2020
Annual
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“ Good energy is helping
Australia transition to
a cleaner energy future”
Scott Andreas
Field Manager East
Asset Services
Brooke Geary
Field Project Engineer
Annual Report 2020
Featured on our front cover are Scott Andreas
and Brooke Geary
Scott is Field Manager East, Asset Services and Brooke
is Field Project Engineer, both in our Integrated Gas
business. Scott and Brooke work to safely deliver gas
to our customers, helping support the transition to a
cleaner future.
Scott and Brooke were photographed at an Australia
Pacific LNG well site at Condabri Central. Origin owns
37.5 per cent of Australia Pacific LNG, and as upstream
operator, produces coal seam gas (CSG) from the Surat
and Bowen basins in Queensland. Australia Pacific
LNG provides ~30 per cent of Australian east coast gas
and is a major exporter of liquefied natural gas to Asia.
Contents
1
Contents
Welcome to the 2020 Annual Report
20-year Timeline
About Origin
Where We Operate
Board of Directors
Executive Leadership Team
Operating and Financial Review
Directors’ Report
Remuneration Report
Lead Auditor’s Independence Declaration
Financial Statements
Directors’ Declaration
Independent Auditor’s Report
Share and Shareholder Information
Exploration and Production Permits and Data
Annual Reserves Report
Five-year Financial History
Glossary and Interpretation
2
4
6
7
8
10
12
49
52
73
75
131
132
140
144
146
152
154
2
2
A message from Gordon
A message from Frank
Dear Shareholder,
Welcome to the 2020 Annual Report.
I was elected Chairman of Origin Energy in October 2013.
As announced, I will be stepping down at this year’s AGM
in October.
I looked back at our message to shareholders in the 2014
Annual Report. We commented that our industry was at the
forefront of economic, social and political debate. We noted in
particular that our challenge every day was to deliver reliable,
affordable and cleaner energy. And we bore witness to the
substantial change in energy policy settings. How prescient we
were, and how tumultuous that seven years has been. But how
resilient Origin has demonstrated, in embracing the challenges
and transforming its business.
We are very different to the company of 2014. We have
become a customer obsessed retailer, and our strategic
investment in Octopus Energy, I am certain, will be a step
change in that journey. We are pivoting to a greener future with
gas as the transition fuel and a leading role in renewables. We
have demonstrated the financial viability of investing in APLNG,
with production costs competitive with US shale gas. We are
at the forefront of building IoT propositions to harness data
and to connect customers to the latest technology. We look
confidently to the future with e-mobility, hydrogen and LNG
for transport extending us beyond the core.
As a backdrop to all of this we have demonstrated sound
capital management, maintaining our investment grade rating,
reducing debt, and maintaining our dividend. The externalities
have not changed, arguably have got more challenging, but we
have focused on what we can control, and shown commitment
and resilience.
For this I owe a deep well of thanks. Firstly, to a management
team, superbly led by Frank. If a Board’s first priority is to
appoint the right CEO, we succeeded.
Secondly, to a wonderful Board of fellow directors who
demonstrate every day the value of our mantra “the obligation
to dissent”. This constructive contestability has made for better
decisions. And finally, to our shareholders and their proxy
advisors. I have enjoyed our regular interactions, listened and
learned, and we as a company are the better for their counsel.
And so I leave optimistic about the future of Origin. Board
renewal has been front of mind for the Board for some time,
and after a rigorous chair development and succession
program, Scott Perkins was the unanimous choice of his fellow
directors. We have worked together closely over the past five
years and he and I will ensure a seamless handover. Scott and
Frank will form a formidable team, as the leadership of the
company, shaping this future.
I will cheer from the sidelines.
Gordon Cairns
Chairman
In an extraordinary year, Origin quietly turned 20. In February
2000, Origin was first listed on the ASX and today we are
Australia’s number one energy retailer, a significant energy
producer and a major contributor to the Australian economy.
It has taken a dedicated group of people to create our business,
and I thank our more than 5,200 people who represent Origin
every day, from the Surat Basin to Sydney, and from Minto to
Melbourne. Two of those people are Scott Andreas and Brooke
Geary, who are featured on the front cover of this report.
Scott and Brooke were photographed at a well site at Condabri
Central, in Queensland. As part of our Integrated Gas team,
Scott and Brooke work to safely deliver gas to our customers
and are also helping Origin as we transition to a cleaner
energy future.
Our philanthropic foundation also achieved a milestone,
celebrating its 10-year anniversary in February. Over this
time, the Origin Energy Foundation has provided more
than $27 million to good causes across Australia and
supported more than 62,000 young people to achieve
success in education. I am exceptionally proud of the work
the Foundation undertakes to create better lives for young
Australians through the power of education.
Progress on our commitments
In response to significant challenges this year, Origin’s
focus has been on maintaining reliable energy supply,
keeping our people safe, and supporting our customers and
communities. Against this backdrop, Origin’s underlying
business performance continued to improve across the year,
driving growth in free cash flow, which allowed further debt
reduction, disciplined investment in growth opportunities and
distributions to shareholders.
Origin delivered a stable underlying profit of $1,023 million in
FY2020, and our capital structure continued to improve, with
adjusted net debt of $5,158 million at 30 June 2020. Through
our Integrated Gas business, strong field production helped
drive record production for Australia Pacific LNG and a record
cash distribution to Origin of $1,275 million. In Energy Markets,
electricity gross profit was lower following the introduction
of retail price regulation, while we were able to utilise the
flexibility of our generation fleet and wholesale gas portfolio to
adapt to the reduced demand caused by the pandemic.
Importantly, our focus on a safety culture based on learning has
yielded strong improvements this year. Our Total Recordable
Injury Frequency Rate (TRIFR) reduced to 2.6, from 4.4 the
previous year.
Annual Report 2020
Welcome to the 2020 Annual Report
33
In keeping with our commitment to progressively decarbonise
our business, we have announced a new short-term target to
reduce our Scope 1 emissions by 10 per cent on average between
FY2021 and FY2023. This reduction will be done from an FY2017
baseline. Our commitment remains to halve our Scope 1 and
Scope 2 emissions by 2032 and we are aiming to achieve net-zero
emissions across the business by 2050.
Supporting customers and communities
I am proud of Origin’s efforts to support our customers throughout
the year, including in times of bushfires, floods and then the
COVID-19 pandemic. Our people have gone above and beyond
for our customers; helping with energy bills including payment
extensions and access to hardship services. We also passed on
lower wholesale costs to customers and further improved our
digital platforms to make it easier to engage with us.
Over the summer, volunteers through the Origin Energy Foundation
provided practical support to bushfire-affected communities cut
off from power by assembling over 1,500 portable SolarBuddy
lights for distribution. It is this giving back to the community by our
people which supports our ‘good energy’ brand position.
Our gas exploration in the Beetaloo Basin was paused in March
in response to the COVID-19 pandemic to help protect Northern
Territory communities and people. The project is expected to
resume later this year. Origin remains committed to the Beetaloo
which, if successful, has the potential to deliver long-term
economic and social benefits for the Northern Territory, Australia
and the Asia Pacific region.
Our business performance
In Integrated Gas, improved field performance contributed
to record production of 708 petajoules for Australia Pacific
LNG, up four per cent on FY2019. A continued focus on cost
reduction resulted in operating and capital costs falling by
eight per cent. Underlying EBITDA for Integrated Gas was
$1,741 million in FY2020, eight per cent lower than the prior
year, primarily reflecting a change in accounting treatment at
Australia Pacific LNG.
Across Energy Markets, performance was largely driven by a
reduction in electricity gross profit, due to lower retail margins
following the introduction of the Default Market Offer and Victorian
Default Offer. The COVID-19 pandemic also impacted demand
in the final quarter, particularly for our commercial customers.
Within this challenging environment, we focussed on efficiencies,
including reducing our retail cost to serve by $40 million.
Underlying EBITDA in Energy Markets was $1,459 million, down
$115 million on FY2019.
Outlook
Origin provided the following guidance at our annual results on
20 August 2020 on the basis that market conditions and the
regulatory environment do not materially change, adversely
impacting on operations. Considerable uncertainty exists relating
to the potential ongoing impacts of COVID-19 and this guidance
is subject to any further material impact on demand and customer
affordability.
Energy Markets Underlying EBITDA is expected to be $1,150-
$1,300 million. This guidance reflects lower electricity gross profit
due to passthrough of reduced wholesale prices to customers,
higher network costs absorbed in the regulated tariffs and lower
natural gas gross profit, partially offset by a targeted $70 million
reduction in cost to serve.
Australia Pacific LNG’s FY2021 production is expected to be lower
at 650-680 petajoules, reflecting anticipated reduced demand
with strong field capability to increase production to respond to
changes in demand. Distribution breakeven is expected to be in the
range of US$27-US$31 a barrel.
Looking forward
In January, Origin welcomed Kate Jordan to our executive
leadership team as General Counsel and Executive General
Manager, Company Secretariat, Risk and Governance. Kate brings
extensive corporate advisory and commercial experience in what is
a fast-moving and competitive industry landscape.
As you will be aware, our chairman Gordon Cairns, will be retiring
from the board in October. Gordon has served as a director since
2007 and as chairman for the last seven years. On behalf of the
board and the business, I want to thank Gordon for his tireless
dedication to Origin and our direction over the last 13 years.
