
l
a
t
o
T
348.7
170.3
25.3
165.8
148.7
1,432.7
1,432.7
Reserves
2,634.9 9,034.6
11,669.4
45.4
14.8
60.2
35.5
148.7
184.2
543.1
1,748.5
2,291.7
Qualified Petroleum Reserves and Resource Evaluator
Statement
The estimates of petroleum resources are based on and
fairly represent information and supporting documentation
prepared under the supervision of and approved by Mr
Jason Greenwald, Woodside’s Vice President Reservoir
Management, who is a full-time employee of the company
and a member of the Society of Petroleum Engineers. Mr
Greenwald’s qualifications include a Bachelor of Science
(Chemical Engineering) from Rice University, Houston, Texas,
and more than 20 years of relevant experience.
* Small differences are due to rounding.
Governance and Assurance
Woodside as an Australian company listed on the Australian
Securities Exchange, reports its petroleum resource estimates
using definitions and guidelines consistent with the 2018
Society of Petroleum Engineers (SPE)/World Petroleum
Council (WPC)/American Association of Petroleum Geologists
(AAPG)/Society of Petroleum Evaluation Engineers (SPEE)
Petroleum Resources Management System (PRMS).
Woodside has several processes to provide assurance for
reserves reporting, including the Woodside Reserves Policy,
Petroleum Resources Management Procedure, Petroleum
Resource Management Guideline, staff training and minimum
competency levels and external reserves audits. On average,
99% of Woodside’s Proved Reserves have been externally
verified by independent review over the past four years.
Unless otherwise stated, all petroleum resource estimates are
quoted as net Woodside share at standard oilfield conditions
of 14.696 pounds per square inch (psi) (101.325 kPa) and
sixty degrees Fahrenheit (15.56 degrees Celsius).
58 Annual Report 2021
Notes to the Reserves and Resource Statement
1.
2.
‘Reserves’ are estimated quantities of petroleum that have been
demonstrated to be producible from known accumulations in which
the company has a material interest from a given date forward, at
commercial rates, under presently anticipated production methods,
operating conditions, prices and costs.
‘Contingent resources’ are those quantities of petroleum estimated, as of
a given date, to be potentially recoverable from known accumulations,
but the applied project(s) are not yet considered mature enough for
commercial development due to one or more contingencies. Contingent
resources may include, for example, projects for which there are
currently no viable markets, or where commercial recovery is dependent
on technology under development, or where evaluation of the
accumulation is insufficient to clearly assess commerciality. Woodside
reports contingent resources net of the fuel and flare required for
production, processing and transportation up to a reference point and
non-hydrocarbons not present in sales products. Contingent resources
estimates may not always mature to reserves and do not necessarily
represent future reserves bookings. Contingent resource volumes are
reported at the ‘Best Estimate’ (P50) confidence level.
Assessment of the economic value of the project, in support of a
reserves classification, uses Woodside Portfolio Economic Assumptions
(PEAs). The PEAs are reviewed on an annual basis or more often if
required. The review is based on historical data and forecast estimates
for economic variables such as product prices and exchange rates.
The PEAs are approved by the Woodside Board. Specific contractual
arrangements for individual projects are also taken into account.
4. Woodside uses both deterministic and probabilistic methods for
3.
estimation of petroleum resources at the field and project levels. Unless
otherwise stated, all petroleum estimates reported at the company or
region level are aggregated by arithmetic summation by category. Note
that the aggregated Proved level may be a very conservative estimate
due to the portfolio effects of arithmetic summation. Probabilistic
aggregation at field and project level is more appropriate than arithmetic
summation as inter-field dependencies reflecting different reservoir
characteristics between fields are incorporated.
5. Woodside reports reserves net of the fuel and flare required for
production, processing and transportation up to a reference point. For
offshore oil projects, the reference point is defined as the outlet of
the floating production storage and offloading facility (FPSO), while
for the onshore gas projects the reference point is defined as the
inlet to the downstream (onshore) processing facility. Downstream
fuel and flare represent 10.0% of Woodside’s Proved (Developed and
Undeveloped) reserves, and 9.9% of Proved plus Probable (Developed
and Undeveloped) reserves.
’Dry gas’ is defined as ‘C4 minus’ petroleum components including
non-hydrocarbons. These volumes include LPG (propane and butane)
resources. Dry gas reserves and contingent resources include ‘C4 minus’
hydrocarbon components and non-hydrocarbon volumes that are
present in sales product.
‘Condensate’ is defined as ‘C5 plus’ petroleum components.
‘Bcf’ means Billions (109) of cubic feet of gas at standard oilfield
conditions of 14.696 psi (101.325 kPa) and sixty degrees Fahrenheit
(15.56 degrees Celsius).
‘MMbbl’ means millions (106) of barrels of oil and condensate at
standard oilfield conditions of 14.696 psi (101.325 kPa) and sixty degrees
Fahrenheit (15.56 degrees Celsius).
‘MMboe’ means millions (106) of barrels of oil equivalent. Dry gas
volumes, defined as ‘C4 minus’ hydrocarbon components and non-
hydrocarbon volumes that are present in sales product, are converted
to oil equivalent volumes via a constant conversion factor, which
for Woodside is 5.7 Bcf of dry gas per 1 MMboe. Volumes of oil and
condensate, defined as ‘C5 plus’ petroleum components, are converted
from MMbbl to MMboe on a 1:1 ratio.
‘Proved reserves’ are those reserves which analysis of geological and
engineering data suggests, to a high degree of confidence that the
quantities are recoverable. Where probabilistic methods are used, there
is at least a 90% probability that the quantities actually recovered will
equal or exceed the sum of estimated Proved (1P) reserves.
‘Probable reserves’ are those reserves which analysis of geological and
engineering data suggests are more likely than not to be recoverable.
Proved plus Probable reserves represent the best estimate of recoverable
quantities. Where probabilistic methods are used, there is at least a 50%
probability that the quantities actually recovered will equal or exceed the
sum of estimated Proved plus Probable (2P) reserves.
‘Developed reserves’ are those reserves that are producible through
currently existing completions and installed facilities for treatment,
compression, transportation and delivery, using existing operating
methods and standards.
6.
7.
8.
9.
10.
11.
12.
13.
15.
14.
‘Undeveloped reserves’ are those reserves for which wells and facilities
have not been installed or executed but are expected to be recovered
through future investments.
The ‘reserves replacement ratio’ is the reserves (Developed and
Undeveloped) change during the year, before the deduction of
production, divided by production during the year. The ‘three-year
reserves replacement ratio’ is the reserves (Developed and Undeveloped)
change over three years, before the deduction of production for that
period, divided by production during the same period.
16. The ‘organic annual reserves replacement ratio’ is the reserves
(Developed and Undeveloped) change during the year, before the
deduction of production and adjustment for acquisition and divestments,
divided by production during the year.
The ‘reserves life’ is the reserves (Developed and Undeveloped) divided
by production during the year.
‘Annual production’ is the volume of dry gas, condensate and oil
produced during the year and converted to ’MMboe’ for the specific
purpose of reserves reconciliation and the calculation of reserves
replacement ratios. The ‘Reserves and Resources Statement’ annual
production differs from production volumes reported in the company's
annual and quarterly reports due to differences between the sales and
reserves product definitions, differences between the Woodside equity
share of NWS domestic gas production and independently marketed
pipeline gas sales, reserves being reported gross of downstream fuel and
flare and the ‘MMboe’ conversion factors applied.
‘Revision of Previous Estimates’ are revisions (either upward or
downward) in previous estimates of reserves or contingent resources,
which are a result from new information normally obtained from
development drilling, field re-interpretation, production performance,
or are the result of a change in economic factors including any change
in Woodside net revenue interest not arising from acquisition or
divestment. This change category is associated with absolute changes
to the resource estimates associated with the affected reference projects
but excludes re-classification changes.
‘Transfer to/from Reserves’ are revisions that represent changes (either
upward or downward) in previous estimates of reserves or contingent
resources, which are a result of re-classification of resource estimates
(i.e. from reserves to contingent resources or vice versa) associated with
one or more reference project(s).
‘Extensions and discoveries’ represent additions to reserves or
contingent resources that result from increased areal extensions of
previously discovered fields demonstrated to exist subsequent to the
original discovery and/or discovery of reserves or contingent resource in
new fields or new reservoirs in old fields.
‘Acquisitions and Divestments’ represent changes to resource entitlement
(either upward or downward) that result from either purchase or sale of
interests and/or execution of contracts conveying entitlement.
17.
18.
19.
20.
21.
22.
23. Material concentrations of undeveloped reserves in the North West Shelf,
Greater Pluto and Julimar-Brunello region(s) have remained undeveloped
for longer than 5 years from the dates they were initially reported
as the incremental reserves are expected to be recovered through
future developments to meet long-term contractual commitments.
The incremental projects are included in the company business plan,
demonstrating the intent to proceed with the developments.
24. The ‘Greater Pluto’ region comprises the Pluto-Xena, Pyxis, Larsen,
Martell, Martin, Noblige and Remy fields.
25. The ‘North West Shelf’ (NWS) region includes all oil and gas fields within
the North West Shelf Project Area.
26. The ‘Greater Exmouth’ region comprises Vincent, Enfield, Greater Enfield,
Greater Laverda, Ragnar and Toro fields.
27. The ‘Julimar-Brunello’ region comprises the Julimar and Brunello fields.
28. The ‘Senegal’ region comprises the Sangomar field. The Developed and
Undeveloped reserves comprise of oil estimates. The Best Estimate (2C)
Contingent resources include gas and oil estimates.
29. The ‘Greater Browse’ region comprises the Brecknock, Calliance and
Torosa fields.
30. The ‘Greater Scarborough’ region comprises the Jupiter, Scarborough
and Thebe fields.
The ‘Greater Sunrise’ region comprises the Sunrise and Troubadour fields.
31.
32. The ‘Myanmar’ region comprises the fields within the A-6 development.
The Myanmar Best Estimate Contingent Resource (2C) of 109.5 MMboe
is referenced at 31 December 2021. Woodside announced its decision to
withdraw from its interests in Myanmar on 27 January 2022.
33. The ‘Canada’ region comprises unconventional resources in the Liard
Basin. The increase in Liard Best Estimate (2C) Contingent Resources at
31 December 2021 is due to Woodside assuming full equity in 28 non-
infrastructure related Liard Basin leases from Chevron Canada.
34. The Julimar-Brunello and Greater Pluto reserves estimates in this
statement differ from the estimates reported in the 21 October 2021
and 5 November 2021 reserves updates, due to the impact of full year
production.
Woodside Petroleum Ltd 59
GOVERNANCE
WOODSIDE BOARD
OF DIRECTORS
Richard Goyder, AO
Meg O’Neill
Larry Archibald
Frank Cooper, AO
Swee Chen Goh
Christopher Haynes, OBE
Ian Macfarlane
Ann Pickard
Sarah Ryan
Gene Tilbrook
Ben Wyatt
Woodside Petroleum Ltd
61
Richard Goyder, AO
BCom, FAICD
Larry Archibald
BSc (Geosciences), BA (Geology), MBA
Chairman: Chairman since April 2018
Term of office: Director since February 2017
Term of office: Director since August 2017
Independent: Yes
Independent: Yes
Experience: 24 years with Wesfarmers Limited, including
Managing Director and CEO from 2005 to late 2017. Chairman
of the Australian B20 (the key business advisory body to the
international economic forum which includes business leaders
from all G20 economies) from February 2013 to December
2014.
Committee membership: Chair of the Nominations &
Governance Committee. Attends other Board committee
meetings.
Experience: Former ConocoPhillips company executive (2008
to 2015), spending eight years in senior positions including
Senior Vice President, Business Development and Exploration,
and Senior Vice President, Exploration. Prior to this, spent
29 years at Amoco (1980 to 1998) and BP (1998 to 2008) in
various positions including leadership of exploration programs
covering many world regions.
Committee membership: Audit & Risk, Sustainability and
Nominations & Governance Committees.
Current directorships/other interests:
Current directorships/other interests:
Chair: University of Arizona Geosciences Advisory Board.
Directorships of other listed entities within the past three
years: Nil.
Frank Cooper, AO
BCom, FCA, FAICD
Term of office: Director since February 2013
Independent: Yes
Experience: More than 35 years’ experience in corporate tax,
specialising in the mining, energy and utilities sector, including
senior leadership roles at three of the largest accounting firms
and director of a leading Australian utility company.
Committee membership: Chair of the Audit & Risk
Committee. Member of the Human Resources &
Compensation and Nominations & Governance Committees.
Current directorships/other interests:
Chair: Insurance Commission of Western Australia.
Director: St John of God Australia Limited (since 2015)
and South32 Limited (since 2015).
Pro Chancellor: Senate of the University of Western Australia.
Trustee: St John of God Health Care (since 2015).
Directorships of other listed entities within the past three
years: Nil.
Chairman: Qantas Airways Limited, Australian Football
League Commission, Channel 7 Telethon Trust and West
Australian Symphony Orchestra.
Member: Evans and Partners Investment Committee.
Directorships of other listed entities within the past three
years: Nil.
Meg O'Neill
BSc (Ocean Engineering), BSc (Chemical Engineering), MSc (Ocean
Systems Management)
CEO and Managing Director
Term of office: Director since August 2021
Independent: No
Experience: Joined Woodside as Chief Operations Officer
in May 2018. Previously held senior roles with ExxonMobil,
including regional production and development leadership
positions, and country leadership positions in Norway and
Canada.
Committee membership: Attends Board committee
meetings.
Current directorships/other interests:
Vice Chair: Australian Petroleum Production & Exploration
Association (APPEA)
Director: Reconciliation WA, WA Venues & Events Pty Ltd
(WAVE), West Australian Symphony Orchestra (WASO)
Vice President: Australian Resources and Energy Group
(AMMA)
Member: Chief Executive Women, UWA Business School
Advisory Board
Directorships of other listed entities within the past three
years: Nil.
62 Annual Report 2021
Swee Chen Goh
BSc (Information Science), MBA
Term of office: Director since January 2020
Independent: Yes
Experience: Joined Shell in 2003 and retired as Chairperson
of the Shell companies in Singapore in January 2019.
Served on the boards of a number of Shell joint ventures
in China, Korea and Saudi Arabia and has extensive board
and governance experience. Prior to joining Shell, worked at
Procter & Gamble and IBM. Gained significant experience in
a diverse range of industries, including oil and gas, consumer
goods and IT.
Committee membership: Member of the Human Resources
& Compensation, Sustainability and Nominations &
Governance Committees.
Current directorships/other interests:
Chair: Nanyang Technological University (since 2021), National
Arts Council Singapore (since 2019) and the Singapore
Institute for Human Resource Professionals (since 2016).
Director:
CapitaLand Investment Ltd (since 2021), The Centre for
Liveable Cities (since 2021), Singapore Airlines Ltd (since
2019) and Singapore Power Ltd (since 2019).
Member: Singapore Legal Services Commission.
President: Global Compact Network Singapore.
Directorships of other listed entities within the past three
years: Nil.
Christopher Haynes, OBE
BSc, DPhil, FREng, CEng, FIMechE, FIEAust
Term of office: Director since June 2011
Independent: Yes
Experience: A 38-year career with Shell including as Executive
Vice President, Upstream Major Projects within Shell’s
Projects and Technology business, General Manager of Shell’s
operations in Syria and a secondment as Managing Director of
Nigeria LNG Ltd. From 1999 to 2002, seconded to Woodside
as General Manager of the North West Shelf Venture. Retired
from Shell in 2011.
Committee membership: Member of the Audit & Risk,
Sustainability and Nominations & Governance Committees.
Current directorships/other interests:
Director: Worley Limited (since 2012).
Directorships of other listed entities within the past three
years: Nil.
Ian Macfarlane
Former Australian Federal Minister
(Resources; Energy; Industry and Innovation), FAICD
Term of office: Director since November 2016
Independent: Yes
Experience: Australia’s longest-serving Federal Resources
and Energy Minister and the Coalition’s longest-serving
Federal Industry and Innovation Minister with over 14 years
of experience in both Cabinet and shadow ministerial
positions. Before entering politics, Mr Macfarlane’s experience
included agriculture, and being President of the Queensland
Graingrowers Association (1991 to 1998) and the Grains
Council of Australia (1994 to 1996).
Committee membership: Member of the Human Resources
& Compensation, Sustainability and Nominations
& Governance Committees.
Current directorships/other interests:
Chief Executive: Queensland Resources Council (since 2016).
Chair: Innovative Manufacturing Co-operative Research
Centre.
Director: CSIRO (since 2021).
Member: Toowoomba Community Advisory Committee of the
University of Queensland Rural Clinical School.
Directorships of other listed entities within the past three
years: Nil.
Ann Pickard
BA, MA
Term of office: Director since February 2016
Independent: Yes
Experience: Retired from Shell in 2016 after a 15-year tenure
holding numerous positions, including Executive Vice
President Arctic, Executive Vice President Exploration and
Production, Country Chair of Shell in Australia, and Executive
Vice President Africa. Previously had an 11-year tenure with
Mobil prior to its merger with Exxon.
Committee membership: Chair of the Sustainability
Committee. Member of the Human Resources &
Compensation and Nominations & Governance Committees.
Current directorships/other interests:
Director: Noble Corporation plc (since 2021) and KBR Inc.
(since 2015).
Member: Chief Executive Women and University of Wyoming
Foundation Board.
Directorships of other listed entities within the past three
years: Nil.
Woodside Petroleum Ltd 63
Ben Wyatt
LLB, MSc
Term of office: Director since June 2021
Independent: Yes
Experience: 15 years in the Western Australian Legislative
Assembly, including as the Western Australian Treasurer,
Minister for Finance, Energy, Aboriginal Affairs and Lands.
The first Indigenous treasurer of any Australian government,
and has held various shadow cabinet portfolios including
responsibility for Native Title and the Pilbara.
Committee membership: Member of the Human Resources &
Compensation, Sustainability and Nominations & Governance
Committees.
Current directorships/other interests:
Director: West Coast Eagles (since 2021), Telethon Kids
Institute (since 2021), Rio Tinto Limited (since 2021) and Perth
International Arts Festival (since 2021).
Member: UWA Business School Advisory Board, APM
Advisory Board and the Australian Institute of Company
Directors.
Directorships of other listed entities within the past three
years: Nil.
Peter Coleman
BEng, MBA, FTSE, MAICD, D.Eng (Hon), D.Law (Hon)
Mr Peter Coleman retired effective 19 April 2021 after 10 years
of service as Woodside's CEO and Managing Director.
Sarah Ryan
BSc (Geology), BSc (Geophysics) (Hons 1), PhD
(Petroleum and Geophysics), FTSE
Term of office: Director since December 2012
Independent: Yes
Experience: More than 30 years’ experience in the oil and
gas industry in various technical, operational and senior
management positions, including 15 years with Schlumberger
Ltd. From 2007 to 2017 was an equity analyst, portfolio
manager and energy advisor for Earnest Partners.
Committee membership: Member of the Audit & Risk,
Sustainability and Nominations & Governance Committees.
Current directorships/other interests:
Director: OZ Minerals (since 2021), Future Battery Industries
Co-operative Research Centre (since 2020), Aurizon Holdings
(since 2019), Viva Energy Group Ltd (since 2018) and MPC
Kinetic Pty Ltd (since 2016).
Member: ASIC Corporate Governance Consultative Panel
(since 2019) and Chief Executive Women (since 2016).
Directorships of other listed entities within the past three
years: Nil.
Gene Tilbrook
BSc, MBA, FAICD
Term of office: Director since December 2014
Independent: Yes
Experience: Broad experience in corporate strategy,
investment and finance. Senior executive of Wesfarmers
Limited between 1985 and 2009, including roles as
Executive Director Finance and Executive Director Business
Development.
Committee membership: Chair of the Human Resources &
Compensation Committee. Member of the Audit & Risk and
Nominations & Governance Committees.
Current directorships/other interests:
Director: Orica Limited (since 2013).
Member: Western Australian division of the Australian
Institute of Company Directors (since 2013).
Directorships of other listed entities within the past three
years: GPT Group Limited (2010-2021).
64 Annual Report 2021
CORPORATE GOVERNANCE
We believe high standards of governance and transparency are essential.
Corporate governance at Woodside
Woodside is committed to a high level of corporate
governance and fostering a culture that values ethical
behaviour, integrity and respect. We believe that adopting
and operating in accordance with high standards of
corporate governance is essential for sustainable long-term
performance and value creation.
Woodside’s Compass is core to our governance framework.
It sets out our core values of integrity, respect, sustainability,
working together, ownership and courage. The Compass is the
overarching guide for everyone who works for Woodside.
Our values define what is important to us in the way we work.
Refer to Woodside’s website for more information
(woodside.com.au).
Our corporate governance model is illustrated below.
The Woodside Management System (WMS) describes the
Woodside way of working, enabling Woodside to understand
and manage its business to achieve its objectives. It defines
the boundaries within which our employees and contractors
are expected to work. The WMS establishes a common
approach to how we operate, wherever the location.
These principles and practices are reviewed regularly
and revised as appropriate to reflect changes in law
and developments in corporate governance.
The Corporate Governance Statement discusses
arrangements in relation to our Board of Directors,
committees of the Board, shareholders, risk management
and internal control, the external auditor relationship, and
inclusion and diversity.
The Chairman of the Board, Mr Richard Goyder, is an
independent, non-executive director and a resident Australian
citizen. The Chairman of the Board is responsible for leadership
and effective performance of the Board. The Chairman’s
responsibilities are set out in more detail in the Board Charter.
Mr Goyder is also Chairman of Qantas Airways Limited.
The Board considers that neither his chairmanship of Qantas
Airways Limited, nor any of his other commitments listed
on page 62, interfere with the discharge of his duties to
Woodside. The Board has arrangements in place to ensure
ongoing leadership if unforeseen circumstances mean Mr
Goyder is not available. Mr Goyder’s office is located in
Woodside’s headquarters in Perth, Western Australia. The
Board is satisfied that Mr Goyder commits the time necessary
to discharge his role effectively.
Woodside follows the ASX Corporate Governance Council’s
Corporate Governance Principles and Recommendations
(fourth edition) (ASXCGC Recommendations). Throughout
the year, Woodside complied with all the ASXCGC
Recommendations.
Our website contains copies of Board and committee
charters and copies of many of the policies and documents
mentioned in the Corporate Governance Statement. The
website is updated regularly to ensure that it reflects
Woodside’s most current corporate governance information.
Our Corporate Governance Statement reports on Woodside’s
key governance principles and practices.
Refer to Woodside’s Corporate Governance Statement
for more information (woodside.com.au).
STAKEHOLDERS
BOARD
AUDIT & RISK
COMMITTEE
HUMAN RESOURCES &
COMPENSATION COMMITTEE
CHIEF EXECUTIVE
OFFICER
NOMINATIONS &
GOVERNANCE COMMITTEE
SUSTAINABILITY
COMMITTEE
INDEPENDENT ASSURANCE
MANAGEMENT GOVERNANCE AND ASSURANCE
EXTERNAL AUDIT
__________________________________
STRATEGY
INTERNAL AUDIT
RISK MANAGEMENT
WOODSIDE
MANAGEMENT SYSTEM
INCLUDING WOODSIDE
COMPASS AND POLICIES
AUTHORITIES
OPERATING
STRUCTURE
Woodside Petroleum Ltd 65
DIRECTORS' REPORT
The directors of Woodside Petroleum Ltd present their report (including
the Remuneration Report) together with the Financial Statements of the
consolidated entity, being Woodside Petroleum Ltd and its controlled entities,
for the year ended 31 December 2021.
Directors
The directors of Woodside Petroleum Ltd in office at any
time during or since the end of the 2021 financial year and
information on the directors (including qualifications and
experience and directorships of listed companies held by the
directors at any time in the last three years) are set out on
pages 62-64.
The number of directors’ meetings held (including meetings
of committees of the Board) and the number of meetings
attended by each of the directors of Woodside Petroleum
Ltd during the financial year are shown in Table 3 on page 19
of the Corporate Governance Statement.
Details of director and senior executive remuneration are set
out in the Remuneration Report.
The particulars of directors’ interests in shares of the
company as at the date of this report are set out on page 68.
Principal activities
The principal activities and operations of the Group during
the financial year were hydrocarbon exploration, evaluation,
development, production and marketing.
Other than as previously referred to in the Annual Report,
there were no other significant changes in the nature of the
activities of the consolidated entity during the year.
Consolidated results
The consolidated operating profit attributable to the
company’s shareholders after provision for income tax was
$1,983 million (loss of $4,028 million in 2020).
Review of operations
A review of the operations of the Woodside Group during
the financial year and the results of those operations are set
out on pages 6-59.
Significant changes in the state of affairs
The review of operations (pages 6-59) sets out a number
of matters that have had a significant effect on the state of
affairs of the consolidated entity.
Other than those matters, there were no significant changes
in the state of affairs of the consolidated entity during the
financial year.
Events subsequent to end of financial year
Since the reporting date, the directors have declared a
fully franked dividend. More information is available in the
‘Dividend’ section below. No provision has been made for
this dividend in the financial report as the dividend was not
declared or determined by the directors on or before the end
of the financial year.
Dividend
The directors have declared a final dividend in respect of
the year ended 31 December 2021 of 105 cents per ordinary
share (fully franked) payable on 23 March 2022.
Type
2021 final
2021 interim
2020 final
Payment date
23 March 2022
24 September 2021
24 March 2021
Period ends
31 December 2021
30 June 2021
31 December 2020
Cents
per share
Value
$ million
Fully franked
105
1,018
30
289
12
115
The full-year 2021 dividend was 135 cents per share.
Likely developments and expected results
In general terms, the review of operations of the Group
gives an indication of likely developments and the expected
results of the operations. In the opinion of the directors,
disclosure of any further information would be likely to result
in unreasonable prejudice to the Group.
66 Annual Report 2021
Environmental compliance
Woodside is subject to a range of environmental legislation
in Australia and other countries in which it operates.
Details of Woodside’s environmental performance are
provided on pages 23-41 of the Sustainable Development
Report 2021.
Through its Health, Safety and Environment Policy and
Quality Policy, Woodside plans and performs activities so
that adverse effects on the environment are avoided or kept
as low as reasonably practicable.
Company Secretaries
The following individuals have acted as Company Secretary
during 2021:
Andrew Cox BA (Hons), LLB, MA
Vice President Legal and General Counsel, and Joint
Company Secretary
Mr Cox joined Woodside in 2004 and was appointed to
the role of Vice President Legal in January 2015. He was
appointed Vice President Legal and General Counsel and
Joint Company Secretary on 1 June 2017.
Warren Baillie LLB, BCom, Grad. Dip. CSP
Company Secretary
Mr Baillie joined Woodside in 2005 and was appointed
Company Secretary effective 1 February 2012. Mr Baillie is a
solicitor and chartered secretary. He is a former President of
the board of the Governance Institute of Australia.
Indemnification and insurance of directors and officers
The company’s constitution requires the company to
indemnify each director, secretary, executive officer or
employee of the company or its wholly owned subsidiaries
against liabilities (to the extent the company is not precluded
by law from doing so) incurred in or arising out of the
conduct of the business of the company or the discharge of
the duties of any such person. The company has entered into
deeds of indemnity with each of its directors, secretaries,
certain senior executives, and employees serving as officers
on wholly owned or partly owned companies of Woodside
in terms of the indemnity provided under the company’s
constitution.
From time to time, Woodside engages its external auditor,
Ernst & Young, to conduct non-statutory audit work and
provide other services in accordance with Woodside’s
External Auditor Guidance Policy. The terms of engagement
include an indemnity in favour of Ernst & Young:
• against all losses, claims, costs, expenses, actions,
demands, damages, liabilities or any proceedings
(liabilities) incurred by Ernst & Young in respect of third-
party claims arising from a breach by the Group under the
engagement terms; and
• for all liabilities Ernst & Young has to the Group or any
third-party as a result of reliance on information provided
by the Group that is false, misleading or incomplete.
The company has paid a premium under a contract
insuring each director, officer, secretary and employee
who is concerned with the management of the company
or its subsidiaries against liability incurred in that capacity.
Disclosure of the nature of the liability covered by and the
amount of the premium payable for such insurance is subject
to a confidentiality clause under the contract of insurance.
The company has not provided any insurance for the external
auditor of the company or a body corporate related to the
external auditor.
Non-audit services and auditor independence declaration
Details of the amounts paid or payable to the external
auditor of the company, Ernst & Young, for audit and non-
audit services provided during the year are disclosed in note
E.4 to the Financial Statements.
Based on advice provided by the Audit & Risk Committee,
the directors are satisfied that the provision of non-audit
services by the external auditor during the financial year
is compatible with the general standard of independence
for auditors imposed by the Corporations Act 2001 for the
following reasons:
• all non-audit services were provided in accordance with
Woodside’s External Auditor Policy and External Auditor
Guidance Policy; and
• all non-audit services were subject to the corporate
governance processes adopted by the company and
have been reviewed by the Audit & Risk Committee to
ensure that they do not affect the integrity or objectivity
of the auditor.
Further information on Woodside’s policy in relation to the
provision of non-audit services by the auditor is set out in
section 7 of the Corporate Governance Statement.
The auditor’s independence declaration, as required under
section 307C of the Corporations Act 2001, is set out on this
page and forms part of this report.
Proceedings on behalf of the company
No proceedings have been brought on behalf of the company,
nor has any application been made in respect of the company,
under section 237 of the Corporations Act 2001.
Rounding of amounts
The amounts contained in this report have been rounded
to the nearest million dollars under the option available to
the company under Australian Securities and Investments
Commission Corporations (Rounding in Financial/Directors’
Reports) Instrument 2016/191 dated 24 March 2016.
Woodside Petroleum Ltd 67
Directors’ relevant interests in Woodside shares as at the
Auditor’s independence declaration to the Directors of
date of this report
Director
L Archibald
F Cooper
S C Goh
R Goyder
C Haynes
I Macfarlane
M O'Neill1
A Pickard
S Ryan
G Tilbrook
B Wyatt2
1 Ms O'Neill also holds Performance Rights under the Executive Incentive Scheme,
Relevant interest in shares
11,977
13,450
12,786
23,634
14,598
10,329
229,652
14,206
11,910
7,949
Nil
details of which are set out in the Remuneration Report in Table 12 on pages 89-90
and Table 14 on page 91.
2 Mr Wyatt is participating in the Non-Executive Directors' Share Plan and will acquire
shares going forward under this plan.
Signed in accordance with a resolution of the directors.
Woodside Petroleum Ltd
As lead auditor for the audit of the financial report of
Woodside Petroleum Ltd for the financial year ended
31 December 2021, I declare to the best of my knowledge
and belief, there have been:
(a) no contraventions of the auditor independence
requirements of the Corporations Act 2001 in relation to
the audit;
(b) no contraventions of any applicable code of professional
conduct in relation to the audit; and
(c) no non-audit services provided that contravene any
applicable code of professional conduct in relation to the
audit.
This declaration is in respect of Woodside Petroleum Ltd and
the entities it controlled during the financial year.
R J Goyder, AO
Chairman
Perth, Western Australia
17 February 2022
M E O'Neill
Chief Executive Officer and Managing Director
Perth, Western Australia
17 February 2022
Ernst & Young
R Kirkby
Partner
Perth, Western Australia
17 February 2022
Liability limited by a scheme approved under Professional
Standards Legislation
68 Annual Report 2021
REMUNERATION REPORT CONTENTS
Committee Chair's letter
Remuneration Report (audited)
KMP and summary of Woodside’s five-year performance
Remuneration Policy
2021 remuneration changes
Executive Incentive Scheme
Executive KMP remuneration structure
Executive KMP KPIs and outcomes for 2021
Other equity plans
Contracts for Executive KMP
Non-executive directors
Human Resources & Compensation Committee
Use of remuneration consultants
Reporting notes
Statutory tables
Glossary
71
73
73
74
74
75
76
80
84
85
86
87
87
87
88
92
70 Annual Report 2021
Committee Chair's letter
17 February 2022
Dear Shareholders
On behalf of the Board, I am pleased to present the Remuneration Report for the year ended 31 December 2021.
In 2021 we maintained reliable operations, started up new projects and leveraged favourable market conditions to achieve
strong earnings outcomes. We took significant steps to support long-term sustainable returns for shareholders, entering into a
binding share sale agreement for the merger with BHP’s oil and gas portfolio and taking FIDs on Scarborough and Pluto Train 2.
We progressed a portfolio of new energy opportunities and completed our largest ever planned maintenance campaign.
2021 was also a challenging year in which we saw disappointing safety performance compared to our strong results in 2019 and
2020. We fell short of our internal production targets, although results were in line with market guidance.
These results are reflected in our 2021 Executive remuneration outcomes, as outlined below and in further detail in this report.
Remuneration Policy
2021 marked the fourth year since the introduction of the EIS. Changes were made to the Corporate Scorecard for 2021 to
strengthen the link between Executive reward and shareholder experience.
The 2021 Corporate Scorecard was based on the following five equally weighted metrics, with two new financial metrics
introduced in place of NPAT:
• Operating Expenditure – 20% (New in 2021)
• Earnings Before Interest, Taxes, Depreciation and Amortisation (EBITDA) – 20% (New in 2021)
• Production – 20%
• Material Sustainability Issues – 20%
• Delivery against Business Priorities – 20%
We describe Executive KMP performance and pay outcomes in this report (pages 81-82). This includes discussion of Executives’
performance against carbon-related measures which impact award outcomes. Woodside adopted a specific measure for net
equity Scope 1 and 2 greenhouse gas emissions reduction for the first time in the 2021 Corporate Scorecard. We will continue to
enhance reporting of remuneration outcomes linked to climate metrics as we progress lower carbon solutions and our new energy
portfolio.
The take home pay table is on page 83.
The EIS continues to achieve remuneration outcomes which fairly reflect Woodside’s performance and are strongly linked to the
creation of value for shareholders. There are no material changes to the EIS structure anticipated for 2022.
Proposed Merger
The merger with BHP’s oil and gas portfolio represents a substantial opportunity for Woodside and its shareholders and is
expected to involve updates to our Remuneration Policy including how we benchmark Executive reward, reflecting changes to
Executive roles and accountabilities. The international peer group used to measure RTSR performance for equity components of
future Executive awards will be reviewed to maintain alignment with Woodside’s expanded global business activities.
The Committee has reviewed preliminary plans for a new senior management structure and the transition of several BHP
executives to the EIS on merger completion. The transition will be aimed at ensuring Woodside can continue to attract and retain
executive capability in a globally competitive market.
Business Performance
2021 has been a year of substantial progress for Woodside as it maintains safe and efficient operations in a COVID-19-challenged
environment, progressing a binding share sale agreement for the merger with BHP’s oil and gas portfolio and the FIDs for
Scarborough and Pluto Train 2. It is pleasing that the focus on delivering a successful merger has not diverted attention away from
other business priorities, including progress on new energy opportunities.
The company’s EBITDA for 2021 was above target at $4,135 million, primarily due to significantly improved market pricing for
Woodside’s products and activities focussed on optimising value from this.
Operating expenditure failed to meet the target of A$1,000 million, primarily due to costs associated with merger activities, partially
offset by lower production costs.
Production for 2021 was within the range but below target at 91.1 MMboe. Performance was lower largely due to weather impacts.
Safety performance has been a disappointment, with a TRIR of 1.74 which exceeded the target of 1.0. Performance against the
remaining Material Sustainability Issues was strong, with no Tier 1 or Tier 2 Process Safety Events occurring and year-end emissions
abatement of 80.1kT CO2-e, more than double the annual baseline target.
Our overall Corporate Scorecard was above target at 6 out of 10.
Woodside Petroleum Ltd
71
Executive KMP Changes
Peter Coleman retired as CEO and Managing Director effective 19 April 2021 after more than ten years in the role and departed
Woodside on 3 June 2021. Details of the treatment of Mr Coleman’s unvested equity incentives and his pro-rata 2021 EIS award are
on page 80 of this report.
Meg O’Neill was appointed as Acting CEO on 20 April 2021, during the Board’s internal and external CEO search, and was
subsequently appointed Woodside’s CEO and Managing Director on 17 August 2021. Ms O’Neill’s FAR on appointment was
A$2,200,000 with a target value for VAR set at A$4,400,000. In a year of strong corporate and personal performance, Ms O’Neill
achieved a 2021 EIS award of 75.6% of the maximum award. Details of the assessment of the CEO’s performance and 2021 award
are set out in Table 4 on page 81 of this report. The equity components of Ms O’Neill’s 2021 VAR will be presented for shareholder
approval at the 2022 AGM.
Sherry Duhe resigned as Executive Vice President and Chief Financial Officer on 16 November 2021 and remained with the
company until 4 February 2022 to ensure a smooth transition of her responsibilities. In accordance with the EIS, Ms Duhe’s
unvested equity incentives lapsed following her resignation. She was not entitled to receive a 2021 EIS award.