We have achieved a lot in Origin’s first two decades, and I am
extremely proud of how our people are delivering on our purpose
of getting energy right for our customers, communities and planet.
As shareholders, I thank you for being part of our story and hope
you feel proud too.
I look forward to welcoming many of you to our Annual General
Meeting on 20 October, which will be held virtually this year in
response to the COVID-19 pandemic.
Thank you for your continued support.
Frank Calabria
Chief Executive Officer
4
20-year Timeline
Origin Energy listed
Origin Energy listed on the
Australian Securities Exchange
on 21 February 2000.
February
212000
2000
Acquired 51.4% controlling
interest in Contact Energy,
one of New Zealand’s leading
energy retailers and power
generators.
Commenced development
of the Otway gas project
in the offshore Otway
Basin in Victoria.
Invested in the Fairview and
Durham Coal Seam Gas
(CSG) fields in Queensland,
the start of our focus on
producing natural gas from
coal seams.
2002
2004
2001
2003
2005
Acquired Powercore retail
business with over 580,000
Victorian customers.
BassGas project approved
for construction, opening up
new offshore gas resources
for Victoria.
Acquired 580k
customer accounts
Acquired 264k
customer accounts
Spring Gully CSG
processing facilities
in Queensland
commenced
production.
Opened up new
offshore gas resources
Mortlake Power Station in
Victoria is completed and
commenced operations.
Acquired a 35% interest in
the Beetaloo Basin shale gas
resource in Northern Territory.
Launched littleBIGidea to
encourage young inventors
to share their ideas to solve
real-world problems.
Origin’s first CEO and Managing
Director, Grant King, retires.
Frank Calabria appointed CEO.
The $24.7 billion APLNG project
shipped its first cargo of LNG.
2012
2014
2016
2013
2015
2017
Acquired Eraring Power
Station and Shoalhaven
Pumped Hydro Storage
Scheme – two key generation
assets in New South Wales.
Joined the We Mean
Business global climate
action coalition – the first
company in Australia and first
energy company in the world
to commit to seven targets
to drive emissions reduction
across our business.
Launched our Reconciliation
Action Plan, as a demonstration
of our commitment to
Indigenous Australians.
Booked Australia’s first
significant shale gas resource
in the Beetaloo Basin.
Introduced a new company
purpose: Getting energy
right for our customers,
community and planet.
Launched our Origin mobile
app, helping electricity
and natural gas customers
control their energy use
and costs.
Annual Report 2020 20-year Timeline
5
Australia Pacific LNG
(APLNG) joint venture
Became Australia’s
largest energy retailer
Acquired Uranquinty Power Station,
a 640 MW gas-fired peaking station
in New South Wales.
Formed the multibillion-
dollar APLNG
incorporated joint
venture in Queensland
with ConocoPhillips,
to commercialise
CSG assets.
Acquired 1.6m customer accounts
Kupe gas project in New Zealand
commenced operations.
Origin Energy Foundation
established to empower young
Australians through education
– a focus chosen by employees.
Darling Downs Power Station
in Queensland commenced operations.
BassGas project operations
commenced, capable
of meeting almost 10%
of Victoria’s gas needs.
2006
2008
2010
2007
2009
2011
Acquired Sun Retail,
adding 800,000 new
Queensland customers.
Acquired 800k
customer accounts
Acquired WindPower and
its development portfolio,
including Stockyard Hill
Wind Farm in Victoria.
Our first wind farm,
Cullerin Range Wind
Farm in New South Wales,
commenced operations.
APLNG welcomes
Sinopec as equity
partner and foundation
buyer of liquid natural
gas (LNG) – at the
time the largest single
CSG to LNG supply
agreement ever signed.
Launched new Origin Values,
guiding the way our people work.
Created the Good Energy brand
platform and campaign – the first
major rebrand in our 18-year history.
Acquired 20% interest in UK
company Octopus Energy,
and an Australian licence for
the Kraken customer platform.
APLNG exported its
500th cargo.
Committed to halve our emissions
(Scope 1 and Scope 2) by 2032,
in line with the Paris Agreement.
>$27m distributed by
Origin Energy Foundation
since inception.
2018
2020
2019
Launched our Stretch Reconciliation
Action Plan, continuing our
commitment to advance Australia’s
reconciliation efforts.
6
Annual Report 2020
About Origin
Origin at a glance
Leading integrated
energy company
4.2 million
customer accounts
5,200
employees
Listed on the Australian Securities
Exchange in 2000
Electricity, gas and LPG customers
across Australia and the Pacific
Inclusivity in the workplace,
leading parental support
Five-pillar approach
to decarbonisation
Powering
Australia
37.5% interest in
Australia Pacific LNG
Australia’s first science-based
emissions targets, aligned with
the Paris Agreement
7,400 MW generation portfolio,
including 1,400 MW owned and
contracted renewables and storage
Exporting to Asia and supplying ˜30%
of Australian east coast gas demand
Supporting Australian
communities
Driving future
energy innovation
Exploration
and development
Over its 10 years, the Origin Energy
Foundation has contributed more
than $27 million
Investing in new technology,
start-ups and future fuels
77.5% interest in Beetaloo Basin
exploration permits
Bringing
good
energy
to everything
we say
and do.
Where We Operate
7
Where We Operate
Browse
Basin
Browse
Basin
Browse
Basin
Browse
Basin
14k
14k
14k
14k
South East Queensland
South East Queensland
South East Queensland
Gladstone
Gladstone
Gladstone
South East Queensland
Bowen/
Surat
Bowen/
basins
Surat
Bowen/
basins
Surat
basins
Bowen/
Surat
basins
Pacific countries LPG
Pacific countries LPG
Rabaul
Pacific countries LPG
Rabaul
Lae
Beetaloo
Basin
Beetaloo
Basin
Beetaloo
Basin
Beetaloo
Basin
239k
211k
239k
211k
239k
211k
Cooper
Basin
Cooper
Basin
Cooper
Basin
239k
211k
Cooper
Basin
Adelaide
Adelaide
Adelaide
Adelaide
645k
181k
645k
181k
645k
181k
645k
181k
1191k
335k
1191k
335k
1191k
335k
Bowen/
Surat
basins
Bowen/
Surat
basins
Bowen/
Surat
basins
Bowen/
Surat
basins
1191k
335k
Melbourne
Melbourne
Melbourne
Gladstone
LNG Export
Gladstone
LNG Export
Gladstone
LNG Export
Brisbane
Brisbane
Brisbane
Gladstone
LNG Export
Brisbane
Sydney
Sydney
Sydney
Sydney
556k
479k
556k
479k
556k
479k
Melbourne
Hobart
Hobart
Hobart
556k
479k
Hobart
Exploration & production acreage
Generation
Gladstone
Brisbane
Brisbane
Brisbane
Origin upstream acreage
Exploration & production acreage
Exploration & production acreage
APLNG upstream acreage
Origin upstream acreage
Production facility
Origin upstream acreage
APLNG upstream acreage
APLNG pipeline
Production facility
APLNG upstream acreage
Exploration & production acreage
Production facility
APLNG pipeline
Origin upstream acreage
Brisbane
APLNG pipeline
APLNG upstream acreage
Production facility
APLNG pipeline
Gas
Generation
Generation
Gas
Gas
Pumped hydro
Gas
Solar (contracted)
Pumped hydro
Wind (contracted)
Pumped hydro
Solar (contracted)
Generation
Coal
Solar (contracted)
Wind (contracted)
Under construction
Wind (contracted)
Coal
Pumped hydro
Under construction
Solar (contracted)
LPG seaboard terminal
Under construction
Wind (contracted)
LPG seaboard terminal
Electricity customer accounts
LPG seaboard terminal
Under construction
Natural gas customer accounts
Electricity customer accounts
Coal
Coal
Rabaul
Port Moresby
Lae
Pacific countries LPG
Lae
Port Moresby
Port Moresby
Rabaul
Lae
Port Moresby
Honiara
Honiara
Honiara
Santo
Santo
Port Vila
Honiara
Santo
Port Vila
Port Vila
Labasa
Lautoka
Labasa
Lautoka
Labasa
Suva
Lautoka
Suva
Electricity customer accounts
Natural gas customer accounts
LPG seaboard terminal
Natural gas customer accounts
Apia
Electricity customer accounts
Natural gas customer accounts
Apia
Pago Pago Rarotonga
Apia
Pago Pago Rarotonga
Pago Pago Rarotonga
Santo
Port Vila
Lautoka
Suva
Labasa
Suva
Apia
Pago Pago Rarotonga
8
Board of
Directors
Gordon Cairns
Independent
Non-executive Chairman
John Akehurst
Independent
Non-executive Director
Maxine Brenner
Independent
Non-executive Director
Frank Calabria
Managing Director and
Chief Executive Officer
Teresa Engelhard
Independent
Non-executive Director
Tenure 13 years, 2 months
Tenure 11 years, 4 months
Tenure 6 years, 9 months
Tenure 3 years, 10 months
Tenure 3 years, 3 months
Gordon Cairns joined
the Board in June 2007
and became Chairman
in October 2013. He is
Chairman of the Nomination
Committee and a member
of the Audit, Health, Safety
and Environment, Risk and
Remuneration and People
committees.
Gordon has extensive
Australian and international
experience as a senior
executive, as Chief
Executive Officer of Lion
Nathan Ltd, and has
held senior management
positions in marketing,
operations and finance
with PepsiCo, Cadbury
Ltd and Nestlé.
Gordon is Chairman of
Woolworths Group Limited
(since September 2015),
a Non-executive Director
of Macquarie Group
Limited and Macquarie
Bank Limited (since
November 2014) and World
Education Australia (since
November 2007).
Gordon was previously
Chairman of the Origin
Energy Foundation,
David Jones Limited
(March 2014–August
2014) and Rebel Group
(2010–2012), Director of
The Centre for Independent
Studies (May 2006–
August 2011), Quick
Service Restaurant Group
(October 2011–May 2017)
and Westpac Banking
Corporation (July 2004–
December 2013). He was
also a senior advisor to
McKinsey & Company.
Gordon holds a Master of
Arts (Honours) from the
University of Edinburgh.
John Akehurst joined the
Board in April 2009. He is
Chairman of the Health,
Safety and Environment
Committee and a member
of the Nomination and
Risk committees.
John’s executive career was
in the upstream oil and gas
and LNG industries, initially
with Royal Dutch Shell and
then as Chief Executive
Officer of Woodside
Petroleum Limited.
John is a Director of Human
Nature Adventure Therapy
Ltd (since February 2018).
John was previously
Chairman of the National
Centre for Asbestos
Related Diseases
(2009–April 2020),
the Fortitude Foundation
(2007–April 2020),
Transform Exploration
Pty Ltd (February
2012–December 2017),
Alinta Limited (January
2007–September 2007)
and Coogee Resources
Ltd (2008–2009) and
a former Board member
of the Reserve Bank of
Australia (September
2007–September 2017),
Director of CSL Limited
(April 2004–October
2016), Oil Search Limited
(1998–2003), Securency
Ltd (2008–2012), Murdoch
Film Studios Pty Ltd and
the University of Western
Australia Business School.
John holds a Masters in
Engineering Science from
Oxford University and is a
Fellow of the Institution of
Mechanical Engineers.
Maxine Brenner joined
the Board in November
2013. She is Chairman of
the Risk Committee and a
member of the Audit and
Nomination committees.
Maxine was previously
a Managing Director of
Investment Banking at
Investec Bank (Australia)
Ltd. Prior to Investec,
Maxine was a Lecturer
in Law at the University
of NSW and a lawyer at
Freehills, specialising in
corporate law.
Maxine is a Non-executive
Director and Chairman
of the Remuneration
Committee of Orica Ltd
(since April 2013) and
Qantas Airways Ltd (since
August 2013). She is also
an Independent Director
and Chairman of the Audit
and Risk Committee for
Growthpoint Properties
Australia and a member
of the University of
NSW Council.
Maxine’s former
directorships include
Treasury Corporation of
NSW, Bulmer Australia Ltd,
Neverfail Springwater Ltd
(1999–2003) and Federal
Airports Corporation, where
she was Deputy Chair. In
addition, Maxine has served
as a Council Member of
the State Library of NSW
and as a member of the
Takeovers Panel.
Maxine holds a Bachelor of
Arts and a Bachelor of Laws.
Frank Calabria was
appointed Managing
Director & Chief Executive
Officer in October 2016.
Frank is a member of
the Health, Safety and
Environment Committee
and a Director of the
Origin Energy Foundation.
Frank first joined Origin as
Chief Financial Officer in
November 2001 and was
appointed Chief Executive
Officer, Energy Markets in
March 2009. In that latter
role, Frank was responsible
for the integrated business
within Australia including
retailing and trading of
natural gas, electricity and
LPG, power generation and
solar and energy services.
Frank is a Director of
the Australian Energy
Council and the Australian
Petroleum Production &
Exploration Association.
He is a former Chairman
of the Australian Energy
Council and former Director
of the Australian Energy
Market Operator.
Frank has a Bachelor of
Economics from Macquarie
University and a Master of
Business Administration
(Executive) from the
Australian Graduate School
of Management. Frank
is also a Fellow of the
Chartered Accountants
Australia and New Zealand
and a Fellow of the
Financial Services Institute
of Australasia.
Teresa Engelhard joined
the Board in May 2017. She
is a member of the Audit
and Remuneration and
People committees.
Teresa has more than
20 years’ experience
in the information,
communication, technology
and energy sectors as
a senior executive and
venture capitalist.
Teresa is a Non-executive
Director of Wisetech
Global (since March 2018),
StartupAUS (since March
2016), and LaunchVic (since
July 2020). Teresa started
her career at McKinsey
& Company in California
where she served energy
and retail clients. More
recently, she focused on
energy sector innovation
as a Managing Partner at
Jolimont Capital.
Teresa’s former
directorships include
Daintree Networks, Planet
Innovation Ltd (April
2016–November 2019)
and RedBubble Limited
(July 2011–October 2017).
Teresa holds a Bachelor
of Science (Hons) degree
from the California Institute
of Technology (Caltech),
an MBA from Stanford
University and is a graduate
of the Australian Institute of
Company Directors.
Annual Report 2020 Board of Directors
9
Greg Lalicker
Independent
Non-executive Director
Bruce Morgan
Independent
Non-executive Director
Scott Perkins
Independent
Non-executive Director
Steven Sargent
Independent
Non-executive Director
Tenure 1 year, 4 months
Tenure 7 years, 9 months
Tenure 4 years, 11 months
Tenure 5 years, 3 months
Greg Lalicker joined the
Board in March 2019.
Greg is the Chief Executive
Officer of Hilcorp Energy
Company, based in
Houston, USA. Hilcorp
is the largest privately
held independent oil
and gas exploration and
production company in
the United States.
Greg joined Hilcorp’s
leadership team in 2006
as Executive Vice President
where he was responsible
for all exploration and
production activities. He
was appointed President
in 2011 and Chief Executive
Officer in 2018. Prior to
working for Hilcorp, Greg
was with BHP Petroleum
based in Midland, Houston,
London and Melbourne
as well as McKinsey &
Company where he worked
in its Houston, Abu Dhabi
and London offices.
Greg graduated as a
petroleum engineer from
the University of Tulsa.
He also has a Master of
Business Administration
and a law degree.
Bruce Morgan joined the
Board in November 2012.
He is Chairman of the Audit
Committee and a member
of the Health, Safety and
Environment, Nomination
and Risk committees.
Scott Perkins joined the
Board in September 2015.
He is a member of the
Audit, Health, Safety and
Environment, Nomination,
Remuneration and People
and Risk committees.
Bruce is Chairman of
Transport Asset Holding
Entity of New South Wales
(since July 2020), Sydney
Water Corporation (since
October 2013), a Director
of Redkite, the University
of NSW Foundation
and Deputy Chair of
the European Australian
Business Council.
Bruce served as
Chairman of the Board of
PricewaterhouseCoopers
(PwC) Australia between
2005 and 2012. In 2009,
he was elected as a member
of the PwC International
Board, serving a four-year
term. He was previously a
Director of Caltex Australia
Ltd (2013 to May 2020)
and Managing Partner of
PwC’s Sydney and Brisbane
offices. An audit partner
of the firm for over 25
years, he was focused on
the financial services and
energy and mining sectors
leading some of the firm’s
most significant clients in
Australia and internationally.
Bruce has a Bachelor of
Commerce (Accounting
and Finance) from the
University of NSW and is
an adjunct Professor of
the University. Bruce is a
Fellow of the Chartered
Accountants Australia
and New Zealand and of
the Australian Institute of
Company Directors.
Scott has extensive
Australian and international
experience as a leading
corporate adviser. He was
formerly Head of Corporate
Finance for Deutsche
Bank Australia and New
Zealand and a member of
the Executive Committee
with overall responsibility
for the Bank’s activities in
this region. Prior to that he
was Chief Executive Officer
of Deutsche Bank New
Zealand and Deputy CEO of
Bankers Trust New Zealand.
Scott is a Non-executive
Director of Woolworths
Limited (since September
2014) and Brambles
Limited (since May 2015).
He is Chairman of Sweet
Louise (since 2005) and
the New Zealand Initiative
(since 2012). Scott was
previously a Director of the
Museum of Contemporary
Art in Sydney (2011–2020)
and a Non-executive
Director of Meridian Energy
(1999–2002).
Scott has a longstanding
commitment to breast
cancer causes, the visual
arts and public policy
development.
Scott holds a Bachelor of
Commerce and a Bachelor
of Laws (Hons) from
Auckland University.
Steven Sargent joined
the Board in May 2015.
He is Chairman of the
Origin Energy Foundation,
Chairman of the
Remuneration and People
Committee and a member
of the Health, Safety and
Environment, Nomination
and Risk committees.
Steven’s executive career
included 22 years at
General Electric, where
he led businesses across
the USA, Europe and
Asia Pacific. Steven was
President and CEO of
GE Mining, GE’s global
mining technology and
services business. Prior
to this he was President
and CEO of GE Australia,
NZ & PNG where he
had local responsibility
for GE’s Energy, Oil and
Gas, Aviation, Healthcare
and Financial Services
businesses.
Steven is Chairman of OFX
Group Ltd (since November
2016) and Deputy
Chairman of Nanosonics
Ltd (since July 2016).