The Board appointed Mr Graham Tiver as Executive Vice President and Chief Financial Officer effective 1 February 2022.
The Board is pleased to have appointed to the CEO and CFO positions two outstanding people who will work with a strong
senior team to deliver value for shareholders and advance the organisation’s capability and culture to implement the significant
opportunities ahead of the company.
Executive Remuneration Outcomes
The 2021 remuneration outcomes include:
• No fixed remuneration increase for Senior Executives (other than in connection with changes to role scope and accountabilities).
• CEO EIS award of 117% of target (75.6% of maximum opportunity).
• Senior Executive awards ranging from 69.4% to 73.1% of maximum opportunity.
• The 2015 and 2016 awards under the prior Executive Incentive Plan were tested against their respective RTSR hurdles. This was
the second test for the 2015 award which resulted in 9.2% partial vesting. Overall, 47.5% of the 2015 award vested. This was the
first test for the 2016 award and resulted in 63% vesting.
• No fee increases for the non-executive directors.
The Board has reviewed the 2021 EIS outcomes and considers that they align with overall corporate performance.
2021 Committee Activities
Key activities undertaken by the Committee during the year included reviewing the company’s remuneration policies and practices
and changes for Executives who report directly to the CEO and moved roles or reporting structures, including the appointment
and remuneration packages of those Executives.
The Committee considered activities to assess and monitor culture, including across all areas of our Integrated Culture Framework
(values, safety, risk and compliance). This included ensuring a robust approach to bullying and harassment in the workplace and
endorsing a new Working Respectfully Policy.
The Committee oversaw implementation of the 2021-2025 inclusion and diversity strategy and reviewed progress against the key
performance measures. Details of Woodside's performance against the inclusion and diversity strategy in 2021 are available on
pages 53-64 of the Sustainable Development Report 2021.
Summary
The Board has been proud of the leadership and collaboration shown by our employees during this significant phase of growth,
including progressing the merger with BHP’s oil and gas portfolio and transforming the way we work in response to the energy
transition.
Our employees continued to respond strongly to the ongoing challenges of the COVID-19 pandemic in ensuring the safety of our
employees and the ongoing performance of our assets.
We look forward to our ongoing engagement with Woodside’s shareholders and sharing in Woodside’s future success.
Yours sincerely
Gene Tilbrook
Chair of Human Resources & Compensation Committee
72 Annual Report 2021
Remuneration Report (audited)
KMP and summary of Woodside’s five-year performance
This report outlines the remuneration arrangements in place
and outcomes achieved for Woodside’s KMP during 2021.
Woodside’s KMP are the people who have the authority
to shape and influence the Group’s strategic direction and
performance through their actions, either collectively (in the
case of the Board) or as individuals acting under delegated
authorities (in the case of the CEO and Senior Executives).
During 2021 the following changes to KMP occurred:
• Meg O’Neill was appointed Acting CEO with effect from
20 April 2021 and CEO and Managing Director on 17
August 2021. Ms O’Neill was previously Executive Vice
President Development and Marketing.
• Peter Coleman retired as CEO and Managing Director
and ceased to be an Executive KMP on 19 April 2021. He
departed Woodside on 3 June 2021. The treatment of
Mr Coleman’s unvested equity awards and his pro-rata
2021 award are detailed on page 80.
• Sherry Duhe resigned as Executive Vice President and
CFO on 16 November 2021. Ms Duhe remained with
Woodside until 4 February 2022 to ensure a smooth
transition of key responsibilities.
• On 14 December 2021, Woodside announced that it
had appointed Graham Tiver as Executive Vice President
and CFO. Mr Tiver commenced with Woodside on
1 February 2022.
• Ben Wyatt was appointed a non-executive director
on 1 June 2021.
The names and positions of the individuals who were
KMP during 2021 are set out in Tables 1A and 1B.
TABLE 1A - EXECUTIVE KMP
TABLE 1B - NON-EXECUTIVE DIRECTORS KMP
Executive Director
Meg O’Neill (Chief Executive Officer and Managing Director
(CEO))1
Peter Coleman (former Chief Executive Officer and Managing
Director)2
Senior Executives
Shaun Gregory (Executive Vice President Sustainability and Chief
Technology Officer)
Fiona Hick (Executive Vice President Operations)3
Sherry Duhe (former Executive Vice President and Chief Financial
Officer)4
Richard Goyder, AO (Chairman)
Larry Archibald
Frank Cooper, AO
Swee Chen Goh
Christopher Haynes, OBE
Ian Macfarlane
Ann Pickard
Sarah Ryan
Gene Tilbrook
Ben Wyatt5
1 Ms M O’Neill’s title changed from Executive Vice President Development and Marketing to Acting Chief Executive Officer on 20 April 2021. Ms O’Neill was appointed Chief Executive Officer and
Managing Director on 17 August 2021.
2 Mr P Coleman ceased to be Chief Executive Officer, Managing Director and an Executive KMP on 19 April 2021. Mr Coleman departed Woodside on 3 June 2021.
3 Ms F Hick’s title changed from Senior Vice President Operations to Executive Vice President Operations on 1 April 2021.
4 Ms S Duhe ceased to be an Executive Vice President, Chief Financial Officer and Executive KMP on 4 February 2022.
5 Mr B Wyatt was appointed a non-executive director on 1 June 2021.
TABLE 2 – FIVE-YEAR PERFORMANCE
Earnings before interest, tax, depreciation and
amortisation (EBITDA)1
Operating Expenditure2
Net profit after tax (NPAT)3
Basic earnings per share4
Dividends per share
Share closing price (last trading day of the year)
Production
Average annual dated Brent
(US$ million)
(A$ million)
(US$ million)
(US cents)
(US cents)
(A$)
(MMboe)
(US$/boe)
2021
4,135
1,030
1,983
206
135
21.93
91.1
71
2020
1,922
2019
3,531
2018
3,814
20175
2,918
(4,028)
(424)
38
22.74
100.3
42
343
37
91
34.38
89.6
64
1,364
1,069
148
144
123
98
31.32
33.08
91.4
71
84.4
54
1 This is a non-IFRS measure that is unaudited but derived from audited Financial Statements. This measure is presented to provide further insight into Woodside’s performance. Refer to
footnote 4 on page 159 for the calculation methodology of EBIDTA.
2 Operating Expenditure was not disclosed prior to 2021. Operating Expenditure is defined in the Glossary on page 92. This is a non-IFRS measure that is unaudited.
3 Represents NPAT attributable to equity holders of the parent with further details presented in the Financial Statements on pages 93-148.
4 Basic earnings per share from total operations.
5 2017 NPAT has been restated for the retrospective application of AASB 15 Revenue from Contracts with Customers (AASB 15), and earnings per share has been restated for the retrospective
application of AASB 15 and the Retail Entitlement Offer.
Woodside Petroleum Ltd
73
Remuneration Policy
Woodside aims to deliver affordable energy solutions and
superior outcomes to stakeholders. We are managing our
business by focusing on the energy transition through:
the provision of natural gas; the decarbonisation of our
business; and incremental investment in targeted new
energy businesses with prospective exponential growth,
such as hydrogen and the development of new, value-
creating projects. To do so, the company must be able
to attract and retain executive capability in a globally
competitive market. The Board structures remuneration so
that it rewards those who perform, is valued by Executives,
and is aligned with the company’s Compass, strategic
direction and the creation of enduring value to shareholders,
and other stakeholders.
Fixed Annual Reward (FAR) is determined having regard
to the scope of each Executive’s role and their level of
knowledge, skills and experience.
Variable Annual Reward (VAR) at target is structured to
reward the Executives for achieving challenging yet realistic
targets set by the Board which deliver short-term and long-
term returns for the company. VAR aligns shareholder and
executive remuneration outcomes by ensuring a significant
portion of executive remuneration is at risk, while rewarding
performance.
Executive remuneration is reviewed annually, having regard
to the accountabilities, experience and performance of the
individual. FAR and VAR are compared against domestic and
international competitors at target, to maintain Woodside’s
capacity to attract and retain talent and to ensure
appropriate motivation is provided to Executives to deliver
on the company's strategic objectives.
2021 remuneration changes
Following feedback from our investors, we implemented
changes for 2021 to our Corporate Scorecard and the
weighting of individual and corporate performance which
determine executive VAR. The change strengthened the
connection between corporate performance, executive
reward and shareholder experience.
An Executive’s award is based on their individual
performance against KPIs and the company’s performance
against the Corporate Scorecard. Individual performance
measures are designed to ensure Executives focus on driving
Woodside’s culture and the values and behaviours that
underpin our success whilst executing Woodside’s strategic
imperatives.
Individual performance is weighted at 30% and corporate
performance is weighted at 70% to determine an Executive’s
final performance outcome and reward.
CORPORATE SCORECARD
70%
INDIVIDUAL
PERFORMANCE
FACTOR
INDIVIDUAL KPIs
30%
Corporate Scorecard
In 2021, the overall weighting of the financial metrics
increased from 25% (based on NPAT) to 40% (EBITDA and
Operating Expenditure).
Individual Performance
Individual performance is assessed by the Board in the case
of the CEO, and by the CEO and the Human Resources &
Compensation Committee in the case of Senior Executives.
The 2021 Corporate Scorecard for Executive KMP was based
on five equally weighted measures that were chosen because
they impact short-term and long-term shareholder value,
with a score of 5 for an outcome at target and a maximum
score of 10 on each measure. The Corporate Scorecard is
the same for all employees to enable Executives to drive
performance at all levels of the organisation. The 2022
Corporate Scorecard is expected to be based on the same
five equally weighted measures.
The Board has strong oversight and governance to ensure
that appropriate and challenging targets are set to create
a clear link between performance and reward. The Board
has an overriding discretion which it can and does exercise
to adjust outcomes in line with shareholder experience and
company or management performance.
74 Annual Report 2021
EBITDA
Production
CORPORATE SCORECARD
Operating
Expenditure
Controlling Operating
Expenditure brings
a focus on efficient
operations; cost
competitiveness; and
shareholder returns.
_____
20%
EBITDA is a key
measure of annual
profitability and
is influenced by
both management
performance and
commodity prices.
_____
20%
Revenue is maximised
and value generated
from our assets when
they are fully utilised in
production.
Material
Sustainability
Issues
Material sustainability
issues include personal
and process safety,
environment, emissions
reductions, and our
social licence to
operate.
Deliver
Business
Priorities
Business priorities
focus on progress and
milestones of capital
projects; business
developments;
and balance sheet
management.
_____
20%
_____
20%
_____
20%
Executive Incentive Scheme
VAR is delivered under the Woodside Executive Incentive Scheme (EIS). The EIS remunerates Executives for delivering results
against measurable criteria aimed at safe, efficient operations; delivery of new projects and an effective financial structure
against the following three key objectives:
EXECUTIVE ENGAGEMENT
ALIGNMENT WITH THE
SHAREHOLDER EXPERIENCE
STRATEGIC FIT
Enable Woodside to
attract and retain executive
capability in a globally
competitive environment by
providing Executives with a
simple remuneration structure
and clear line of sight to how
performance is reflected in
remuneration outcomes.
87.5% of the award is
delivered as equity in a
combination of Restricted
Shares or Performance
Rights. The Performance
Rights are relative total
shareholder return (RTSR)
tested against comparator
groups, after five years.
60% of the award has a
five-year deferral period,
which reflects Woodside’s
strategic time horizons
to drive Executives to
deliver our strategic
objectives with discipline
and collaboration, in turn
creating shareholder value.
Woodside Petroleum Ltd
75
Executive KMP remuneration structure
Woodside’s remuneration structure for the CEO and Senior Executives is comprised of two components: FAR and VAR.
FAR
• Based upon the scope of the
VAR
• Executives are eligible to receive a single variable reward linked to challenging
Executive’s role and their individual
level of knowledge, skill and
experience.
• Benchmarked for competitiveness
against domestic and international
peers to enable the company to
attract and retain superior executive
capability.
individual and company annual targets set by the Board.
• The VAR is subject to performance against individual and corporate
performance in the initial 12-month period and is determined at the conclusion
of the performance year.
• 12.5% of the variable reward is paid in cash.
• 27.5% is allocated in Restricted Shares, subject to a three-year deferral period.
• 30% is allocated in Restricted Shares, subject to a five-year deferral period.
• 30% is allocated in Performance Rights which are subject to a RTSR test five
years after the date of allocation, with one-third tested against a comparator
group that comprises the ASX 50 and the remaining two-thirds against a group
of international oil and gas companies determined by the Board.
Performance
Rights1
30%
Restricted
Shares1
30%
Restricted
Shares1
27.5%
Cash
12.5%
Performance tested
Subject to a five-year deferral period with a RTSR test five years after the date of
allocation; with one-third of performance rights tested against the ASX 50 companies
and the remaining two-thirds against a group of international oil and gas companies
Deferred
Subject to a five-year deferral period
Deferred
Subject to a three-year deferral period
Payable
following the
end of the
performance
year
Year 12
Year 2
Year 3
Year 4
Year 5
1 Allocated using a face value methodology.
2 Award allocated after completion of 12-month performance period.
76 Annual Report 2021
TABLE 3 – KEY EIS FEATURES
Allocation
methodology
Dividends
Clawback
provisions
Control event
Restricted Shares and Performance Rights are allocated using a face value allocation methodology. The number of
Restricted Shares and Performance Rights is calculated by dividing the value by the volume weighted average price
(VWAP) in December each year.
Executives are entitled to receive dividends on Restricted Shares. No dividends are paid on Performance Rights prior
to vesting. For Performance Rights that do vest, a dividend equivalent payment will be paid by Woodside for the
period between allocation and vesting.
The Board has the discretion to reduce unvested entitlements including where an Executive has acted fraudulently or
dishonestly or is found to be in material breach of their obligations; there is a material misstatement or omission in the
financial statements; or the Board determines that circumstances have occurred that have resulted in an unfair benefit
to the Executive.
The Board has the discretion to determine the treatment of any EIS award on a change of control event. If a change of
control occurs during the 12-month performance period, an Executive will receive at least a pro-rata cash payment in
respect of the unallocated cash and Restricted Share components of the EIS award for that year, assessed at target.
If a change of control occurs during the vesting period for equity awards, Restricted Shares will vest in full whilst
Performance Rights may, at the discretion of the Board, vest on an at least pro-rata basis.
Cessation of
employment
During a performance period, should an Executive resign or be terminated for cause, no EIS award will be provided
(unless the Board determines otherwise). In any other case, Woodside will have regard to performance against target
and the portion of the performance period elapsed in determining the form of any EIS award.
During a deferral period, should an Executive resign or be terminated for cause, any EIS award will be forfeited or
lapse (unless the Board determines otherwise). In any other case, any Restricted Shares will vest in full from a date
determined by the Board while any Performance Rights will remain on foot and vest in the ordinary course subject to
the satisfaction of applicable conditions. The Board will have discretion to accelerate the vesting of unvested equity
awards, subject to termination benefits laws.
No retesting
There will be no retest applied to EIS awards. Performance Rights will lapse if the required RTSR performance is not
achieved at the conclusion of the five-year period.
Calculation of award for 2021
Each Executive’s award is based upon two components:
individual performance against challenging KPIs (30%
weighting) and the company’s performance against the
Corporate Scorecard (70% weighting). This results in an
individual performance factor (IPF) which ranges from
0 to 1.6 for Executive KMP. The Corporate Scorecard targets
and individual KPIs are designed to promote short-term and
long-term shareholder value. Exceeding targets may result in
an increased award, whereas under-performance will result
in a reduced award. The minimum award that an Executive
can receive is zero if the performance conditions are not
achieved.
The decision to pay or allocate an EIS award is subject to
the overriding discretion of the Board, which may adjust
outcomes to better reflect shareholder outcomes and
company or management performance.
See pages 81-82 for details of the CEO’s and Senior
Executives’ individual performance assessement.
Woodside Petroleum Ltd
77
Target variable reward opportunity for 2021
Each Executive is given a target VAR opportunity and a maximum VAR opportunity which is a percentage of the Executive’s FAR.
The opportunities for 2021 are outlined below.
Position
CEO
Senior Executives
Minimum opportunity
(% of FAR)
Target opportunity
(% of FAR)
Maximum opportunity
(% of FAR)
Zero
200
160
300
256
Cash
The cash component represents 12.5% of the VAR and is
payable following the end of the performance year.
Restricted Shares
The Restricted Shares are divided into two tranches.
The first tranche is 27.5% of the award and subject to a
three-year deferral period. The second tranche is 30% of
the award and subject to a five-year deferral period.
There are no further performance conditions attached
to these awards. This element creates a strong retention
proposition for Executives as vesting is subject to
employment not being terminated with cause or by
resignation during the deferral period. The deferral ensures
that awards remain subject to fluctuations in share price
across the three and five-year periods, which is intended
to reflect the sustainability of performance over the
medium-term and long-term and support increased
alignment between Executives and shareholders.
Performance Rights
The Performance Rights are divided into two portions
with each portion subject to a separate RTSR performance
hurdle tested over a five-year period. Performance is tested
after five years as Woodside operates in a capital intensive
industry with long investment timelines. It is imperative
that Executives take decisions in the long-term interest
of shareholders, focused on value creation across the
commodity price cycles of the oil and gas industry.
Our view is that RTSR is the best measure of long-term value
creation across the commodity price cycle of our industry.
One-third of the Performance Rights are tested against a
comparator group that comprises the entities within the
ASX 50 index at 1 December 2021. The remaining two-thirds
are tested against an international group of oil and gas
companies, set out in Table 11 on page 88.
RTSR outcomes are calculated by an external adviser
on or after the fifth anniversary of the allocation of the
Performance Rights. The outcome of the test is measured
against the schedule below. For EIS awards, any Performance
Rights that do not vest will lapse and are not retested.
RTSR PERFORMANCE HURDLE VESTING
Woodside RTSR percentile position within peer group
Vesting of Performance Rights
Less than 50th percentile
Equal to 50th percentile
No vesting
50% vest
Vesting between the 50th and 75th percentile
Vesting on a pro-rata basis
Equal to or greater than 75th percentile
100% vest
CEO target remuneration
Senior Executive target remuneration
FIXED REWARD 33%
VARIABLE REWARD 67%
FIXED REWARD 38%
VARIABLE REWARD 62%
78 Annual Report 2021
CORPORATE SCORECARD OUTCOMES FOR 2021
Operating Expenditure (20%)
MID-POINT
MAX
OUTCOME 5
Controlling Operating Expenditure brings a focus on efficient operations; cost competitiveness; and shareholder returns.
2021 Performance:
Operating Expenditure was A$1,030 million, which did not meet the target of A$1,000 million primarily due to costs associated with the
proposed merger with BHP's oil and gas portfolio, partially offset by lower production costs.
EBITDA (20%)
MID-POINT
MAX
OUTCOME 10
EBITDA is a key measure of annual profitability and is influenced by both management performance and commodity prices. EBITDA is closely
aligned with short-term shareholder value creation. EBITDA is underpinned by efficient operational performance and outcomes are exposed to
the upside and downside of oil price and foreign exchange fluctuations, as are returns to shareholders.
2021 Performance:
EBITDA was $4,135 million, significantly above the target of $2,908 million due to strong operational performance and higher realised oil and
gas pricing, through proactive decisions to manage our sales portfolio and successful completion of Pluto LNG price reviews.
Production (20%)
MID-POINT
MAX
OUTCOME 2
Revenue is maximised and value generated from Woodside's assets when they are fully utilised in production. Production must be carefully
managed throughout the year to optimise value from the assets. The production target is set relative to the company’s annual budget and
market guidance and is not revised through the year.
2021 Performance:
2021 production was 91.1 MMboe, lower than the 92.6 MMboe internal target, due to weather impacts and equipment reliability. Production
performance was in line with market guidance of 90-95 MMboe.
Material Sustainability Issues (20%)
MID-POINT
MAX
OUTCOME 5
The Board considers performance across material sustainability issues including personal and process safety, climate change and greenhouse
gas emissions, and our social licence to operate. Strong performance in this area creates and protects value in four ways; it reduces the
likelihood of major accident events and catastrophic losses; it maintains Woodside’s licence to operate which enables the development of its
growth portfolio; it reflects efficient, optimised and controlled business processes that generate value; and it supports the company’s position
as a partner of choice.
2021 Performance:
Safety performance was disappointing in 2021, with a TRIR of 1.74 significantly above the target of 1.0. No Tier 1 or 2 Process Safety Events
were recorded and year-end emissions abatement of 80.1 kT CO2-e was more than double the target of 36 kT CO2-e.
Delivery against Business Priorities (20%)
MID-POINT
MAX
OUTCOME 8
In 2021, we focused on key business priorities supporting delivery of long-term shareholder value; safe and reliable base business; advancing
our growth projects (Scarborough, Pluto Train 2 and Sangomar) and maturing future opportunities.
2021 Performance:
Merger with BHP Petroleum
• In addition to the key Business Priorities, merger announced with BHP’s oil and gas portfolio to deliver increased scale, diversity and
resilience; provide financial strength to help fund planned developments in the near-term and invest in future energy opportunities and
return value to shareholders through the cycle.
Scarborough and Pluto Train 2 Final Investment Decisions
• Final Investment Decisions (FIDs) for Scarborough and Pluto Train 2 developments approved
• Sale and purchase agreement with Global Infrastructure Partners for 49% interest in the Pluto Train 2 Joint Venture
• Fully termed processing and services agreement to process Scarborough gas through Pluto LNG facilities
• Issued full notice to proceed to key Scarborough contractors for offshore project execution
Sangomar
• Sangomar Field Development Phase 1 48% complete and on track for targeted first oil in 2023
• Drilling commenced in July, first well completed
• Subsea offshore construction campaign: Vessel mobilisation deferred to Q1 2022 for cost and schedule optimisation
• Sales process launched and management presentations underway
Future Opportunities
• US H2OK 290MW FEED entry decision
• Heliogen 5MW FID approved
OVERALL CORPORATE PERFORMANCE OUTCOME
TARGET
MAX
OUTCOME 6
Woodside Petroleum Ltd 79
Executive KMP KPIs and outcomes for 2021
CEO KPIs and outcomes
In August 2021, Meg O’Neill was appointed CEO and
Managing Director. Ms O’Neill had been Acting CEO since
20 April 2021 following Peter Coleman’s retirement.
Ms O’Neill’s incentive arrangements are governed under
the EIS.
FAR
Ms O’Neill’s FAR was increased to A$2,200,000 on
appointment to CEO and Managing Director. The FAR for
Ms O’Neill is 18.5 per cent less than the FAR paid to her
predecessor, Mr Coleman. The Board considers that Ms
O’Neill’s remuneration is competitive and benchmarks
appropriately to peer companies. It is anticipated that the
CEO’s remuneration will be reviewed following completion
of the merger of Woodside and BHP’s oil and gas portfolios.
Upon Ms O'Neill's appointment to CEO and Managing
Director, the Board approved the accelerated vesting of
37,048 Restricted Shares as set out in Table 12 on page 89.
Each vested Restricted Share entitled Ms O’Neill to receive
one Woodside share.
VAR
For 2021, the individual performance of the CEO was
reviewed by the Board against five equally weighted
measures. These metrics, outlined in Table 4, were chosen
because successful performance in each area is a key driver
of superior shareholder returns.
The same metrics were cascaded to the Senior Executives
to measure individual performance.
At the end of the year, the Board reviews the CEO’s
performance for that year. The CEO is given an individual
performance score of between 0 and 1.6, which together
with the Corporate Scorecard outcome results in an IPF.
The CEO’s overall IPF for 2021 resulted in an award of
75.6% of maximum opportunity.
Ms O'Neill. Mr Coleman's EIS award earned as a percentage
of maximum opportunity is 72%. The Board exercised its
discretion to award Mr Coleman cash in lieu of the Restricted
Shares component of his EIS award. The Performance Rights
component of the award is subject to a three-year deferral
period with a RTSR test three years after the date of
allocation.
No termination payments were made on cessation of Mr
Coleman’s employment, other than a payment in lieu of a
portion of his contractual notice period and his statutory
leave entitlements. Amounts payable to Mr Coleman in 2021
are shown in Table 10 on page 88.
Senior Executive FAR
In August 2021, Woodside conducted a review of Senior
Executive remuneration based on benchmarking data
against a defined peer group alongside the consideration
of executive performance and role accountabilities. The
Committee approved the continued freeze on FAR and
considers that Senior Executive remuneration remains
competitive. Senior Executive remuneration will be reviewed
following completion of the merger of Woodside and BHP’s
oil and gas portfolios to ensure it remains competitive
and appropriate given any changes in role scope and
accountabilities.
Senior Executive VAR and other incentives
For 2021, the individual performance of each Senior
Executive was evaluated against the same performance
measures as the CEO, with individual KPIs set relevant to
each Senior Executive's area of responsibility. These metrics
aim to align individual performance with the achievement of
Woodside’s corporate strategy while fostering collaboration
between Executives.
The Board approved EIS awards to Senior Executives based
on the Corporate Scorecard result and their individual
performance assessment, resulting in an IPF between 0 and 1.6.
The 2021 EIS award for the CEO is detailed in Table 7
on page 84.
Information on the individual performance of the CEO is
shown in Table 4 on page 81.
Information on the individual performance of Executives
who were KMP as at 31 December 2021 is shown in Table
4 on page 82. Details of the EIS award for each Senior
Executive are set out in Table 7 on page 84.
Former CEO and Managing Director
Peter Coleman ceased to be CEO and Managing Director
on 19 April 2021 and departed Woodside on 3 June 2021.
In accordance with the terms of his contract, Mr Coleman
is eligible for a 2021 EIS award for the period in which he
remained in service. The 2021 award for Mr Coleman is
detailed in Table 7 on page 84.
Mr Coleman was key to the delivery of a number of
achievements in 2021 including the approval of FIDs for the
Scarborough and Pluto Train 2 developments. He facilitated
a smooth transition of CEO and Managing Director to
Ms Duhe was not eligible for a 2021 EIS award as she
resigned during the period. No individual performance
assessment has been included for Ms Duhe.
For 2021, Woodside made one-off cash bonus payments
to two Executive KMP, Shaun Gregory (A$170,700) and Ms
Duhe (two payments totaling A$220,000), in connection
with discretionary efforts related the merger with BHP's oil
and gas portfolio and the Scarborough and Pluto Train 2
FIDs. These payments are detailed in Table 5 on page 83 and
Table 10 on page 88.
80 Annual Report 2021
TABLE 4 – CEO AND SENIOR EXECUTIVE INDIVIDUAL PERFORMANCE FOR 2021 EIS
MEG O’NEILL – CEO AND MANAGING DIRECTOR
KPI
Performance
Outcome
Growth agenda
Assesses the alignment of growth opportunities to
shareholder return; portfolio balance; the achievement of
challenging business objectives.
Effective execution
Assesses the maintenance, operation and profitability of
existing assets; project delivery to achieve budget, schedule
and stated performance; cost reduction; achievement of
health, safety and community expectations.
Enterprise capability
Assesses leadership development; workforce planning;
executive succession; Indigenous participation and diversity;
effective risk identification and management.
Culture and reputation
Assesses performance culture and emphasis on values;
engagement and enablement; improved employee climate;
Woodside’s brand as a partner of choice.
Shareholder focus
Assesses whether decisions are made with a long-term
shareholder return focus; efficient and timely communication
to shareholders, market analysts and fund managers; the
focus on shareholder return throughout the organisation.
• Executed agreements to merge with BHP’s oil and gas portfolio
• Achieved FIDs on Scarborough and Pluto Train 2 with compelling
commercial outcomes
• Advanced Woodside strategy to transform the way we work in response to
the energy transition, including clear targets and metrics
• Set financial return targets and $5 billion investment target by 2030 for new
Above
target
energy investments
• Growth agenda for energy transition materially progressed by four
new energy opportunities and strategic partnerships established across
value chain
• Personal safety performance failed to meet the target, although process
safety was strong
• Abatement of greenhouse gas emissions was well above target
• Production within range but below budget
• Production operating costs were under budget. Total operating expenditure
was over budget, primarily due to costs associated with the merger with
BHP’s oil and gas portfolio
On
target
• Executed LNG SPAs with Uniper and RWE
• Sangomar execution on schedule and on budget
•
•
•
•
Identified and took steps to address areas of cultural focus, including
maturing commercial capability across the business and improving
transparency
Implemented value at risk framework to underpin growth of trading portfolio
Implemented new ways of working including leadership development,
refreshed Inclusion and Diversity strategy, enhanced approach to flexible
working policy and endorsing Working Respectfully Policy
Increased female and Indigenous representation across organisation
• Provided a clear vision for Woodside’s desired culture, including to
address the potential for bullying and harassment in the workplace whist
encouraging an environment where people can speak up and debate
• Led a cohesive and effective executive team during a significant phase
of growth and in response to the ongoing challenges of the COVID-19
pandemic
• Refreshed Woodside Compass with focus on trust, transparency and
courage
On
target
Above
target
• Executed selldown of 49% equity in Pluto Train 2 to Global Infrastructure
Partners
• Launched Woodside Transformation to drive cultural shift with increased
accountability and streamlined decision-making to enhance cost focus
whilst maintaining operational discipline
On
target
• Exit from Kitimat LNG to focus on higher value opportunities
EIS earned as percentage of maximum opportunity1
75.6%2
1 The award of Restricted Shares and Performance Rights is subject to shareholder approval at the 2022 Woodside Annual General Meeting.
2 Ms M O'Neill's EIS structure changed following her appointment as CEO and Managing Director on 17 August 2021, including her target and maximum award. Her 2021 EIS award was calculated
on a pro-rata basis including target and maximum opportunity.
Woodside Petroleum Ltd
81
SHAUN GREGORY – EXECUTIVE VICE PRESIDENT SUSTAINABILITY AND CHIEF TECHNOLOGY OFFICER
KPI
Performance
Growth agenda
Assesses the alignment of growth opportunities to
shareholder return; portfolio balance; the achievement of
challenging business objectives.
Effective execution
Assesses the maintenance, operation and profitability of
existing assets; project delivery to achieve budget, schedule
and stated performance; cost reduction; achievement of
health, safety and community expectations.
Enterprise capability
Assesses leadership development; workforce planning;
executive succession; Indigenous participation and diversity;
effective risk identification and management.
Culture and reputation
Assesses performance culture and emphasis on values;
engagement and enablement; improved employee climate;
Woodside’s brand as a partner of choice.
Shareholder focus
Assesses whether decisions are made with a long-term
shareholder return focus; efficient and timely communication
to shareholders, market analysts and fund managers; the
focus on shareholder return throughout the organisation.
• Commercial and technical progress across New Energy opportunity portfolio
• Secured carbon offsets to meet 2025 net emissions reduction target
• Safety and efficiency improvements delivered to business through robotics and
technology
• Safely completed Korea 3D seismic survey acquisition
• High-performing system availability and cyber security systems
• Matured data platforms to improve digital and cyber organisational capabilities
On target
and enable personnel
• Advanced strategic partnerships covering technology and New Energy market
development
• Below budget exploration and operating expenditure for carbon, technology
and digital
• Focus on successful delivery of nearer-term, higher value opportunities
• No commercial discovery from Myanmar exploration campaign
EIS earned as percentage of maximum opportunity
73.1%
FIONA HICK – EXECUTIVE VICE PRESIDENT OPERATIONS
KPI
Performance
Growth agenda
Assesses the alignment of growth opportunities to
shareholder return; portfolio balance; the achievement of
challenging business objectives.
Effective execution
Assesses the maintenance, operation and profitability of
existing assets; project delivery to achieve budget, schedule
and stated performance; cost reduction; achievement of
health, safety and community expectations.
Enterprise capability
Assesses leadership development; workforce planning;
executive succession; Indigenous participation and diversity;
effective risk identification and management.
Culture and reputation
Assesses performance culture and emphasis on values;
engagement and enablement; improved employee climate;
Woodside’s brand as a partner of choice.
Shareholder focus
Assesses whether decisions are made with a long-term
shareholder return focus; efficient and timely communication
to shareholders, market analysts and fund managers; the
focus on shareholder return throughout the organisation.
• Support to international growth projects, Scarborough and Pluto Train 2 FIDs
and base business and projects
Injury rate higher than target
• Zero Tier 1 or Tier 2 process safety events
•
• Production within market guidance but below internal target
• Reliability above target for gas facilities but below for oil facilities
• Emissions reductions above target including due to strong reliability and
delivery of emissions reduction projects
• Seven turnaround maintenance campaigns (offshore and onshore), Woodside's
largest ever planned maintenance campaign
• Material progress on decommissioning obligations
• Matured capability across operating assets to manage significant challenges
including organisational change and the impacts of COVID-19 and border
closures on personnel and supply chain
Improved inclusion and diversity performance in Operations
•
• Key role in implementation of Woodside's new leadership development
framework in Operations
• Values focus demonstrated through significant challenges including impacts of
COVID-19 and organisational change
• Disciplined cost focus
•
Implemented transformation initiatives
EIS earned as percentage of maximum opportunity
69.4%
Outcome
Above
target
Above
target
Above
target
On target
Outcome
On target
Below
target
Above
target
On target
Above
target
CEO actual remuneration
FIXED REWARD 32.4%
Senior Executive actual remuneration1
FIXED REWARD 35.4%
VARIABLE REWARD 67.6%
VARIABLE REWARD 64.6%
1 This represents an average of all Senior Executives’ actual and variable remuneration for 2021. It does not not include Ms S Duhe who was not eligible for a 2021 EIS award.
82 Annual Report 2021
The following table details the CEO and Senior Executives’
take home pay. This table has been included to provide
greater transparency to shareholders of the take home pay
received or receivable by the CEO and Senior Executives in
2020 and 2021. This includes FAR, EIS cash awards earned
in respect of performance for the year and the value of
shares and rights which vested during the year calculated
using the five-day VWAP leading up to but not including the
vesting, forfeiture or lapsing date. Termination benefits are
not included in the table below; these amounts are disclosed
in Table 10 on page 88. Amounts are shown in AUD (the
currency in which the remuneration is paid), whereas Table 10
is expressed in USD which is Woodside’s reporting currency.
Take home pay differs from statutory remuneration reported
in Table 10 that is prepared in accordance with the
Corporations Act 2001 (Cth) and Accounting Standards which
require share-based payments to be reported as remuneration
from the time of grant, even though actual value may
ultimately not be realised from these share-based payments.
TABLE 5 – CEO AND SENIOR EXECUTIVE TAKE HOME PAY TABLE (NON-IFRS INFORMATION)
Salary,
allowances and
superannuation1
A$
EIS cash
and other
cash
incentives2
A$
Restricted
Shares vested3
A$
RTSR tested
VPRs vested3
A$
Equity
Rights vested3
A$
Total
remuneration
received
A$
Previous
years' awards
forfeited or
lapsed3
A$
1,906,872
465,168
1,647,167
1,471,330
-
823,331
360,778
821,739
-
750,091
177,667
568,396
-
-
122,257
222,183
52,486
65,632
-
-
137,129
123,659
80,822
19,651
1,149,246
1,723,075
957,150
2,035,462
2,701,000
-
1,522,420
1,835,255
1,024,439
220,000
1,091,798
-
11,110
-
-
-
-
-
-
4,019,207
1,471,330
-
-
1,443,495
204,377
31,658
1,199,239
-
1,061,066
31,658
685,337
84,155
30,286
-
5,864,933
3,031,953
6,058,675
1,248,406
1,255,549
346,775
1,438,573
-
-
-
-
-
Name
M O’Neill
S Gregory
F Hick
P Coleman5, 6
S Duhe7
Year
2021
20204
2021
20204
2021
20204
2021
20204
2021
20204
1 Represents the total fixed annual rewards earned in 2021 and 2020 including salaries, fees, allowances and company contributions to superannuation. This may differ from amounts disclosed in
Table 10 which reflects pro-rated amounts for the period that Executives were in KMP roles, except for Mr P Coleman whose FAR is disclosed based on his contract end date.
2 Includes the EIS cash incentive earned in the respective year, which is actually paid in the following year. This is calculated on the same basis as amounts disclosed in Table 10. There was no EIS
cash incentive earned in 2020.
3 The value of Restricted Shares, Variable Pay Rights and Equity Rights is calculated using the five-day VWAP leading up to but not including the vesting or forfeiture or lapsing date.
4 For the 2020 EIS Awards, the Board exercised its discretion to reduce VAR by 30%.
5 The 2020 EIS Award to Mr P Coleman (allocated in April 2021) was allocated in Performance Rights in lieu of cash and Restricted Shares. Mr P Coleman's 2021 EIS award was allocated in cash in
lieu of Restricted Shares.