Over recent years Steven
has been a Non-executive
Director of Veda Group Ltd
(2015–2016).
Steven holds a Bachelor of
Business from Charles Sturt
University and is a Fellow
with the Australian Institute
of Company Directors and
a Fellow with the Australian
Academy of Technological
Sciences and Engineering.
10
Executive
Leadership Team
Jon Briskin
Greg Jarvis
Kate Jordan
Tony Lucas
Executive General Manager,
Retail
Executive General Manager,
Energy Supply and Operations
Jon Briskin joined Origin in
2010 and was appointed
Executive General Manager,
Retail in December 2016.
Jon leads the teams responsible
for energy sales, marketing,
product development
and service experience
for Origin’s residential and
SME customers. Jon has
held various roles at Origin,
leading customer operations,
service transformation and
customer experience, and
prior to Origin worked as a
management consultant.
Greg Jarvis joined Origin in
2002 as Electricity Trading
Manager and was appointed
Executive General Manager,
Energy Supply and Operations
in December 2016. Greg is
responsible for Wholesale,
Trading, Business Energy,
Solar, Generation, HSE and
LPG. Greg has over 20 years’
experience in the financial and
energy markets.
General Counsel and
Executive General Manager,
Company Secretariat,
Risk and Governance
Kate Jordan joined Origin
in March 2020 as General
Counsel and Executive General
Manager, Company Secretariat,
Risk and Governance. Kate
leads the legal, company
secretariat, risk and internal
audit teams. Prior to joining
Origin, Kate was Deputy
Chief Executive Partner at
Clayton Utz, responsible for
people and development.
Kate has over 20 years’ legal
experience across a range of
corporate transactions.
Executive General Manager,
Future Energy and Business
Development
Tony Lucas joined Origin
as Risk Analysis Manager in
2002 and was appointed
Executive General Manager,
Future Energy and Business
Development in December
2016. Tony leads the team
responsible for future energy,
strategy and technology,
ensuring that Origin is well
positioned to lead the transition
into a low-carbon, technology-
enabled world. Tony began
his career in the banking
industry before moving into
the energy sector.
Sharon Ridgway
Mark Schubert
Samantha Stevens
Lawrie Tremaine
Executive General Manager,
People and Culture
Executive General Manager,
Integrated Gas
Executive General Manager,
Corporate Affairs
Chief Financial Officer
Sharon Ridgway joined
Origin in 2009 and has been
responsible for People and
Culture since December
2016. Sharon’s team provides
strategic support to the
business in key areas such as
engagement, diversity, talent
management and culture
change. Prior to joining Origin,
Sharon developed a wide range
of experience across operational
and human resources roles
while working at Dixons, a large
European electrical retailer.
Mark Schubert joined Origin in
April 2015 and was appointed
Executive General Manager,
Integrated Gas in April 2017.
He is responsible for Origin’s
Integrated Gas business, which
manages the Company’s
portfolio of natural gas, LNG
and hydrogen interests. Mark
has also held a number of senior
positions during an 18-year
career with Shell, including
having direct accountability
for developing the world’s
first floating LNG facility,
Prelude FLNG.
Samantha Stevens joined Origin
in March 2018 as Executive
General Manager, Corporate
Affairs. Samantha is responsible
for Origin’s external affairs,
government and public policy,
and employee communication
functions, and the Origin
Energy Foundation. Samantha
has more than 20 years’
experience in corporate
affairs, mainly in the resources,
industrials and financial services
sectors. Prior to joining Origin,
Samantha headed up corporate
affairs for the global mining
services company Orica.
Lawrie Tremaine joined Origin
in June 2017 and as Chief
Financial Officer. Lawrie
leads the teams responsible
for all finance activities,
corporate strategy, corporate
development, procurement,
investor relations and corporate
HSE. Lawrie has over 30
years’ experience in financial
and commercial leadership,
predominantly in the resource,
oil and gas, and minerals
processing industries having
previously worked at Woodside
Petroleum and Alcoa.
Annual Report 2020
11
12
Operating and Financial Review
For the year ended 30 June 2020
This report forms part of the Directors’ Report.
1. Our purpose underpins everything we do
Our purpose: Getting energy right for our customers, communities and planet
Getting energy right for our customers
Our customers are at the heart of everything we do. We are committed
to providing ‘good energy’ that is reliable, affordable and sustainable. In
FY2020, we:
• responded to the COVID-19 pandemic with a commitment to not disconnect
or default list residential or small business customers in financial distress until
at least 31 October 2020;
• extended regulated retail pricing to our customers beyond regulatory
requirements;
• supported customers experiencing financial hardship, with 33,100
successfully completing our Power On hardship program;
• continued to support local businesses with supply from new APLNG acreage
dedicated to large manufacturing customers;
•
improved our Strategic Net Promoter Score (NPS) by eight points to +2 as at
30 June 2020, increasing further to +5 as at July 2020;
• continued to support customer take-up of renewable energy, as one of
Australia’s leading installers of rooftop solar and providers of GreenPower
and Green Gas; and
•
leveraged our global energy accelerator program, Free Electrons, to partner
with start-ups, including OhmConnect and Orison to roll out solutions in
demand-side management and storage.
Getting energy right for our communities
We respect the rights and interests of the communities in which we operate,
and consult with them to understand and manage our impact.
The Origin Energy Foundation is celebrating its 10th anniversary in 2020.
Through grants, volunteering and workplace giving programs, the Foundation
contributed more than $2.9 million to the community in FY2020.
Origin and its employees donated more than $870,000 to support
communities affected by bushfires and drought. This included $300,000 given
to the Australian Red Cross and state-based rural fire services, and $100,000
to Drought Angels.
We spent $365 million directly with regional suppliers, or 14 per cent of our
total spend.
We launched our Stretch Reconciliation Action Plan (RAP) in July 2019 to show
our commitment to participating in Australia’s reconciliation efforts through
targeted activities across learning, procurement and employment. In FY2020,
we spent $5.3 million with Indigenous suppliers, exceeding our Stretch RAP
target of $5 million.
This year, we announced our new three-year community partnership with
Netball Australia, supporting players at all levels across the country – from local
clubs to the Australian Diamonds.
We continue to work closely with the Northern Land Council to engage with
and maintain the support of our host Traditional Owners, who are the Native
Title holders where we work in the Beetaloo Basin.
Customers
Strategic NPS
FY20
2
FY19
(6)
33,100
Customers successfully completed
our Power On hardship program
Communities
>$2.9M
contributed to the community
by the Origin Energy Foundation
Regional procurement spend
as a % of total spend
14%
12%
FY19
FY20
Annual Report 2020 13
Planet
Getting energy right for the planet
We unequivocally support the Paris Agreement to limit the world’s temperature
rise to well below 2°C above pre-industrial levels and pursue efforts to further
limit this increase to 1.5°C.
Greenhouse gas emissions (mt CO2-e)
In line with our decarbonisation strategy, we are:
20.3
18.5
FY19
FY20
Scope 1
Scope 2
61 MW
Solar installations,
up from 50 MW in FY2019
• committed to lowering Scope 1 and 2 emissions by 50 per cent and Scope 3
emissions by 25 per cent by 2032, approved by the Science Based Targets
initiative;
• targeting more than 25 per cent of owned and contracted generation
capacity from renewables and storage by the end of 2020, subject to
development and commissioning timelines;
• setting a new target to reduce Scope 1 emissions by 10 per cent on average
over FY2021–23 from an FY2017 baseline;
•
including a new climate change target linked to executive remuneration; and
• planning to update our existing science-based target to a 1.5°C pathway
with an aim to achieve net zero emissions by 2050.
During FY2020, we:
• reduced our operational Scope 1 and Scope 2 emissions by 1.8 million
tonnes, or 9 per cent;
•
increased solar installations to 61 MW, up from 50 MW in FY2019; and
• published updated scenario analysis evaluating the impact of a 1.5°C carbon
reduction pathway on our wholesale and generation portfolio.
Our disclosures under the Task Force on Climate-related Financial Disclosure
guidelines are set out in our Sustainability Report.
Our people
People
Our people are one of our greatest strengths. Having a diverse and inclusive
workplace is key to creating a culture where people thrive, contributing to the
success of our business.
75%
Staff engagement,
our highest ever score
Total Recordable Injury Frequency Rate (TRIFR)
4.4
During FY2020, we:
•
•
increased our engagement score from 61 per cent to 75 per cent, placing
Origin in the top quartile across Australia and New Zealand;
improved our TRIFR score from 4.4 to 2.6; and
• were ranked number nine globally in Equileap’s 2019 Gender Equality Global
Report & Ranking.
During the year, we also enhanced the learning and development options
available to our people by launching our Learning and Development Hub.
We partnered with a new Employee Assistance Provider to give our people
access to free, confidential, independent and professional support. We also
launched an online Mental Health and Wellbeing Hub, which provides regular
webinars, factsheets, videos, mindfulness exercises and support information.
We also recently launched Gender Affirming Support@Origin and a new gender
affirming leave policy.
2.6
COVID-19 response
FY19
FY20
In response to the COVID-19 pandemic, we focused on the health and safety of
our people and the communities in which we operate by maintaining a reliable
supply of energy and supporting customers in need. We swiftly transitioned
most of our people to working from home, with only people in critical roles
remaining at sites, under strict health and safety measures. Our supply chains
and operations adapted seamlessly without significant disruptions.
Operating and Financial Review 14
2. Highlights
Financial performance
Statutory Profit
Underlying Profit
Underlying ROCE
$1,211M
68.8 cps
$1,028M
$1,023M
58.4 cps
58.1 cps
9.1%
8.8%
$83M
4.7 cps
FY19
FY20
FY19
FY20
FY19
FY20
Free Cash Flow
(before major growth)
$1,539M
$1,644M
Adjusted Net Debt
Final Dividend
$514M
$5,417M
$4,644M
10 cps
Unfranked
25 cps total FY2020 dividend
(27% of FY2020 Free Cash Flow)
FY19
FY20
June 2019
June 2020
Lease liabilities
In FY2020, Origin delivered a strong operational and underlying financial result with increased Free Cash Flow underpinning continued
debt reduction and disciplined investment in future growth.
Underlying Profit was in line with the prior year at $1,023 million, reflecting a stable result from Australia Pacific LNG (APLNG) but a lower
contribution from Energy Markets, offset by lower commodity hedging costs in Integrated Gas, lower interest expense and the prior year
non-cash remediation provision not repeating. Statutory Profit reduced, driven by non-cash APLNG impairment and onerous contract
provision charges that totalled $1.2 billion, reflecting lower oil and LNG price assumptions.
Strong Free Cash Flow was driven by record cash distributions from APLNG of $1,275 million and proceeds from the sale of Ironbark of
$231 million. This was partially offset by higher Energy Markets working capital and higher tax paid.
Adjusted Net Debt was down $773 million excluding the impact of lease liabilities under AASB 16 Leases. Adjusted Net Debt/Adjusted
Underlying EBITDA reduced from 2.6x at June 2019 to 2.1x, the lower end of our 2.0–3.0x target range.
COVID-19 impacted the business in the final quarter of FY2020, primarily through lower commodity prices and lower electricity and gas
demand from small and large business customers, partly offset by a moderate increase in retail demand. APLNG production in the fourth
quarter reduced due to lower demand, and activity was paused in the Beetaloo Basin. Due to lagged contract pricing, reduced oil prices in
the final quarter are expected to affect APLNG revenue in FY2021.
We continued to adopt a disciplined approach to capital management to maintain resilience and maximise returns. In response to the
COVID-19 pandemic and a material reduction in commodity prices, we announced a number of cost reduction initiatives across both
businesses. On 1 May 2020, we announced a strategic partnership with Octopus Energy, a fast-growing UK retailer, to radically transform
our retail operations.
Annual Report 2020 15
Energy Markets performance
Underlying EBITDA
Operating cash flow
$1,459M $1,307M
Down $115m or 7% vs FY2019
Down $400m vs FY2019
due to working capital movements
10.2%
Underlying ROCE
Down 2% vs FY2019
Cost to serve
Electricity and gas
customer accounts
Strategic Net
Promoter Score
$570M 3,851k
+2
Down $40m ($58m after adjusting for
AASB 16 Leases and COVID-19)
Up 21k vs June 2019
Up 8 points vs FY2019
Energy Markets Underlying EBITDA reduced in FY2020 as higher gas Gross Profit and savings in cost to serve were more than offset by
lower electricity Gross Profit. Lower Electricity Gross Profit was driven by the introduction of retail price regulations and lower volumes due
to weather, solar uptake and energy efficiency, and the impact of COVID-19.
Operating cash flow was lower due to higher working capital, reflecting the timing of collateral deposited with the futures exchange
associated with forward electricity hedge positions as part of our electricity risk management.
Despite the challenges posed during FY2020 by bushfires, extreme weather events and the COVID-19 pandemic, our power stations
continued to supply the market as needed. We successfully returned a Mortlake unit to service ahead of the summer peak demand period
and reduced our output in response to lower demand associated with COVID-19.
Construction of the 530 MW Stockyard Hill Wind Farm progressed and is targeted by the developer to come online by the end of 2020,
subject to development and commissioning timelines. We continue to explore generation expansion opportunities, including grid-scale
storage and fast-start gas. While forward wholesale electricity prices are currently below the price needed for investment, our longer-
term view remains that as coal generation progressively exits, new firm and flexible generation capacity will be required to complement
increasing renewable generation.
Retail markets remained competitive throughout FY2020; however, we increased the number of energy customer accounts by 21,000,
led by gains in residential gas and community energy services (CES). In addition, we grew our Broadband accounts by 12,000 with a
continued focus on balancing share and customer lifetime value. Market churn reduced following the introduction of regulated default
tariffs and we maintained a churn rate of 5 per cent below the market.
Our retail transformation program is on track and focused on improving customer experience, targeting a market-leading cost position and
growing new revenue streams. Our Strategic NPS score increased to +2 as at 30 June 2020, increasing to +5 as at July 2020. We have
simplified our product suite and continue to streamline and digitise the customer journey. Customers are increasingly choosing to engage
with us through digital channels, with 68 per cent of customers now on e-billing, and service call volumes reduced by a further 8 per cent
this year. We are on track to achieve our target of reducing cost to serve by $100 million from FY2018 to FY2021 and growing our Solar,
CES and Broadband businesses.
On 1 May 2020, we announced a strategic partnership with disruptive energy retailer and technology company Octopus Energy to adopt
its globally distinctive operating model and proprietary Kraken platform, as well as taking a 20 per cent equity stake. This partnership will
accelerate our retail strategy by delivering superior customer experience, driving a further step change in cost reduction, and opening up
further growth opportunities.
We are making good progress customising the Kraken platform for the Australian market and are on track to migrate our first customer
cohort by the end of the calendar year. Our first group of Energy Specialists have been trained on Octopus Energy’s UK Kraken platform
and are supporting its UK customers.
Operating and Financial Review 16
Integrated Gas performance
Underlying EBITDA
Cash distributions from APLNG
$1,741M $1,275M
Down $151m or 8% vs FY2019,
Underlying EBIT up $46m
Up $301m or 31% vs FY2019,
8.2%
Underlying ROCE
In line with FY2019
Record APLNG
production (37.5%)
265PJ
Up 4% vs FY2019
Average realised LNG price
Opex and Capex1/GJ
US$9.1/
MMBTU
Down 10% vs FY2019,
down 5% in A$ terms at $12.9/GJ
$3.5/GJ
Down 13% vs FY2019
Integrated Gas Underlying EBITDA reduced as lower commodity hedging costs were more than offset by a decrease in share of APLNG
Underlying EBITDA. This reflected a higher proportion of LNG sales into a weaker spot market, lower domestic sales volumes and average
price, and higher costs associated with a change in accounting treatment for dewatering and workovers, which was more than offset by a
reduction in ITDA.
APLNG delivered record production, reflecting improved field performance with higher well availability and facility reliability. Eurombah
Reedy Creek Interconnect (ERIC) pipeline came online in July 2019, improving utilisation of processing capacity. Talinga Orana Gas
Gathering Station (TOGGS) came online in July 2020, it compresses and transports gas through the Talinga to Condabri Interconnect
Pipeline to utilise processing capacity in Condabri.
Total capital and operating expenditure1 decreased by more than $200 million compared with FY2019. This was due to improved field
performance resulting in less gas purchases and lower costs associated with well workovers, as well as reduced exploration, lower non-
operated activity and lower infrastructure spend. As upstream operator, Origin delivered average operating costs of $1.0/GJ (excluding
pipeline and major turnaround costs) and average standard unfracked vertical Surat well costs of $1.2 million. Total operating and capital
expenditure in FY2020 was $3.50/GJ.1
The four-yearly maintenance of 15 upstream operated gas processing facility trains was completed in early FY2020. Due to the COVID-19
pandemic, a shutdown of one LNG train planned for May 2020 was deferred to July 2021.
During the period:
• APLNG delivered record production of 265 PJ (Origin share), shipped its 500th LNG cargo and made record cash distributions to
Origin of $1,275 million;
• Origin’s share of APLNG 2P (proved plus probable) operated reserves increased 168 PJ or 5 per cent before production, reflecting
higher estimated recovery from strong field performance, the inclusion of new areas to reserves and the Ironbark acquisition. This
enabled a decision to not participate in less economic non-operated fields;
• APLNG executed new contracts for over 100 PJ of gas sales to domestic customers starting in calendar year 2020;
• both long-term buyers declared LNG downward quantity tolerance for calendar year 2020; and
• the first price review under APLNG’s contract with Sinopec was completed with no change to the contract price.
In April 2020, Origin increased its interest in the Beetaloo Basin by 7.5 per cent to 77.5 per cent, in exchange for increasing its carry of its
minority partner’s share of costs by $25 million. Testing a liquids-rich gas play, the Kyalla horizontal well was drilled, cased and cemented
during the period, before activity was paused due to COVID-19. Subject to COVID-19-related conditions, fracture stimulation of the Kyalla
well is planned to resume in Q3/Q4 calendar year 2020, with extended production testing to follow.
1 Operating cash costs excludes APLNG’s Ironbark acquisition costs and purchases, and reflects royalties paid at the breakeven oil price. Royalties increase as oil
price increases.
Annual Report 2020 17
3. Strategy and prospects
Our business drivers
As a leading integrated energy company, Origin’s earnings drivers are spread across the energy value chain.