6 Mr P Coleman ceased being an Executive KMP on 19 April 2021.
7 Ms S Duhe ceased being an Executive KMP on 4 February 2022.
TABLE 6 – 2021 VESTINGS1
2017 deferred short-term award Restricted Shares vested on 20 February 2021
2016 long-term award VPRs had a partial vesting of 63% on 9 March 2021
2015 long-term award VPRs had a partial vesting of 9.2% on 9 March 20212
2018 Restricted Shares sign on bonus vested on 1 May 2021
2018 Restricted Shares sign on bonus vested on 17 August 2021
1 Amounts that vested in 2021 (other than for Ms M O'Neill) relate to prior schemes as outlined on pages 89-90.
2 This was the second test for the 2015 award. Overall, 47.5% of the total 2015 award vested.
Executive
S Gregory
F Hick
P Coleman
S Duhe
S Gregory
F Hick
P Coleman
S Gregory
F Hick
P Coleman
M O’Neill
M O’Neill
Shares
4,831
2,074
37,822
439
4,502
3,010
66,822
963
211
14,297
37,048
37,048
Woodside Petroleum Ltd 83
TABLE 7 – VALUATION SUMMARY OF EXECUTIVE KMP EIS FOR 2021 AND 2020
Name
M O’Neill
S Gregory
F Hick
P Coleman4,5
S Duhe6
Year
20212
20203
20212
20203
20212
20203
20212
20203
2021
20203
Cash1
$
337,421
-
137,878
-
128,875
-
1,249,873
-
-
-
Restricted Shares
3-year vesting
period
$
Restricted Shares
5-year vesting
period
$
Performance
Rights 3-year
vesting period
$
Performance
Rights 5-year
vesting period
$
745,559
309,344
304,645
177,107
284,757
146,255
-
-
-
813,351
309,344
332,344
177,107
310,643
146,255
-
-
-
225,387
225,387
-
-
-
-
-
-
455,488
2,133,567
-
-
688,613
426,616
281,375
244,243
263,002
201,700
-
-
-
310,849
Total EIS
$
2,584,944
1,045,304
1,056,242
598,457
987,277
494,210
1,705,361
2,133,567
-
761,623
1 Represents the cash incentive earned in the respective year, which is actually paid in the following year. Amounts were translated to USD using the closing spot rate on 31 December. There was
no cash incentive earned in 2020.
2 The number of Restricted Shares and Performance Rights allocated for 2021 was calculated by dividing the amount of the Executive's entitlement allocated to Restricted Shares and
Performance Rights by the face value of Woodside shares. The USD fair value of Restricted Shares and Performance Rights at their date of grant has been estimated by reference to the closing
share price at 31 December 2021 and preliminary modelling respectively. Grant date for Senior Executives' awards has been determined to be the date of the Board of Directors' approval, being
16 February 2022 while grant date for Ms M O’Neill's award is the date of shareholder approval at the 2022 Woodside Annual General Meeting. Any differences between the estimated fair value
at 31 December 2021 and the final fair value will be trued-up in the following 2022 financial year. The fair value is not related to or indicative of the benefit (if any) that an individual Executive
may ultimately realise should these equity instruments vest.
3 The number of Restricted Shares and Performance Rights allocated for 2020 was calculated post year-end by dividing the amount of the Executive’s entitlement allocated to Performance
Rights by the face value of Woodside’s shares. The USD fair value shown above was estimated at 31 December 2020 with reference to the closing share price and preliminary modelling. Grant
date for all Executives apart from Mr P Coleman has been determined to be the date of the Board of Directors' approval, being 17 February 2021. The grant date for Mr P Coleman has been
determined to be the date of shareholder approval at the 2021 Woodside Annual General Meeting. The final fair value was calculated at these dates and was trued-up in the 2021 financial year.
The amount above is not related to or indicative of the benefit (if any) that an individual Executive may ultimately realise should these equity instruments vest.
4 Mr P Coleman's 2020 EIS Award was allocated in Performance Rights in lieu of cash and Restricted Shares. Mr P Coleman's 2021 EIS award was allocated in cash in lieu of Restricted Shares.
5 Mr P Coleman ceased being an Executive KMP on 19 April 2021.
6 Ms S Duhe ceased being an Executive KMP on 4 February 2022.
Other equity plans
Woodside has a history of providing employees with the
opportunity to participate in ownership of shares in the
company and using equity to support a competitive base
remuneration position, including the legacy Executive
Incentive Plan.
Details of prior year allocations are provided in Table 12 on
pages 89-90. The terms applying to prior year grants are
described in past Woodside Annual Reports.
Executive Incentive Plan (EIP)
The EIP operated as Woodside’s Executive incentive
framework until the end of 2017, after which the Board
introduced the EIS. The EIP was used to deliver short-term
award (STA) and long-term award (LTA) to Senior Executives.
Eligible Executives could only receive an STA award if their
individual annual performance was assessed as acceptable.
Participants were then divided into “Pool Groups”, with the
size of the pool determined by each participant’s target STA,
and then adjusted based on the Corporate Scorecard result.
STA made up 30-33% of total target remuneration for Senior
Executives with no individual maximum STA opportunity
because the size of the STA pool varied from year to year
depending on performance and other factors. LTA was
granted in the form of Variable Pay Rights (VPRs) making up
20-22% of total target remuneration for Senior Executives.
The LTA award was divided into two portions with each
portion subject to a separate RTSR performance hurdle
tested over a four-year period. One-third of the LTA is tested
against a comparator group that comprises the entities
within the ASX 50 index. The remaining two-thirds is tested
against an international group of oil and gas companies.
RTSR outcomes are calculated by an external adviser on
the fourth anniversary of the allocation. For 2017 awards
to Senior Executives, any VPRs that do not vest will lapse
and are not retested. Awards made to other Executives are
eligible for a retest in the following year. VPRs that do not
vest following the re-test will lapse. 2017 is the last year of
award to which a retest applies.
Executives are entitled to receive dividends on Restricted
Shares. There is no entitlement to dividends on VPRs.
Details of prior year allocations are provided in Table 12
on pages 89-90.
Peter Coleman’s STA and LTA
The former CEO’s incentive arrangements are governed by
his contract of employment. Prior to 2018, the former CEO’s
STA award was determined by multiplying the former CEO’s
FAR by the Corporate Scorecard result and the former CEO’s
individual performance factor as determined by the Board.
Two-thirds of the award was paid in cash with the remaining
third delivered as a deferred equity award of Restricted
Shares, subject to an overall cap of two times FAR.
84 Annual Report 2021
For 2017, the LTA opportunity was set at 133% of the former
CEO’s FAR. The entitlement was allocated at face value and
in the form of VPRs and divided into two portions with each
subject to a separate RTSR performance hurdle tested over
a four year period with no retest. One-third of the LTA will be
tested against a comparator group that comprises the entities
within the ASX 50 index. The remaining two-thirds will be
tested against an international group of oil and gas companies.
Details of prior year allocations are provided in Table 12 on
pages 89-90.
Woodside Equity Plan (WEP)
The WEP is available to all permanent employees except EIS
participants. The purpose of the WEP is to enable eligible
employees to build up a holding of equity in the company as
they progress through their career at Woodside.
The number of Equity Rights (ERs) offered to each eligible
employee is determined by the Board, and based on individual
performance as assessed under the performance review
process. There are no further ongoing performance conditions.
The linking of performance to an allocation allows
Woodside to recognise and reward eligible employees
for high performance.
Each ER entitles the participant to receive a Woodside
share on the vesting date three or five years after the
effective grant date.
For offers prior to 2019, each ER entitled the participant to
receive a Woodside share on the vesting date three years
after the effective grant date. For subsequent awards, the
Board amended the terms of the Plan to allow for 75% vesting
of the ERs three years after the effective grant date and the
remaining 25% of ERs five years after the effective grant date.
Supplementary Woodside Equity Plan (SWEP)
In October 2011, the Board approved a remuneration strategy
which includes the use of equity to support a competitive
base remuneration position. To this end, the Board approved
the establishment of the SWEP to enable the offering of
targeted retention awards of ERs for key capability.
The SWEP was designed to be offered to a small number
of employees identified as being retention critical. The
SWEP awards have service conditions and no performance
conditions. Each ER entitles the participant to receive a
Woodside share on the vesting date three years after the
effective grant date.
There were no allocations under the SWEP in 2021. None of the
Senior Executives have unvested SWEP ERs at the end of 2021.
ERs under both the WEP and the SWEP may vest prior to
the vesting date on a change of control or on a pro-rata
basis, at the discretion of the CEO, limited to the following
circumstances; redundancy, retirement (after six months’
participation), death, termination due to illness or incapacity
or total and permanent disablement of a participating
employee. An employee whose employment is terminated by
resignation or for cause prior to the vesting date will forfeit
all of their ERs.
Minimum Shareholding Requirements (MSR) Policy
The Executive MSR policy reflects the long-term focus of
management and aims to further strengthen alignment with
shareholders.
The policy requires Senior Executives to have acquired and
maintained Woodside shares for a minimum total purchase
price of at least 100% of their fixed remuneration after a
period of five years, and in the case of the CEO a minimum
of 200% of fixed remuneration.
Other equity awards
In February 2018, the Board approved the Equity Award Rules
which apply to EIS and discretionary executive allocations.
This allows the Board and CEO to award discretionary
allocations of Restricted Shares or Performance Rights.
Contracts for Executive KMP
Each Executive KMP has a contract of employment.
Table 8 below contains a summary of the key contractual
provisions of the contracts of employment for the continuing
Executive KMP.
TABLE 8 – SUMMARY OF CONTRACTUAL PROVISIONS FOR EXECUTIVE KMP
M O’Neill3
S Gregory3
F Hick3
Employing company
Contract duration
Woodside Energy Ltd
Woodside Energy Ltd
Woodside Energy Ltd
Unlimited
Unlimited
Unlimited
Termination notice
period company1, 2
Termination notice
period executive
6 months
6 months
6 months
6 months
3 months
3 months
1 Woodside may choose to terminate the contract immediately by making a payment in lieu of notice equal to the fixed remuneration the Executive KMP would have received during the
‘Company Notice Period’. In the event of termination for serious misconduct or other nominated circumstances, Executive KMP are not entitled to this termination payment. Any payments
made in the event of a termination of an executive contract will be consistent with the Corporations Act 2001 (Cth).
2 On termination of employment, Executive KMP will be entitled to the payment of any fixed remuneration calculated up to the termination date, any leave entitlement accrued at the termination
date and any payment or award permitted under the EIS and Equity Award Rules. Executive KMP are restrained from certain activities for specified periods after termination of their
employment in order to protect Woodside’s interests.
3 Remuneration is reviewed annually or as required to maintain alignment with policy and benchmarks.
Woodside Petroleum Ltd 85
Non-executive directors
Remuneration Policy
Woodside’s Remuneration Policy for NEDs aims to attract,
retain, motivate and to remunerate fairly and responsibly
having regard to:
• the level of fees paid to NEDs relative to other major
Australian companies
• the size and complexity of Woodside’s operations
• the responsibilities and work requirements of Board
members.
Fees paid to NEDs are recommended by the Committee
based on benchmarking from external remuneration
consultants and determined by the Board. In 2021, the Board
determined that there would be no increase to the Board or
committee fees or any other benefits.
Fees paid to NEDs are subject to an aggregate limit of
A$4.25 million per financial year, which was approved by
shareholders at the 2019 AGM.
NEDs are required to have acquired shares for a total
purchase price of at least 100% of their pre-tax annual fee
after five years on the Board. The NEDs may utilise the
Non-executive Directors’ Share Plan (NEDSP) to acquire the
shares on market at market value. As the shares are acquired
with net fees, the shares in the NEDSP are not subject to any
forfeiture conditions.
NEDs remuneration structure
NEDs remuneration consists of base Board fees and
committee fees, plus statutory superannuation contributions
or payments in lieu (currently 10%). Other payments may
be made for additional services outside the scope of Board
and Committee duties. NEDs do not earn retirement benefits
other than superannuation and are not entitled to any form
of performance-linked remuneration in order to preserve
their independence.
Table 9 below shows the annual base Board and committee
fees for NEDs. There has been no change to Board or
committee fees since 2019.
In addition to these fees, NEDs are entitled to reimbursement
of reasonable travel, accommodation and other expenses
incurred attending meetings of the Board, committees or
shareholders, or while engaged on Woodside business.
NEDs are not entitled to compensation on termination of
their directorships.
An allowance is paid to any NED required to travel
internationally to attend Board commitments, compensating
for factors related to long-haul travel. Where travel is
between six and ten hours, an allowance of A$5,000 gross
per trip is paid. Where travel exceeds 10 hours, an allowance
of A$10,000 gross per trip is paid.
In 2021, NEDs Frank Cooper, Ben Wyatt and Larry Archibald
received an additional payment of A$20,000 each for
services provided during the period outside the scope
of Board and Committee duties, in connection with the
proposed merger with BHP Group’s oil and gas portfolio,
including membership of the Due Diligence Committee.
Board fees are not paid to the CEO, as the time spent on
Board work and the responsibilities of Board membership
are considered in determining the remuneration package
provided as part of the normal employment conditions.
The total remuneration paid to, or in respect of, each NED
in 2021 is set out in Table 13 on page 90.
TABLE 9 – ANNUAL BASE BOARD AND COMMITTEE FEES FOR NEDS
Position
Chairman of the Board2
Non-executive directors3
Committee chair
Committee member
Board1
A$
723,300
219,178
Audit & Risk
Committee
A$
Human Resources
& Compensation
Committee
A$
Sustainability
Committee
A$
Nominations
& Governance
Committee
A$
59,360
31,964
52,000
26,500
47,400
23,700
Nil
Nil
1 NEDs receive Board and committee fees plus statutory superannuation (or payments in lieu where statutory superannuation is not required to be paid).
2 Inclusive of committee work.
3 Board fees paid to NEDs other than the Chairman.
86 Annual Report 2021
Human Resources & Compensation
Committee
The Committee assists the Board to determine appropriate
remuneration policies and structures for NEDs and
Executives. Further information on the role of the Committee
is described in section 3.4 of the Corporate Governance
Statement, available on Woodside’s website.
Use of remuneration consultants
From time to time, the Committee may directly engage
independent external advisers to provide input to the
process of reviewing the remuneration for NEDs and
Executives. The Committee may receive executive
remuneration advice directly from external independent
remuneration consultants.
Under communications and engagement protocols adopted
by the company, market data reports are provided directly to
the Committee Chair, and a consultant provides a statement
to the Committee that reports have been prepared free of
undue influence from Executive KMP. This process ensures
the Committee has full oversight of the review process
and therefore it, and the Board, can be satisfied that the
work undertaken by external independent remuneration
consultants is free from undue influence by Executive KMP.
No executive remuneration advice was obtained from
external independent remuneration consultants in 2021
and there were no fees payable to independent external
remuneration consultants during the period.
No loans have been made, guaranteed or secured, directly
or indirectly, by Woodside or any of its subsidiaries at any
time throughout the year, to any KMP including to a KMP
related party.
Reporting notes
Reporting in United States dollars
In this report, the remuneration and benefits reported have
been presented in US dollars, unless otherwise stated. This is
consistent with the functional and presentation currency of
the company.
Compensation for Australian-based employees and all
KMP is paid in Australian dollars and, for reporting purposes,
converted to US dollars based on the applicable exchange
rate at the date of payment. Valuation of equity awards is
converted at the spot rate applying when the equity award
is granted.
Woodside Petroleum Ltd 87
Statutory tables
TABLE 10 - COMPENSATION OF CEO AND SENIOR EXECUTIVES FOR THE YEAR ENDED 31 DECEMBER 2021 AND 2020
FAR
VAR and other
incentives
Short-term
Post-
employment
Salaries,
fees and
allowances
Non-
monetary
benefits1
Company
contributions to
superannuation
$
2021
1,431,531
52,614
2020
1,012,177
56,808
$
-
-
Share-
based
payments
Share
plans3
Long
service
leave
Termination
benefits
Total
remuneration4
Performance
related5
$
$
$
$
A$
Cash
Cash2
$
337,421
1,515,992
129,123
- 3,466,681 4,633,501
-
1,066,937
40,928
2021
588,690
15,788
29,403
261,6999
557,279
18,260
2020
550,615
20,381
14,687
-
485,293
24,010
2021
540,368
29,989
22,742
128,875
390,418
11,742
2020
205,773
9,006
9,030
-
150,268
37,37110
-
-
-
-
-
2,176,850 3,164,334
1,471,119
1,971,787
1,094,986
1,591,702
1,124,134 1,503,402
411,448
569,568
2021
879,481
51,506
8,380 1,249,873
4,178,652 543,355
2,447,525 9,358,772 12,219,216
2020 1,843,422
38,301
14,686
-
4,022,663
75,827
- 5,994,899 8,714,358
2021
752,079
120,182
16,990 159,5829
(1,033,319)
14,743
2020
751,084
42,220
-
-
597,006
31,213
-
-
30,257
47,732
1,421,523 2,066,367
%
53
49
56
44
46
37
58
67
-
42
M O’Neill
Chief Executive Officer
and Managing Director6
S Gregory
Executive Vice President
Sustainability and Chief
Technology Officer
F Hick
Executive Vice
President Operations
P Coleman8
S Duhe6, 7
1 Reflects the value of non-monetary benefits (including relocation, travel, car parking and any associated fringe benefit tax).
2 The amount includes the EIS cash incentive earned in the respective year, which is actually paid in the following year. Amounts were translated to USD using the closing spot rate on 31
December. There was no cash incentive earned in 2020.
3 ‘Share plans’ incorporate all equity based plans. In accordance with the requirements of AASB 2 Share-based Payment, the fair value of rights as at their date of grant has been determined by
applying the Black-Scholes option pricing technique or applying the binomial valuation method combined with a Monte Carlo simulation. The fair value of rights is amortised over the vesting
period from the commencement of the service period, such that ‘total remuneration’ includes a portion of the fair value of unvested equity compensation during the year. The portion of the
expense relating to the 2021 EIS has been measured using estimated fair values as disclosed in footnote 2 in Table 7. The amount included as remuneration is not related to or indicative of the
benefit (if any) that individual Executives may ultimately realise should these equity instruments vest.
4 The total remuneration in AUD is converted from USD using the average exchange rate for the period. This non-IFRS information is included for the purposes of showing the total annual cost of
benefits to the company in Australian dollars for the service period.
5 Performance related outcome percentage is calculated as total Variable Annual Reward divided by the total USD remuneration figure.
6 As a non-resident for Australian tax purposes Ms M O’Neill elected to receive a cash payment in lieu of all superannuation contributions in accordance with the Superannuation Guarantee
(Administration) Act 1992. The cash payment is subject to (PAYG) income tax and paid as part of Ms M O’Neill’s normal monthly salary. The amount is included in salaries, fees and allowances.
Ms S Duhe became a resident for Australian tax purposes effective 1 June 2021 and received superannuation contributions following this date. Prior to 1 June 2021, Ms S Duhe elected to receive
a cash payment in lieu of superannuation contributions.
7 In accordance with the requirements of AASB 2 Share-based Payment, Ms S Duhe’s 2018, 2019, 2020 and 2021 share-based payment amortisation expenses have reversed following her notice
of resignation on 16 November 2021.
8 Mr P Coleman ceased being an Executive KMP on 19 April 2021. In accordance with the requirements of AASB 2 Share-based Payment, his 2018, 2019, 2020 and 2021 share-based payment
amortisation expenses have accelerated based on his contract end date of 3 June 2021. This is not reflective of any value received by Mr Coleman as the awards have not vested at 31
December 2021 and are subject to vesting conditions. Vesting details of these awards are disclosed in Table 12 on page 89. Mr P Coleman's FAR is disclosed to 3 June 2021.
9 Cash awards received by Mr S Gregory and Ms S Duhe include a cash bonus payment of $123,821 and $50,776 respectively upon signing of the merger commitment deed announced to ASX on
17 August 2021. Ms S Duhe received a further cash bonus payment of $108,806 in connection with efforts related to the merger share sale agreement and the Scarborough and Pluto Train 2 FIDs.
10 Ms F Hick's long service leave accrued in 2020 has been updated to reflect the period she was an Executive KMP from 1 July 2020 to 31 December 2020.
TABLE 11 - PEER GROUP OF INTERNATIONAL OIL AND GAS COMPANIES1
APA Corporation (previously Apache Corporation)
EOG Resources
Beach Energy
Canadian Natural Resources
ConocoPhillips
ENI S.p.A
Equinor ASA
Hess Corporation
Inpex Corporation
Marathon Oil Company
Occidental Petroleum
Origin Energy Limited
Santos Ltd2
1 Peer group updated for 2021 EIS award to reflect recent changes including merger and acquisition activity in the prior year’s peer group.
2 Oil Search Limited and Santos Limited merged effective 17 December 2021. Oil Search Limited was removed from the Official List of ASX on 20 December 2021.
88 Annual Report 2021
Vested
in 2021
% of total
vested
Lapsed
in 2021
Fair value
of equity4,5,6
TABLE 12 – SUMMARY OF CEO AND SENIOR EXECUTIVES’ ALLOCATED, VESTED OR LAPSED EQUITY
Name
Type of equity1
Grant date
Allocation date
Vesting date2,3
M O’Neill8
Restricted Shares
13 February 2019
19 February 2019
19 February 2022
Restricted Shares
13 February 2019
19 February 2019
19 February 2024
Restricted Shares
12 February 2020
18 February 2020
18 February 2023
Restricted Shares
12 February 2020
18 February 2020
18 February 2025
Restricted Shares
17 February 2021
24 February 2021
24 February 2024
Restricted Shares
17 February 2021
24 February 2021
24 February 2026
Restricted Shares
19 May 2022
Restricted Shares
19 May 2022
Restricted Shares
1 May 2018
Restricted Shares
1 May 2018
19 May 2022
19 May 2022
1 May 2018
1 May 2018
19 May 2025
19 May 2027
1 May 2021
17 August 2021
Awarded
but not
vested
14,097
15,379
15,025
16,391
17,697
17,697
46,861
51,122
-
-
-
-
-
-
-
-
-
-
37,048
37,0488
Performance Rights
13 February 2019
19 February 2019
19 February 2024
Performance Rights
12 February 2020
18 February 2020
18 February 2025
Performance Rights
17 February 2021
24 February 2021
24 February 2026
Performance Rights
19 May 2022
19 May 2022
19 May 2027
15,379
16,391
23,596
51,122
-
-
-
-
S Gregory
Restricted Shares
1 January 2017
20 February 2018
20 February 2021
-
4,831
100
Restricted Shares
13 February 2019
19 February 2019
19 February 2022
Restricted Shares
13 February 2019
19 February 2019
19 February 2024
Restricted Shares
12 February 2020
18 February 2020
18 February 2023
Restricted Shares
12 February 2020
18 February 2020
18 February 2025
Restricted Shares
17 February 2021
24 February 2021
24 February 2024
Restricted Shares
17 February 2021
24 February 2021
24 February 2026
Restricted Shares
16 February 2022
23 February 2022
23 February 2025
12,430
13,560
10,099
11,018
10,132
10,132
19,148
Restricted Shares
16 February 2022
23 February 2022
23 February 2027
20,889
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
100
100
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
RTSR Tested VPRs
1 January 2015
19 February 2016
9 March 2021
RTSR Tested VPRs
1 January 2016
27 February 2017
9 March 2021
-
-
963
4,502
9.2
63.0
5,499
2,646
RTSR Tested VPRs
1 January 2017
20 February 2018
20 February 2022
Performance Rights
13 February 2019
19 February 2019
19 February 2024
Performance Rights
12 February 2020
18 February 2020
18 February 2025
Performance Rights
17 February 2021
24 February 2021
24 February 2026
Performance Rights
16 February 2022
23 February 2022
23 February 2027
7,1507
13,560
11,018
13,509
20,889
-
-
-
-
-
-
-
-
-
-
F Hick
Restricted Shares
1 January 2017
20 February 2018
20 February 2021
-
2,074
100
Restricted Shares
13 February 2019
19 February 2019
19 February 2022
Restricted Shares
13 February 2019
19 February 2019
19 February 2024
Restricted Shares
12 February 2020
18 February 2020
18 February 2023
Restricted Shares
12 February 2020
18 February 2020
18 February 2025
Restricted Shares
17 February 2021
24 February 2021
24 February 2024
Restricted Shares
17 February 2021
24 February 2021
24 February 2026
Restricted Shares
16 February 2022
23 February 2022
23 February 2025
Restricted Shares
16 February 2022
23 February 2022
23 February 2027
RTSR Tested VPRs
1 January 2015
19 February 2016
9 March 2021
RTSR Tested VPRs
1 January 2016
27 February 2017
9 March 2021
RTSR Tested VPRs
1 January 2017
20 February 2018
20 February 2022
Performance Rights
13 February 2019
19 February 2019
19 February 2024
Performance Rights
12 February 2020
18 February 2020
18 February 2025
Performance Rights
17 February 2021
24 February 2021
24 February 2026
Performance Rights
16 February 2022
23 February 2022
23 February 2027
6,807
7,426
5,501
6,002
8,367
8,367
17,898
19,525
-
1,7697
4,9447
7,426
6,602
11,156
19,525
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
211
3,010
9.2
63.0
-
-
-
-
-
-
-
-
-
-
P Coleman9 Restricted Shares
Restricted Shares
1 January 2017
20 February 2018
20 February 2021
-
37,822
100
13 February 2019
19 February 2019
19 February 2022
Restricted Shares
13 February 2019
19 February 2019
19 February 2024
Restricted Shares
12 February 2020
18 February 2020
18 February 2023
Restricted Shares
12 February 2020
18 February 2020
18 February 2025
61,660
67,266
61,083
45,812
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
1,207
-
-
-
-
-
-
-
-
-
-
-
RTSR Tested VPRs
1 January 2015
19 February 2016
9 March 2021
RTSR Tested VPRs
1 January 2016
27 February 2017
9 March 2021
-
-
14,297
66,822
9.2
63.0
81,587
39,245
RTSR Tested VPRs
1 January 2017
20 February 2018
20 February 2022
104,7977
Performance Rights
13 February 2019
19 February 2019
19 February 2024
Performance Rights
12 February 2020
18 February 2020
18 February 2025
Performance Rights
15 April 2021
15 April 20219
15 April 20249
Performance Rights
16 February 2022
23 February 2022
23 February 2025
67,266
45,812
118,007
33,815
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
24.71
24.71
22.76
22.76
20.18
20.18
15.91
15.91
24.45
24.45
16.87
15.81
14.44
13.47
22.49
24.71
24.71
22.76
22.76
20.18
20.18
15.91
15.91
17.39
12.05
12.06
16.87
15.81
14.44
13.47
22.49
24.71
24.71
22.76
22.76
20.18
20.18
15.91
15.91
17.39
12.05
12.06
16.87
15.81
14.44
13.47
22.49
24.71
24.71
22.76
22.76
17.39
12.05
12.06
16.87
15.81
11.66
13.47
Woodside Petroleum Ltd 89
Name
S Duhe10
Type of equity1
Grant date
Allocation date
Vesting date2,3
Awarded
but not
vested
Vested
in 2021
% of total
vested
Lapsed
in 2021
Fair value
of equity4,5,6
Restricted Shares
1 January 2017
20 February 2018
20 February 2021
-
439
100
Restricted Shares
13 February 2019
19 February 2019
19 February 2022
Restricted Shares
13 February 2019
19 February 2019
19 February 2024
Restricted Shares
12 February 2020
18 February 2020
18 February 2023
Restricted Shares
12 February 2020
18 February 2020
18 February 2025
Restricted Shares
17 February 2021
24 February 2021
24 February 2024
Restricted Shares
17 February 2021
24 February 2021
24 February 2026
RTSR Tested VPRs
1 January 2017
20 February 2018
20 February 2022
Performance Rights
13 February 2019
19 February 2019
19 February 2024
Performance Rights
12 February 2020
18 February 2020
18 February 2025
Performance Rights
17 February 2021
24 February 2021
24 February 2026
14,604
15,931
11,816
12,890
12,894
12,894
8687
15,931
12,890
17,193
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
22.49
24.71
24.71
22.76
22.76
20.18
20.18
12.06
16.87
15.81
14.44
1 For valuation purposes all VPRs and performance rights are treated as if they will be equity settled.
2 Vesting date and exercise date are the same. Vesting is subject to the satisfaction of vesting conditions. Full details of the vesting conditions for all prior year equity grants to Executive KMP are
included in the remuneration report for the relevant year. The minimum total value of the grants for future financial years is nil if relevant vesting conditions are not satisfied. An estimate of the
maximum possible total value in future financial years is the fair value at grant date multiplied by the number of equity instruments awarded.
3 Any RTSR-tested VPRs allocated to Senior Executives prior to 2017 that do not vest as a result of the first test will be re-tested over a five year performance period. RTSR-tested VPRs allocated
in 2017 and performance rights will not be re-tested. The second test date for earlier VPR allocations is one year after the vesting date listed in the table.
4 In accordance with the requirements of AASB 2 Share-based Payment, the fair value of VPRs as at their date of grant has been determined by applying the Black-Scholes option pricing
technique or binomial valuation method combined with a Monte Carlo simulation. The amount included as remuneration is not related to or indicative of the benefit (if any) that individual
Executives may ultimately realise should these equity instruments vest.
5 The fair value of Rights and Restricted Shares as at their date of grant has been determined by reference to the share price at acquisition. The fair value is not related to or indicative of the
benefit (if any) that individual Executives may ultimately realise should these equity instruments vest.
6 Fair values for the 2020 EIS with a grant date of 17 February 2021 have been estimated as disclosed in footnotes 2 and 3 of Table 7. Fair values for the 2021 EIS with a grant date of 16 February
2022 have been estimated as disclosed in footnote 2 of Table 7.
7 The RTSR-tested VPRs allocated for the 2015 and 2016 performance years have been updated to include any adjustments made as part of the Retail Entitlement Offer.
8 Ms M O'Neill was appointed CEO and Managing Director on 17 August 2021. The Board approved the accelerated vesting of 37,048 Restricted Shares upon her appointment as CEO and
Managing Director. The grant of the Performance Rights and Restricted Shares components of Ms M O'Neill's 2021 EIS award is subject to shareholder approval at the 2022 Woodside Annual
General Meeting. The grant date for Performance Rights and Restricted Shares is the date of shareholder approval.
9 Mr P Coleman ceased being an Executive KMP on 19 April 2021. Mr Coleman’s Restricted Shares, VPRs and Performance Rights remain on foot and will vest in the ordinary course subject
to the satisfaction of applicable conditions. The grant date and allocation date for 118,007 Performance Rights awarded to Mr Coleman was the 2021 Annual General Meeting following
shareholder approval.
10 Ms S Duhe resigned on 16 November 2021 and ceased to be an Executive KMP on 4 February 2022. Ms Duhe's Restricted Shares and Performance Rights lapsed on 7 February 2022.
The following table provides a detailed breakdown of the components of remuneration for each of the company’s NEDs.
TABLE 13 - TOTAL REMUNERATION PAID TO NEDS IN 2021 AND 2020
Short-term
Post employment
Cash salary and allowances
Pension/Superannuation
Board and
Committee fees
$
Other fees and
allowances
$
Company contributions
to superannuation
$
542,997
497,582
206,330
189,073
228,999
209,846
202,228
185,314
206,330
189,073
202,228
185,314
220,020
201,618
206,330
189,073
227,575
208,542
114,868
-
35,953
32,584
35,132
24,841
15,014
-
21,452
19,154
20,117
24,841
15,294
10,381
21,452
26,033
-
-
-
-
14,718
-
16,990
14,687
-
-
22,327
19,935
-
-
-
-
4,423
7,224
-
-
20,117
17,962
22,189
19,811
16,082
-
Non-executive
director
R Goyder
L Archibald2
F Cooper
S C Goh2
C Haynes2
I Macfarlane
A Pickard2
S Ryan
G Tilbrook
B Wyatt
2021
2020
20211
2020
20211
2020
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
20211
2020
Total
$
595,940
544,853
241,462
213,914
266,340
229,781
223,680
204,468
226,447
213,914
221,945
202,919
241,472
227,651
226,447
207,035
249,764
228,353
145,668
-
Total
A$3
793,822
792,014
321,639
310,952
354,779
334,017
297,953
297,220
301,639
310,952
295,642
294,969
321,653
330,920
301,639
300,952
332,698
331,940
197,944
-
1 Includes an additional payment of A$20,000 each for services outside the scope of Board and Committee duties, in connection with the proposed merger with BHP Group’s oil and gas portfolio.
2 As non-residents for Australian tax purposes Mr L Archibald, Ms S C Goh, Dr C Haynes and Ms A Pickard have elected to receive a cash payment in lieu of all superannuation contributions, in
accordance with the Superannuation Guarantee (Administration) Act 1992. The cash payment is subject to (PAYG) income tax and paid as part of their normal monthly fees. The amount is
included in Other fees and allowances.
3 This non-IFRS information is included for the purposes of showing the total annual cost of benefits to the company in Australian dollars for the service period.
90 Annual Report 2021
Details of shares held by KMP including their personally related entities1 for the 2021 financial year are as follows:
TABLE 14 - KMP SHARE AND EQUITY HOLDINGS
Name
Type of
equity
Non-executive directors
Opening
holding at
1 January 2021²
Rights
allocated in
2021
Rights vested
in 2021
Restricted
Shares
granted
Net changes
- other
NEDSP³
Closing
holding at
31 December
20214
R Goyder
L Archibald
F Cooper
S C Goh
C Haynes
I Macfarlane
A Pickard
S Ryan
G Tilbrook
B Wyatt5
Executives
M O’Neill
S Gregory
F Hick
P Coleman6
S Duhe7
Shares
Shares
Shares
Shares
Shares
Shares
Shares
Shares
Shares
Shares
Rights
Shares
Rights
Shares
Rights
Shares
Rights
Shares
Rights
Shares
23,634
8,249
11.541
5,089
12,734
7,841
10,196
10,247
7,949
-
31,770
194,258
45,338
67,228
24,569
29,557
419,826
530,985
29,689
70,833
-
3,728
1,909
7,697
1,864
2,488
4,010
1,663
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
23,596
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
35,394
-
-
-
-
-
-
-
-
-
-
-
-
13,509
(5,465)
-
(8,145)
-
11,156
-
118,007
-
17,193
-
5,465
(3,221)
3,221
(81,119)
81,119
-
-
20,264
(6,633)
-
(1,207)
16,734
-
-
-
-
25,788
(456,714)
(612,104)
-
-
23,634
11,977
13,450
12,786
14,598
10,329
14,206
11,910
7,949
-
55,366
229,652
45,237
86,324
31,297
49,512
-
-
46,882
96,621
1 Personally related entities include a KMP’s spouse, dependants or entities over which they have direct control or significant influence.
2 Opening holding represents amounts carried forward in respect of KMP.
3 Related to participation in the Non-executive Directors’ Share Plan (NEDSP).
4 Closing rights holdings represents unvested options and rights held at the end of the reporting period. There are no options or rights vested but unexercised as at 31 December 2021.
5 Mr B Wyatt was appointed as a non-executive director on 1 June 2021. Mr Wyatt is participating in the NEDSP and will acquire shares under this plan going forward.
6 Mr P Coleman was granted 118,007 Performance Rights as approved at the 2021 Annual General Meeting under Listing Rule 10.14. As Mr Coleman ceased being an Executive KMP on
19 April 2021, the information disclosed in Table 14 is only in relation to the period he was an Executive KMP.
7 Ms S Duhe ceased to be an Executive KMP on 4 February 2022. Her Restricted Shares and Performance Rights lapsed on 7 February 2022.