Our electricity margin is predominantly driven by outperforming the market cost of energy through our generation portfolio (power
stations and supply contracts). Although Origin generates less electricity than it sells, a significant portion of its wholesale costs are
relatively fixed, and so margins are leveraged to movements in wholesale market prices as they flow through into retail tariffs.
In natural gas, Origin’s wholesale margin is driven by a strong gas supply portfolio with pipeline and storage flexibility enabling us to direct
gas to where it is most needed. A large portion of supply is under long-term contracts that are either fixed-price or linked to oil and Japan
Korea Marker (JKM) prices, some of which reprice to market over time.
Profitability in energy retailing is driven by attracting and retaining customers by providing a superior customer experience and low-
cost service.
Origin is the upstream operator and has a 37.5 per cent interest in APLNG, which is Australia’s largest CSG to LNG project. It is a
significant supplier to both domestic gas and international LNG markets, with the majority of volume contracted until approximately 2035.
Profitability is underpinned by maintaining a low annual capital and operating cost base relative to revenues. In FY2020, approximately
72 per cent of APLNG gas volume was sold as LNG (of which 93 per cent was under long-term oil-linked contracts). The remaining 28 per
cent was sold domestically via a mix of long-term and short-term contracts. This contracting strategy minimises our exposure to the short-
term LNG market.
Market outlook
In the near term, COVID-19 has impacted the outlook for economic growth at the macro level as well as the specific markets in which we
operate domestically and internationally.
International oil and LNG markets are experiencing reduced demand due to COVID-19, coinciding with a period of LNG oversupply. This
has resulted in depressed prices for both commodities in the near term.
The domestic electricity and gas markets have also experienced reduced demand due to COVID-19, with electricity demand down
5–10 per cent over the fourth quarter of FY2020 (weather corrected). This coincides with increased supply of renewable energy and lower
international gas prices, reducing the near-term outlook for domestic electricity and gas prices.
The impact on employment and economic conditions more generally will have implications for our customers, and will affect energy
demand and affordability.
The path to recovery for the economy and the markets in which we operate will depend on the effectiveness of the health and community
responses to contain the virus, and the policy response to mitigate the economic impacts.
In the longer term, we continue to expect global trends towards decarbonisation, decentralisation and digitisation will shape energy
markets. If anything, we believe the enduring impacts of COVID-19 may accelerate the pace of change.
We expect:
• continued increases in large- and small-scale renewable energy will maintain downward pressure on average electricity prices, but will
also increase volatility and the need for more reliable, dispatchable (‘firming’) capacity such as flexible gas-fired generation and battery
storage, which Origin is well placed to supply;
•
increased electrification over time, particularly in transportation near term;
• growth in global demand for gas in power generation, industrial heating, building heating and transportation;
• LNG markets to remain oversupplied in the near term, but that new supply will be required from the early 2030s;
• east coast domestic gas prices to be impacted by a number of factors, including Asian LNG and international oil prices, procurement
and transportation costs; and
• retail markets to remain competitive, but with improved transparency due to market reference bill requirements.
It is in this context that we continue to evolve our strategy to respond to the short-term impacts of COVID-19 and position our business to
capture value in a future shaped by these global trends.
Operating and Financial Review 18
Our strategy
“Connecting customers to the energy and technologies of the future”
Our strategy is centred
around our core beliefs:
Decarbonisation:
Replacement of coal by
renewables, partnered
with firming capacity from
gas, pumped hydro and
storage will support emission
reductions.
Decentralisation:
Technological advancement
and consumer desire for
greater control will result in
an increase in distributed
generation and storage.
Digitisation: More connected
homes and businesses
will change all aspects of
operations and customer
experience.
The right
energy
Accelerate towards
clean energy
Low cost operator
developing and growing
gas resources
The right
technologies
Embracing a decentralised
and digital future
The right
customer
solutions
Leading customer
experience and solutions
Underpinned by a commitment to capital discipline
The right energy
We believe our generation and fuel supply portfolios provide flexibility to adapt and prosper in
a changing energy market. We are targeting renewables and storage to account for more than
25 per cent of our owned and contracted generation capacity by the end of 2020, subject to
development and commissioning timelines.
Accelerate towards
clean energy
Our renewable target is supported by Origin being the sole off-taker of the 530 MW Stockyard Hill
Wind Farm until the end of 2030. Tower components are now on site, and 116 of the 149 turbines have
been erected.
We own Australia’s largest peaking gas generation fleet, which is well placed to provide firming
capacity to support renewables and supply critical peak demand periods during extreme weather
events or baseload supply shortages.
Coal currently plays a critical role for baseload supply in Australia, but with an ageing fleet and
growing renewables driving down average prices and increasing intra-day volatility, the role of coal
is diminishing. As coal is retired and use of renewables increases, the market will require investment
in reliability. We are progressing a range of brownfield generation opportunities, including fast-start
gas and batteries, which would further improve our flexibility and capacity to support the increase in
renewables. Subject to market signals and regulatory certainty, we could quickly implement these at
the appropriate time.
Annual Report 2020 19
Our Integrated Gas business is anticipating lower short-term demand caused by COVID-19 and lower
production accordingly. Strong field performance has enabled reduced development activity and
provides the capability to ramp up production in response to demand, if required. APLNG continues
to meet the needs of its customers and remains focused on key value drivers such as workover costs,
fracture stimulation costs and horizontal wells.
Low cost operator
developing and growing gas
resources
Beyond APLNG, our strategy is to scale the low-cost upstream operating model to new development
opportunities. In the Beetaloo Basin, we have a 77.5 per cent interest and operatorship of three
exploration permits covering 18,500km2. We are currently part way through Stage 2 of a farm-in work
program targeting two independent potentially liquids-rich shale gas plays.
We are also farming into a 75 per cent interest and operatorship of five permits located in the Cooper–
Eromanga Basin in south west Queensland. The staged farm-in work program involves the drilling
of up to five exploration wells to be completed by the end of calendar year 2024, targeting both
unconventional liquids and gas.
The right technologies
The energy markets around the world are rapidly transforming towards low-cost renewables and new
digital technologies, and Australia is no exception. Continued penetration of decentralised generation
and storage, combined with the rise of internet-enabled devices, is changing the way our customers
interact with us and use energy at home and in their businesses. We are developing a leading digital
platform and analytics capability to connect millions of distributed assets and data points to provide
more personalised and value-add services to our customers, both in front of and behind the meter.
We have developed a proprietary Virtual Power Plant (VPP) platform to connect, and use artificial
intelligence to orchestrate distributed assets such as air conditioning units, batteries, hot water systems
and electric vehicle (EV) chargers. Through this platform, we have more than 85 MW from 11,000
connected customers. We expect this to increase as we demonstrate the benefits to both customers
and to the grid of optimising these distributed assets at critical times of market volatility.
We are also working with other businesses to source technical solutions and capabilities. We are
co-founders of the Free Electrons global energy group, which brings together global utilities and
leading start-ups looking to deploy new technology. Domestically, we sponsor EnergyLab, Australia’s
leading platform for launching energy start-ups. Recent products include Spike (a gamified demand
response program that rewards customers for reducing their energy use) and a portable battery
product for the home.
Origin is also pursuing opportunities in low-carbon technologies such as hydrogen, e-mobility, small-
scale LNG and carbon-neutral LNG. In terms of hydrogen, Origin’s integrated energy position provides
a unique advantage in producing green hydrogen and ammonia using renewables. Hydrogen and
ammonia demand is forecast to grow, allowing countries to reduce emissions and diversify fuel supply.
In terms of e-mobility, we provide charging solutions and infrastructure, and are partnering with a
fleet management operator to provide an end-to-end solution that will enable businesses to make a
seamless transition to EVs. We are also undertaking a smart charging trial aimed at optimising the value
for EV drivers and the grid.
The right customer solutions
Origin is Australia’s largest energy retailer by number of customer accounts, and is well placed to
harness opportunities to deliver value to customers in a changing energy landscape. Customers are
at the heart of everything we do, and our immediate focus is to transform their experience to make it
simple, seamless and increasingly digital.
In the near term, we are focused on delivering a superior customer experience, a market leading cost
position and growing our product offerings, including solar, CES and broadband.
Our strategic partnership with Octopus Energy is expected to fast-track our strategy to deliver a
superior customer experience at even lower cost, while opening up future growth opportunities.
Embracing a decentralised
and digital future
Leading customer
experience and solutions
Operating and Financial Review 20
4. FY2021 guidance
Guidance is provided on the basis that market conditions and the regulatory environment do not materially change, adversely impacting
on operations. Considerable uncertainty exists relating to potential ongoing impacts of COVID-19 and this guidance is subject to any
further material impact on demand and customer affordability.
Energy Markets Underlying EBITDA
Integrated Gas – APLNG 100%
Production
Capex and opex, excluding purchases(a)
Unit capex + opex, excluding purchases(a)
Distribution breakeven(b)
Integrated Gas – Other
Oil/LNG hedging and trading (loss)/gain(c)
Corporate
Underlying costs
Capital expenditure (excluding investments)
FY20
FY21
guidance
A$m
1,459
1,150–1,300
PJ
A$m
A$/GJ
US$/boe
A$m
A$m
A$m
708
(2,482)
3.5
29
650–680
(2,000)–(2,200)
2.9–3.4
27–31
(92)
(59)
(500)
50
(75)–(85)
(420)–(470)
(a) Operating cash costs excludes purchases and reflects royalties payable at breakeven oil prices.
(b) FY2020 foreign exchange rate: 0.67 AUD/USD excludes Ironbark acquisition costs; FY2021 foreign exchange rate 0.69 AUD/USD.
(c) FY2021 guidance is based on forward market prices as at 17 August 2020.
Energy Markets
We estimate Energy Markets Underlying EBITDA to be lower than FY2020 at $1,150-$1,300 million driven by:
• Electricity Gross Profit reduction of $170-$220 million, reflecting lower wholesale electricity and renewable certificate prices flowing
into tariffs, and increased network costs of $40 million that are not recovered in regulated tariffs;
• Gas Gross Profit reduction of $100-$150 million, reflecting the roll-off of certain long-term supply and transport capacity sales
contracts ($70 million) and repricing of retail and business tariffs; and
• Cost to serve savings of approximately $70 million, in line with the target of >$100 million savings from FY2018 (subject to any
additional material increase in bad and doubtful debts provisioning).
Integrated Gas
We estimate reduced APLNG (100 per cent) production in FY2021 of 650–680 PJ, reflecting anticipated lower demand with strong field
capability to increase production in response to demand.
APLNG is able to further manage sales volumes through flexibility in lifted non-operated production and gas purchases.
We estimate total APLNG capex + opex of $2.0-$2.2 billion, reflecting reduced development activity with fewer drilling rigs, reduced
workovers and lower infrastructure spend due to TOGGS being online, and lower exploration and appraisal (E&A) spend.
APLNG is targeting FY2021 distribution breakeven of US$27–31/boe including US$12/boe in project finance costs.
We estimate a net gain on Origin’s oil/LNG hedging and trading positions of $50 million based on current forward prices. Refer to
Section 6.2.2 for details. Other Origin only costs are estimated to be similar to FY2020 and include overheads net of recoverables from
APLNG, Beetaloo Basin and other costs.
Corporate
FY2021 Corporate costs are estimated to be $75-$85 million, reflecting higher costs associated with enterprise resource planning (ERP)
replacement, FY2020 FX gains and Mortlake self-insurance costs not repeating.
Capital expenditure is estimated to be $420-$470 million including $65–$80 million E&A spend, primarily relating to Beetaloo appraisal.
This excludes $90-$100 million relating to the Octopus Energy investment.
Depreciation and amortisation is estimated to be $50-$60 million higher than FY2020 driven by decommissioning retail IT systems and
increased generation restoration provisions.
Annual Report 2020 21
5. Financial update
5.1 Reconciliation from Statutory to Underlying Profit
Statutory Profit/(Loss)
Items Excluded from Underlying Profit (post-tax):
Increase/(decrease) in fair value and foreign exchange movements
Oil and gas
Electricity
Foreign exchange and interest rate derivatives
Other financial assets/liabilities
Foreign exchange on foreign-denominated financing
Disposals, impairments, onerous contracts and business restructuring
Total Items Excluded from Underlying Profit (post-tax)
Underlying Profit
FY20
($m)
FY19
($m)
Change
($m)
Change
(%)
83
1,211
(1,128)
(93)
275
153
85
(46)
86
(3)
(1,215)
(940)
1,023
139
59
(88)
(43)
274
(63)
44
183
1,028
136
94
173
(3)
(188)
60
(1,259)
(1,123)
(5)
98
159
(197)
7
(69)
(95)
(2,861)
(614)
(0)
Fair value and foreign exchange movements reflect fair value gains/(losses) associated with commodity hedging, interest rate swaps and
other financial instruments. These amounts are excluded from Underlying Profit to remove the volatility caused by timing mismatches in
valuing financial instruments and the underlying transactions they relate to.
• Oil and gas derivatives manage exposure to fluctuations in the underlying commodity price to which Origin is exposed through its gas
portfolio, and indirectly through Origin’s investment in APLNG. See Section 6.2.2 for details of Origin’s oil hedging carried out in relation
to its investment in APLNG.
• Electricity derivatives, including swaps, options and forward purchase contracts, are used to manage fluctuations in wholesale
electricity and environmental certificate prices in respect of electricity purchased to meet customer demand.1
• Foreign exchange and interest rate derivatives manage exposure to foreign exchange and interest rate risk associated with the debt
portfolio. A significant portion of debt is Euro-denominated and cross-currency interest rate swaps hedge that debt to AUD.
• Other financial assets/liabilities reflects investments held by Origin including MRCPS issued by APLNG.2
• Foreign exchange on foreign-denominated financing reflects currency fluctuations on unhedged USD debt. Debt is maintained in USD
to offset the USD investment in MRCPS, which delivers USD distributions.
Disposals, impairments, onerous contracts and business restructuring are either non-cash or non-recurring items and are excluded from
Underlying Profit to better reflect the underlying performance of the business. They include:
• a non-cash impairment of $746 million relating to Origin’s carrying value of APLNG. The charge is driven by a reduction in oil price
assumptions over the near term and a revised long-term Brent crude oil price assumption of US$60/bbl (real 2020) from FY2026,
partially offset by cost reductions from improved field and operating performance. There is no tax impact, as any impact is offset by
recognising part of a previously unrecognised deferred tax liability;
• a non-cash onerous provision charge of $455 million post-tax relating to a 20-year off-take contract from Cameron LNG. The provision
is primarily due to a reduction in JKM LNG sale price assumptions, reflecting medium-term demand and moderately lower long-term
prices driven by expected lower US gas liquefaction fees, as well as lower US treasury bond rates; and
• transaction costs of $8 million post-tax primarily relating to OC Energy integration and Origin restructuring costs of $6 million.
The nature of Items Excluded from Underlying Profit set out in the above table have been reviewed by our auditor for consistency with the
description in note A1 of the Origin Energy Financial Statements.
5.2 Accounting changes
AASB 16 Leases has been adopted from 1 July 2019, which requires leases to be brought on balance sheet, resulting in a $97 million
increase in Underlying EBITDA, more than offset by increases in depreciation and amortisation and financing costs with a net reduction
to Underlying Profit after tax of $18 million. A lease liability of $514 million and a right-of-use (ROU) asset of $467 million have been
recognised at 30 June 2020. Refer to Appendix 1 and the Overview section of the Origin Energy Financial Statements for details.
From 1 July 2019, APLNG dewatering and workover costs have been expensed as incurred within Underlying EBITDA rather than
capitalised and amortised. Following a period of embedding steady state operations, these costs are considered ongoing and operational
in nature going forward and the change in application of accounting practice reflects this. During commissioning of the project and in
the lead up to steady state operations, these amounts were capitalised as they represented costs incurred to bring the assets into their
intended state of use. This results in a $107 million reduction in share of APLNG EBITDA, which is more than offset by a $152 million
reduction in share of depreciation and amortisation from APLNG. Refer to Appendix 2 and Section 6.2.1 for further information.
There has been no change to comparative information for the above accounting changes.
1
2
Under AASB 9, from 1 July 2018, Origin Energy holds MRCPS at fair value, rather than at cost.
Operating and Financial Review 22
5.3 Underlying Profit
Energy Markets
Integrated Gas – Share of APLNG
Integrated Gas – Other
Corporate
Underlying EBITDA
Underlying depreciation and amortisation
Underlying share of ITDA
Underlying EBIT
Underlying interest income – MRCPS
Underlying interest income – Other
Underlying interest expense
Underlying Profit before income tax and non-controlling interests
Underlying income tax expense
Non-controlling interests’ share of Underlying Profit
Underlying Profit
FY20
($m)
1,459
1,915
(174)
(59)
3,141
(509)
(1,303)
1,329
174
16
(316)
1,203
(177)
(3)
1,023
FY19
($m)
1,574
2,123
(231)
(234)
3,232
(419)
(1,504)
1,308
226
8
(388)
1,154
(123)
(3)
1,028
Change
($m)
Change
(%)
(115)
(208)
57
175
(91)
(90)
201
21
(52)
8
72
49
(54)
–
(5)
(7)
(10)
(25)
(75)
(3)
21
(13)
2
(23)
100
(19)
4
44
–
–
Refer to Sections 6.1 and 6.2 respectively for Energy Markets and Integrated Gas analysis.
Corporate costs reduced by $175 million, reflecting the prior year non-cash remediation provision increase of $170 million not repeating
and $17 million FX gains, primarily relating to hedging USD cash flow received from APLNG. This was partly offset by self-insurance costs
of $7 million associated with the Mortlake electrical fault and higher costs associated with ERP replacement of $6 million.
Underlying depreciation and amortisation increased by $90 million, largely due to the impact of adopting the new leasing standard.
Underlying share of ITDA decreased $201 million, driven by lower APLNG amortisation, reflecting the change in treatment of dewatering
and workover costs, which are now directly expensed as incurred ($152 million), and reduced interest expense on project finance due to a
lower average interest rate from refinancing activities at APLNG partly offset by a lower AUD/USD exchange rate. Refer to Section 6.2 for
further detail.
Underlying interest income on MRCPS reduced $52 million, driven by a lower balance following buy-backs by APLNG, partly offset by a
lower AUD/USD exchange rate.