Woodside Petroleum Ltd
91
Glossary
Key terms used in the Remuneration Report
Term
Committee
Meaning
The Human Resources & Compensation Committee
Corporate Scorecard
A corporate scorecard of key measures that aligns with Woodside’s overall business performance
EIP
EIS
The Executive Incentive Plan
The Executive Incentive Scheme
Equity Award Rules
The rules which govern offers of incentive securities to eligible employees
ER
Equity right. ERs are awarded under the WEP and SWEP and each one entitles participants to receive
a fully paid share in Woodside on the vesting date (or a cash equivalent in the case of international
assignees). No amount is payable by the participants on the grant or vesting of an ER
Executive
A senior employee whom the Board has determined to be eligible to participate in the EIS
Executive Director
Meg O’Neill
Executive KMP
The Executive Director and Senior Executives listed in Table 1A on page 73
FAR
FID
Fixed Annual Reward
Final Investment Decision
Former CEO
Peter Coleman. Mr Coleman ceased to be an Executive KMP on 19 April 2021
IPF
KMP
KPI
LTA
MSR
NED
Individual Performance Factor
Key management personnel
Key performance indicator
Long-term award
Minimum shareholding requirements
Non-executive director
NEDSP
The Non-executive Directors' Share Plan
Operating Expenditure
Operating and general, administrative and other expenses incurred in generating revenue from the
sale of hydrocarbons from Woodside's operating assets
Performance Rights
Restricted Shares
Each Performance Right is a right to receive a fully paid ordinary share in Woodside (or, at the
Board’s discretion, as cash equivalent). No amount is payable by the Executive on the grant or
vesting of a Performance Right
Woodside ordinary shares that are awarded to Executives as the deferred component of their STA
or as a part of their VAR under the EIS. No amount is payable by the Executive on the grant or
vesting of a Restricted Share
Retail Entitlement Offer
The pro-rata renounceable offer made to Eligible Retail Shareholders to subscribe for 1 new share
for every 9 existing shares on 19 February 2018
Rights
RTSR
ERs, Performance Rights and VPRs
Relative total shareholder return
Senior Executive
A Senior Executive listed as KMP in Table 1A on page 73, excluding the Executive Director
STA
SWEP
VAR
VPR
Short-term award
The Supplementary Woodside Equity Plan
Variable Annual Reward
Variable Pay Right. Each VPR is a right to receive a fully paid ordinary share in Woodside (or, at
the Board’s discretion, as cash equivalent). No amount is payable by the Executive on the grant or
vesting of a VPR
WEP
The Woodside Equity Plan
92 Annual Report 2021
FINANCIAL STATEMENTS CONTENTS
Financial statements
Consolidated income statement
Consolidated statement
of comprehensive income
Consolidated statement
of financial position
Consolidated statement
of cash flows
Consolidated statement
of changes in equity
Notes to the financial statements
About these statements
A. Earnings for the year
A.1 Segment revenue and expenses
A.2 Finance costs
A.3 Dividends paid and proposed
A.4 Earnings/(losses) per share
A.5 Taxes
B. Production and growth assets
B.1 Segment production and growth assets
B.2 Exploration and evaluation
B.3 Oil and gas properties
B.4 Impairment of exploration and evaluation and oil and gas
properties
B.5 Significant production and growth asset acquisitions
B.6 Non-current assets held for sale
C. Debt and capital
C.1 Cash and cash equivalents
C.2 Interest-bearing liabilities and financing facilities
C.3 Contributed equity
C.4 Other reserves
D. Other assets and liabilities
D.1 Segment assets and liabilities
D.2 Receivables
D.3 Inventories
D.4 Payables
D.5 Provisions
D.6 Other financial assets and liabilities
D.7 Leases
E. Other items
E.1 Contingent liabilities and assets
E.2 Employee benefits
E.3 Related party transactions
E.4 Auditor remuneration
E.5 Events after the end of the reporting period
E.6 Joint arrangements
E.7 Parent entity information
E.8 Subsidiaries
E.9 Other accounting policies
Directors' declaration
Independent audit report
95
96
97
98
99
100
102
103
106
106
106
107
109
110
112
113
115
120
121
122
123
123
125
125
126
127
127
127
128
128
130
132
134
135
135
137
137
137
137
138
139
141
142
143
Significant changes in the current reporting period
The financial performance and position of the Group were particularly affected by the following events and transactions during the reporting period:
• On 10 February 2021, the Group redeemed the $700 million 2021 US bond (refer to Note C.2).
• On 18 May 2021, the Group exited its 50% non-operated participating interest in the Kitimat LNG development. A net expense of $33 million, reflecting various exit
costs, was recognised in the period (refer to Note A.1).
• On 7 July 2021, the Group completed the acquisition of FAR Senegal RSSD SA’s interest in the Rufisque Offshore, Sangomar Offshore and Sangomar Deep Offshore
(RSSD) Joint Venture (refer to Note B.5).
• On 15 November 2021, the Group entered into a sale and purchase agreement with Global Infrastructure Partners for the sale of 49% of the Pluto Train 2 Joint Venture.
As at 31 December 2021, the transaction has not been completed. Pluto Train 2 assets of $252 million have been reclassified to non-current assets held for sale as at
31 December 2021 (refer to Note B.6).
• On 22 November 2021, the Group took unconditional FID on the Scarborough and Pluto Train 2 developments. Related exploration and evaluation assets were
transferred to oil and gas properties (refer to Notes B.2 and B.3). In addition, FID triggered contingent payments of $300 million and $150 million to ExxonMobil and BHP
Group respectively, which have been capitalised to oil and gas properties (refer to Note B.3).
• The Group decided to withdraw from its interests in Myanmar and capitalised costs of $209 million were expensed (refer to Note B.2).
• The Group recognised impairment reversals of $1,058 million (refer to Note B.4).
• The Group hedged an increased percentage of its exposure to commodity price and foreign exchange risk through commodity swaps and foreign exchange forward
derivatives (refer to Note D.6).
94 Annual Report 2021
CONSOLIDATED INCOME STATEMENT
for the year ended 31 December 2021
Operating revenue
Cost of sales
Gross profit
Other income
Other expenses
Impairment losses
Impairment reversals
Profit/(loss) before tax and net finance costs
Finance income
Finance costs
Profit/(loss) before tax
Petroleum resource rent tax (expense)/benefit
Income tax (expense)/benefit
Profit/(loss) after tax
Profit/(loss) attributable to:
Equity holders of the parent
Non-controlling interest
Profit/(loss) for the period
Basic earnings/(losses) per share attributable to equity holders of the parent (US cents)
Diluted earnings/(losses) per share attributable to equity holders of the parent (US cents)
The accompanying notes form part of the Financial Statements.
Notes
A.1
A.1
A.1
A.1
A.1
A.1
A.2
A.5
A.5
E.8
A.4
A.4
2021
US$m
6,962
(3,845)
3,117
139
(811)
(10)
1,058
3,493
27
(230)
3,290
(297)
(957)
2,036
1,983
53
2,036
206.0
204.1
2020
US$m
3,600
(2,985)
615
(36)
(481)
(5,269)
-
(5,171)
58
(327)
(5,440)
439
1,026
(3,975)
(4,028)
53
(3,975)
(423.5)
(423.5)
Woodside Petroleum Ltd 95
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
for the year ended 31 December 2021
Profit/(loss) for the period
Other comprehensive income/(loss)
Items that may be reclassified to the income statement in subsequent periods:
Loss on cash flow hedges (refer to Note D.6 for more details)
Loss on cash flow hedges reclassified to the income statement
Tax recognised within other comprehensive income
Items that will not be reclassified to the income statement in subsequent periods:
Remeasurement gains on defined benefit plan
Other comprehensive income/(loss) for the period, net of tax
Total comprehensive income/(loss) for the period
Total comprehensive income/(loss) attributable to:
Equity holders of the parent
Non-controlling interest
Total comprehensive income/(loss) for the period
The accompanying notes form part of the Financial Statements.
2021
US$m
2,036
(390)
66
(5)
13
(316)
1,720
1,667
53
1,720
2020
US$m
(3,975)
(136)
52
25
2
(57)
(4,032)
(4,085)
53
(4,032)
96 Annual Report 2021
CONSOLIDATED STATEMENT OF FINANCIAL POSITION
as at 31 December 2021
Current assets
Cash and cash equivalents
Receivables
Inventories
Other financial assets
Other assets
Non-current assets held for sale
Total current assets
Non-current assets
Receivables
Inventories
Other financial assets
Other assets
Exploration and evaluation assets
Oil and gas properties
Other plant and equipment
Deferred tax assets
Lease assets
Total non-current assets
Total assets
Current liabilities
Payables
Interest-bearing liabilities
Other financial liabilities
Other liabilities
Provisions
Tax payable
Lease liabilities
Total current liabilities
Non-current liabilities
Interest-bearing liabilities
Deferred tax liabilities
Other financial liabilities
Other liabilities
Provisions
Lease liabilities
Total non-current liabilities
Total liabilities
Net assets
Equity
Issued and fully paid shares
Shares reserved for employee share plans
Other reserves
Retained earnings
Equity attributable to equity holders of the parent
Non-controlling interest
Total equity
The accompanying notes form part of the Financial Statements.
Notes
C.1
D.2
D.3
D.6
B.6
D.2
D.3
D.6
B.2
B.3
A.5
D.7
D.4
C.2
D.6
D.5
A.5
D.7
C.2
A.5
D.6
D.5
D.7
C.3
C.3
C.4
E.8
2021
US$m
3,025
368
202
320
109
254
4,278
686
19
107
34
614
18,434
215
1,007
1,080
22,196
26,474
639
277
411
86
605
413
191
2020
US$m
3,604
303
125
172
48
-
4,252
423
40
54
55
2,045
15,267
199
1,304
984
20,371
24,623
505
776
37
136
500
46
94
2,622
2,094
5,153
878
161
36
2,219
1,176
9,623
12,245
14,229
9,409
(30)
683
3,381
13,443
786
14,229
5,438
549
34
42
2,407
1,184
9,654
11,748
12,875
9,297
(23)
1,403
1,398
12,075
800
12,875
Woodside Petroleum Ltd 97
CONSOLIDATED STATEMENT OF CASH FLOWS
for the year ended 31 December 2021
Cash flows from operating activities
Profit/(loss) after tax for the period
Adjustments for:
Non-cash items
Depreciation and amortisation
Depreciation of lease assets
Change in fair value of derivative financial instruments
Net finance costs
Tax expense/(benefit)
Exploration and evaluation written off
Impairment losses
Impairment reversals
Restoration
Onerous contracts provision
Other
Changes in assets and liabilities
(Increase)/decrease in trade and other receivables
(Increase)/decrease in inventories
Increase in lease assets
(Decrease)/increase in provisions
(Decrease)/increase in lease liabilities
Increase in other assets and liabilities
Increase/(decrease) in trade and other payables
Cash generated from operations
Purchases of shares and payments relating to employee share plans
Interest received
Dividends received
Borrowing costs relating to operating activities
Income tax paid
Payments for restoration
Net cash from operating activities
Cash flows used in investing activities
Payments for capital and exploration expenditure
Borrowing costs relating to investing activities
Advances to other external entities
Proceeds from disposal of non-current assets
Payments for acquisition of joint arrangements
Net cash used in investing activities
Cash flows used in financing activities
Proceeds from borrowings
Repayment of borrowings
Borrowing costs relating to financing activities
Repayment of lease liabilities
Borrowing costs relating to lease liabilities
Contributions to non-controlling interests
Dividends paid (net of DRP)
Net proceeds from share issuance
Net cash used in financing activities
Net decrease in cash held
Cash and cash equivalents at the beginning of the period
Effects of exchange rate changes
Cash and cash equivalents at the end of the period
The accompanying notes form part of the Financial Statements.
98 Annual Report 2021
Notes
2021
US$m
2020
US$m
2,036
(3,975)
1,582
108
31
203
1,254
265
10
(1,058)
68
(95)
30
(39)
(4)
(16)
(75)
(25)
(128)
75
4,222
(47)
11
6
(91)
(271)
(38)
3,792
1,730
94
31
269
(1,465)
2
5,269
-
28
347
(12)
41
51
-
155
40
(137)
(121)
2,347
(32)
64
4
(180)
(331)
(23)
1,849
(2,406)
(1,418)
(126)
(206)
9
(212)
(57)
(110)
-
(527)
(2,941)
(2,112)
-
(784)
(15)
(155)
(89)
(92)
(289)
-
(1,424)
(573)
3,604
(6)
3,025
600
(83)
(21)
(71)
(86)
(111)
(454)
23
(203)
(466)
4,058
12
3,604
B.2
B.4
B.4
B.5
C.2
C.2
C.1
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
for the year ended 31 December 2021
d
i
a
p
y
l
l
u
f
d
n
a
d
e
u
s
s
I
s
e
r
a
h
s
s
n
a
l
p
e
r
a
h
s
e
e
y
o
p
m
e
l
r
o
f
d
e
v
r
e
s
e
r
s
e
r
a
h
S
s
t
fi
e
n
e
b
e
e
y
o
p
m
E
l
e
v
r
e
s
e
r
e
v
r
e
s
e
r
n
o
i
t
a
l
s
n
a
r
t
y
c
n
e
r
r
u
c
n
g
i
e
r
o
F
s
t
fi
o
r
p
e
l
b
a
t
u
b
i
r
t
s
i
D
e
v
r
e
s
e
r
e
v
r
e
s
e
r
g
n
g
d
e
H
i
e
h
t
l
f
o
s
r
e
d
o
h
y
t
i
u
q
E
t
n
e
r
a
p
i
s
g
n
n
r
a
e
d
e
n
i
a
t
e
R
C.3
US$m
C.3
US$m
C.4
US$m
C.4
US$m
C.4
US$m
C.4
US$m
US$m
US$m
9,297
-
-
-
112
-
-
-
-
9,409
9,010
-
-
-
-
264
23
-
-
-
-
9,297
(23)
-
-
-
-
(47)
40
-
-
(30)
(39)
-
-
-
-
-
-
(32)
48
-
-
(23)
219
-
13
13
-
-
(40)
40
-
232
211
-
-
2
2
-
-
-
(48)
54
-
219
793
-
-
-
-
-
-
-
-
793
793
-
-
-
-
-
-
-
-
-
-
793
(71)
-
(329)
(329)
-
-
-
-
-
(400)
(12)
-
-
(59)
(59)
-
-
-
-
-
-
(71)
462
-
-
-
-
-
-
-
(404)
58
-
710
-
-
-
-
-
-
-
-
(248)
462
1,398
1,983
-
1,983
-
-
-
-
-
3,381
6,654
(710)
(4,028)
-
(4,028)
-
-
-
-
-
(518)
1,398
12,075
1,983
(316)
1,667
112
(47)
-
40
(404)
13,443
16,617
-
(4,028)
(57)
(4,085)
264
23
(32)
-
54
(766)
12,075
g
n
i
l
l
o
r
t
n
o
c
-
n
o
N
t
s
e
r
e
t
n
i
E.8
US$m
800
53
-
53
-
-
-
-
(67)
786
792
-
53
-
53
-
-
-
-
-
(45)
800
y
t
i
u
q
e
l
a
t
o
T
US$m
12,875
2,036
(316)
1,720
112
(47)
-
40
(471)
14,229
17,409
-
(3,975)
(57)
(4,032)
264
23
(32)
-
54
(811)
12,875
Notes
At 1 January 2021
Profit for the period
Other comprehensive income/(loss)
Total comprehensive income/(loss) for the period
Dividend Reinvestment Plan
Employee share plan purchases
Employee share plan redemptions
Share-based payments (net of tax)
Dividends paid
At 31 December 2021
At 1 January 2020
Transfers
Profit/(loss) for the period
Other comprehensive income/(loss)
Total comprehensive income/(loss) for the period
Dividend Reinvestment Plan
Shares issued
Employee share plan purchases
Employee share plan redemptions
Share-based payments (net of tax)
Dividends paid
At 31 December 2020
The accompanying notes form part of the Financial Statements.
Woodside Petroleum Ltd 99
NOTES TO THE FINANCIAL STATEMENTS
for the year ended 31 December 2021
About these statements
Woodside Petroleum Ltd and its controlled entities (Woodside
or the Group) is a for-profit entity limited by shares, incorporated
and domiciled in Australia. Its shares are publicly traded on the
Australian Securities Exchange. The nature of the operations and
the principal activities of the Group are described in the Directors’
Report and in the segment information in Note A.1.
The financial statements were authorised for issue in accordance
with a resolution of the directors on 17 February 2022.
Statement of compliance
The financial statements are general purpose financial statements,
which have been prepared in accordance with the requirements
of the Corporations Act 2001, Australian Accounting Standards
(AASBs) and other authoritative pronouncements of the
Australian Accounting Standards Board. The financial statements
comply with International Financial Reporting Standards (IFRS)
as issued by the International Accounting Standards Board.
The accounting policies are consistent with those disclosed in
the 2020 Financial Statements, except for the impact of all new or
amended standards and interpretations adopted with effect from 1
January 2021. The adoption of these standards and interpretations
did not result in any significant changes to the Group’s accounting
policies, with the exception of AASB 2020-8 Amendments to
Australian Accounting Standards - Interest Rate Benchmark
Reform (refer to Note E.9(c)).
Estimates and judgements reflect current market conditions,
including the impact of COVID-19. Estimates used for impairment
assessments and the measurement of onerous contracts are
disclosed in Notes B.4 and D.5 respectively. Given ongoing economic
uncertainty, these assumptions could change in the future.
Currency
The functional and presentation currency of Woodside Petroleum
Ltd and all its subsidiaries is the US dollar.
Transactions in foreign currencies are initially recorded in the
functional currency of the transacting entity at the exchange
rates ruling at the date of transaction. Monetary assets and
liabilities denominated in foreign currencies at the reporting
date are translated at the rates of exchange ruling at that date.
Exchange differences in the consolidated financial statements
are taken to the income statement.
Rounding of amounts
The amounts contained in these financial statements have been
rounded to the nearest million dollars under the option available
to the Group under Australian Securities and Investments
Commission (ASIC) Corporations (Rounding in Financial/Directors’
Reports) Instrument 2016/191 dated 24 March 2016, unless
otherwise stated.
Basis of preparation
The financial statements have been prepared on a historical cost
basis, except for derivative financial instruments and certain
other financial assets and financial liabilities, which have been
measured at fair value or amortised cost adjusted for changes
in fair value attributable to the risks that are being hedged in
effective hedge relationships. Where not carried at fair value,
100 Annual Report 2021
if the carrying value of financial assets and financial liabilities does
not approximate their fair value, the fair value has been included
in the notes to the financial statements.
The financial statements comprise the financial results of the
Group as at 31 December each year (refer to Note E.8).
Subsidiaries are fully consolidated from the date on which control
is obtained by the Group and cease to be consolidated from the
date at which the Group ceases to have control.
The subsidiaries of the Group have the same reporting period
and accounting policies as the parent company. All intercompany
balances and transactions, including unrealised profits and losses
arising from intra-group transactions, have been eliminated in full.
Non-controlling interests are allocated their share of the net profit
after tax in the consolidated income statement and their share
of other comprehensive income net of tax in the consolidated
statement of comprehensive income, and are presented within
equity in the consolidated statement of financial position,
separately from parent shareholders’ equity.
The consolidated financial statements provide comparative
information in respect of the previous period. Where required, a
reclassification of items in the financial statements of the previous
period has been made in accordance with the classification of
items in the financial statements of the current period.
Financial and capital risk management
The Board of Directors has overall responsibility for the establishment
and oversight of the Group’s risk management framework, including
review and approval of the Group’s risk management strategy, policy
and key risk parameters. The Board of Directors and the Audit and Risk
Committee have oversight of the Group’s internal control system and risk
management process, including oversight of the internal audit function.
The Group’s management of financial and capital risks is aimed at
ensuring that available capital, funding and cash flows are sufficient to:
• meet the Group’s financial commitments as and when they fall due;
• maintain the capacity to fund its committed project developments;
• pay a reasonable dividend; and
• maintain a long-term credit rating of not less than ‘investment grade’.
The Group monitors and tests its forecast financial position against
these criteria and, in general, will undertake hedging activity only when
necessary to ensure that these objectives are achieved.
Other circumstances that may lead to hedging activities include
the management of exposures relating to trading activities and the
underpinning of the economics of a new project. It is, and has been
throughout the period, the Group Treasury policy that no speculative
trading in financial instruments shall be undertaken. Refer to the Risk
section of Corporate on pages 51-54 for more information on the
Group’s objectives, policies and processes for managing financial risk.
The below risks arise in the normal course of the Group’s business.
Risk information can be found in the following sections:
Section A
Section A
Section C
Section C
Section C
Section D
Commodity price risk
Foreign exchange risk
Capital risk
Liquidity risk
Interest rate risk
Credit risk
Page 102
Page 102
Page 122
Page 122
Page 122
Page 126
NOTES TO THE FINANCIAL STATEMENTS
for the year ended 31 December 2021
Key estimates and judgements
In applying the Group’s accounting policies, management continually
evaluates judgements, estimates and assumptions based on
experience and other factors, including expectations of future events
that may have an impact on the Group. All judgements, estimates
and assumptions made are believed to be reasonable based on the
most current set of circumstances known to management, and actual
results may differ. Significant judgements, estimates and assumptions
made by management in the preparation of these financial
statements are found in the following notes:
Note A.1
Note A.5
Note B.2
Note B.3
Note B.4
Note B.5
Note D.5
Note D.6
Note D.7
Note E.6
Revenue from contracts with customers
Taxes
Exploration and evaluation
Oil and gas properties
Impairment of exploration and evaluation
and oil and gas properties
Significant production and growth assets
Provisions
Other financial assets and liabilities
Leases
Joint arrangements
Page 103
Page 108
Page 112
Page 114
Page 117
Page 120
Page 129
Page 131
Page 133
Page 137
Woodside Petroleum Ltd 101
NOTES TO THE FINANCIAL STATEMENTS A. EARNINGS FOR THE YEAR
for the year ended 31 December 2021
In this section
This section addresses financial performance of the Group for the reporting period including, where applicable, the accounting policies
applied and the key estimates and judgements made. This section also includes the tax position of the Group for and at the end of the
reporting period.
A.
A.1
A.2
A.3
A.4
A.5
Earnings for the year
Segment revenue and expenses
Finance costs
Dividends paid and proposed
Earnings/(losses) per share
Taxes
Page 103
Page 106
Page 106
Page 106
Page 107
Key financial and capital risks in this section
Commodity price risk management
The Group’s revenue is exposed to commodity price fluctuations through the sale of hydrocarbons. Commodity price risks are measured by
monitoring and stress testing the Group’s forecast financial position to sustained periods of low oil and gas prices. This analysis is regularly
performed on the Group’s portfolio and as required for discrete projects and transactions.
The Group’s management of commodity price risk includes the use of commodity swap derivatives to hedge its exposure (refer to Note
D.6). The hedged exposure includes LNG revenue related to produced volumes and revenues derived from trading operations. Commodity
swap derivatives protect the Group against downside risk within its strategic and trading portfolio.
As at the reporting date, the Group held hedging financial instruments with a net liability carrying value of $431 million (2020: $9 million)
exposed to commodity price risk. An increase in relevant commodity prices of 10% would decrease the instruments’ carrying value by
$255 million, the effect of which would be recognised within reserves and/or the income statement in accordance with hedge accounting
application. A 10% decrease would have the same but opposite effect. The analysis assumes that all other variables remain constant
(including the price on underlying physical exposures).
Foreign exchange risk management
Foreign exchange risk arises from future commitments, financial assets and financial liabilities that are not denominated in US dollars.
The majority of the Group’s revenue is denominated in US dollars. The Group is exposed to foreign currency risk arising from operating
and capital expenditure incurred in currencies other than US dollars, particularly Australian dollars.
The Group’s management of foreign exchange risk relating to capital expenditure includes the use of forward exchange contract
derivatives to hedge its exposure (refer to Note D.6).
As at the reporting date, the Group held hedging financial instruments with a net asset carrying value of $10 million (2020: nil) exposed to
foreign exchange risk.
Measuring the exposure to foreign exchange risk is achieved by regularly monitoring and performing sensitivity analysis on the
Group’s financial position.
A reasonably possible change in the exchange rate of the US dollar to the Australian dollar (+12%/-12% (2020: +12%/-12%)), with all other
variables held constant, would not have a material impact on the Group’s equity or the profit or loss in the current period. Refer to Notes C1,
C2, D2, D4 and D7 for details of the denominations of cash and cash equivalents, interest-bearing liabilities, receivables, payables
and lease liabilities held at 31 December 2021.
In order to hedge the foreign exchange risk and interest rate risk (refer to Section C) of a Swiss Franc (CHF) denominated medium term
note, Woodside holds a number of cross-currency interest rate swaps (refer to Note C.2 and D.6). The aim of this hedge is to convert the
fixed interest CHF bond into variable interest US dollar debt. The Group also entered into foreign exchange forward contracts to fix the
Australian dollar to US dollar exchange rate in relation to a portion of the Australian dollar denominated capital expenditure expected to
be incurred under the Scarborough development (refer to Note D.6).
102 Annual Report 2021
NOTES TO THE FINANCIAL STATEMENTS A. EARNINGS FOR THE YEAR
for the year ended 31 December 2021
A.1 Segment revenue and expenses
Operating segment information
The Group has identified its operating segments based on the
internal reports that are reviewed and used by the executive
management team in assessing performance and in determining
the allocation of resources.
The Group has reviewed its operating segments and has identified
the Sangomar and Scarborough Development as separate
operating segments within Development due to the progress and
materiality of the related projects. The 2020 amounts have been
restated to reflect this change.
Management monitors the performance of the operating results
of the segments separately for the purpose of making decisions
about resource allocation and performance assessment. The
performance of operating segments is evaluated based on profit
before tax and net finance costs and is measured in accordance
with the Group’s accounting policies.
Financing requirements, including cash and debt balances, finance
income, finance costs and taxes are managed at a Group level.
Operating segments outlined below are identified by
management based on the nature and geographical location
of the business or venture.
Producing
North West Shelf Project – Exploration, evaluation,
development, production and sale of liquefied natural gas,
pipeline natural gas, condensate and liquefied petroleum gas in
assigned permit areas.
Pluto LNG – Exploration, evaluation, development, production
and sale of liquefied natural gas, pipeline natural gas and
condensate in assigned permit areas.
Australia Oil – Exploration, evaluation, development, production
and sale of crude oil in assigned permit areas (North West Shelf,
Greater Enfield and Vincent).
Wheatstone – Exploration, evaluation, development, production
and sale of liquefied natural gas, pipeline natural gas and
condensate in assigned permit areas.
Development
Scarborough – Exploration, evaluation and development of
liquified natural gas, pipeline natural gas and condensate in
assigned permit areas.
Sangomar – Exploration, evaluation and development of crude
oil in assigned permit areas.
Other development segments – This segment comprises
exploration, evaluation and development of liquefied natural gas,
pipeline natural gas and condensate in the Browse, Kitimat and
Sunrise projects.
Other
Other segments – This segment comprises trading and shipping
activities and activities undertaken in other international
locations.
Unallocated items – Unallocated items comprise primarily
corporate non-segmental items of revenue and expenses
and associated assets and liabilities not allocated to operating
segments as they are not considered part of the core operations
of any segment.
Major customer information
The Group has two major customers which respectively account for
8% and 6% of the Group’s external revenue. The sales are generated
by the Pluto, North West Shelf and Wheatstone operating segments
(2020: two major customers; 15% and 13% generated by Pluto and
North West Shelf).
Geographic information
Revenue from external
customers1
Non-current assets2
Oceania
Asia
Canada
Africa
Other
2021
US$m
313
6,029
-
-
620
2020
US$m
286
3,076
-
-
238
2021
US$m
18,386
-
-
2,802
1
2020
US$m
17,559
229
34
1,244
1
19,067
Consolidated
1. Revenue is attributable to geographic region based on the location of the customer.
2. Non-current assets exclude deferred tax of $1,007 million (2020: $1,304 million).
21,189
3,600
6,962
Recognition and measurement
Revenue from contracts with customers
Revenue is recognised when or as the Group transfers control
of products or provides services to a customer at the amount
to which the Group expects to be entitled. If the consideration
includes a variable component, the Group estimates the amount
of the expected consideration receivable. Variable consideration
is estimated throughout the contract and is constrained until it is
highly probable a significant revenue reversal in the amount of
cumulative revenue recognised will not occur.
• Revenue from sale of hydrocarbons - Revenue from the sale of
hydrocarbons is recognised at a point in time when control of the
product is transferred to the customer, which is typically on delivery.
Revenue from take or pay contracts is recorded as unearned
revenue until the product has been drawn by the customer
(transfer of control), at which time it is recognised in earnings.
• Other operating revenue - Revenue earned from LNG
processing and other services is recognised over time as
the services are rendered.
Expenses
• Royalties, excise and levies - Royalties, excise and levies
under existing regimes are considered to be production-based
taxes and are therefore accrued on the basis of the Group’s
entitlement to physical production.
• Depreciation and amortisation - Refer to Note B.3.
• Impairment and impairment reversals - Refer to Note B.4.
• Leases - Refer to Note D.7.
• Employee benefits - Refer to Note E.2.
Key estimates and judgements
Revenue from contracts with customers
Judgement is required to determine the point at which the customer obtains
control of hydrocarbons. Factors including transfer of legal title, transfer of
significant risks and rewards of ownership and the existence of a present right to
payment for the hydrocarbons typically result in control transferring on delivery
of hydrocarbons at port of loading or port of discharge.
The transaction price at the date control passes for sales made subject to
provisional pricing periods in oil and condensate contracts is determined with
reference to quoted commodity prices.
Judgement is also used to determine if it is probable that a significant reversal
will occur in relation to revenue recognised during open pricing periods in LNG
contracts. The Group estimates variable consideration based on reasonably
available information from contract negotiations and market indicators.
Progress of performance obligations for LNG processing services revenue
recognised over time is measured using the output method which most
accurately measures the progress towards satisfaction of the performance
obligation of the services provided.
Woodside Petroleum Ltd 103
NOTES TO THE FINANCIAL STATEMENTS A. EARNINGS FOR THE YEAR
for the year ended 31 December 2021
A.1 Segment revenue and expenses (cont.)
Producing
Development
Other
t
s
e
W
h
t
r
o
N
f
l
e
h
S
2021
US$m
1,209
8
253
-
60
1,530
-
-
-
1,530
(116)
(200)
(7)
-
(323)
(3)
(9)
(183)
(3)
(198)
(45)
-
-
-
-
(45)
o
t
u
P
l
2021
US$m
2,415
19
215
-
-
2,649
143
2
145
2,794
(192)
(9)
(19)
1
(219)
(28)
(27)
(827)
-
(882)
(70)
(138)
-
(11)
-
(219)
(566)
(1,320)
964
1,474
17
(2)
-
-
(2)
(1)
-
(1)
15
(10)
3
1
-
376
75
(2)
-
-
(2)
(2)
-
(27)
-
(3)
(32)
(34)
-
682
l
i
O
a
i
l
a
r
t
s
u
A
2021
US$m
-
-
-
673
-
673
-
-
-
673
(109)
(7)
(4)
8
(112)
-
(21)
(199)
-
(220)
-
-
-
-
-
-
(332)
341
5
(1)
-
-
(1)
-
-
-
(95)
(6)
(101)
(102)
-
-
e
n
o
t
s
t
a
e
h
W
2021
US$m
581
16
175
-
-
772
-
-
-
772
(72)
(2)
(2)
8
(68)
(20)
(22)
(207)
-
(249)
(42)
-
(6)
-
-
(48)
(365)
407
(1)
(1)
-
-
(1)
(1)
-
-
-
(38)
(39)
(40)
(10)
-
h
g
u
o
r
o
b
r
a
c
S
2021
US$m
-
-
-
-
-
-
-
-
-
r
a
m
o
g
n
a
S
2021
US$m
-
-
-
-
-
-
-
-
-
s
t
n
e
m
p
o
l
e
v
e
d
r
e
h
t
O
2021
US$m
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
(3)
-
-
(3)
5
-
-
-
-
5
2
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
(1)
(2)
-
-
(2)
(1)
-
-
12
(32)
(21)
(23)
-
-
s
t
n
e
m
g
e
s
r
e
h
t
O
2021
US$m
1,154
-
-
-
-
1,154
-
39
39
1,193
-
-
-
-
-
-
-
-
-
-
(53)
(1,357)
-
(1)
140
(1,271)
(1,271)
(78)
-
(43)
(3)
(265)
(311)
(5)
-
(47)
-
-
(52)
(363)
-
-
d
e
t
a
c
o
l
l
a
n
U
s
m
e
t
i
2021
US$m
-
-
-
-
-
-
-
-
-
-
8
-
1
-
9
-
-
-
-
-
-
-
-
-
-
-
9
9
44
-
-
-
-
(153)
(30)
(33)
-
(36)
(252)
(252)
-
-
Liquefied natural gas
Domestic gas
Condensate
Oil
Liquefied petroleum gas
Revenue from sale of hydrocarbons
Processing and services revenue
Shipping and other revenue
Other revenue
Operating revenue1
Production costs
Royalties, excise and levies
Insurance
Inventory movement
Costs of production
Land and buildings
Transferred exploration and evaluation
Plant and equipment
Marine vessels and carriers
Oil and gas properties depreciation and
amortisation
Shipping and direct sales costs2
Trading costs3
Other hydrocarbon costs
Other cost of sales
Movement in onerous contract provision4
Other cost of sales
Cost of sales
Gross profit
Other income5
Exploration and evaluation expenditure
Amortisation
Write-offs6
Exploration and evaluation
General, administrative and other costs
Depreciation of other plant and equipment
Depreciation of lease assets
Restoration movement
Other7
Other costs
Other expenses
Impairment losses
Impairment reversals8
Profit/(loss) before tax and net finance costs
1. Operating revenue includes revenue from contracts with customers of $6,923 million and sub-lease income of $39 million disclosed within shipping and other revenue.
2. Includes repurchase and cancellation costs to optimise Group operating revenues.
3. Trading costs within Other segments relate to purchase costs of non-produced volumes (including Corpus Christi) and other volumes purchased to optimise produced
2,197
1,358
(199)
(441)
244
356
(24)
2
-
d
e
t
a
d
i
l
o
s
n
o
C
2021
US$m
5,359
43
643
673
60
6,778
143
41
184
6,962
(481)
(218)
(31)
17
(713)
(51)
(79)
(1,416)
(3)
(1,549)
(210)
(1,495)
(6)
(12)
140
(1,583)
(3,845)
3,117
139
(54)
(3)
(265)
(322)
(158)
(30)
(108)
(68)
(125)
(489)
(811)
(10)
1,058
3,493
LNG revenue.
4. Comprises provisions used of $45 million and changes in estimates of $95 million. Refer to Note D.5 for more details.
5. Includes other income of $67 million relating to Pluto volumes delivered into Wheatstone's sales commitments and net foreign exchange gains of $44 million.
6. $56 million relates to costs of unsuccessful wells. $209 million relates to capitalised costs written off due to the Group's decision to withdraw from its interests in Myanmar.
Refer to Note B.2.
7. Includes net loss on hedging activities of $91 million and other expenses not associated with the ongoing operations of the business. The Other developments segment also
includes $33 million for various costs relating to Woodside's exit from the Kitimat LNG development.
8. Impairment reversals on oil and gas properties. Refer to Note B.4 for more details.
104 Annual Report 2021
NOTES TO THE FINANCIAL STATEMENTS A. EARNINGS FOR THE YEAR
for the year ended 31 December 2021
A.1 Segment revenue and expenses (cont.)
Producing
Development
Other
t
s
e
W
h
t
r
o
N
f
l
e
h
S
2020
US$m
722
44
194
-
16
976
-
-
-
976
(118)
(79)
(7)
(1)
(205)
(4)
(13)
(228)
(2)
(247)
(49)
(8)
-
-
-
(57)
o
t
u
P
l
2020
US$m
1,320
11
114
-
-
1,445
142
-
142
1,587
(189)
-
(19)
(7)
(215)
(27)
(32)
(823)
-
(882)
(53)
(49)
-
-
-
(102)
(509)
(1,199)
467
388
12
(3)
-
-
(3)
(1)
-
-
(5)
(15)
(21)
(24)
(6)
(1)
-
-
(1)
(1)
-
(26)
-
12
(15)
(16)
l
i
O
a
i
l
a
r
t
s
u
A
2020
US$m
-
-
-
432
-
432
-
-
-
432
(107)
(3)
(3)
(21)
(134)
-
(32)
(251)
-
(283)
-
-
-
-
-
-
(417)
15
-
(1)
-
-
(1)
(1)
-
-
(62)
(12)
(75)
(76)
e
n
o
t
s
t
a
e
h
W
2020
US$m
365
18
103
-
-
486
-
-
-
486
(72)
-
(3)
(3)
(78)
(24)
(22)
(231)
-
(277)
(44)
(10)
(4)
-
-
(58)
(413)
73
1
(3)
-
-
(3)
(1)
-
-
-
8
7
4
(454)
(1,291)
(674)
(1,401)
-
-
-
-
Liquefied natural gas1
Domestic gas
Condensate
Oil
Liquefied petroleum gas
Revenue from sale of hydrocarbons
Processing and services revenue
Shipping and other revenue
Other revenue
Operating revenue
Production costs
Royalties, excise and levies
Insurance
Inventory movement
Costs of production
Land and buildings
Transferred exploration and evaluation
Plant and equipment
Marine vessels and carriers
Oil and gas properties depreciation and
amortisation
Shipping and direct sales costs
Trading costs
Other hydrocarbon costs
Other cost of sales
Movement in onerous contract provision2
Other cost of sales
Cost of sales
Gross profit
Other income 3
Exploration and evaluation expenditure
Amortisation
Write-offs
Exploration and evaluation
General, administrative and other costs
Depreciation of other plant and equipment
Depreciation of lease assets
Restoration movement
Other3
Other costs
Other expenses
Impairment losses4
Impairment reversals
h
g
u
o
r
o
b
r
a
c
S
20205
US$m
-
-
-
-
-
-
-
-
-
r
a
m
o
g
n
a
S
20205
US$m
-
-
-
-
-
-
-
-
-
s
t
n
e
m
p
o
l
e
v
e
d
r
e
h
t
O
20205
US$m
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
(2)
-
-
(2)
2
-
-
-
-
2
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
(1)
-
-
(1)
(13)
-
-
39
(1)
25
24
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
(3)
-
-
-
-
(3)
-
-
-
-
(3)
(3)
-
-
s
t
n
e
m
g
e
s
r
e
h
t
O
2020
US$m
112
-
-
-
-
112
-
7
7
119
-
-
-
-
-
-
-
-
-
-
35
(144)
-
-
(347)
(456)
(456)
(337)
(42)
(56)
(12)
(2)
(70)
(6)
-
(34)
-
42
2
(68)
d
e
t
a
c
o
l
l
a
n
U
s
m
e
t
i
2020
US$m
-
-
-
-
-
-
-
-
-
-
8
-
1
-
9
-
-
-
-
-
-
-
-
-
-
-
9
9
2
-
-
-
-
(166)
(29)
(34)
-
(93)
(322)
(322)
d
e
t
a
d
i
l
o
s
n
o
C
2020
US$m
2,519
73
411
432
16
3,451
142
7
149
3,600
(478)
(82)
(31)
(32)
(623)
(55)
(99)
(1,533)
(2)
(1,689)
(111)
(211)
(4)
-
(347)
(673)
(2,985)
615
(36)
(67)
(12)
(2)
(81)
(190)
(29)
(94)
(28)
(59)
(400)
(481)
(321)
(977)
(151)
-
-
-
-
-
(5,269)
-
(5,171)
Profit/(loss) before tax and net finance costs
1. Includes an adjustment of $113 million related to price reviews currently under negotiation for multiple contracts across North West Shelf and Pluto, reducing revenue recognised
(1,323)
(311)
(925)
(321)
(953)
(598)
(735)
(6)
1
in the current and prior periods and increasing other liabilities.
2. Comprised of the recognition of an onerous contract provision $447 million, offset by changes in estimates of $54 million, provisions used of $41 million and a revision of
discount rates of $5 million. Refer to Note D.5 for more details.
3. Includes foreign exchange gains and losses, gains and losses on hedging activities, cancellation costs and other expenses not associated with the ongoing operations of the
business.
4. The impairment losses represent charges on exploration and evaluation of $1,557 million and oil and gas properties of $3,712 million.
5. The 2020 amounts have been restated to reflect the changes in the Development segment.
Woodside Petroleum Ltd 105
NOTES TO THE FINANCIAL STATEMENTS A. EARNINGS FOR THE YEAR
for the year ended 31 December 2021
A.2 Finance costs
A.4 Earnings/(losses) per share
Interest on interest-bearing liabilities
Interest on lease liabilities
Accretion charge
Other finance costs
Less: Finance costs capitalised against
qualifying assets
2021
US$m
2020
US$m
201
97
29
26
(123)
230
237
86
32
29
(57)
327
A.3 Dividends paid and proposed
Woodside Petroleum Ltd, the parent entity, paid and proposed
dividends set out below:
(a) Dividends paid during the financial year
Prior year fully franked final dividend US$0.12,
paid on 24 March 2021
(2020: US$0.55, paid on 20 March 2020)
Current year fully franked interim dividend
US$0.30, paid on 24 September 2021
(2020: US$0.26, paid on 18 September 2020)
(b) Dividend declared subsequent to the reporting
period (not recorded as a liability)
Final dividend US$1.05 (2020: US$0.12)
(c) Other information
Franking credits available for subsequent periods
Current year dividends per share (US cents)
2021
US$m
2020
US$m
115
518
289
404
248
766
1,018
115
1,744
135
1,823
38
The Dividend Reinvestment Plan (DRP) was approved by the
shareholders at the Annual General Meeting in 2003 for activation
as required to fund future growth. The DRP was reactivated for
the 2019 interim dividend and remains in place until further notice.
Profit/(loss) attributable to equity holders of the
parent (US$m)
Weighted average number of shares on issue for
basic earnings/(loss) per share
Effect of dilution from contingently issuable shares
Weighted average number of shares on issue
adjusted for the effect of dilution1
Basic earnings/(losses) per share (US cents)
2021
2020
1,983
(4,028)
962,604,811 951,113,086
-
9,023,439
971,628,250 951,113,086
(423.5)
206.0
Diluted earnings/(losses) per share (US cents)
1. The contingently issuable shares in 2020 have an anti-dilutive impact.
204.1
(423.5)
Earnings/(losses) per share is calculated by dividing the
profit/(loss) for the year attributable to ordinary equity holders
of the parent by the weighted average number of ordinary
shares on issue during the year. The weighted average number of
shares makes allowance for shares reserved for employee share
plans. Diluted earnings per share is calculated by adjusting basic
earnings per share by the number of ordinary shares that would
be issued on conversion of all the dilutive potential ordinary shares
into ordinary shares. At 31 December 2021, 9,023,439 awards
granted under the Woodside employee share plans are considered
dilutive. Total outstanding share awards as at 31 December 2020
were 9,392,203 and considered anti-dilutive due to the loss
position in 2020.
On 22 November 2021, Woodside and BHP Group (BHP) signed
a binding share sale agreement to combine their respective oil
and gas portfolios by an all stock merger (the Transaction). On
completion of the Transaction, BHP's oil and gas business would
merge with Woodside, and Woodside would issue new shares
to be distributed to BHP shareholders. The expanded Woodside
would be owned 52% by existing Woodside shareholders and 48%
by existing BHP shareholders. This Transaction is not considered
dilutive for the current period.
There have been no significant transactions involving ordinary
shares between the reporting date and the date of completion
of these financial statements.
106 Annual Report 2021
NOTES TO THE FINANCIAL STATEMENTS A. EARNINGS FOR THE YEAR
for the year ended 31 December 2021
A.5 Taxes
(a) Tax expense comprises
Petroleum resource rent tax (PRRT)
Deferred tax expense/(benefit)
PRRT expense/(benefit)
Income tax
Current year
Current tax expense
Deferred tax expense/(benefit)
Adjustment to prior years
Current tax (benefit)/expense
Deferred tax expense/(benefit)
Income tax expense/(benefit)
Tax expense/(benefit)
(b) Reconciliation of income tax expense
Profit/(loss) before tax
PRRT (expense)/benefit
Profit/(loss) before income tax
Income tax expense/(benefit) calculated at 30%
Foreign income tax expense/(benefit)
Non-deductible items
Foreign expenditure not brought to account
Adjustment to prior years
Foreign exchange impact on tax (benefit)/
expense
Income tax expense/(benefit)
(c) Reconciliation of PRRT benefit
Profit/(loss) before tax
Non-PRRT assessable (profit)/loss
PRRT projects profit/(loss) before tax1
PRRT expense/(benefit) calculated at 40%2
Augmentation
Derecognition of Pluto general expenditure1
Other
PRRT expense/(benefit)
(d) Deferred tax income statement
reconciliation
PRRT
Production and growth assets
Augmentation for current year
Provisions
Other
PRRT expense/(benefit)
Income tax
Oil and gas properties
Exploration and evaluation assets
Provisions
PRRT liabilities
Lease assets and liabilities
Unused tax losses and tax credits
Non-current assets held for sale
Other
Income tax deferred tax expense/(benefit)
Deferred tax expense/(benefit)
(e) Deferred tax balance sheet reconciliation
Deferred tax assets
PRRT
Production and growth assets
Augmentation for current year
Provisions
Other
2021
US$m
2020
US$m
2021
US$m
2020
US$m
297
297
658
301
(20)
18
957
1,254
3,290
(297)
2,993
898
23
7
49
(2)
(18)
957
3,290
(2,134)
1,156
462
(166)
-
1
297
455
(166)
(29)
37
297
674
(204)
(10)
(88)
1
149
(205)
2
319
616
767
166
75
(1)
1,007
(439)
(439)
275
(1,308)
16
(9)
(1,026)
(1,465)
(5,440)
439
(5,001)
(1,500)
(11)
2
473
7
3
(1,026)
(5,440)
3,080
(2,360)
(944)
(138)
627
16
(439)
(242)
(138)
(32)
(27)
(439)
(981)
(210)
(106)
134
(16)
(149)
-
11
(1,317)
(1,756)
1,098
124
46
36
1,304
(e) Deferred tax balance sheet
reconciliation (cont.)
Deferred tax liabilities
PRRT
Production and growth assets
Augmentation for current year
Provisions
Other
Income tax
Oil and gas properties
Exploration and evaluation assets
Lease assets and liabilities
Provisions
PRRT liabilities
Unused tax losses and tax credits
Non-current assets held for sale
Other3
(f) Tax payable reconciliation
Income tax payable
(g) Effective income tax rate: Australian
and global operations
Effective income tax rate4
Australia
Global
(h) Current income tax expense reconciliation
Profit/(loss) before income tax
Income tax expense/(benefit) at the statutory tax
rate of 30%
Foreign income tax expense/(benefit)
Non-temporary differences5,6
Temporary differences: deferred tax6
Foreign exchange impact on tax (benefit)/
expense
-
-
-
-
1,520
51
(38)
(706)
303
-
(205)
(47)
878
413
413
224
(14)
(214)
4
846
255
(39)
(696)
391
(149)
-
(59)
549
46
46
30.6%
32.0%
29.6%
20.5%
2,993
(5,001)
898
23
56
(301)
(18)
(1,500)
(11)
475
1,308
3
275
Current income tax expense
1. The net $348 million reduction of the Pluto PRRT deferred tax asset in 2020
658
includes derecognition of general expenditure of $627 million (based on expected
future utilisation) offset by a reduction in the Pluto asset accounting base of
$279 million (included within 'PRRT projects profit/(loss) before tax').
2. Includes a $226 million PRRT expense as a result of the 2021 Pluto-Scarborough
impairment reversal increasing the asset accounting base and thereby reducing
the deferred tax asset.
3. Includes $10 million tax expense recognised in other comprehensive income
(2020: $19 million benefit).
4. The global operations effective income tax rate (ETR) is calculated as the Group’s
income tax expense divided by profit before income tax. The Australian operations
ETR is calculated with reference to all Australian companies and excludes foreign
exchange on settlement and revaluation of income tax liabilities.
5. Primarily expenditure in respect of foreign operations, including the impairment
of foreign assets and onerous contract provision.
6. Excludes adjustment to prior years.
Woodside Petroleum Ltd 107
NOTES TO THE FINANCIAL STATEMENTS A. EARNINGS FOR THE YEAR
for the year ended 31 December 2021
Key estimates and judgements
(a) Income tax classification
Judgement is required when determining whether a particular tax is an
income tax or another type of tax. PRRT is considered, for accounting
purposes, to be an income tax. Accounting for deferred tax is applied
to income taxes as described above, but is not applied to other types
of taxes, e.g. North West Shelf royalties, excise and levies which are
recognised in cost of sales in the income statement.
(b) Deferred tax asset recognition
Australian tax losses: A deferred tax asset (DTA) of nil (2020:
$149 million) has been recognised for carry forward unused tax losses
and credits. The 2020 DTA was fully utilised in 2021.
Foreign tax losses: Deferred tax assets of $497 million (2020:
$477 million) relating to unused foreign tax losses have not been
recognised on the basis that it is not probable that the assets will be
utilised based on current planned activities in those regions.
PRRT: The recoverability of PRRT deferred tax assets is primarily
assessed with regard to future oil price assumptions. As a result of the
Pluto impairment reversal (as disclosed in Note B.4) increasing the
Pluto PRRT accounting base, the Pluto PRRT DTA has been reduced
by $226 million. The Pluto PRRT DTA of $785 million continues to be
recognised on the basis that it is probable that future taxable profits
will be available to utilise the deductible expenditure. In determining
the amount of DTA that is considered probable and eligible for
recognition, forecast future taxable profits are risk-adjusted where
appropriate by a market premium risk rate to reflect uncertainty
inherent in long-term forecasts. A long-term bond rate of 1.5%
(31 December 2020: 1.0%) was used for the purposes of augmentation.
All other deferred PRRT and income tax movements are a result of
the effective income tax rates applicable to each Australian or foreign
jurisdiction.
Certain deferred tax assets on deductible temporary differences
have not been recognised on the basis that deductions from future
augmentation of the deductible temporary difference will be sufficient
to offset future taxable profit. $4,507 million (2020: $4,167 million)
relates to the North West Shelf Project, $1,432 million (2020:
$1,345 million) relates to the quarantined exploration spend and
unrecognised general spend of Pluto LNG and $1,071 million (2020:
$1,049 million) relates to Wheatstone. A long-term bond rate of 1.5%
(31 December 2020: 1.0%) was used for the purposes of augmentation.
Had an alternative approach been used to assess recovery of the
deferred tax assets, whereby future augmentation was not included
in the assessment, the additional deferred tax assets would be
recognised, with a corresponding benefit to income tax expense. It was
determined that the approach adopted provides the most meaningful
information on the implications of the PRRT regime, whilst ensuring
compliance with AASB 112 Income Taxes.
A.5 Taxes (cont.)
Tax transparency code
Woodside participates in the Australian Board of Taxation’s
voluntary Tax Transparency Code (TTC). To increase public
confidence in the contributions and compliance of corporate
taxpayers, the TTC recommends public disclosure of tax
information. Woodside has addressed the recommended
disclosures in two parts. The Part A disclosures are addressed
within this Taxes note; the Part B disclosures are addressed
in our Sustainable Development Report.
Recognition and measurement
Current tax assets and liabilities are measured at the amount
expected to be recovered from or paid to the taxation authorities.
Deferred tax assets and liabilities are measured at the tax rates
that are expected to apply in the period in which the liability is
settled or the asset is realised. The tax rates and laws used to
determine the amount are based on those that have been enacted
or substantially enacted by the end of the reporting period.
Income taxes relating to items recognised directly in equity are
recognised in equity.
Current taxes
Current tax expense is the expected tax payable on the taxable
income for the year and any adjustment to tax payable in respect
of previous years.
Deferred taxes
Deferred tax expense represents movements in the temporary
differences between the carrying amount of an asset or liability
in the statement of financial position and its tax base.
With the exception of those noted below, deferred tax liabilities
are recognised for all taxable temporary differences.
Deferred tax assets are recognised for deductible temporary
differences, unused tax losses and tax credits only if it is probable
that sufficient future taxable income will be available to utilise
those temporary differences and losses.
Deferred tax is not recognised if the temporary difference arises
from goodwill or from the initial recognition (other than in a
business combination) of assets and liabilities in a transaction
that affects neither accounting profit nor the taxable profit.
In relation to PRRT, the impact of future augmentation on
expenditure is included in the determination of future taxable
profits when assessing the extent to which a deferred tax asset
can be recognised in the statement of financial position.
Offsetting deferred tax balances
Deferred tax assets and liabilities are offset only if there is a legally
enforceable right to offset current tax assets and liabilities and
when they relate to income taxes levied by the same taxation
authority on either the same taxable entity or different taxable
entities that the Group intends to settle its current tax assets
and liabilities on a net basis. Refer to Notes E.8 and E.9 for detail
on the tax consolidated group.
108 Annual Report 2021
NOTES TO THE FINANCIAL STATEMENTS B. PRODUCTION AND GROWTH ASSETS
for the year ended 31 December 2021
In this section
This section addresses the strategic growth (exploration and evaluation), core producing and development (oil and gas properties)
assets position of the Group at the end of the reporting period including, where applicable, the accounting policies and key estimates and
judgements applied. This section also includes the impairment position of the Group at the end of the reporting period.
B.
B.1
B.2
B.3
B.4
B.5
B.6
Production and growth assets
Segment production and growth assets
Exploration and evaluation
Oil and gas properties
Impairment of exploration and evaluation and oil
and gas properties
Page 110
Page 112
Page 113
Page 115
Significant production and growth asset acquisitions
Page 120
Non-current assets held for sale
Page 121
Woodside Petroleum Ltd 109
NOTES TO THE FINANCIAL STATEMENTS B. PRODUCTION AND GROWTH ASSETS
for the year ended 31 December 2021
B.1 Segment production and growth assets
Producing
Development
Other
t
s
e
W
h
t
r
o
N
f
l
e
h
S
o
t
u
P
l
l
i
O
a
i
l
a
r
t
s
u
A
e
n
o
t
s
t
a
e
h
W
h
g
u
o
r
o
b
r
a
c
S
s
t
n
e
m
p
o
l
e
v
e
d
r
e
h
t
O
r
a
m
o
g
n
a
S
d
e
t
a
d
i
l
o
s
n
o
C
r
e
h
t
O
2021
US$m
2021
US$m
2021
US$m
2021
US$m
2021
US$m
2021
US$m
2021
US$m
2021
US$m
2021
US$m
9
-
-
-
-
9
16
65
1,757
8
226
2,072
11
-
1
12
-
-
-
-
119
2
(12)
109
-
-
-
-
-
-
-
-
-
-
321
234
7,651
-
403
8,609
52
-
132
184
-
-
-
-
268
20
4
292
-
-
-
-
13
-
-
-
-
13
-
69
585
-
10
664
-
-
-
-
-
-
-
-
13
-
(13)
-
-
-
-
-
4
-
-
-
-
4
401
158
2,315
-
27
2,901
3
-
-
3
1
-
-
1
112
15
39
166
-
-
-
-
43
-
-
-
-
43
-
-
-
-
1,980
1,980
10
-
-
10
-
446
-
446
559
9
-
568
-
-
-
-
-
-
-
58
-
58
-
-
-
-
2,195
2,195
11
167
9
187
7
-
-
7
1,049
77
14
1,140
14
205
9
228
477
-
-
-
-
477
-
-
-
-
-
-
-
-
-
-
-
5
6
11
-
-
-
-
-
-
-
-
-
-
-
10
-
10
1
-
5
-
7
546
-
-
68
-
614
739
526
12,313
8
4,848
13
18,434
290
-
394
684
34
2
-
36
6
-
-
6
-
-
-
-
377
167
536
1,080
42
453
6
501
2,126
123
32
2,281
14
205
9
228
Balance as at 31 December
Oceania
Asia
Canada
Africa
Other
Total exploration and evaluation
Balance as at 31 December
Land and buildings
Transferred exploration and evaluation
Plant and equipment
Marine vessels and carriers
Projects in development
Total oil and gas properties
Balance as at 31 December
Land and buildings
Plant and equipment
Marine vessels and carriers
Total lease assets
Additions to exploration and evaluation:
Exploration
Evaluation
Restoration
Additions to oil and gas properties:
Oil and gas properties
Capitalised borrowings costs1
Restoration
Additions to lease assets:
Land and buildings
Plant and equipment
Marine vessels and carriers
1. Borrowing costs capitalised were at a weighted average interest rate of 3.6%.
Refer to Note A.1 for descriptions of the Group’s segments and geographical regions.
110 Annual Report 2021
NOTES TO THE FINANCIAL STATEMENTS B. PRODUCTION AND GROWTH ASSETS
for the year ended 31 December 2021
B.1 Segment production and growth assets (cont.)
Producing
Development
Other
t
s
e
W
h
t
r
o
N
f
l
e
h
S
o
t
u
P
l
l
i
O
a
i
l
a
r
t
s
u
A
e
n
o
t
s
t
a
e
h
W
h
g
u
o
r
o
b
r
a
c
S
s
t
n
e
m
p
o
l
e
v
e
d
r
e
h
t
O
r
a
m
o
g
n
a
S
d
e
t
a
d
i
l
o
s
n
o
C
r
e
h
t
O
2020
US$m
2020
US$m
2020
US$m
2020
US$m
20202
US$m
20202
US$m
20202
US$m
2020
US$m
2020
US$m
Balance as at 31 December
Oceania
Asia
Canada
Africa
Other
Total exploration and evaluation
Balance as at 31 December
Land and buildings
Transferred exploration and evaluation
Plant and equipment
Marine vessels and carriers
Projects in development
Total oil and gas properties
Balance as at 31 December
Land and buildings
Plant and equipment
Marine vessels and carriers
Total lease assets
Additions to exploration and evaluation:
Exploration
Evaluation
Restoration
Additions to oil and gas properties:
Oil and gas properties
Capitalised borrowings costs1
Restoration
9
-
-
-
-
9
9
61
1,574
11
131
1,786
12
-
1
13
-
-
-
-
68
1
34
103
-
-
-
-
-
-
307
167
7,498
-
549
8,521
22
-
156
178
-
-
-
-
322
17
68
407
13
-
-
-
-
13
-
90
784
-
10
884
-
-
-
-
-
-
-
-
432
113
2,074
-
395
3,014
3
-
-
3
1
-
-
1
93
2
42
137
287
10
43
340
3
-
-
-
-
3
1,261
-
-
-
-
1,261
-
-
-
-
-
-
4
-
-
4
-
255
-
255
-
-
-
-
Additions to lease assets:
Land and buildings
Plant and equipment
Marine vessels and carriers
6
-
-
6
1. Borrowing costs capitalised were at a weighted average interest rate of 3.8%.
2. The 2020 amounts have been restated to reflect the changes in the Development segment. Refer to Note A.1 for details.
12
-
1
13
3
-
-
3
-
-
-
-
-
-
-
-
-
-
-
51
-
51
-
-
-
-
-
-
1
-
-
1
26
-
-
26
767
27
-
794
-
-
-
-
466
-
-
-
-
466
-
-
-
-
1,055
1,055
33
-
-
33
-
39
44
83
-
-
-
-
1
-
-
1
-
229
-
13
-
242
1
-
3
-
3
7
317
-
435
752
18
16
-
34
2
-
-
2
2
-
101
103
1,752
229
-
64
-
2,045
749
431
11,933
11
2,143
15,267
392
-
592
984
45
310
44
399
1,539
57
187
1,783
24
-
102
126
Woodside Petroleum Ltd 111
NOTES TO THE FINANCIAL STATEMENTS B. PRODUCTION AND GROWTH ASSETS
for the year ended 31 December 2021
B.2 Exploration and evaluation
Year ended 31 December 2021
Carrying amount at 1 January 2021
Additions
Amortisation of licence acquisition costs
Expensed1
Transferred exploration and evaluation
Carrying amount at 31 December 2021
Year ended 31 December 2020
Carrying amount at 1 January 2020
Additions
Amortisation of licence acquisition costs
Expensed1
Impairment losses2
Transferred exploration and evaluation
Carrying amount at 31 December 2020
Exploration commitments
Oceania
US$m
Asia
US$m
Canada
US$m
Africa
US$m
Other
US$m
1,752
458
-
-
(1,664)
546
2,243
272
(5)
-
(748)
(10)
1,752
229
36
-
(265)
-
-
199
34
(4)
-
-
-
229
-
-
-
-
-
-
742
67
-
-
(809)
-
-
64
7
(3)
-
-
68
623
26
(3)
-
-
(582)
64
-
-
-
-
-
-
2
-
-
(2)
-
-
-
Total
US$m
2,045
501
(3)
(265)
(1,664)
614
3,809
399
(12)
(2)
(1,557)
(592)
2,045
94
Year ended 31 December 2021
Year ended 31 December 2020
115
1. $56 million (2020: $2 million) relates to costs of unsuccessful wells. $209 million (2020: nil) relates to capitalised costs written off due to the Group's decision to withdraw from
8
55
77
46
8
11
1
3
-
-
its interests in Myanmar.
2. Refer to Note B.4 for details on impairment.
Recognition and measurement
Expenditure on exploration and evaluation is accounted for
in accordance with the area of interest method. The Group’s
application of the accounting policy is closely aligned to the US
GAAP-based successful efforts method.
Areas of interest are based on a geographical area for which
the rights of tenure are current. All exploration and evaluation
expenditure, including general permit activity, geological and
geophysical costs and new venture activity costs, is expensed
as incurred except for the following:
• where the expenditure relates to an exploration discovery
for which the assessment of the existence or otherwise of
economically recoverable hydrocarbons is not yet complete; or
• where the expenditure is expected to be recouped through
successful exploitation of the area of interest, or alternatively,
by its sale.
The costs of acquiring interests in new exploration and evaluation
licences are capitalised. The costs of drilling exploration wells are
initially capitalised pending the results of the well.
Costs are expensed where the well does not result in the
successful discovery of economically recoverable hydrocarbons
and the recognition of an area of interest.
Subsequent to the recognition of an area of interest, all further
evaluation costs relating to that area of interest are capitalised.
Upon approval for the commercial development of an area of
interest, accumulated expenditure for the area of interest is
transferred to oil and gas properties.
In the statement of cash flows, those cash flows associated
with capitalised exploration and evaluation expenditure,
including unsuccessful wells, are classified as cash flows used
in investing activities.
Exploration commitments
The Group has exploration expenditure obligations which
are contracted for, but not provided for in the financial
statements. These obligations may be varied from time to time
and are expected to be fulfilled in the normal course of the
Group's operations.
Impairment
Refer to Note B.4 for details on impairment, including any
write-offs.
Key estimates and judgements
(a) Area of interest
Typically, an area of interest (AOI) is defined by the Group as an
individual geographical area whereby the presence of hydrocarbons is
considered favourable or proved to exist. The Group has established
criteria to recognise and maintain an AOI.
(b) Transfer to projects in development
Development activities commence after project sanctioning by
the appropriate level of management. Judgement is applied by
management in determining when the project is technically feasible
and economically viable.
112 Annual Report 2021
NOTES TO THE FINANCIAL STATEMENTS B. PRODUCTION AND GROWTH ASSETS
for the year ended 31 December 2021
B.3 Oil and gas properties
Year ended 31 December 2021
Carrying amount at 1 January 2021
Additions
Disposals at written down value
Depreciation and amortisation
Impairment losses1
Impairment reversals1
Completions and transfers
Transfer to non-current assets held for sale2
Carrying amount at 31 December 2021
At 31 December 2021
Historical cost
Accumulated depreciation and impairment
Net carrying amount
Year ended 31 December 2020
Carrying amount at 1 January 2020
Additions
Disposals at written down value
Depreciation and amortisation
Impairment losses1
Completions and transfers
Carrying amount at 31 December 2020
At 31 December 2020
Historical cost
Accumulated depreciation and impairment
Land and
buildings
US$m
Transferred
exploration and
evaluation
US$m
Plant and
equipment
US$m
Marine vessels
and carriers
US$m
Projects in
development
US$m
749
-
(2)
(51)
(10)
44
11
(2)
739
1,701
(962)
739
1,068
-
-
(55)
(264)
-
749
1,722
(973)
431
-
-
(79)
-
66
108
-
526
1,495
(969)
526
729
-
-
(99)
(199)
-
431
1,348
(917)
431
11,933
13
(2)
(1,416)
-
911
874
-
12,313
32,241
(19,928)
12,313
15,813
150
(3)
(1,533)
(2,636)
142
11,933
31,225
(19,292)
11,933
11
-
-
(3)
-
-
-
-
8
184
(176)
8
36
-
-
(2)
(23)
-
11
184
(173)
11
2,143
2,268
(19)
-
-
37
671
(252)
4,848
5,250
(402)
4,848
652
1,633
(2)
-
(590)
450
2,143
2,791
(648)
2,143
Total
US$m
15,267
2,281
(23)
(1,549)
(10)
1,058
1,664
(254)
18,434
40,871
(22,437)
18,434
18,298
1,783
(5)
(1,689)
(3,712)
592
15,267
37,270
(22,003)
15,267
Net carrying amount
1. Refer to Note B.4 for details on impairment losses and impairment reversals.
2. Refer to Note B.6 for details on non-current assets held for sale.
749
Woodside Petroleum Ltd 113
NOTES TO THE FINANCIAL STATEMENTS B. PRODUCTION AND GROWTH ASSETS
for the year ended 31 December 2021
Key estimates and judgements
(a) Reserves
The estimation of reserves requires significant management
judgement and interpretation of complex geological and geophysical
models in order to make an assessment of the size, shape, depth and
quality of reservoirs, and their anticipated recoveries.
Estimates of oil and natural gas reserves are used to calculate
depreciation and amortisation charges for the Group’s oil and gas
properties. Judgement is used in determining the reserve base
applied to each asset. Typically, late life oil assets use proved
reserves.
Estimates are reviewed at least annually or when there are changes
in the economic circumstances impacting specific assets or asset
groups. These changes may impact depreciation, asset carrying
values, restoration provisions and deferred tax balances. If proved
plus probable (2P) reserves estimates are revised downwards,
earnings could be affected by higher depreciation expense or an
immediate write-down of the asset’s carrying value.
For more information regarding reserve assumptions, refer
to the Reserves and resources statement on pages 55-59 of the
Annual Report.
(b) Depreciation and amortisation
Judgement is required to determine when assets are available for
use to commence depreciation and amortisation. Depreciation and
amortisation generally commences on first production.
(c) Change in useful life
As a result of FID on the Scarborough Development and Pluto Train
2, the Group conducted a review of the expected utilisation of the
Pluto LNG onshore assets. Pluto LNG onshore assets were previously
intended for use until the cessation of production from Pluto LNG.
A number of Pluto LNG onshore assets are now expected to be
utilised in the processing of Scarborough reserves and as a result the
expected useful lives of these assets have increased by a range of
1-23 years. The change in useful life has been applied prospectively
from the month of FID and has resulted in a decrease in depreciation
expense of $60 million for the year ended 31 December 2021.
B.3 Oil and gas properties (cont.)
Recognition and measurement
Oil and gas properties are stated at cost less accumulated
depreciation and impairment charges. Oil and gas properties
include the costs to acquire, construct, install or complete
production and infrastructure facilities such as pipelines and
platforms, capitalised borrowing costs, transferred exploration
and evaluation assets, development wells and the estimated cost
of dismantling and restoration.
Subsequent capital costs, including major maintenance, are
included in the asset’s carrying amount only when it is probable
that future economic benefits associated with the item will flow
to the Group and the cost of the item can be reliably measured.
Depreciation and amortisation
Oil and gas properties and other plant and equipment are
depreciated to their estimated residual values at rates based
on their expected useful lives.
Transferred exploration and evaluation and offshore plant and
equipment are depreciated using the unit of production basis
over proved plus probable reserves or proved reserves for late
life assets. The depreciable amount for the unit of production
basis excludes future development costs necessary to bring
probable reserves into production. Onshore plant and equipment
is depreciated using a straight-line basis over the lesser of useful
life and the life of proved plus probable reserves. On a straight-line
basis the assets have an estimated useful life of 5-50 years.
All other items of oil and gas properties are depreciated using the
straight-line method over their useful life. They are depreciated
as follows:
• Buildings – 24-40 years;
• Marine vessels and carriers – 10-40 years;
• Other plant and equipment – 5-15 years; and
• Land is not depreciated.
Impairment
Refer to Note B.4 for details on impairment.
Capital commitments
The Group has capital expenditure commitments contracted for,
but not provided for in the financials statements, of
$7,875 million (2020: $1,569 million) as at 31 December 2021.
Subsequent to year end, capital commitments contracted for
has reduced by approximately $2,876 million due to the Group’s
participating interest in the Pluto Train 2 Joint Venture reducing
from 100% to 51% (refer to Note E.5).
114 Annual Report 2021
NOTES TO THE FINANCIAL STATEMENTS B. PRODUCTION AND GROWTH ASSETS
for the year ended 31 December 2021
B.4
Impairment of exploration and evaluation and oil and gas properties
Exploration and evaluation
Impairment testing
The recoverability of the carrying amount of exploration and
evaluation assets is dependent on successful development and
commercial exploitation, or alternatively, sale of the respective AOI.
Each AOI is reviewed half-yearly to determine whether economic
quantities of hydrocarbons have been found or whether further
exploration and evaluation work is underway or planned to
support continued carry forward of capitalised costs. Where
a potential impairment is indicated for an AOI, an assessment
is performed using a fair value less costs to dispose (FVLCD)
method to determine its recoverable amount. Upon approval for
commercial development, exploration and evaluation assets are
also assessed for impairment before they are transferred to oil
and gas properties.
Impairment calculations
The recoverable amounts of exploration and evaluation assets
are determined using FVLCD as there is no value in use (VIU).
Costs to dispose are the incremental costs directly attributable to
the disposal of an asset, excluding finance costs and income tax
expense.
If the carrying amount of an AOI exceeds its recoverable amount,
the AOI is written down to its recoverable amount and an
impairment loss is recognised in the income statement.
For assets previously impaired, if the recoverable amount exceeds
the carrying amount, the impairment is reversed, but only to
the extent that the asset’s carrying amount does not exceed
the carrying amount that would have been recognised if no
impairment had occurred.
Oil and gas properties
Impairment testing
The carrying amounts of oil and gas properties are assessed half-
yearly to determine whether there is an indication of impairment
or impairment reversal for those assets which have previously
been impaired. Indicators of impairment and impairment reversals
include changes in future selling prices, future costs and reserves.
Oil and gas properties are assessed for impairment indicators and
impairments on a cash-generating unit (CGU) basis. CGUs are
determined as an FPSO and associated oil fields for an oil asset,
and an LNG plant, offshore infrastructure and associated gas fields
for a gas asset.
If there is an indicator of impairment or impairment reversal
for a CGU then the recoverable amount is calculated.
Impairment calculations
The recoverable amount of an asset or CGU is determined as
the higher of its VIU and FVLCD. VIU is determined by estimating
future cash flows after taking into account the risks specific to
the asset and discounting to present value using an appropriate
discount rate.
If the carrying amount of an asset or CGU exceeds its recoverable
amount, the asset or CGU is written down and an impairment loss
is recognised in the income statement.
For assets previously impaired, if the recoverable amount exceeds
the carrying amount, the impairment is reversed. The carrying
amount of the asset or CGU is increased to the revised estimate
of its recoverable amount, but only to the extent that the asset’s
carrying amount does not exceed the carrying amount that would
have been determined, net of depreciation or amortisation, if no
impairment had been recognised.
Woodside Petroleum Ltd 115
NOTES TO THE FINANCIAL STATEMENTS B. PRODUCTION AND GROWTH ASSETS
for the year ended 31 December 2021
B.4
Impairment of exploration and evaluation and oil and gas properties (cont.)
Recognised impairment and impairment reversals
As at 31 December 2021, the Group identified the following indicators for impairment and impairment reversals:
• Pluto-Scarborough and Wheatstone CGU - a reduction of 2P total reserves within the Greater Pluto and Wheatstone reserves and
resources estimates.
• Pluto-Scarborough CGU - additional value generated by Scarborough and Pluto Train 2, which have been combined with Pluto into a
new Pluto-Scarborough CGU following the final investment decision for Scarborough and Pluto Train 2 in November 2021.
• North West Shelf CGU - updated cost and production profiles, including the impact of third-party processing agreements, and short-
term pricing assumptions.
• NWS Oil (Okha) CGU - the reclassification to a late life oil asset due to natural reservoir decline and short-term pricing assumptions.
No impairment was recognised for Wheatstone and NWS Oil (Okha) as the recoverable amount exceeds the carrying amount of the CGU.
Impairment reversals were recognised for Pluto-Scarborough and NWS Gas (refer to Note A.1). The results were as follows:
Impairment reversal
Oil and gas properties
Segment
CGU
Producing and
Development
Pluto-Scarborough
Producing
North West Shelf
Total
Recoverable
amount
US$m
17,474
2,425
19,899
Land and
buildings
US$m
Transferred
exploration and
evaluation
US$m
Plant and
equipment
US$m
Projects in
development
US$m
42
2
44
53
13
66
563
348
911
24
13
37
Total
US$m
682
376
1,058
The recoverable amounts have been determined using the VIU method. The carrying amounts of the CGUs include all assets allocated to
the CGU. Refer to key estimates and judgements for further details.
Sensitivity analysis
Changes in the following key assumptions have been estimated to result in a higher or lower carrying amounts1 than what was
determined as at 31 December 2021:
Discount rate:
increase of 1%3,4
Discount rate:
decrease of 1%
Brent price:
increase of 10%
Brent price:
decrease of 10%
FX:
FX:
increase of 12%5
decrease of 12%
Sensitivity (US$m)2
Oil and gas
properties
Producing and
Development Pluto-Scarborough
Producing
North West Shelf
Wheatstone
NWS Oil (Okha)
-
-
(159)
(4)
-
-
178
4
-
-
438
39
-
(13)
(438)
(39)
-
-
(122)
(28)
-
-
122
28
1. Increases to carrying amounts are limited to historical impairment losses recognised, net of depreciation and amortisation that would have been incurred had no impairment
taken place.
2. The sensitivities represent reasonable possible changes to the discount rate, oil price and FX assumptions.
3. A change of 1% represents 100 basis points.
4. The relationship between the discount rate and carrying amount is non-linear and as such, the sensitivities are unlikely to result in a symmetrical impact. Due to the non-linear
relationship, the impact of changing the discount rate is likely to be greater at a lower discount rate than at a higher discount rate.
5. FX sensitivity of +12%/-12% was determined based on historical 5-year standard deviation of AU$/US$.
Impairment on non-current assets held for sale
The pending sale of a portion of the Wheatstone Construction Village resulted in an impairment loss of $10 million as the asset's carrying
value exceeded its FVLCD, which was determined based on the underlying sale agreements, classified as Level 3 on the fair value hierarchy.
An impairment loss of $10 million was recognised in the Wheatstone operating segment of Note A.1. Refer to Note B.6 for more details.
116 Annual Report 2021
NOTES TO THE FINANCIAL STATEMENTS B. PRODUCTION AND GROWTH ASSETS
for the year ended 31 December 2021
B.4
Impairment of exploration and evaluation and oil and gas properties (cont.)
Key estimates and judgements
CGU determination
Identification of a CGU requires management judgement. In determining
the new combined Pluto-Scarborough CGU, management has
determined that the Scarborough and Pluto Train 2 development
concept integrates with the existing Pluto onshore assets and is the
smallest group of assets that generate significant cash inflows that are
independent from other assets or group of assets.
Recoverable amount calculation key assumptions
In determining the recoverable amount of CGUs, estimates are made
regarding the present value of future cash flows when determining the
VIU. These estimates require significant management judgement and
are subject to risk and uncertainty, and hence changes in economic
conditions can also affect the assumptions used and the rates used to
discount future cash flow estimates.
The basis for each estimate used to determine recoverable amounts as at
31 December 2021 is set out below:
• Resource estimates – 2P reserves for oil and gas properties, except
for NWS Oil (Okha) which is based on 1P reserves due to the
reclassification to a late life asset. The reserves are as disclosed in the
Reserves and resources statement in the 31 December 2021 Annual
Report on pages 55-59.
• Inflation rate – an inflation rate of 2.0% has been applied.
• Foreign exchange rates – a rate of $0.75 US$:AU$ is based on
management’s view of long-term exchange rates.
• Discount rates – a range of pre-tax discount rates between 8.9% and
11.6% (post-tax discount rate 7.5%-8.5%) for CGUs has been applied.
The discount rate reflects an assessment of the risks specific to
the asset.
• An evaluation of climate risk is reflected in Woodside's assumptions
on carbon cost pricing, including a long-term Australian carbon price
of US$80/tonne of emissions (real terms 2022). This is applicable
to Australian emissions that exceed facility-specific baselines in
accordance with Australian regulations, as well as global emissions
that exceed voluntary corporate net emissions targets. Woodside
continues to monitor the uncertainty around climate change risks and
will revise carbon pricing assumptions accordingly.
• LNG price – the majority of LNG sales contracts are linked to an oil
price marker; accordingly the LNG prices used are consistent with oil
price assumptions.
• Brent oil prices – derived from long-term views of global supply
and demand, building upon past experience of the industry and
consistent with external sources. Prices are adjusted for premiums and
discounts based on the nature and quality of the product. Brent oil
price estimates have considered the risk of climate policies along with
other factors such as industry investment and cost trends. There is
significant uncertainty around how society will respond to the climate
challenge; Woodside’s pricing assumptions reflect a ‘most-likely’
scenario in which global governments pursue decarbonisation as well
as other goals such as energy security and economic development. As
with carbon pricing, Woodside continues to monitor this uncertainty
and will revise its oil pricing assumptions accordingly in its transition to
a lower carbon economy. Further information on climate change risk
is provided in Woodside’s Climate Report 2021. The nominal Brent oil
prices (US$/bbl) used were:
2023
71
31 December 20211
30 June 20202
62
1. Based on US$65/bbl (2022 real terms) from 2024 with prices escalated at
2025
69
72
2022
73
57
2026
70
73
2024
68
67
2027
72
75
2.0% annually thereafter.
2. Based on US$65/bbl (2020 real terms) from 2025 with prices escalated at
2.0% annually thereafter.
Woodside Petroleum Ltd 117
NOTES TO THE FINANCIAL STATEMENTS B. PRODUCTION AND GROWTH ASSETS
for the year ended 31 December 2021
B.4
Impairment of exploration and evaluation and oil and gas properties (cont.)
Recognised impairment and impairment reversals (cont.)
For the year ended 31 December 2020
As at 30 June 2020 the Group assessed each AOI and CGU and identified the following indicators of impairment for certain AOIs and all CGUs:
• AOIs – uncertainties on fiscal conditions and/or development strategies have led to a lack of substantive ongoing and/or planned
activity; and
• CGUs – the decrease in global oil and gas prices due to the impacts of the COVID-19 pandemic, oversupply and weakened global demand.
Impairment losses before tax were recognised in profit and loss, refer to Note A.1. The results were as follows, which include the AOIs and
CGUs which were subject to impairment testing:
Impairment losses
Oil and gas properties
Segment
Producing
AOI/CGU
Pluto
(WA-404-P)²,⁴
Development
Kitimat LNG⁵
Other
segments
Producing
Sunrise⁶
Toro (WA-93-R)/
Ragnar (WA-
94-R)³,⁷
North West Shelf
Pluto
Australia Oil
Vincent
(Ngujima-Yin)
NWS Oil (Okha)
Wheatstone
Development
Sangomar
Recoverable
amount1
US$m
Exploration
and
evaluation
US$m
Land and
buildings
US$m
Transferred
exploration
and
evaluation
US$m
Plant and
equipment
US$m
Marine
vessels and
carriers
US$m
Projects in
development
US$m
-
-
-
-
1,922
9,712
836
102
3,029
415
429
809
168
151
-
-
-
-
-
-
-
-
-
-
2
54
-
-
208
-
-
-
-
-
15
59
64
3
58
-
-
-
-
-
387
666
517
61
1,005
-
-
-
-
-
23
-
-
-
-
-
-
-
-
-
27
83
26
3
130
321
590
1. The recoverable amounts for exploration and evaluation assets and oil and gas properties were determined using the FVLCD and VIU methods, respectively.
16,016
2,636
1,557
Total
199
264
23
Total
US$m
-
-
-
-
454
862
607
67
1,401
321
3,712
The carrying amount of the CGUs include all assets allocated to the CGU. Refer to key estimates and judgements for further details.
2. The impairment of Pluto (WA-404-P) has resulted in a reclassification of the Greater Pluto (WA-404-P) Proved (1P) Undeveloped Reserves of 91 MMboe and Proved plus
Probable (2P) Undeveloped Reserves of 123 MMboe, to Best Estimate (2C) Contingent Resources.
3. Converted from WA-430-P.
Impairment indicators for exploration and evaluation assets:
4. Increased uncertainty of development timing, given the prioritisation of the higher-value Scarborough resource.
5. The revision of long-term oil and Alberta natural gas market spot price assumptions, and a change to the development concept to a standalone LNG facility, de-linked
from the upstream resource, with different accounting requirements.
6. Increased uncertainty of regulatory conditions, fiscal terms and development concept.
7. Increased uncertainty of development timing.
118 Annual Report 2021
NOTES TO THE FINANCIAL STATEMENTS B. PRODUCTION AND GROWTH ASSETS
for the year ended 31 December 2021
B.4
Impairment of exploration and evaluation and oil and gas properties (cont.)
Following the impairment recognised at 30 June 2020, the Group assessed each AOI and CGU for indicators of impairment as at
31 December 2020 in accordance with the Group's accounting policy. In assessing whether there was an indicator of impairment or
impairment reversal, the Group considered whether there were any significant changes in the key estimates and judgements and
underlying project assumptions used for the 30 June 2020 impairment assessment and determined that there were none. No indicators
of additional impairment or impairment reversal were identified as at 31 December 2020.
Key estimates and judgements
Recoverable amount calculation key assumptions
In determining the recoverable amounts of exploration and evaluation
assets, the market comparison approach using adjusted market multiples
(fair value hierarchy Level 3) was utilised to determine FVLCD.
In determining the recoverable amount of CGUs, estimates are made
regarding the present value of future cash flows when determining the
VIU. These estimates require significant management judgement and
are subject to risk and uncertainty, and hence changes in economic
conditions can also affect the assumptions used and the rates used
to discount future cash flow estimates.
The basis for the estimates used to determine recoverable amounts as
at 30 June 2020 is set out below:
• Resource estimates – 2P reserves for oil and gas properties as
disclosed in the Reserves and resources statement in the
31 December 2019 Annual Report on pages 44 to 47.
• Inflation rate – an inflation rate of 2.0% has been applied.
• Foreign exchange rates – a rate of $0.75 US$:AU$ is based on
management’s view of long-term exchange rates.
• Discount rates – a range of pre-tax discount rates between 9.3% and
14.8% (post-tax discount rates 7.5% and 11.0%) for CGUs has been
applied. The discount rate reflects an assessment of the risks specific
to the asset, including country risk.
• An evaluation of climate risk impacts, including a long-term
Australian carbon price of US$80/tonne (real terms 2020), applicable
to Australian emissions that exceed facility-specific baselines in
accordance with Australian regulations.
• LNG price – the majority of LNG sales contracts are linked to an oil
price marker; accordingly the LNG prices used are consistent with oil
price assumptions.
• Brent oil prices – derived from long-term views of global supply and
demand, building upon past experience of the industry and consistent
with external sources. Prices are adjusted for premiums and discounts
based on the nature and quality of the product. The nominal Brent oil
prices (US$/bbl) used were:
30 June 2020
2020
35
2021
45
2022
57
2023
62
2024
67
2025
721
1. Based on US$65/bbl (2020 real terms) from 2025 and prices are escalated at
2.0% onwards (31 December 2019: US$72.5/bbl (2020 real terms) and prices
are escalated at 2.0% onwards).
Woodside Petroleum Ltd 119
NOTES TO THE FINANCIAL STATEMENTS B. PRODUCTION AND GROWTH ASSETS
for the year ended 31 December 2021
B.5 Significant production and growth asset acquisitions
a) Sangomar - Acquisition from FAR Senegal RSSD SA
b) BHP merger commitment deed
On 7 July 2021, Woodside completed the acquisition of FAR
Senegal RSSD SA’s interest in the RSSD Joint Venture (13.67%
interest in the Sangomar exploitation area and 15% interest in the
remaining RSSD evaluation area), for an aggregate purchase price
of $212 million. The transaction was accounted for as an asset
acquisition.
Additional payments of up to $55 million are contingent on future
commodity prices and timing of first oil. The contingent payments
terminate on the earliest of 31 December 2027, three years from
first oil being sold, and a total contingent payment of $55 million
being reached. The contingent payments are accounted for as
contingent liabilities in accordance with the Group’s accounting
policies.
Woodside’s interest has increased to 82% in the Sangomar
exploitation area (31 December 2020: 68.33%) and to 90% in the
remaining RSSD evaluation area (31 December 2020: 75%).
Assets acquired and liabilities assumed
The identifiable assets and liabilities acquired as at the date of the
acquisition inclusive of transaction costs are:
Oil and gas properties
Exploration and evaluation
Cash acquired
Payables
Net other assets and liabilities assumed
Total identifiable net assets at acquisition
Cash flows on acquisition
Purchase cash consideration
Transaction costs
Total purchase consideration
Net cash outflows on acquisition
US$m
205
7
3
(13)
10
212
US$m
212
-
212
212
Key estimates and judgements
Nature of acquisition
Judgement is required to determine if the transaction is the acquisition of
an asset or a business combination. The Sangomar project is in the early
phase of development and a substantive process that has the ability to
convert inputs to outputs is not present and therefore the acquisitions in
both 2020 and 2021 are treated as asset acquisitions.
On 17 August 2021, Woodside and BHP Group (BHP) entered
into a merger commitment deed to combine their respective oil
and gas portfolios by an all stock merger (the Transaction). The
share sale agreement and the integration and transition services
agreement were executed on 22 November 2021.
On completion of the Transaction, BHP’s oil and gas business
will merge with Woodside, and Woodside will issue new shares
to be distributed to BHP shareholders. The expanded Woodside
will be owned 52% by existing Woodside shareholders and
48% by existing BHP shareholders. The Transaction is subject
to satisfaction of conditions precedent including shareholder,
regulatory and other approvals. The completion of the proposed
merger is targeted for Q2 2022 following all necessary approvals.
Woodside and BHP have also agreed on an option for BHP to sell
its 26.5% interest in the Scarborough Joint Venture and its 50%
interest in the Thebe and Jupiter Joint Ventures to Woodside.
The option is exercisable by BHP in the second half of 2022 and, if
exercised, consideration of $1,000 million is payable to BHP plus
working capital adjustments from 1 July 2021 to completion date.
An additional $100 million is payable contingent upon future FID
for a Thebe development.
c) Sangomar - Acquisition from Capricorn Senegal Limited
On 22 December 2020, Woodside completed the acquisition of
Capricorn Senegal Limited’s (Cairn’s) interest in the RSSD Joint
Venture (36.44% interest in the Sangomar exploitation area
and 40% interest in the remaining RSSD evaluation area) for an
aggregate purchase price of $527 million. The transaction was
accounted for as an asset acquisition.
Additional payments of up to $100 million are contingent on
future commodity prices and the timing of first oil. The contingent
payments are accounted for as contingent liabilities in accordance
with the Group’s accounting policies.
Assets acquired and liabilities assumed
The identifiable assets and liabilities acquired as at the date of the
acquisition inclusive of transaction costs were:
Oil and gas properties
Exploration and evaluation
Cash acquired
Payables
Net other assets and liabilities assumed
Total identifiable net assets at acquisition
Cash flows on acquisition
Purchase cash consideration
Transaction costs
Total purchase consideration
Net cash outflows on acquisition
US$m
540
26
5
(51)
7
527
US$m
525
2
527
527
120 Annual Report 2021
NOTES TO THE FINANCIAL STATEMENTS B. PRODUCTION AND GROWTH ASSETS
for the year ended 31 December 2021
Impairment relating to the non-current assets held for sale
Immediately before the classification as non-current assets held
for sale, the recoverable amount of the relevant assets were
calculated and an impairment of the Wheatstone Construction
Village amounting to $10 million was recognised within oil and gas
properties (refer to Note B.4).
Assets and liabilities of the non-current assets held for sale
As at 31 December 2021, the Group has reclassified $252 million
of Pluto Train 2 assets, $1 million of the Wheatstone Construction
Village assets and $1 million of the Pluto residential housing to
non-current assets held for sale. There are no recognised liabilities
associated with the non-current assets held for sale.
B.6 Non-current assets held for sale
Recognition and measurement
The Group classifies non-current assets and liabilities as held for
sale if their carrying amounts will be recovered principally through
sale rather than through continuing use. Such non-current assets
and liabilities classified as held for sale are measured at the lower
of their carrying amount and fair value less costs to sell. Costs
to sell are the incremental costs directly attributable to the sale,
excluding the finance costs and income tax expense.
The criteria for held for sale classification is regarded as met only
when the sale is highly probable and the asset is available for sale
in its present condition. Actions required to complete the sale
should indicate that it is unlikely that significant changes to the
sale will be made or that the decision to sell will be withdrawn.
Management must be committed to the sale, expected within one
year from the date of the classification.
Property, plant and equipment and intangible assets are not
depreciated or amortised once classified as held for sale. Assets
and liabilities classified as held for sale are presented separately as
current items in the statement of financial position.
Transfers to non-current assets held for sale
On 15 November 2021, the Group and Global Infrastructure
Partners (GIP) entered into a Sale and Purchase Agreement for
GIP to acquire a 49% participating interest in the Pluto Train 2
Joint Venture. The transaction completed on 18 January 2022
(refer to Note E.5), reducing the Group’s participating interest
from 100% to 51%. Accordingly, the associated Pluto Train 2 assets
within the Development segment have been reclassified to
non-current assets held for sale. The arrangements require GIP to
fund its 49% share of capital expenditure from 1 October 2021 and
an additional amount of capital expenditure of approximately
$822 million. If the total capital expenditure incurred is less
than $5,600 million, GIP will pay Woodside an additional
amount equal to 49% of the under-spend. In the event of a cost
overrun, Woodside will fund up to approximately $822 million
of GIP’s share of the overrun. Delays to the expected start-up of
production will result in payments by Woodside to GIP in certain
circumstances. The arrangements include provisions for GIP to
be compensated for exposure to additional Scope 1 emissions
liabilities above agreed baselines, and to sell its 49% interest
back to Woodside if the status of key regulatory approvals
materially changes.
In addition, in December 2021, Woodside committed to sell a
portion of the Wheatstone Construction Village and six residential
properties. The construction village within the Wheatstone
operating segment and the residential properties within the Pluto
segment have been reclassified as non-current assets held for sale
and both sale transactions are expected to complete in 2022.
Woodside Petroleum Ltd 121
NOTES TO THE FINANCIAL STATEMENTS C. DEBT AND CAPITAL
for the year ended 31 December 2021
In this section
This section addresses cash, debt and the capital position of the Group at the end of the reporting period including, where applicable,
the accounting policies applied and the key estimates and judgements made.
C.
C.1
C.2
C.3
C.4
Debt and capital
Cash and cash equivalents
Interest-bearing liabilities and financing facilities
Contributed equity
Other reserves
Page 123
Page 123
Page 125
Page 125
Key financial and capital risks in this section
Capital risk management
Group Treasury is responsible for the Group's capital management including cash, debt and equity. Capital management is undertaken
to ensure that a secure, cost-effective and flexible supply of funds is available to meet the Group’s operating and capital expenditure
requirements. A stable capital base is maintained from which the Group can pursue its growth aspirations, whilst maintaining a flexible
capital structure that allows access to a range of debt and equity markets to both draw upon and repay capital.
The Dividend Reinvestment Plan (DRP) was approved by shareholders at the Annual General Meeting in 2003 for activation as required
to fund future growth. The DRP was reactivated for the 2019 interim dividend and will remain in place until further notice.
A range of financial metrics are monitored, including gearing and cash flow leverage, and Treasury policy breaches and exceptions.
Liquidity risk management
Liquidity risk arises from the financial liabilities of the Group and the Group’s subsequent ability to meet its obligations to repay financial
liabilities as and when they fall due. The liquidity position of the Group is managed to ensure sufficient liquid funds are available to meet
its financial commitments in a timely and cost-effective manner.
The Group’s liquidity is continually reviewed, including cash flow forecasts to determine the forecast liquidity position and maintain
appropriate liquidity levels. At 31 December 2021, the Group had a total of $6,125 million (2020: $6,704 million) of available undrawn
facilities and cash at its disposal. The maturity profile of interest-bearing liabilities is disclosed in Note C.2, trade and other payables are
disclosed in Note D.4 and lease liabilities are disclosed in Note D.7. Financing facilities available to the Group are disclosed in Note C.2.
Interest rate risk management
Interest rate risk is the risk that the Group’s financial position will fluctuate due to changes in market interest rates.
The Group’s exposure to the risk of changes in market interest rates relates primarily to financial instruments with floating interest rates
including long-term debt obligations, cash and short-term deposits. The Group manages its interest rate risk by maintaining an appropriate
mix of fixed and floating rate debt. To manage the ratio of fixed rate debt to floating rate debt, the Group may enter into interest rate
swaps. The Group holds cross-currency interest rate swaps to hedge the foreign exchange risk (refer to Section A) and interest rate risk
of the CHF denominated medium term note. The Group also holds interest rate swaps to hedge the interest rate risk associated with the
$600 million syndicated facility. Refer to Notes C.2 and D.6 for further details.
At the reporting date, the Group was exposed to various benchmark interest rates that were not designated in cash flow hedges, primarily
through $2,962 million (2020: $3,527 million) on cash and cash equivalents, $367 million (2020: $450 million) on interest-bearing liabilities
(excluding transaction costs) and $9 million (2020: $15 million) on cross-currency interest rate swaps.
A reasonably possible change in the USD London Interbank Offered Rate (LIBOR) (+1.0%/-1.0% (2020: +0.5%/-0.5%)), with all variables
held constant, would not have a material impact on the Group’s equity or the income statement in the current period.
The Group's Treasury function is closely monitoring the market and the output from the various industry working groups managing the
transition to new benchmark interest rates. The Treasury function is assessing the implications of the Interbank Offered Rates (IBOR)
reform across the Group and will manage and execute the transition from current benchmark rates to alternative benchmark rates.
122 Annual Report 2021
NOTES TO THE FINANCIAL STATEMENTS C. DEBT AND CAPITAL
for the year ended 31 December 2021
C.1 Cash and cash equivalents
Cash and cash equivalents
Cash at bank
Term deposits
Total cash and cash equivalents
2021
US$m
300
2,725
3,025
2020
US$m
367
3,237
3,604
Recognition and measurement
Cash and cash equivalents in the statement of financial position
comprise cash at bank and short-term deposits with an original
maturity of three months or less. Cash and cash equivalents are
stated at face value in the statement of financial position.
Foreign exchange risk
The Group held $108 million of cash and cash equivalents at
31 December 2021 (2020: $78 million) in currencies other
than US dollars.
C.2
Interest-bearing liabilities and financing facilities
Bilateral
Facilities
US$m
Syndicated
Facilities
US$m
JBIC
Facility
US$m
US Bonds
US$m
Medium Term
Notes
US$m
Year ended 31 December 2021
At 1 January 2021
Repayments1
Fair value adjustment and foreign exchange movement
Transaction costs capitalised and amortised
Carrying amount at 31 December 2021
Current
Non-current
Carrying amount at 31 December 2021
(4)
-
-
-
(4)
(2)
(2)
(4)
593
-
-
2
595
(2)
597
595
Undrawn balance at 31 December 2021
1,900
1,200
Year ended 31 December 2020
At 1 January 2020
Repayments1
Drawdowns1
Fair value adjustment and foreign exchange movement
Transaction costs capitalised and amortised
Carrying amount at 31 December 2020
Current
Non-current
Carrying amount at 31 December 2020
(3)
-
-
-
(1)
(4)
(1)
(3)
(4)
(4)
-
600
-
(3)
593
(2)
595
593
Undrawn balance at 31 December 2020
1,900
1,200
1. Included in cash flows classified within financing activities in the statement of cash flows.
250
(84)
-
-
166
83
83
166
-
333
(83)
-
-
-
250
83
167
250
-
4,778
(700)
-
3
4,081
(2)
4,083
4,081
-
4,775
-
-
-
3
4,778
696
4,082
4,778
-
597
-
(5)
-
592
200
392
592
-
578
-
-
19
-
597
-
597
597
-
Total
US$m
6,214
(784)
(5)
5
5,430
277
5,153
5,430
3,100
5,679
(83)
600
19
(1)
6,214
776
5,438
6,214
3,100
Recognition and measurement
All borrowings are initially recognised at fair value less transaction
costs. Borrowings are subsequently carried at amortised cost.
Any difference between the proceeds received and the
redemption amount is recognised in the income statement over
the period of the borrowings using the effective interest method.
Borrowings designated as a hedged item are measured at
amortised cost adjusted to record changes in the fair value of risks
that are being hedged in fair value hedges. The changes in the
fair value risks of the hedged item resulted in a gain of $5 million
being recorded (2020: loss of $19 million), and a loss of $7 million
recorded on the hedging instrument (2020: gain of $18 million).
All bonds, notes and facilities are subject to various covenants and
negative pledges restricting future secured borrowings, subject to
a number of permitted lien exceptions. Neither the covenants nor
the negative pledges have been breached at any time during the
reporting period.
Fair value
The carrying amount of interest-bearing liabilities approximates
their fair value, with the exception of the Group’s unsecured
bonds and the medium term notes. The unsecured bonds have a
carrying amount of $4,081 million (2020: $4,778 million) and a fair
value of $4,443 million (2020: $5,196 million). The medium term
notes have a carrying amount of $592 million (2020: $597 million)
and a fair value of $604 million (2020: $617 million). Fair value
is calculated based on the present value of future principal and
interest cash flows, discounted at the market rate of interest at the
reporting date and classified as Level 1 on the fair value hierarchy.
Where these cash flows are in a foreign currency, the present
value is converted to US dollars at the foreign exchange spot rate
prevailing at the reporting date. The Group’s repayment obligations
remain unchanged.
Foreign exchange risk
All interest-bearing liabilities are denominated in US dollars,
excluding the CHF175 million medium term note.
Woodside Petroleum Ltd 123
NOTES TO THE FINANCIAL STATEMENTS C. DEBT AND CAPITAL
for the year ended 31 December 2021
C.2
Interest-bearing liabilities and financing facilities (cont.)
Maturity profile of interest-bearing liabilities
The table below presents the contractual undiscounted cash
flows associated with the Group’s interest-bearing liabilities,
representing principal and interest. The figures will not necessarily
reconcile with the amounts disclosed in the consolidated
statement of financial position.
Due for payment in:
1 year or less
1-2 years
2-3 years
3-4 years
4-5 years
More than 5 years
2021
US$m
470
462
188
1,169
951
3,320
6,560
2020
US$m
979
470
462
178
1,161
4,266
7,516
Amounts exclude transaction costs.
Bilateral facilities
The Group has 14 bilateral loan facilities totalling $1,900 million
(2020: 14 bilateral loan facilities totalling $1,900 million). Details
of bilateral loan facilities at the reporting date are as follows:
To the extent that this reserve amount remains fully funded
and no default notice or acceleration notice has been given, the
revenue from Pluto LNG continues to flow directly to the Group
from the trust account.
Medium term notes
On 28 August 2015, the Group established a $3,000 million Global
Medium Term Notes Programme listed on the Singapore Stock
Exchange. Three notes have been issued under this programme
as set out below:
Maturity date
Currency
Carrying amount
(million)
15 July 2022
11 December 2023
29 January 2027
The unutilised program is not considered to be an unused facility.
US$
CHF
US$
200
175
200
Nominal interest
rate
Floating three
month US$
LIBOR
1%
3%
US bonds
The Group has four unsecured bonds issued in the United States
of America as defined in Rule 144A of the US Securities Act of 1933
as set out below:
Number of
facilities
5
2
7
Term (years)
Currency
Extension option
5
4
3
US$
US$
US$
Evergreen
Evergreen
Evergreen
Maturity date
5 March 2025
15 September 2026
15 March 2028
4 March 2029
Carrying amount
US$m
1,000
800
800
1,500
Nominal interest
rate
3.65%
3.70%
3.70%
4.50%
Interest on the bonds is payable semi-annually in arrears.
During the period, the Group redeemed the $700 million 2021
US bond and repaid $84 million on the JBIC facility.
Interest rates are based on USD LIBOR and margins are fixed
at the commencement of the drawdown period. Interest is paid
at the end of the drawdown period. Evergreen facilities may be
extended continually by a year subject to the bank’s agreement.
Syndicated facility
On 14 October 2019, Woodside increased the existing facility to
$1,200 million, with $400 million expiring on 11 October 2022 and
$800 million expiring on 11 October 2024. Interest rates are based
on USD LIBOR and margins are fixed at the commencement of the
drawdown period.
On 17 January 2020, the Group completed a new $600 million
syndicated facility with a term of seven years. Interest is based
on the USD London Interbank Offered Rate (LIBOR) plus 1.2%.
Interest is paid on a quarterly basis.
Japan Bank for International Cooperation (JBIC) facility
On 24 June 2008, the Group entered into a two tranche
committed loan facility of $1,000 million and $500 million
respectively. The $500 million tranche was repaid in 2013.
There is a prepayment option for the remaining balance.
Interest rates are based on LIBOR. Interest is payable semi-
annually in arrears and the principal amortises on a straight-line
basis, with equal instalments of principal due on each interest
payment date (every six months).
Under this facility, 90% of the receivables from designated Pluto
LNG sale and purchase agreements are secured in favour of the
lenders through a trust structure, with a required reserve amount
of $30 million.
124 Annual Report 2021
NOTES TO THE FINANCIAL STATEMENTS C. DEBT AND CAPITAL
for the year ended 31 December 2021
C.3 Contributed equity
C.4 Other reserves
Other reserves
Employee benefits reserve
Foreign currency translation reserve
Hedging reserve
Distributable profits reserve
Nature and purpose
2021
US$m
2020
US$m
232
793
(400)
58
683
219
793
(71)
462
1,403
Employee benefits reserve
Used to record share-based payments associated with the
employee share plans and remeasurement adjustments relating to
the defined benefit plan.
Foreign currency translation reserve
Used to record foreign exchange differences arising from the
translation of the financial statements of foreign entities from
their functional currency to the Group’s presentation currency.
Hedging reserve
Used to record gains and losses on hedges designated as cash
flow hedges, and foreign currency basis spread arising from the
designation of a financial instrument as a hedging instrument.
Gains and losses accumulated in the cash flow hedge reserve are
taken to the income statement in the same period during which
the hedged expected cash flows affect the income statement.
Distributable profits reserve
Used to record distributable profits generated by the Parent
entity, Woodside Petroleum Ltd.
Recognition and measurement
Issued capital
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.
Reserved shares
The Group’s own equity instruments, which are reacquired
for later use in employee share-based payment arrangements
(reserved shares), are deducted from equity. No gain or loss is
recognised in the income statement on the purchase, sale, issue
or cancellation of the Group’s own equity instruments.
(a) Issued and fully paid shares
Year ended 31 December 2021
Opening balance
DRP - ordinary shares issued at A$24.77
(2020 final dividend)
DRP - ordinary shares issued at A$19.47
(2021 interim dividend)
Number of
shares
US$m
962,225,814
9,297
1,354,072
6,051,940
26
86
Amounts as at 31 December 2021
969,631,826
9,409
Year ended 31 December 2020
Opening balance
DRP - ordinary shares issued at A$25.61
(2019 final dividend)
DRP - ordinary shares issued at A$18.79
(2020 interim dividend)
Employee share plan - ordinary shares
issued at A$18.27
(2017 Woodside equity plan)
Amounts as at 31 December 2020
942,286,900
9,010
12,072,034
6,091,035
1,775,845
962,225,814
181
83
23
9,297
All shares are a single class with equal rights to dividends, capital,
distributions and voting. The Company does not have authorised
capital nor par value in relation to its issued shares.
(b) Shares reserved for employee share plans
Year ended 31 December 2021
Opening balance
Purchases during the year
Vested during the year
Amounts at 31 December 2021
Year ended 31 December 2020
Opening balance
Purchases during the year
Vested during the year
Amounts at 31 December 2020
Number of
shares
1,766,099
2,683,469
(2,629,824)
1,819,744
1,985,306
2,242,345
(2,461,552)
1,766,099
US$m
(23)
(47)
40
(30)
(39)
(32)
48
(23)
Woodside Petroleum Ltd 125
NOTES TO THE FINANCIAL STATEMENTS D. OTHER ASSETS AND LIABILITIES
for the year ended 31 December 2021
In this section
This section addresses the other assets and liabilities position at the end of the reporting period including, where applicable, the accounting
policies applied and the key estimates and judgements made.
D.
D.1
D.2
D.3
D.4
D.5
D.6
D.7
Other assets and liabilities
Segment assets and liabilities
Receivables
Inventories
Payables
Provisions
Page 127
Page 127
Page 127
Page 128
Page 128
Other financial assets and liabilities
Page 130
Leases
Page 132
Key financial and capital risks in this section
Credit risk management
Credit risk is the risk that a counterparty will not meet its obligation under a financial instrument or customer contract, leading to a financial
loss to the Group. Credit risk arises from the financial assets of the Group, which comprise trade and other receivables, loans receivables
and deposits with banks and financial institutions.
The Group manages its credit risk on trade receivables and financial instruments by predominantly dealing with counterparties with an
investment grade credit rating. Sufficient collateral is obtained to mitigate the risk of financial loss when transacting with counterparties
with below investment grade credit ratings. Customers who wish to trade on unsecured credit terms are subject to credit verification
procedures. Receivable balances are monitored on an ongoing basis. As a result, the Group’s exposure to bad debts is not significant.
The Group’s maximum credit risk is limited to the carrying amount of its financial assets.
Customer credit risk is managed by the Treasury function subject to the Group’s established policy, procedures and controls relating to
customer credit risk management. Credit quality of a customer is assessed based on an extensive credit rating scorecard and individual
credit limits are defined in accordance with this assessment. Outstanding customer receivables are regularly monitored. At 31 December
2021, the Group had four customers (2020: four customers) that owed the Group more than $10 million each and accounted for
approximately 88% (2020: 82%) of all trade receivables. Payment terms are typically 14 to 30 days providing only a short credit exposure.
The Group considers the probability of default upon initial recognition of the asset and whether there has been a significant depreciation
in credit quality on an ongoing basis. A significant decrease in credit quality is defined as a debtor being greater than 30 days past due
in making a contractual payment. Credit losses for trade receivables (including lease receivables) and contract assets are determined
by applying the simplified approach and are measured at an amount equal to lifetime expected loss. Under the simplified approach,
determination of the loss allowance provision and expected loss rate incorporates past experience and forward-looking information,
including the outlook for market demand and forward-looking interest rates. A default on other financial assets is considered to be when
the counterparty fails to make contractual payments within 60 days of when they fall due.
At 31 December 2021, the Group had a provision for credit losses of nil (2020: nil). Subsequent to 31 December 2021, 100% (2020: 100%) of
the trade receivables balance of $152 million (2020: $164 million) has been received.
Credit risk from balances with banks is managed by the Treasury function in accordance with the Group’s policy. The Group's main funds
are placed as short-term deposits with reputable financial institutions with strong investment grade credit ratings. At 31 December 2021
and 31 December 2020, there were no significant concentrations of credit risk within the Group and financial instruments are spread
amongst a number of financial institutions to minimise the risk of counterparty default. The maximum exposure to financial institution
credit risk is represented by the sum of all cash deposits plus accrued interest, bank account balances and fair value of derivative assets.
The Group’s counterparty credit policy limits this exposure to commercial and investment banks, according to approved credit limits based
on the counterparty’s credit rating.
126 Annual Report 2021
NOTES TO THE FINANCIAL STATEMENTS D. OTHER ASSETS AND LIABILITIES
for the year ended 31 December 2021
D.1 Segment assets and liabilities
(a) Segment assets
NWS
Pluto
Australia Oil
Wheatstone
Scarborough
Sangomar
Other development
Other segments
Unallocated items
(b) Segment liabilities
NWS
Pluto
Australia Oil
Wheatstone
Scarborough
Sangomar
Other development
Other segments
Unallocated items
2021
US$m
2,208
9,380
758
3,047
2,281
2,872
482
411
5,035
26,474
2021
US$m
647
937
913
302
84
350
83
798
8,131
12,245
2020
US$m
1,943
9,250
978
3,108
1,294
1,254
507
697
5,592
24,623
2020
US$m
679
950
848
281
16
96
153
953
7,772
11,748
Refer to Note A.1 for descriptions of the Group’s segments.
Unallocated assets mainly comprise cash and cash equivalents,
deferred tax assets and lease assets. Unallocated liabilities mainly
comprise interest-bearing liabilities, deferred tax liabilities and
lease liabilities.
D.2 Receivables
(a) Receivables (current)
Trade receivables1
Other receivables1
Loans receivable
Lease receivables
Interest receivable
Dividend receivable
(b) Receivables (non-current)
Loans receivable
Lease receivables
Defined benefit plan asset
2021
US$m
2020
US$m
152
123
75
18
-
-
368
627
26
33
686
164
75
59
3
1
1
303
394
10
19
423
1. Interest-free and settlement terms are usually between 14 and 30 days.
Recognition and measurement
Trade receivables are initially recognised at the transaction
price determined under AASB 15 Revenue from Contracts with
Customers. Other receivables are initially recognised at fair value.
Receivables that satisfy the contractual cash flow and business
model tests are subsequently measured at amortised cost less
an allowance for uncollectable amounts. Uncollectable amounts
are determined using the expected loss impairment model.
Collectability and impairment are assessed on a regular basis.
Subsequent recoveries of amounts previously written off are
credited against other expenses in the income statement. Certain
receivables that do not satisfy the contractual cash flow and
business model tests are subsequently measured at fair value
(refer to Note D.6).
The Group’s customers are required to pay in accordance with
agreed payment terms. Depending on the product, settlement
terms are 14 to 30 days from the date of invoice or bill of lading and
customers regularly pay on time. There are no significant overdue
trade receivables as at the end of the reporting period (2020: nil).
Fair value
The carrying amount of trade and other receivables approximates
their fair value.
Foreign exchange risk
The Group held $121 million of receivables at 31 December
2021 (2020: $68 million) in currencies other than US dollars
(predominantly Australian dollars).
Loans receivable
On 9 January 2020, Woodside Energy Finance (UK) Ltd entered
into a secured loan agreement with Petrosen (the Senegal
National Oil Company), to provide up to $450 million for the
purpose of funding Sangomar project costs. The facility has a
maximum term of 12 years and semi-annual repayments of the
loan are due to commence at the earlier of 12 months after RFSU
or 30 June 2025. The carrying amount of the loan receivable
is $335 million at 31 December 2021 (2020: $113 million), which
approximates its fair value. The remaining balance of loans
receivable is due from non-controlling interests.
D.3
Inventories
(a) Inventories (current)
Petroleum products
Goods in transit
Finished stocks
Warehouse stores and materials
(b) Inventories (non-current)
Warehouse stores and materials
2021
US$m
2020
US$m
35
34
133
202
19
19
18
33
74
125
40
40
Recognition and measurement
Inventories include hydrocarbon stocks, consumable supplies
and maintenance spares. Inventories are valued at the lower of
cost and net realisable value. Cost is determined on a weighted
average basis and includes direct costs and an appropriate portion
of fixed and variable production overheads where applicable.
Inventories determined to be obsolete or damaged are written
down to net realisable value, being the estimated selling price less
selling costs.
Woodside Petroleum Ltd 127
NOTES TO THE FINANCIAL STATEMENTS D. OTHER ASSETS AND LIABILITIES
for the year ended 31 December 2021
D.4 Payables
The following table shows the Group’s payables balances and
maturity analysis.
30-60
days
< 30
Total
days
US$m US$m US$m US$m
> 60
days
Year ended 31 December 2021
Trade payables1
Other payables1
Interest payable2
191
390
7
-
-
-
-
-
51
51
-
588
Total payables
Year ended 31 December 2020
100
Trade payables1
342
Other payables1
7
Interest payable2
Total payables
449
1. Interest-free and normally settled on 30 day terms.
2. Details regarding interest-bearing liabilities are contained in Note C.2.
-
-
5
5
-
-
51
51
191
390
58
639
100
342
63
505
Recognition and measurement
Trade and other payables are carried at amortised cost and are
recognised when goods and services are received, whether or not
billed to the Group, prior to the end of the reporting period.
Fair value
The carrying amount of payables approximates their fair value.
Foreign exchange risk
The Group held $311 million of payables at 31 December 2021
(2020: $210 million) in currencies other than US dollars
(predominantly Australian dollars).
D.5 Provisions
Year ended 31 December 2021
At 1 January 2021
Change in provision
Unwinding of present value discount
Carrying amount at 31 December 2021
Current
Non-current
Net carrying amount
Year ended 31 December 2020
At 1 January 2020
Change in provision
Unwinding of present value discount
Carrying amount at 31 December 2020
Current
Non-current
Restoration1
US$m
Employee benefits Onerous contracts2
US$m
US$m
Other
US$m
2,134
60
24
2,218
235
1,983
2,218
1,869
237
28
2,134
54
2,080
295
(9)
-
286
269
17
286
189
106
-
295
272
23
349
(140)
5
214
-
214
214
-
347
2
349
46
303
129
(23)
-
106
101
5
106
70
59
-
129
128
1
Total
US$m
2,907
(112)
29
2,824
605
2,219
2,824
2,128
749
30
2,907
500
2,407
Net carrying amount
1. 2021 change in provision is due to changes in estimates of $239 million (primarily due to the inclusion of costs for the removal of rigid plastic-coated pipelines, reflecting an update
2,134
2,907
295
129
349
to Woodside’s assumptions based on decommissioning planning activities in 2021), offset by a revision of discount rates of $134 million and provisions used of $45 million.
2. 2021 change in provision is due to provisions used of $45 million and changes in estimates of $95 million.
Recognition and measurement
Provisions are recognised when the Group has a present
obligation (legal or constructive) as a result of a past event, it
is probable that an outflow of resources embodying economic
benefits will be required to settle the obligation and a reliable
estimate can be made of the amount of the obligation.
Restoration
The restoration provision is first recognised in the period in which
the obligation arises. The nature of restoration activities includes
the removal of facilities, abandonment of wells and restoration
of affected areas. Restoration provisions are updated annually,
with the corresponding movement recognised against the related
exploration and evaluation assets or oil and gas properties.
Over time, the liability is increased for the change in the present
value based on a pre-tax discount rate appropriate to the risks
inherent in the liability. The unwinding of the discount is recorded
as an accretion charge within finance costs. The carrying amount
capitalised in oil and gas properties is depreciated over the useful
life of the related asset (refer to Note B.3).
128 Annual Report 2021
Costs incurred that relate to an existing condition caused by
past operations, and which do not have a future economic benefit,
are expensed.
Employee benefits
Provision is made for employee benefits accumulated as a result
of employees rendering services up to the end of the reporting
period. These benefits include wages, salaries, annual leave and
long service leave.
Liabilities in respect of employees’ services rendered that are not
expected to be wholly settled within one year after the end of
the period in which the employees render the related services are
recognised as long-term employee benefits.
These liabilities are measured at the present value of the
estimated future cash outflow to the employees using the
projected unit credit method. Liabilities expected to be wholly
settled within one year after the end of the period in which the
employees render the related services are classified as short-term
benefits and are measured at the amount due to be paid.
NOTES TO THE FINANCIAL STATEMENTS D. OTHER ASSETS AND LIABILITIES
for the year ended 31 December 2021
D.5 Provisions (cont.)
Onerous contract provision
Provision is made for loss-making contracts at the present value of the lower of the net cost of fulfilling and the cost arising from failure to
fulfill each contract. Long-term expectations of reduced spreads between North American and European/Asian LNG or gas markets has
given rise to a loss-making contract.
Key estimates and judgements
(a) Restoration obligations
The Group estimates the future remediation and removal costs of offshore
oil and gas platforms, production facilities, wells and pipelines at different
stages of the development and construction of assets or facilities. In many
instances, removal of assets occurs many years into the future.
The Group’s restoration obligations are based on compliance with the
requirements of relevant regulations which vary for different jurisdictions
and are often non-prescriptive. Australian legislation requires removal
of structures, equipment and property, or alternative arrangements to
removal which are satisfactory to the regulator. The Group maintains
technical expertise to ensure that industry learnings, scientific research
and local and international guidelines are reviewed in assessing its
restoration obligations.
The restoration obligation requires judgemental assumptions regarding
removal date, environmental legislation and regulations, the extent of
restoration activities required, the engineering methodology for estimating
cost, future removal technologies in determining the removal cost, and
liability-specific discount rates to determine the present value of these cash
flows. The Group's provision includes the following costs:
• for onshore assets, provision has been made for the full removal of
production facilities and aboveground pipelines.
(b) Long service leave
Long service leave is measured at the present value of benefits
accumulated up to the end of the reporting period. The liability is
discounted using an appropriate discount rate. Management uses
judgement to determine key assumptions used in the calculation
including future increases in salaries and wages, future on-cost rates and
future settlement dates of employees’ departures.
(c) Legal case outcomes
Provisions for legal cases are measured at the present value of the
amount expected to settle the claim. Management is required to use
judgement when assessing the likely outcome of legal cases, estimating
the risked amount and whether a provision or contingent liability should
be recognised.
(d) Onerous contracts
The onerous contract provision assessment requires management
to make certain estimates regarding the unavoidable costs and the
expected economic benefits from the contract. These estimates
require significant management judgement and are subject to risk and
uncertainty, and hence changes in economic conditions can affect the
assumptions. The present value of the provision was estimated using the
assumptions set out below:
• Contract term – 19 years; the provision is released as contract deliveries
• for offshore assets, provision has been made for the plug and
are made up to 2040.
abandonment of wells and the removal of offshore platform topsides,
floating production storage offloading (FPSO) and some subsea
infrastructure. It is currently the Group’s assumption that certain
pipelines and infrastructure, parts of offshore platform substructures,
and certain subsea infrastructure remain in-situ where it can be
demonstrated that this will deliver equal or better health, safety and
environmental outcomes than full removal and that regulatory approval
is obtained where arrangements are satisfactory to the regulator.
Elements composed of steel, or steel and concrete, with hydrocarbons
removed have previously been accepted by the Australian regulator to
be decommissioned in-situ where it has been demonstrated there is an
acceptable impact to the environment and to current and future marine users
(i.e. fishing, shipping and other activities).
The basis of the restoration obligation provision for assets with approved
decommissioning plans or general directions issued by the regulator can
differ from the assumptions disclosed above. Whilst the provisions reflect
the Group’s best estimate based on current knowledge and information,
further studies and detailed analysis of the restoration activities for
individual assets will be performed near the end of their operational life
and/or when detailed decommissioning plans are required to be submitted
to the relevant regulatory authorities. Actual costs and cash outflows
can materially differ from the current estimate as a result of changes in
regulations and their application, prices, analysis of site conditions, further
studies, timing of restoration and changes in removal technology. These
uncertainties may result in actual expenditure differing from amounts
included in the provision recognised as at 31 December 2021.
A range of pre-tax discount rates between 0.4% and 2.4% (2020: 0.1% to
2%) has been applied. If the discount rates were decreased by 0.5% then the
provision would be $134 million higher. If the cost estimates were increased
by 10% then the provision would be $225 million higher. The proportion of
the non-current balance not expected to be settled within 10 years is 65%
(2020: 73%).
In the event that the removal of all, or a substantial portion of, the elements
was required, Woodside estimates the additional cost would lead to
an increase to the provision of approximately $300 - $500 million. This
excludes costs related to large diameter trunklines between the offshore
platforms and onshore plants as further assessment is required for these
pipelines which are buried below the seabed or heavily stabilised by rock
or concrete due to their location and metocean conditions.
• Discount rate – a pre-tax, risk free US government bond rate
of 1.855% (2020: 1.390%) has been applied.
• LNG pricing – forecast sales and purchase prices are subject to a
number of price markers. Price assumptions are based on the best
information on the market available at measurement date and derived
from short- and long-term views of global supply and demand, building
upon past experience of the industry and consistent with external
sources. The forecasted sales are linked to gas hub prices (Title Transfer
Facility (TTF)) at which physical sales are expected to occur and
incorporates known pricing information related to sales1. The long-term
gas sales price is estimated on the basis of the Group's Brent price
forecast. The estimated purchase price is linked to US gas hub prices
(Henry Hub (HH)) at which physical purchases are expected to occur.
The nominal TTF, Brent oil prices and HH gas prices used at
31 December 2021 were:
TTF (US$/MMBtu)
Brent (US$/bbl)
HH (US$/MMBtu)
2022
15.0
73
4.0
2023
8.2
71
3.6
2024
6.9
68
3.1
2025
7.0
69
3.2
2026
7.2
70²
3.33
The nominal impact of the effects of changes to discount rate and long-
term price assumptions are estimated as follows:
Change in assumption4
LNG sales price1: increase of 10%
LNG sales price1: decrease of 10%
US hub gas price (HH)3: increase of 10%
US hub gas price (HH)3: decrease of 10%
Discount rate: increase of 1%5
Discount rate: decrease of 1%5
1. For committed volumes, contracted pricing has been applied. For hedge
US$m
500
(509)
(282)
282
19
(20)
accounted volumes, the relevant hedged prices have been applied.
2. Long-term oil prices are based on US$65/bbl (2022 real terms) from 2024
and prices are escalated at 2.0% onwards.
3. Long-term gas prices are based on US$3.0/MMBtu (2022 real terms) from
2025 to 2029 and thereafter US$3.5/MMBtu (2022 real terms). All long-
term prices are escalated at 2.0%.
4. Amounts shown represent the change of the present value of the contract
keeping all other variables constant. Any reduction in the onerous provision
recognised would not exceed the balance of the provision itself.
5. A change of 1% represents 100 basis points.
Woodside Petroleum Ltd 129
NOTES TO THE FINANCIAL STATEMENTS D. OTHER ASSETS AND LIABILITIES
for the year ended 31 December 2021
D.6 Other financial assets and liabilities
Other financial assets
Financial instruments at fair value through
profit and loss
Derivative financial instruments designated
as hedges
Other financial assets
Total other financial assets
Current
Non-current
Net carrying amount
Other financial liabilities
Financial instruments at fair value through
profit and loss
Derivative financial instruments designated
as hedges
Other financial liabilities
Total other financial liabilities
Current
Non-current
Net carrying amount
2021
US$m
2020
US$m
134
293
427
320
107
427
563
9
572
411
161
572
31
195
226
172
54
226
68
3
71
37
34
71
Ineffectiveness may arise where the timing of the transaction
changes from what was originally estimated such as delayed
shipments or changes in timing of forecast sales. This may also
arise where the commodity swap pricing terms do not perfectly
match the pricing terms of the LNG revenue contracts.
Fair value
Except for the other financial assets and other financial liabilities
set out in this note, there are no material financial assets or
financial liabilities carried at fair value.
The fair value of commodity derivative financial instruments is
determined based on observable quoted forward pricing and swap
models and is classified as Level 2 on the fair value hierarchy. The
most frequently applied valuation techniques include forward
pricing and swap models that use present value calculations. The
models incorporate various inputs including the credit quality of
counterparties and forward rate curves of the underlying commodity.
The fair value of interest rate swaps is calculated by discounting
estimated future cash flows based on the terms of maturity of each
contract, using market interest rates for a similar instrument at the
reporting date and is classified as Level 2 on the fair value hierarchy.
Recognition and measurement
Other financial assets and liabilities
Receivables subject to provisional pricing adjustments are initially
recognised at the transaction price and subsequently measured at
fair value with movements recognised in the income statement.
The fair value of foreign exchange forward contracts is
determined using quoted forward exchange rates at the reporting
date and present value calculations based on high credit quality
yield curves in the respective currencies and is classified as Level 2
on the fair value hierarchy.
Derivative financial instruments
Derivative financial instruments that are designated within
qualifying hedge relationships are initially recognised at fair value
on the date the contract is entered into. For relationships
designated as fair value hedges, subsequent fair value movements
of the derivative are recognised in the income statement.
For relationships designated as cash flow hedges, subsequent
fair value movements of the derivative for the effective portion
of the hedge are recognised in other comprehensive income and
accumulated in reserves in equity; fair value movements for the
ineffective portion are recognised immediately in the income
statement. Costs of hedging have been separated from the hedging
arrangements and deferred to other comprehensive income and
accumulated in reserves in equity. Amounts accumulated in equity
are reclassified to the income statement in the periods when the
hedged item affects profit or loss.
Hedge effectiveness is determined at the inception of the hedge
relationship, and through periodic prospective effectiveness
assessments to ensure that an economic relationship exists
between the hedged exposure and the hedging instrument.
The Group assesses whether the derivative designated in each
hedging relationship has been, and is expected to be, effective in
offsetting changes in cash flows of the hedged exposure using the
hypothetical derivative method.
Ineffectiveness is recognised where the cumulative change in
the designated component value of the hedging instrument on
an absolute basis exceeds the change in value of the hedged
exposure attributable to the hedged risk.
130 Annual Report 2021
The fair values of other financial assets and other financial
liabilities are predominantly determined based on observable
quoted forward pricing and are predominantly classified as Level 2
on the fair value hierarchy.
Foreign exchange
The derivative financial instruments include foreign exchange
forward contracts that are denominated in Australian dollars.
The Group had no material other financial assets and liabilities
denominated in currencies other than US dollars.
Hedging activities
During the period, the following hedging activities were undertaken:
• The Group hedged a percentage of its oil-linked exposure,
entering into oil swap derivatives settling between 2021 to 2023
in order to achieve a minimum average sales price per barrel.
• The Group also entered into separate HH commodity swaps
to hedge the purchase leg of the Corpus Christi volumes and
separate TTF commodity swaps to hedge the sales leg of
Corpus Christi volumes effectively protecting against pricing
risk for 2022 and 2023. As a result of hedging and term sales,
approximately 97% of Corpus Christi volumes in 2022 and 70%
in 2023 have hedged pricing risk.
• The Group entered into TTF commodity swaps to hedge equity
LNG cargoes expected to be exposed to winter 2021/22 natural
gas pricing.
• The Group entered into foreign exchange forward contracts to
fix the Australian dollar to US dollar exchange rate in relation to a
portion of the Australian dollar denominated capital expenditure
expected to be incurred under the Scarborough development.
NOTES TO THE FINANCIAL STATEMENTS D. OTHER ASSETS AND LIABILITIES
for the year ended 31 December 2021
D.6 Other financial assets and liabilities (cont.)
Hedging activities (cont.)
For the year ended 31 December 2020 the following main hedging
activities were undertaken:
The Group hedged a percentage of its exposure to commodity price
risk, entering into 13.4 million barrels of oil swap derivatives to achieve a
minimum average sales price of $33 per barrel. The Group also entered
into 7.9 million barrels of oil call options, to take advantage of increases
in oil prices above $40 per barrel, for a premium of $37 million. Most of
the derivatives settled between April 2020 and December 2020, with
swaps and options for 1.3 million barrels settling in 2021. The swaps and
call options were designated as cash flow hedges.
2021
2020
Oil swaps (cash flow hedges)
Carrying amount (US$m)
Notional amount (MMbbl)
Maturity date
Hedge ratio
Weighted average hedged rate (US$/MMbbl)
HH Corpus Christi commodity swaps (cash
flow hedges)
Carrying amount (US$m)
Notional amount (TBtu)
Maturity date
Hedge ratio
Weighted average hedged rate (US$/MMBtu)
TTF Corpus Christi commodity swaps (cash
flow hedges)
Carrying amount (US$m)
Notional amount (TBtu)
Maturity date
Hedge ratio
Weighted average hedged rate (US$/MMBtu)
TTF commodity swaps (cash flow hedges)
Carrying amount (US$m)
Notional amount (TBtu)
Maturity date
Hedge ratio
Weighted average hedged rate (US$/MMBtu)
Interest rate swap (cash flow hedges)
Carrying amount (US$m)
Notional amount (US$m)
Maturity date
Hedge ratio
Weighted average hedged rate
Cross currency interest rate swap (cash flow
and fair value hedges)
Carrying amount (US$m)
Notional amount (Swiss Franc)
Maturity date
Hedge ratio
Weighted average hedged rate
Oil call options (cash flow hedges)
Carrying amount (US$m)
Notional amount (MMbbl)
Maturity date
Hedge ratio
Weighted average hedged rate (US$/MMbbl)
FX forwards (cash flow hedges)
Carrying amount (US$m)
Notional amount (AUD$m)
Maturity date
Hedge ratio
Weighted average hedged rate (AUD:USD)
(1)
30
2022-2023
1:1
74
31
65
2022-2023
1:1
3
(465)
49
2022-2023
1:1
9
4
3
2022
1:1
26
(17)
600
2027
1:1
1.7%
(22)
1
2021
1:1
33
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
(43)
600
2027
1:1
1.7%
9
175
2023
1:1
Three month
US$ LIBOR
+2.8%
15
175
2023
1:1
Three month
US$ LIBOR
+2.8%
-
-
-
-
-
10
934
2022-2025
1:1
0.71
13
1
2021
1:1
33
-
-
-
-
-
Hedge ineffectiveness of $38 million (2020: $1 million) has been
recognised in the profit and loss.
Other financial assets
Other financial assets measured at fair value include receivables
subject to provisional pricing adjustments of $163 million
(2020: $144 million) and repurchase agreements entered into for
the purposes of net settlement rather than for physical delivery of
$69 million (2020: nil).
Interest Rate Benchmark Reform
A fundamental reform of major interest rate benchmarks is being
undertaken globally, including the replacement of some interbank
offered rates (IBORs) with alternative nearly risk-free rates (referred
to as 'IBOR reform'). The Group has exposures to IBORs on its
financial instruments that will be impacted as part of these market-
wide initiatives. The Group's main IBOR exposure at the reporting
date is USD LIBOR. In 2020, the Federal Reserve announced that
LIBOR will be phased out and eventually replaced by June 2023.
The Group anticipates that IBOR reform will impact its operational
and risk management processes and hedge accounting. The main
risks to which the Group is exposed as a result of IBOR reform
are operational, for example renegotiating borrowing contracts
through bilateral negotiation with counterparties, implementing
new fallback clauses with its derivative counterparties, updating
contractual terms and revising operational controls related to
the reform. Financial risk is predominantly limited to interest rate
risk. Hedging relationships may experience ineffectiveness due
to uncertainty about when and how replacement may occur with
respect to the relevant hedged item and hedging instrument or
the difference in the timing of a replacement.
The Group's financial instruments have not yet transitioned to an
alternative interest rate benchmark. The Group has financial liabilities
and financial assets with a total carrying value of $957 million and
$367 million respectively, with reference to USD LIBOR.
The Group has the following hedging relationships which are
exposed to interest rate benchmarks impacted by IBOR Reform:
• Interest rate swaps to hedge the LIBOR interest rate risk
associated with the $600 million syndicated facility (refer to
Note C.2). The interest rate swaps are designated as cash flow
hedges, converting the variable interest into fixed interest US
dollar debt, and mature in 2027.
• A fixed rate 175 million Swiss Franc (CHF) denominated medium
term note, which it hedges with cross-currency interest rate
swaps designated in both fair value and cash flow hedge
relationships. The cross-currency interest rate swaps are
referenced to LIBOR (refer to Note C.2).
The Group's Treasury function continues to assess the implications
of the IBOR reform across the Group and will manage and
execute the transition from current benchmark rates to alternative
benchmark rates.
Key estimates and judgements
Fair value of other financial assets and liabilities
Estimates have been applied in the measurement of other financial
assets and liabilities and, where required, judgement is applied in the
settlement of any financial assets or liabilities. In the current period,
this included a $56 million periodic adjustment which increased other
financial liabilities, reflecting the arrangements governing Wheatstone
LNG sales (2020: $12 million decrease).
Woodside Petroleum Ltd 131
NOTES TO THE FINANCIAL STATEMENTS D. OTHER ASSETS AND LIABILITIES
for the year ended 31 December 2021
D.7 Leases
Lease assets
Year ended 31 December 2021
Carrying amount at 1 January 2021
Additions
Lease remeasurements
Disposals at written down value
Depreciation
Carrying amount at 31 December 2021
At 31 December 2021
Historical cost and remeasurements
Accumulated depreciation,
impairment and disposals
Net carrying amount
Lease liabilities
Year ended 31 December 2021
At 1 January 2021
Additions
Repayments (principal and interest)
Accretion of interest
Lease remeasurements
Carrying amount at 31 December 2021
Current
Non-current
Carrying amount at 31 December 2021
Lease assets
Year ended 31 December 2020
Carrying amount at 1 January 2020
Additions
Lease remeasurements
Depreciation
Carrying amount at 31 December 2020
At 31 December 2020
Historical cost
Accumulated depreciation
and impairment
Net carrying amount
Lease liabilities
Year ended 31 December 2020
At 1 January 2020
Additions
Repayments (principal and interest)
Accretion of interest
Lease remeasurements
Carrying amount at 31 December 2020
Current
Non-current
Carrying amount at 31 December 2020
Marine
vessels
and
carriers
Total
US$m US$m US$m
Plant and
equipment
Land and
buildings
US$m
392
14
15
(12)
(32)
377
-
205
-
-
(38)
167
592
9
16
-
(81)
984
228
31
(12)
(151)
536
1,080
462
205
743
1,410
(85)
377
484
7
(70)
25
(9)
437
19
418
437
396
24
1
(29)
392
447
(55)
392
431
24
(34)
23
40
484
16
468
484
(38)
(207)
(330)
167
536
1,080
3
231
(48)
7
(1)
192
87
105
192
791
13
(144)
65
13
1,278
251
(262)
97
3
738
1,367
85
653
191
1,176
738
1,367
-
-
-
-
-
-
-
-
-
3
-
-
-
3
1
2
3
552
102
4
(66)
592
948
126
5
(95)
984
718
1,165
(126)
(181)
592
984
739
107
(123)
1,170
134
(157)
63
5
86
45
791
1,278
77
714
94
1,184
791
1,278
Recognition and measurement
When a contract is entered into, the Group assesses whether
the contract contains a lease. A lease arises when the Group
has the right to direct the use of an identified asset which is not
substitutable and to obtain substantially all economic benefits
from the use of the asset throughout the period of use. The leases
recognised by the Group predominantly relate to LNG vessels,
property and drilling rigs.
The Group separates the lease and non-lease components of the
contract and accounts for these separately. The Group allocates
the consideration in the contract to each component on the basis
of their relative stand-alone prices.
Leases as a lessee
Lease assets and lease liabilities are recognised at the lease
commencement date, which is when the assets are available for
use. The assets are initially measured at cost, which is the present
value of future lease payments adjusted for any lease payments
made at or before the commencement date, plus any make-good
obligations and initial direct costs incurred.
Lease assets are depreciated using the straight-line method over
the shorter of their useful life and the lease term. Refer to Note
B.3 for the useful lives of assets. Periodic adjustments are made
for any re-measurements of the lease assets and for impairment
losses, assessed in accordance with the Group’s impairment
policies.
Lease liabilities are initially measured at the present value of
future minimum lease payments, discounted using the Group’s
incremental borrowing rate if the rate implicit in the lease cannot
be readily determined, and are subsequently measured at
amortised cost using the effective interest rate. Minimum lease
payments are fixed payments or index-based variable payments
incorporating the Group’s expectations of extension options and
do not include non-lease components of a contract. A portfolio
approach was taken when determining the implicit discount rate
for LNG vessels with similar terms and conditions on transition.
The lease liability is remeasured when there are changes in
future lease payments arising from a change in rates, index or
lease terms from exercising an extension or termination option.
A corresponding adjustment is made to the carrying amount of
the lease assets, with any excess recognised in the consolidated
income statement.
There are no restrictions placed upon the lessee by entering into
these leases.
Short-term leases and leases of low value
Short-term leases (lease term of 12 months or less) and leases of
low value assets are recognised as incurred as an expense in the
consolidated income statement. Low value assets comprise plant
and equipment.
Foreign exchange risk
The Group held $476 million of lease liabilities at
31 December 2021 (2020: $518 million) in currencies other than
the US dollar (predominantly Australian dollars).
132 Annual Report 2021
NOTES TO THE FINANCIAL STATEMENTS D. OTHER ASSETS AND LIABILITIES
for the year ended 31 December 2021
Key estimates and judgements
(a) Control
Judgement is required to assess whether a contract is or contains a
lease at inception by assessing whether the Group has the right to
direct the use of the identified asset and obtain substantially all the
economic benefits from the use of that asset.
(b) Lease term
Judgement is required when assessing the term of the lease and
whether to include optional extension and termination periods. Option
periods are only included in determining the lease term at inception
when they are reasonably certain to be exercised.
Lease terms are reassessed when a significant change in circumstances
occurs. On this basis, possible additional lease payments amounting
to $1,654 million (2020: $1,670 million) were not included in the
measurement of lease liabilities.
(c) lnterest in joint arrangements
Judgement is required to determine the Group's rights and obligations
for lease contracts within joint operations, to assess whether lease
liabilities are recognised gross (100%) or in proportion to the Group’s
participating interest in the joint operation. This includes an evaluation
of whether the lease arrangement contains a sublease with the joint
operation.
(d) Discount rates
Judgement is required to determine the discount rate, where the
discount rate is the Group’s incremental borrowing rate if the rate
implicit in the lease cannot be readily determined. The incremental
borrowing rate is determined with reference to the Group's borrowing
portfolio at the inception of the arrangement or the time of the
modification.
D.7 Leases (cont.)
Maturity profile of lease liabilities
The table below presents the contractual undiscounted cash flows
associated with the Group’s lease liabilities, representing principal
and interest. The figures will not necessarily reconcile with the
amounts disclosed in the consolidated statement of financial position.
Due for payment in:
1 year or less
1-2 years
2-3 years
3-4 years
4-5 years
More than 5 years
2021
US$m
283
283
191
171
161
789
1,878
2020
US$m
184
181
180
174
174
994
1,887
Lease commitments
The table below presents the contractual undiscounted cash flows
associated with the Group's future lease commitments for non-
cancellable leases not yet commenced, representing principal
and interest.
Due for payment:
Within one year
After one year but not more than five years
Later than five years
2021
US$m
2020
US$m
80
159
49
288
90
365
45
500
Subsequent to year end, contractual undiscounted future lease
commitments for non-cancellable leases not yet commenced
increased by $634 million. The leases commence from 2025 and
relate to facilities, marine vessels and carriers (refer to Note E.5).
Payments of $68 million (2020: $101 million) for short-term leases
(lease term of 12 months or less) and payments of $18 million
(2020: $17 million) for leases of low value assets were expensed in
the consolidated income statement. Total payments for leases in
the statement of cash flows are $330 million (2020: $275 million),
with $244 million (2020: $157 million) included in financing
activities.
The Group has short-term and low value lease commitments
for marine vessels and carriers, property, drill rigs and plant and
equipment contracted for, but not provided for in the financial
statements, of $53 million (2020: $94 million).
Woodside Petroleum Ltd 133
NOTES TO THE FINANCIAL STATEMENTS E. OTHER ITEMS
for the year ended 31 December 2021
In this section
This section addresses information on items which require disclosure to comply with Australian Accounting Standards and the
Corporations Act 2001, however are not considered critical in understanding the financial performance or position of the Group.
This section includes Group structure information and other disclosures.
E.
E.1
E.2
E.3
E.4
E.5
E.6
E.7
E.8
E.9
Other items
Contingent liabilities and assets
Employee benefits
Related party transactions
Auditor remuneration
Events after the end of the reporting period
Joint arrangements
Parent entity information
Subsidiaries
Other accounting policies
Page 135
Page 135
Page 137
Page 137
Page 137
Page 137
Page 138
Page 139
Page 141
134 Annual Report 2021
NOTES TO THE FINANCIAL STATEMENTS E. OTHER ITEMS
for the year ended 31 December 2021
E.1 Contingent liabilities and assets
(b) Compensation of key management personnel
2021
US$m
20201
US$m
Key management personnel (KMP) compensation for the financial
year was as follows:
Contingent liabilities at reporting date
Contingent liabilities
Guarantees
195
7
202
587
10
597
1. Contingent payments of $450 million were paid in 2021 due to a positive FID to
develop the Scarborough field and capitalised to oil and gas properties.
Contingent liabilities relate predominantly to possible obligations
whose existence will only be confirmed by the occurrence or non-
occurrence of uncertain future events, and therefore the Group
has not provided for such amounts in these financial statements.
Additionally, there are a number of other claims and possible
claims that have arisen in the course of business against entities in
the Group, the outcome of which cannot be estimated at present
and for which no amounts have been included in the table above.
The above table includes contingent payments of $155 million
(31 December 2020: $100 million) relating to the Sangomar
development, dependent on commodity prices and the timing of
first oil.
Additionally, the Group has issued guarantees relating to workers’
compensation liabilities.
There were no contingent assets as at 31 December 2021 or
31 December 2020.
E.2 Employee benefits
Employee benefits
Share-based payments
Defined contribution plan costs
Defined benefit plan expense
2021
US$m
2020
US$m
217
12
26
1
256
252
19
27
2
300
(a) Employee benefits
Employee benefits for the reporting period are as follows:
Recognition and measurement
The Group’s accounting policy for employee benefits other than
superannuation is set out in Note D.5. The policy relating to share-
based payments is set out in Note E.2(c).
All employees of the Group are entitled to benefits on retirement,
disability or death from the Group’s superannuation plan. The
majority of employees are party to a defined contribution scheme
and receive fixed contributions from Group companies and
the Group’s legal or constructive obligation is limited to these
contributions. Contributions to defined contribution funds are
recognised as an expense as they become payable. Prepaid
contributions are recognised as an asset to the extent that a
cash refund or a reduction in the future payment is available. The
Group also operates a defined benefit superannuation scheme, the
membership of which is now closed. The net defined benefit plan
asset at 31 December 2021 was $33 million (2020: $19 million).
Short-term employee benefits
Post-employment benefits
Share-based payments
Long-term employee benefits
Termination benefits
(c) Share plans
2021
US$
2020
US$
6,599,678
77,515
5,609,022
717,223
2,447,525
15,450,963
5,868,476
63,805
7,201,653
515,585
390,087
14,039,606
The Group provides benefits to its employees (including KMP)
in the form of share-based payments whereby employees render
services for shares (equity-settled transactions).
Woodside equity plan (WEP) and supplementary Woodside
equity plan (SWEP)
The WEP is available to all permanent employees, but since 1 January
2018 has excluded EIS participants. The number of Equity Rights
(ERs) offered to each eligible employee is calculated with reference to
salary and performance. The linking of performance to an allocation
allows the Group to recognise and reward eligible employees for
high performance. The ERs have no further ongoing performance
conditions after allocation, and do not require participants to make
any payment in respect of the ERs at grant or at vesting.
Each ER relating to the WEP for 2018 and prior years entitles the
participant to receive a Woodside share on a vesting date three
years after the grant date. From the 2019 WEP onwards, 75% of the
ERs offered to each participant will vest three years after the grant
date, with the remaining 25% vesting five years after the grant date.
The SWEP award is available to employees identified as being retention
critical. Each ER entitles the participant to receive a Woodside share on
the vesting date three years after the effective grant date. Participants
do not make any payment in respect of the ERs at grant or at vesting.
Executive incentive plans (EIP)
The EIP operated as Woodside’s Executive incentive framework
until the end of 2017, after which the Board introduced the EIS.
The EIP was used to deliver short-term awards (STA) and long-
term awards (LTA) to Senior Executives.
Short-term awards (STA)
STAs were delivered in the form of restricted shares to Executives,
including all Executive KMP. There are no further performance
conditions for vesting of deferred STA. Participants are not required
to make any payments in respect of STA awards at grant or at
vesting. Restricted shares entitle their holders to receive dividends.
Long-term awards (LTA)
LTAs were granted in the form of Performance Rights (PRs) to
Executives, including all Executive KMP. Vesting of LTA is subject
to achievement of relative total shareholder return (RTSR) targets,
with 33% measured against the ASX 50 and the remaining 67%
tested against an international group of oil and gas companies.
Participants are not entitled to receive dividends and are not
required to make any payments in respect of LTA awards at grant
or at vesting.
Woodside Petroleum Ltd 135
NOTES TO THE FINANCIAL STATEMENTS E. OTHER ITEMS
for the year ended 31 December 2021
E.2 Employee benefits (cont.)
Executive incentive scheme (EIS)
The EIS was introduced for the 2018 performance year for all
Executives including Executive KMP. The EIS is delivered in the form
of a cash incentive, Restricted Shares and Performance Rights. The
grant date of the Restricted Shares and Performance Rights has been
determined to be subsequent to the performance year, being the date
of the Board of Directors’ approval. Accordingly, the 2020 Restricted
Shares and Performance Rights for Executives were granted on
17 February 2021, while the Performance Rights for the outgoing
CEO were granted on 15 April 2021 and have been included in
the table below. The expense estimated as at 31 December 2021
in relation to the 2021 performance year was updated to the fair
value on grant date during the period.
The 2021 Restricted Shares and Performance Rights have not been
included in the table below as they have not been approved as at 31
December 2021. An expense related to the 2021 performance year has
been estimated for Restricted Shares and Performance Rights, using
fair value estimates based on inputs at 31 December 2021.
Recognition and measurement
All compensation under WEP, SWEP and Executive share plans
is accounted for as share-based payments to employees for
Year ended 31 December 2021
Opening balance
Granted during the year1,2
Vested during the year
Forfeited during the year
Awards at 31 December 2021
Fair value of awards granted during the year
Year ended 31 December 2020
Opening balance
Granted during the year1,2
Vested during the year
Forfeited during the year
Awards at 31 December 2020
services provided. The cost of equity-settled transactions with
employees is measured by reference to the fair values of the equity
instruments at the date at which they are granted. The fair value
of share-based payments is recognised, together with the
corresponding increase in equity, over the period in which the
vesting conditions are fulfilled, ending on the date on which the
relevant employee becomes fully entitled to the shares. At each
balance sheet date, the Group reassesses the number of awards
that are expected to vest based on service conditions. The expense
recognised each year takes into account the most recent estimate.
The fair value of the benefit provided for the WEP and SWEP
is estimated using the Black-Scholes option pricing technique.
The fair value of the restricted shares is estimated as the closing
share price at grant date. The fair value of the benefit provided for
the RTSR PRs was estimated using the Binomial or Black-Scholes
option pricing technique combined with a Monte Carlo simulation
methodology, where relevant, using historical volatility to estimate
the volatility of the share price in the future.
The number of awards and movements for all share plans are
summarised as follows:
Number of performance awards
Employee plans
Executive plans
WEP
SWEP
STA3
LTA3
5,618,603
2,507,167
(1,999,676)
(476,311)
5,649,783
US$m
39
-
-
-
-
-
US$m
-
975,295
353,412
(307,402)
(26,869)
994,436
US$m
7
2,798,305
553,849
(322,746)
(650,188)
2,379,220
US$m
9
Number of performance awards
Employee plans
Executive plans
WEP
SWEP
STA3
LTA3
6,911,551
1,127,546
(1,943,777)
(476,717)
5,618,603
17,678
-
(17,678)
-
-
867,716
373,774
(257,489)
(8,706)
975,295
2,704,143
617,091
(242,608)
(280,321)
2,798,305
US$m
US$m
US$m
US$m
Fair value of awards granted during the year
1. For the purpose of valuation, the share price on grant date for the 2021 WEP allocations was $15.17 (2020: WEP allocations $12.57).
2. For the purpose of valuation, the share price on grant date for Restricted Shares was $20.18 (2020: $22.76) and Performance Rights were $11.66 and $14.44 (2020: $15.81).
3. Includes awards issued under EIP and EIS.
13
9
-
12
For more detail on these share plans and performance rights issued to KMPs, refer to the Remuneration Report on pages 69-92.
136 Annual Report 2021
NOTES TO THE FINANCIAL STATEMENTS E. OTHER ITEMS
for the year ended 31 December 2021
E.3 Related party transactions
(b) Interest percentage in joint operations
Transactions with directors
There were no transactions with directors during the year. Key
management personnel compensation is disclosed in Note E.2(b).
E.4 Auditor remuneration
The auditor of Woodside Petroleum Ltd is Ernst & Young (EY).
Amounts received or due and receivable to:
Ernst & Young (Australia)
- Fees for auditing the statutory financial report
of the parent covering the group and auditing
the statutory financial reports of any controlled
entities
- Fees for assurance services that are required by
legislation to be provided by the auditor
- Fees for other assurance and agreed upon
procedures services under other legislation
or contractual arrangements where there is
discretion as to whether the service is provided by
the auditor or another firm
- Other services
Other overseas member firms of Ernst & Young
(Australia)
- Audit of the financial reports of controlled
entities
- Fees for other assurance and agreed upon
procedures services under other legislation
or contractual arrangements where there is
discretion as to whether the service is provided by
the auditor or another firms
- Other services
2021
US$000
2020
US$000
1,455
1,521
2,687
-
22
134
4,298
110
164
1,795
277
165
11
14
302
30
14
209
E.5 Events after the end of the reporting period
On 15 November 2021, the Group and Global Infrastructure
Partners (GIP) entered into a Sale and Purchase Agreement
for GIP to acquire a 49% participating interest in the Pluto
Train 2 Joint Venture. The transaction completed on 18 January
2022, reducing the Group’s participating interest from 100%
to 51% and reducing the Group’s future capital commitments
by approximately $2,876 million. The full financial effect of the
transaction is still being assessed.
Subsequent to year end, the Group entered into new lease
arrangements (refer to Note D.7).
E.6 Joint arrangements
(a) Interest percentage in joint ventures
Entity
North West Shelf Gas Pty
Ltd
North West Shelf Liaison
Company Pty Ltd
China Administration
Company Pty Ltd
North West Shelf Shipping
Service Company Pty Ltd
North West Shelf Lifting
Coordinator Pty Ltd
Principal activity
Marketing services for
ventures in the sale of gas
to the domestic market.
Liaison for ventures in the
sale of LNG to the Japanese
market.
Marketing services for
ventures in the sale of LNG
to international markets.
LNG vessel fleet advisor.
Coordinator for venturers
for all equity liftings.
Group Interest %
2021
2020
16.67
16.67
16.67
16.67
16.67
16.67
16.67
16.67
16.67
16.67
Producing and developing assets
Oceania
North West Shelf
Greater Enfield and Vincent
Stybarrow
Balnaves
Pluto
Wheatstone
Scarborough1
Africa
Senegal2
Exploration and evaluation assets
Oceania
Browse Basin
Carnarvon Basin and Scarborough1
Bonaparte Basin
Africa
Congo
Senegal2
Americas
Kitimat3
Asia
Republic of Korea
Myanmar4
Europe
Ireland5
Bulgaria5
Group Interest %
2021
2020
12.5 - 50
60.0
50.0
65.0
90.0
13.0 - 65.0
73.5
12.5 - 50
60.0
50.0
65.0
90.0
13.0 - 65.0
-
82.0
68.3
30.6
15.8 - 70.0
26.7 - 35.0
30.6
15.8 - 73.5
26.7 - 35.0
42.5
90.0
50.0
42.5
75.0
50.0
50.0
40.0 - 50.0
50.0
40.0 - 50.0
-
-
90.0
30.0
1. FID taken on permits WA-61-L and WA-62-L announced on 22 November 2021.
2. Following the completion of the sale of FAR's interest in the RSSD joint venture
during the year, Woodside's participating interest increased to 82% in the
exploitation area and 90% in the exploration area (refer to Note B.5 more details).
3. Woodside is retaining an upstream position in the Liard Basin by taking on full
equity in 28 non-infrastructure related Liard Basin leases from Chevron Canada.
4. The Group completed the relinquishment of permits AD-2, AD-5 and A-4 in 2021
and is in the process of withdrawing from AD-6, AD-7 and A-7. In 2022, the Group
will also commence arrangements to formally exit AD-1, AD-8, the A-6 Joint
Venture and the A-6 production sharing contract.
5. Licence surrendered in 2021.
The principal activities of the joint operations above are
exploration, development and production of hydrocarbons.
Key estimates and judgements
Accounting for interests in other entities
Judgement is required in assessing the level of control obtained
in a transaction to acquire an interest in another entity; depending
upon the facts and circumstances in each case, Woodside may
obtain control, joint control or significant influence over the entity or
arrangement. Judgement is applied when determining the relevant
activities of a project and if joint control is held over it.
Relevant activities include, but are not limited to, work program and
budget approval, investment decision approval, voting rights in joint
operating committees, amendments to permits and changes to joint
arrangement participant holdings. Transactions which give Woodside
control of a business are business combinations. If Woodside obtains
joint control of an arrangement, judgement is also required to assess
whether the arrangement is a joint operation or a joint venture.
If Woodside has neither control nor joint control, it may be in a
position to exercise significant influence over the entity, which is then
accounted for as an associate.
Woodside Petroleum Ltd 137
NOTES TO THE FINANCIAL STATEMENTS E. OTHER ITEMS
for the year ended 31 December 2021
E.6 Joint arrangements (cont.)
E.7 Parent entity information
Recognition and measurement
Joint arrangements are arrangements in which two or more
parties have joint control. Joint control is the contractual agreed
sharing of control of the arrangement which exists only when
decisions about the relevant activities require unanimous consent
of the parties sharing control. Joint arrangements are classified as
either a joint operation or joint venture, based on the rights and
obligations arising from the contractual obligations between the
parties to the arrangement.
To the extent the joint arrangement provides the Group with
rights to the individual assets and obligations arising from the joint
arrangement, the arrangement is classified as a joint operation,
and as such the Group recognises its:
• assets, including its share of any assets held jointly;
• liabilities, including its share of any liabilities incurred jointly;
• revenue from the sale of its share of the output arising from
the joint operation;
• share of revenue from the sale of the output by the joint
operation; and
• expenses, including its share of any expenses incurred jointly.
To the extent the joint arrangement provides the Group with
rights to the net assets of the arrangement, the investment
is classified as a joint venture and accounted for using the
equity method.
Joint arrangements acquired which are deemed to be carrying
on a business are accounted for applying the principles of AASB 3
Business Combinations. Joint arrangements which are not deemed
to be carrying on a business are treated as asset acquisitions.
Woodside Petroleum Ltd:
Current assets
Non-current assets
Current liabilities
Non-current liabilities
Net assets
Issued and fully paid shares
Shares reserved for employee share plans
Employee benefits reserve
Foreign currency translation reserve
Distributable profits reserve
Retained earnings
Total shareholders equity
Profit of parent entity
Total comprehensive income of parent entity
2021
US$m
456
10,037
(357)
(300)
9,836
9,409
(30)
112
296
58
(9)
9,836
18
18
2020
US$m
444
10,257
-
(579)
10,122
9,297
(23)
117
296
462
(27)
10,122
852
852
Guarantees
Woodside Petroleum Ltd and Woodside Energy Ltd (a subsidiary
company) are parties to a Deed of Cross Guarantee as disclosed
in Note E.8. The effect of the Deed is that Woodside Petroleum
Ltd has guaranteed to pay any deficiency in the event of winding
up of the subsidiary company under certain provisions of the
Corporations Act 2001. The subsidiary company has also given
a similar guarantee in the event that Woodside Petroleum Ltd is
wound up.
Woodside Petroleum Ltd has guaranteed the discharge by a
subsidiary company of its financial obligations under debt facilities
disclosed in Note C.2. Woodside Petroleum Ltd has guaranteed
certain obligations of subsidiaries to unrelated parties on behalf of
their performance in contracts. No liabilities are expected to arise
from these guarantees.
138 Annual Report 2021
NOTES TO THE FINANCIAL STATEMENTS E. OTHER ITEMS
for the year ended 31 December 2021
E.8 Subsidiaries
(a) Subsidiaries
Name of entity
Ultimate Parent Entity
Woodside Petroleum Ltd
Subsidiaries
Company name
Woodside Energy Ltd
Woodside Browse Pty Ltd
Woodside Burrup Pty Ltd
Burrup Facilities Company Pty Ltd
Burrup Train 1 Pty Ltd
Pluto LNG Pty Ltd
Woodside Burrup Train 2 A Pty Ltd
Woodside Burrup Train 2 B Pty Ltd
Woodside Energy (LNG Fuels and Power) Pty Ltd
Woodside Energy (Domestic Gas) Pty Ltd
Woodside Energy (Algeria) Pty Ltd
Woodside Energy Australia Asia Holdings Pte Ltd y
Woodside Energy Holdings International Pty Ltd
Woodside Energy Mediterranean Pty Ltd
Woodside Energy International (Canada) Limited t
Woodside Energy (Canada LNG) Limited t
Woodside Energy (Canada PTP) Limited t
KM LNG Operating General Partnership t
KM LNG Operating Ltd t
Woodside Energy Holdings Pty Ltd
Woodside Energy Holdings (USA) Inc q
Woodside Energy (USA) Inc q
Gryphon Exploration Company q
Woodside Energy (Cameroon) SARL n
Woodside Energy (Gabon) Pty Ltd
Woodside Energy (Indonesia) Pty Ltd
Woodside Energy (Indonesia II) Pty Ltd
Woodside Energy (Malaysia) Pty Ltd
Woodside Energy (Ireland) Pty Ltd
Woodside Energy (Korea) Pte Ltd y
Woodside Energy (Korea II) Pte Ltd y
Woodside Energy (Myanmar) Pte Ltd y
Woodside Energy (Morocco) Pty Ltd
Woodside Energy (New Zealand) Limited z
Woodside Energy (New Zealand 55794) Limited z
Woodside Energy (Peru) Pty Ltd
Woodside Energy (Senegal) Pty Ltd
Woodside Energy (Tanzania) Limited ¥
Woodside Energy Holdings II Pty Ltd
Woodside Power Pty Ltd
Woodside Power (Generation) Pty Ltd
Woodside Energy Holdings (South America) Pty Ltd
Woodside Energia (Brasil) Apoio Administrativo Ltda l
Woodside Energy Holdings (UK) Pty Ltd
Woodside Energy (UK) Limited p
Woodside Energy Finance (UK) Limited p
Woodside Energy (Congo) Limited p
Woodside Energy (Bulgaria) Limited p
Woodside Energy Holdings (Senegal) Limited p
Woodside Energy (Senegal) B.V.
Woodside Energy (France) SAS £
Woodside Energy Iberia S.A. º
Woodside Energy (N.A.) Ltd p
Woodside Energy Services (Qingdao) Co Ltd
Woodside Energy Julimar Pty Ltd
Woodside Energy (Norway) Pty Ltd
Notes
(1,2,3)
(2,3,4)
(2,4)
(2,4)
(5)
(5)
(5)
(2,4)
(2,4)
(2,4)
(2,4)
(2,4)
(4)
(2,4)
(2,4)
(4)
(4)
(4)
(8)
(4)
(2,4)
(4)
(4)
(4)
(4)
(2,4)
(2,4)
(2,4)
(2,4,10)
(2,4)
(4)
(4)
(4)
(2,4)
(4)
(4)
(2,4)
(2,4)
(6)
(2,4)
(2,4)
(2,4)
(2,4)
(7)
(2,4)
(4)
(4)
(4)
(4)
(4)
(4)
(4)
(4)
(4)
(4)
(2,4)
(2,4)
Name of entity
Woodside Energy Technologies Pty Ltd
Woodside Technology Solutions Pty Ltd
Woodside Energy Scarborough Pty Ltd
Woodside Energy Carbon Holdings Pty Ltd
Woodside Energy Carbon (Assets) Pty Ltd
Woodside Energy Carbon (Services) Pty Ltd
Woodside Energy (Financial Advisory Services) Pty Ltd
Woodside Energy Trading Singapore Pte Ltd y
WelCap Insurance Pte Ltd y
Woodside Energy Shipping Singapore Pte Ltd y
Metasource Pty Ltd
Mermaid Sound Port and Marine Services Pty Ltd
Woodside Finance Limited
Woodside Petroleum (Timor Sea 19) Pty Ltd
Woodside Petroleum (Timor Sea 20) Pty Ltd
Woodside Petroleum Holdings Pty Ltd
Notes
(2,4,9)
(2,4)
(2,4,11)
(2,4,12)
(2,4,13)
(2,4,13)
(2,4,13)
(4)
(4)
(4)
(2,4)
(2,4)
(2,4)
(2,4)
(2,4)
(2,4)
1. Woodside Petroleum Ltd is the ultimate holding company and the head entity
within the tax consolidated group.
2. These companies were members of the tax consolidated group at 31 December
2021.
3. Pursuant to ASIC Instrument 2016/785, relief has been granted to the controlled
entity, Woodside Energy Ltd, from the Corporations Act 2001 requirements
for the preparation, audit and publication of accounts. As a condition of the
Instrument, Woodside Petroleum Ltd and Woodside Energy Ltd are parties to a
Deed of Cross Guarantee.
4. All subsidiaries are wholly owned except those referred to in Notes 5, 6, 7 and 8.
5. Kansai Electric Power Australia Pty Ltd and Tokyo Gas Pluto Pty Ltd each hold a
5% interest in the shares of these subsidiaries. These subsidiaries are controlled.
6. As at 31 December 2021, Woodside Energy Holdings Pty Ltd held a 99.99%
interest in the shares of Woodside Energy (Tanzania) Limited and Woodside
Energy Ltd held the remaining 0.01% interest.
7. As at 31 December 2021, Woodside Energy Holdings (South America) Pty
Ltd held a 99.99% interest in the shares of Woodside Energia (Brasil) Apoio
Administrativo Ltda and Woodside Energy Ltd held the remaining 0.01% interest.
8. As at 31 December 2021, Woodside Energy International (Canada) Limited and
Woodside Energy (Canada LNG) Limited were the general partners of the KM
LNG Operating General Partnership holding a 99.99% and 0.01% partnership
interest, respectively.
9. Woodside Energy Technologies Pty Ltd owns 30% in Blue Ocean Seismic Services
Limited which is accounted for as an investment in associate.
10. On 4 May 2021, Woodside Energy (Indonesia III) Pty Ltd changed its name to
Woodside Energy (Malaysia) Pty Ltd.
11. Woodside Energy Scarborough Pty Ltd was incorporated on 13 May 2021.
12. Woodside Energy Carbon Holdings Pty Ltd was incorporated on 29 July 2021.
13. Woodside Energy Carbon (Assets) Pty Ltd, Woodside Energy Carbon (Services)
Pty Ltd and Woodside Energy (Financial Advisory Services) Pty Ltd were
incorporated on 3 August 2021.
All subsidiaries were incorporated in Australia unless identified
with one of the following symbols:
The Netherlands ¥ Tanzania
l Brazil
n Cameroon z New Zealand
t Canada
£ France
y Singapore
º Spain
p England and Wales
q USA
China
Classification
Subsidiaries are all the entities over which the Group has the
power over the investee such that the Group is able to direct
the relevant activities, has exposure, or rights, to variable returns
from its involvement with the investee and has the ability to
use its power over the investee to affect the amount of the
investor’s returns.
Woodside Petroleum Ltd 139
NOTES TO THE FINANCIAL STATEMENTS E. OTHER ITEMS
for the year ended 31 December 2021
E.8 Subsidiaries (cont.)
(b) Subsidiaries with material non-controlling interests
The Group has two Australian subsidiaries with material
non-controlling interests (NCI).
Name of entity
Burrup Facilities Company Pty Ltd
Burrup Train 1 Pty Ltd
Principal place of
business
Australia
Australia
% held
by NCI
10%
10%
The NCI in both subsidiaries is 10% held by the same parties
(refer to Note E.8(a) footnote 5 for details).
The summarised financial information (including consolidation
adjustments but before intercompany eliminations) of subsidiaries
with material NCI is as follows:
2021
US$m
2020
US$m
Burrup Facilities Company Pty Ltd
Current assets
Non-current assets
Current liabilities
Non-current liabilities
Net assets
Accumulated balance of NCI
Revenue
Profit
Profit allocated to NCI
Dividends paid to NCI
Operating
Investing
Financing
518
5,038
(71)
(528)
4,957
496
858
328
33
(40)
633
(111)
(522)
Net increase/(decrease) in cash and cash equivalents
-
Burrup Train 1 Pty Ltd
Current assets
Non-current assets
Current liabilities
Non-current liabilities
Net assets
Accumulated balance of NCI
Revenue
Profit
Profit allocated to NCI
Dividends paid to NCI
Operating
Investing
Financing
435
2,915
(110)
(345)
2,895
290
1,421
200
20
(27)
393
(4)
(389)
Net increase/(decrease) in cash and cash equivalents
-
425
5,224
(51)
(571)
5,027
503
859
318
32
(32)
652
(69)
(583)
-
372
3,081
(103)
(385)
2,965
297
1,423
208
21
(13)
473
(2)
(471)
-
(c) Deed of Cross Guarantee and Closed Group
Woodside Petroleum Ltd and Woodside Energy Ltd are parties to
a Deed of Cross Guarantee under which each company guarantees
the debts of the other. By entering into the Deed, the entities have
been granted relief from the Corporations Act 2001 requirements
for the preparation, audit and publication of accounts, pursuant
to ASIC Instrument 2016/785. The two entities represent a Closed
Group for the purposes of the Instrument.
140 Annual Report 2021
The consolidated income statement and statement of financial
position of the members of the Closed Group are set out below:
2021
US$m
2020
US$m
Closed Group Consolidated Income Statement and
Statement of Retained Earnings
Profit/(loss) before tax
Tax (expense)/benefit
Profit/(loss) after tax
Retained earnings at the beginning of the financial year
Transfer of retained earnings to distributable profits
reserve
Dividends
1,599
(50)
1,549
111
-
-
Retained earnings at the end of the financial year
1,660
(3,195)
955
(2,240)
3,579
(710)
(518)
111
131
488
46
118
20
803
29
19
31,771
1,059
2,688
185
580
340
-
160
948
47
173
22
1,350
40
-
36,432
31
2,758
172
579
319
13
40,344
36,671
41,694
37,474
186
409
34
320
357
23
1,329
26,668
-
153
15
1,179
360
156
46
48
261
-
24
535
24,570
-
-
12
1,272
392
28,375
26,246
29,704
26,781
11,990
10,693
9,409
(30)
951
1,660
9,297
(23)
1,308
111
11,990
10,693
Closed Group Consolidated Statement of Financial
Position
Current assets
Cash and cash equivalents
Receivables
Inventories
Other financial assets
Other assets
Total current assets
Non-current assets
Receivables
Inventories
Other financial assets
Exploration and evaluation assets
Oil and gas properties
Other plant and equipment
Deferred tax assets
Lease assets
Other assets
Total non-current assets
Total assets
Current liabilities
Payables
Other financial liabilities
Other liabilities
Provisions
Tax payable
Lease liabilities
Total current liabilities
Non-current liabilities
Payables
Deferred tax liabilities
Other financial liabilities
Other liabilities
Provisions
Lease liabilities
Total non-current liabilities
Total liabilities
Net assets
Equity
Issued and fully paid shares
Shares held for employee share plan
Other reserves
Retained earnings
Total equity
NOTES TO THE FINANCIAL STATEMENTS E. OTHER ITEMS
for the year ended 31 December 2021
E.9 Other accounting policies
(c) New and amended accounting standards and interpretations
adopted
The Group adopted AASB 2020-8 Amendments to Australian
Accounting Standards – Interest Rate Benchmark Reform as of 1
January 2021.
The amendments provide temporary reliefs which address the
financial reporting effects when an interbank offered rate (IBOR) is
replaced with an alternative nearly risk-free interest rate (RFR). The
amendments include the following practical expedients:
• practical expedients when accounting for changes in the basis
for determining the contractual cash flows of financial assets
and liabilities;
• reliefs from discontinuing hedge relationships;
• temporary relief from having to meet the separately identifiable
requirement when a RFR instrument is designated as a hedge of
a risk component; and
• additional AASB 7 - Financial Instruments disclosures.
These amendments did not impact the financial statements of the
Group other than additional required disclosures (refer to Note D.6).
The Group intends to use the practical expedients in future periods
when existing IBORs are replaced by RFRs.
A number of other new standards are also effective from 1 January
2021 but they do not have a material effect on the Group's
financial statements.
(a) Summary of other significant accounting policies
Tax consolidation
The parent and its wholly owned Australian controlled entities have
elected to enter a tax consolidation, with Woodside Petroleum Ltd
as the head entity of the tax consolidated group. The members of
the tax consolidated group are identified in Note E.8(a).
The tax expense/benefit, deferred tax liabilities and deferred tax
assets arising from temporary differences of the members of the
tax consolidated group are recognised in the separate financial
statements of the members of the tax consolidated group, using
the stand-alone approach.
Entities within the tax consolidated group have entered into a tax
funding arrangement and a tax sharing agreement with the head
entity. Under the tax funding agreement, Woodside Petroleum Ltd
and each of the entities in the tax consolidated group have agreed to
pay or receive a tax equivalent payment to or from the head entity,
based on the current tax liability or current tax asset of the entity.
The tax sharing agreement entered into between members of
the tax consolidated group provides for the determination of the
allocation of income tax liabilities between the entities, should the
head entity default on its tax payment obligations. No amounts
have been recognised in the financial statements in respect of
this agreement as payment of any amounts under the tax sharing
agreement is considered remote.
(b) New and amended accounting standards and interpretations
issued but not yet effective
A number of new standards, amendments of standards and
interpretations have recently been issued but are not yet effective
and have not been adopted by the Group as at the financial
reporting date.
The Group has reviewed these standards and interpretations
and has determined that none of the new or amended standards
will significantly affect the Group’s accounting policies, financial
position or performance.
Woodside Petroleum Ltd 141
DIRECTORS’ DECLARATION
In accordance with a resolution of directors of Woodside Petroleum Ltd, we state that:
1. In the opinion of the directors:
(a) the financial statements and notes thereto, and the disclosures included in the audited 2021 Remuneration Report, comply with
Australian Accounting Standards and the Corporations Act 2001;
(b) the financial statements and notes thereto give a true and fair view of the financial position of the Group as at 31 December 2021
and of the performance of the Group for the financial year ended 31 December 2021;
(c) the financial statements and notes thereto also comply with International Financial Reporting Standards as disclosed in the
‘About these statements’ section within the notes to the 2021 Financial Statements;
(d) there are reasonable grounds to believe that the company will be able to pay its debts as and when they become due and payable;
and
(e) there are reasonable grounds to believe that the members of the Closed Group identified in Note E.8 will be able to meet any
obligations or liabilities which they are or may become subject to, by virtue of the Deed of Cross Guarantee.
2. This declaration has been made after receiving the declarations required to be made to the directors in accordance with section 295A
of the Corporations Act 2001 for the year ended 31 December 2021.
For and on behalf of the Board
R J Goyder, AO
Chairman
Perth, Western Australia
17 February 2022
M E O’Neill
Chief Executive Officer and Managing Director
Perth, Western Australia
17 February 2022
142 Annual Report 2021
INDEPENDENT AUDIT REPORT
Ernst & Young
11 Mount s Bay Road
Pert h WA 6000 Australia
GPO Box M939 Pert h WA 6843
Tel: +61 8 9429 2222
Fax: +61 8 9429 2436
ey.com/au
Independent audit or's report t o t he members of Woodside Pet roleum
Lt d
Report on t he audit of t he financial report
Opinion
We have audited the financial report of Woodside Pet roleum Ltd (t he Company) and its subsidiaries
(collectively the Group), which comprises the consolidated statement of financial position as at 31
December 2021, the consolidated income statement, the consolidated statement of comprehensive
income, the consolidated statement of changes in equit y and the consolidated statement of cash flows
for the year then ended, notes to the financial statements, including a summary of significant
accounting policies, and the directors' declaration.
In our opinion, the accompanying financial report of the Group is in accordance with the Corporations
Act 2001, including:
a)
giving a true and fair view of the Group’s financial position as at 31 December 2021 and of its
financial performance for the year ended on that date.
b)
complying with Australian Accounting Standards and the Corporations Regulations 2001.
Basis for opinion
We conducted our audit in accordance with Australian Auditing Standards. Our responsibilities under
those standards are further described in the Auditor’s responsibilities for the audit of the financial
report section of our report. We are independent of the Group in accordance with the auditor
independence requirements of the Corporations Act 2001 and the ethical requirements of the
Accounting Professional and Ethical Standards Board’s APES 110 Code of Ethics for Professional
Accountants (including Independence Standards) (t he Code) that are relevant to our audit of the
financial report in Australia. We have also fulfilled our other et hical responsibilities in accordance with
the Code.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis
for our opinion.
Key audit mat t ers
Key audit matters are those matters that , in our professional judgment, were of most significance in
our audit of the financial report of the current year. These matters were addressed in the context of
our audit of the financial report as a whole, and in forming our opinion thereon, but we do not provide
a separate opinion on these matters. For each matter below, our description of how our audit
addressed the matter is provided in that context.
A member firm of Ernst & Young Global Limited
Liability limited by a scheme approved under Professional Standards Legislation
Woodside Petroleum Ltd 143
Independent audit report (cont.)
We have fulfilled the responsibilities described in the Auditor’s responsibilities for the audit of the
financial report section of our report, including in relation to these matters. Accordingly, our audit
included the performance of procedures designed to respond to our assessment of the risks of
material misstatement of the financial report. The results of our audit procedures, including the
procedures performed to address the matters below, provide the basis for our audit opinion on the
accompanying financial report.
1. Rest orat ion obligat ions
Why significant
How our audit addr essed t he key audit mat t er
We assessed the restoration obligation provisions prepared by the
Group, evaluating the assumptions and methodologies used and
the estimates made.
Our audit procedures included the following:
►
►
►
►
►
►
►
►
evaluating the Group’s process for identif ying legal and
regulatory obligations for restoration and testing the
completeness of operating locations included in the
restoration provision and the completeness and accuracy of
data used within the Group’s estimates;
in conjunction with our environmental specialists, we
evaluated the restoration cost estimates based on the
relevant current legal and regulator y requirements;
compared current year cost estimates to those of the prior
year and considered management’s explanations where
these changed;
compared the timing of the future cash outflows against the
anticipated end of field life, cross-checking these dates were
consistent to the Group’s reserves estimates and impairment
calculations;
evaluated the appropriateness of the discount rates used to
calculate the present value of the provision;
evaluated the appropriateness of management’s
methodology for estimating future costs. For a sample of
locations within the Group, we assessed the reasonableness
of key assumptions in the estimation of future costs;
assessed the competence, capability and objectivity of the
Group’s internal exper ts used in the determination of the
restoration provision;
tested the mathematical accuracy of the restoration
provision calculations and the sensitivity analysis.
We also considered the adequacy and completeness of the
financial report disclosure of the assumptions, key estimates and
judgements applied by the Group.
At 31 December 2021, the Group has
recognised provisions for restoration
obligations relating to onshore and offshore
assets of $2,218 million.
As disclosed in Note D.5, the calculation of
restoration provisions is conducted by
specialist engineers and requires judgemental
assumptions to be made by the Group
regarding removal date, compliance with
environmental legislation and regulations, the
extent of restoration activities required, the
engineering methodology for estimating cost,
future removal technologies in deter mining the
removal cost, and liability-specific discount
rates to determine the present value of these
cash flows.
The judgements and estimates in respect of
restoration provisions are based on conditions
existing at 31 December 2021 including key
assumptions related to certain items composed
of steel, or steel and concrete, with
hydrocar bons removed remaining in-situ.
Australian regulator approval for these items
remaining in-situ will only be provided towar ds
the end of field life and accordingly at 31
December 2021, there is uncertainty whether
the Australian regulator will approve plans for
these items to be decommissioned in-situ.
Significant assumptions and estimates outlined
above are inherently subjective. Changes in
these assumptions can lead to significant
changes in the restoration provision. In this
context, the disclosures in the financial report
provide particularly impor tant information
about the assumptions made in the calculation
of the restoration provision and uncertainties
at 31 December 2021. As a result, we consider
the restoration provision calculation and the
related disclosures in the financial report to be
a key audit matter. For the same reasons, we
consider it important to draw attention to the
information in Note D.5.
A member firm of Ernst & Young Global Limited
Liability limited by a scheme approved under Professional Standards Legislation
144 Annual Report 2021
Independent audit report (cont.)
2. Carrying value of oil and gas propert ies
Why significant
How our audit addressed t he key audit mat t er
Australian Accounting Standar ds require an
entity to assess throughout the reporting
period whether there is any indication that an
asset may be impaired, or that reversal of a
previously recognised impairment may be
required. If any such indication exists, an entity
shall estimate the recoverable amount of the
asset.
At 31 December 2021, the Group concluded
that there were impairment/ impairment
reversal indicators for the Pluto-Scarborough,
NWS Gas, NWS Oil and Wheatstone cash
generating units (CGUs). Impairment testing
was undertaken as outlined in Note B.4,
resulting in an impairment reversal of $1,058
million relating to Pluto-Scarborough and NWS
Gas CGUs. No impairment/ impairment reversal
was recognised in respect to the NWS Oil and
Wheatstone CGUs.
Key assumptions, judgements and estimates,
used in the formulation of the Group’s
impairment testing of the oil and gas properties
are disclosed in Note B.4.
The assessment of indicators of impairment
and reversal of impairment and the impairment
testing process are complex and highly
judgemental and are based on assumptions
which are impacted by expected future
performance and mar ket conditions.
Accordingly, this matter was considered to be a
key audit matter.
We evaluated the Group’s consideration of internal and external
sources of information in assessing whether indicators of
impairment or reversal of impairment existed.
Where impairment or impairment reversal indicators were present
and impairment testing was conducted by the Group, we evaluated
the assumptions and methodologies used by the Group and the
estimates made in conducting this testing. In par ticular, we
considered those judgements and estimates related to the
determination of CGUs, the forecast cash flows and the inputs
used to formulate those cash flows such as commodity prices,
discount rates, reserves, inflation rates, operating costs and
foreign exchange rates.
We involved our valuations, modelling and economics specialists to
assist in the impairment assessment for the audit. Our audit
procedures were undertaken across the CGUs for which
impairment and impairment reversal indicators were identified.
Specifically, we evaluated the discounted cash flow models and
other data supporting the Group’s assessment. In doing so, we:
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considered future production profiles compared to reserves,
current approved budgets and historical production, and
tested variations were in accor dance with our expectations
based upon other information obtained throughout the
audit;
evaluated commodity prices with reference to contractual
arrangements, market prices (where available), broker
consensus, analyst views and historical performance;
evaluated discount rates, inflation rates and foreign
exchange rates with reference to market prices (where
available), market indices, broker consensus and historical
performance;
compared future operating and development expenditure to
current sanctioned budgets, historical expenditure and
tested variations were in accor dance with our expectations
based upon other information obtained throughout the
audit;
evaluated how the Group’s response to climate risk has been
reflected in the assessment of the recoverable amount of
the CGUs;
assessed whether the reversal of impairment charge
recor ded in the financial statements agreed to the
underlying impairment testing models;
assessed the impact of changes to key assumptions on the
recoverable amount of the CGUs; and
tested the mathematical accuracy of the discounted cash
flow models and the sensitivity analysis.
We reviewed the calculation of the extent of the original cost
impaired adjusted for depreciation for the Pluto-Scarborough and
NWS Gas CGUs at 31 December 2021 to test the amount recorded
did not exceed the carrying value of the CGU if the prior year
impairments were not initially recorded.
A member firm of Ernst & Young Global Limited
Liability limited by a scheme approved under Professional Standards Legislation
Woodside Petroleum Ltd 145
Independent audit report (cont.)
Why significant
How our audit addressed t he key audit mat t er
We used the work of the Group’s internal experts with respect to
the hydrocarbon reserve estimates used in the Group’s impairment
testing. This included understanding the reserve estimation
processes carried out, the Group’s internal certification process
for technical and commercial experts who are responsible for
reserves, the design of the Group’s Petroleum Resources
Management procedures and its alignment with the guidelines
prepared by the Society of Petroleum Engineers. We also
examined the competence and objectivity of the Group’s internal
and external experts and the scope and appropriateness of their
work. We involved our oil and gas reserves engineering specialists
in the assessment of the reserves estimation methodology and to
test significant revisions.
We also considered the adequacy of the financial report
disclosures regar ding the assumptions, key estimates and
judgements applied by management for the Group’s impairment
assessments, and in respect of sensitivity analysis disclosed. These
disclosures are included in Note B.4.
Informat ion ot her t han t he financial report and audit or’s report t hereon
The directors are responsible for the other information. The other information comprises the
information included in the Company’s Annual Report for the year ended 31 December 2021, but does
not include the financial report and our auditor’s report thereon.
Our opinion on the financial report does not cover the other information and accordingly we do not
express any form of assurance conclusion thereon, with the exception of the Remuneration Report
and our related assurance opinion.
In connection wit h our audit of the financial report, our responsibility is to read the other information
and, in doing so, consider whether the other information is materially inconsistent with the financial
report or our knowledge obtained in the audit or otherwise appears to be materially misstated.
If, based on the work we have performed, we conclude that there is a material misstatement of this
other information, we are required to report that fact. We have nothing to report in this regard.
Responsibilit ies of t he direct ors for t he financial report
The directors of the Company are responsible for the preparation of the financial report that gives a
true and fair view in accordance with Australian Accounting Standards and the Corporations Act 2001
and for such internal cont rol as the directors determine is necessary to enable the preparation of the
financial report that gives a true and fair view and is free from material misstatement, whether due to
fraud or error.
In preparing the financial report, the directors are responsible for assessing the Group’s ability to
continue as a going concern, disclosing, as applicable, matters relating to going concern and using the
going concern basis of accounting unless the directors either intend to liquidate the Group or to cease
operations, or have no realistic alternative but to do so.
A member firm of Ernst & Young Global Limited
Liability limited by a scheme approved under Professional Standards Legislation
146 Annual Report 2021
Independent audit report (cont.)
Audit or's r esponsibilit ies for t he audit of t he financial report
Our objectives are to obtain reasonable assurance about whether the financial report as a whole is
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 the Australian Auditing Standards 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 this financial report.
As part of an audit in accordance wit h the Australian Auditing Standards, we exercise professional
judgment and maintain professional scepticism throughout the audit. We also:
► Ident ify and assess the risks of material misstatement of the financial report, 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.
► Obtain an understanding of internal control relevant to the audit in order to design audit
procedures t hat are appropriate in t he circumstances, but not for t he purpose of expressing an
opinion on the effectiveness of the Group’s internal control.
► Evaluate the appropriateness of accounting policies used and the reasonableness of accounting
estimates and related disclosures made by the directors.
► Conclude on the appropriateness of the directors’ 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 uncer tainty exists, we are required to draw attention in our auditor’s
report to the related disclosures in the financial report 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 repor t. However, future events or conditions may cause the Group to cease to
continue as a going concern.
► Evaluate the overall presentation, structure and content of the financial report, including the
disclosures, and whether the financial report represents t he underlying transactions and events in
a manner that achieves fair presentation.
We communicate wit h the directors 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 the directors 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, actions
taken to eliminate threats or safeguards applied.
A member firm of Ernst & Young Global Limited
Liability limited by a scheme approved under Professional Standards Legislation
Woodside Petroleum Ltd 147
Independent audit report (cont.)
From the matters communicated to the directors, we determine those matters that were of most
significance in the audit of the financial report 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.
Report on t he audit of t he Remunerat ion Repor t
Opinion on t he Remunerat ion Report
We have audited the Remuneration Report included in pages 73 to 92 of the directors' report for the
year ended 31 December 2021.
In our opinion, the Remuneration Report of Woodside Pet roleum Ltd for the year ended 31 December
2021, complies wit h section 300A of the Corporations Act 2001.
Responsibilit ies
The directors of the Company are responsible for the preparation and presentation of the
Remuneration Report in accordance wit h section 300A of the Corporations Act 2001. Our
responsibilit y is to express an opinion on the Remuneration Report, based on our audit conducted in
accordance with Australian Auditing Standards.
Ernst & Young
Robert A Kirkby
Partner
Perth
17 February 2022
A member firm of Ernst & Young Global Limited
Liabilit y limit ed by a scheme approved under Professional Standards Legislat ion
148 Annual Report 2021
SHAREHOLDER INFORMATION SHAREHOLDER STATISTICS
as at 1 February 2022
Number of shareholdings
There were 261,019 shareholders. All issued shares carry voting rights on a one-for-one basis.
Distribution of shareholdings
Size of shareholding
1–1,000
1,001–5,000
5,001–10,000
10,001–100,000
Greater than 100,000
Total
Number
of holders
179,074
70,912
7,400
3,506
127
261,019
Unmarketable parcels
There were 3,874 members holding less than a marketable parcel of shares in the company.
Twenty largest shareholders
HSBC Custody Nominees (Australia) Limited
J P Morgan Nominees Australia Pty Limited
Citicorp Nominees Pty Limited
National Nominees Limited
BNP Paribas Noms Pty Ltd
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