Underlying interest expense reduced by $72 million, $90 million after excluding the impact from adopting the leasing standard. This
reflects a lower net debt balance and a lower average cost of debt due to refinancing activities. Refer to Section 5.6 for further detail.
Annual Report 2020 23
5.4 Cash flows
Operating cash flow
Underlying EBITDA
Underlying equity accounted share of EBITDA (non-cash)
Other non-cash items in Underlying EBITDA
Underlying EBITDA adjusted for non-cash items
Change in working capital
Energy Markets – excluding electricity futures collateral
Energy Markets – electricity futures collateral
Integrated Gas – excluding APLNG
Corporate
Other
Tax paid
Cash flow from operating activities
FY20
($m)
3,141
(1,911)
157
1,387
(222)
74
(340)
29
15
–
(215)
951
FY19
($m)
3,232
(2,123)
277
1,386
84
(63)
125
17
5
(35)
(110)
1,325
Change
($m)
Change
(%)
(91)
212
(120)
1
(306)
137
(465)
12
10
35
(105)
(374)
(3)
(10)
(43)
0
(364)
(217)
(372)
71
200
(100)
95
(28)
Cash flow from operating activities decreased $374 million, primarily due to higher working capital requirements (–$306 million) and
higher tax paid (–$105 million) associated with higher taxable income in FY2019.
Underlying share of EBITDA (non-cash) reflects share of APLNG ($1,915 million) and Octopus Energy (–$4 million). Other non-cash items
include bad and doubtful debts (+$124 million) and share-based remuneration (+$30 million).
Working capital increased $222 million, primarily due to collateral deposited with the futures exchange (–$340 million) associated with
forward electricity hedge positions that are expected to unwind over time, lower net payables from lower wholesale gas and electricity
prices (–$100 million) and higher inventory (–$26 million) driven by coal, partly offset by lower green inventory (+$90 million) and lower
Retail and Business Energy net working capital (+$93 million).
Investing cash flow
Capital expenditure
Cash distribution from APLNG
Interest received from other parties
Investments/acquisitions
Disposals
Cash flow from investing activities
FY20
($m)
(500)
1,275
18
(165)
234
862
FY19
($m)
(341)
974
2
(64)
18
589
Change
($m)
Change
(%)
(159)
301
16
(101)
216
273
47
31
800
158
N/A
46
FY2020 capital expenditure of $500 million comprises:
• generation sustain ($208 million), primarily related to major overhauls at Eraring Power Station ($92 million) and Uranquinty Power
Station ($29 million), as well as Mortlake Power Station repairs ($41 million);
• other sustain ($115 million) including LPG ($26 million), Origin ERP system replacement ($23 million), regulatory market reforms
($20 million) and CES ($7 million);
• productivity/growth ($92 million) including Quarantine Power Station upgrade ($14 million), CES ($18 million), Kraken licensing costs
($13 million), LPG ($9 million), digital spend ($8 million), solar ($7 million) and other Energy Markets projects; and
• exploration and appraisal spend ($85 million), primarily related to the appraisal program in the Beetaloo Basin.
Cash distributions from APLNG amounted to $1,275 million, comprising $181 million of MRCPS interest (down from $229 million in
FY2019) and $1,094 million of MRCPS buy-backs (up from $745 million in FY2019).
Interest received increased, reflecting a higher cash balance following refinancing in preparation for debt maturities.
Investments include initial payments and transaction costs for the equity interest in Octopus Energy ($128 million) and deferred
consideration for OC Energy ($14 million). Disposals include sale of Ironbark to APLNG for $231 million.
Operating and Financial Review 24
Financing cash flow
Net proceeds/(repayment) of debt
Operator cash call movements
On-market purchase of shares
Settlement of foreign currency contracts
APLNG loan repayment
Interest paid
Payment of lease principal
Dividends paid
Total cash flow from financing activities
Effect of exchange rate changes on cash
FY20
($m)
(1,173)
56
(75)
(55)
(8)
(310)
(75)
(478)
(2,118)
(1)
FY19
($m)
185
7
(77)
(64)
(31)
(375)
–
(165)
(520)
2
Change
($m)
Change
(%)
(1,358)
49
2
9
23
65
(75)
(313)
(1,598)
(3)
(734)
700
(3)
(14)
(74)
(17)
N/A
190
307
(150)
Repayment of debt reflects capital market debt repaid from cash held and Free Cash Flow.
Operator cash call movements represent the movement in funds held and other balances relating to Origin’s role as upstream operator of
APLNG. On-market purchase of shares represents the purchase of shares associated with employee share remuneration schemes and the
dividend reinvestment plan. Settlement of foreign currency contracts represents the partial closure of contracts executed in prior periods
to monetise the value in certain cross-currency interest rate swap contracts. The value of outstanding contracts as at 30 June 2020 was
$156 million.
Interest paid reduced by $65 million, comprising lower interest on debt due to refinancing activities ($81 million), partly offset by a
$16 million increase in interest paid on lease liabilities.
Free Cash Flow
Free Cash Flow represents cash flow available to pay dividends, repay debt, invest in major growth projects or return surplus cash to
shareholders. This is prepared on the basis of equity accounting for APLNG.
The Octopus Energy investment is considered a major growth project and $141 million of associated investing cash flow from
consideration payments and capital expenditure has been excluded from FY2020 Free Cash Flow.
($m)
FY20
FY19
FY20
FY19
FY20
FY19
FY20
FY19
FY20
FY19
Energy Markets
Integrated Gas –
Share of APLNG
Integrated Gas –
Other
Corporate
Total
Underlying EBITDA
Non-cash items
Change in working capital
Other
Tax paid
1,459
137
(266)
(23)
–
1,574
90
62
(20)
–
1,915
(1,915)
–
–
–
2,123
(2,123)
–
–
–
(174)
11
29
24
–
(231)
7
17
(1)
–
(59)
13
15
(1)
(215)
(234)
180
5
(15)
(110)
3,141
(1,753)
(222)
–
(215)
3,232
(1,845)
84
(35)
(110)
Operating cash flow
1,307
1,707
Capital expenditure
Cash distribution from APLNG
(Acquisitions)/disposals
Interest received
(395)
–
(165)
–
(304)
–
(53)
–
Investing cash flow
(560)
(357)
Interest paid
–
–
Free Cash Flow
including major growth
Major growth spend
Free Cash Flow
747
141
1,350
–
888
1,350
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
(109)
(208)
(247)
(174)
951
1,325
(94)
1,275
234
–
(28)
974
1
–
1,414
946
(10)
–
(0)
18
8
(9)
–
7
2
–
(500)
1,275
69
18
(341)
974
(46)
2
862
589
–
–
(310)
(375)
(310)
(375)
1,305
–
737
(549)
–
(548)
–
1,503
141
1,539
–
1,305
737
(549)
(548)
1,644
1,539
Annual Report 2020 25
5.5 Dividends
The Board has determined to pay an unfranked 10 cps dividend in respect of the second half of FY2020, bringing total FY2020 dividends
to 25 cps, which represents 27 per cent of Free Cash Flow. The Board exercised discretion to set the payout ratio below the target
30 per cent to 50 per cent of Free Cash Flow. This reflects current and expected future economic and business conditions, particularly
lower commodity prices.
During FY2020, $141 million was incurred in respect of the strategic partnership with Octopus Energy. This has been treated as major
growth expenditure and excluded from Free Cash Flow when measuring the dividend pay-out percentage.
The nil franking percentage reflects the current franking credit balance. A low franking balance is expected over FY2021–23 due to
realised foreign exchange losses on debt maturities and deducting the remaining tax cost base of Browse Basin exploration permits in the
FY2020 income tax return. Refer to Origin Energy Financial Statements note E2 for further details.
Origin will seek to pay sustainable shareholder distributions through the business cycle and will target an ordinary dividend payout range
of 30 per cent to 50 per cent of Free Cash Flow per annum. Distributions will take the form of franked dividends, subject to the company’s
franking credit balance. Free Cash Flow is defined as cash from operating activities and investing activities (excluding major growth
projects), less interest paid.
Remaining cash flow after ordinary dividends will be applied to further debt reduction, value accretive organic growth and acquisition
opportunities and/or additional capital management initiatives.
The Board maintains discretion to adjust shareholder distributions for economic and business conditions.
The Dividend Reinvestment Plan (DRP) will operate with nil discount and will be satisfied through on-market share purchases. The DRP
price of shares will be the average purchase price, rounded to two decimal places, bought on market over a period of 10 trading days
commencing on the third trading day immediately following the Record Date.
5.6 Capital management
During FY2020, the following capital management initiatives were completed:
• refinanced debt to lower rates and increase tenor:
– raised €600 million (A$973 million) of 10-year debt at 3.2 per cent fixed interest rate;
– raised A$300 million of eight-year debt at 2.7 per cent fixed interest rate;
– repaid €500 million (A$939 million) 3.7 per cent effective interest rate debt;
– redeemed €1,000 million (A$1,391 million) 7.9 per cent fixed interest rate hybrid obligation;
– repaid NZ$141 million (A$125 million) 2.1 per cent effective interest rate debt obligation; and
– renegotiated lower rates on a A$500 million bank guarantee facility.
• cancelled $718 million in undrawn bank loan facilities that were surplus to requirements.
In July 2020, the maturity date of A$1.1 billion of bank debt facilities was extended from FY2023 to a later date in FY2025. Further surplus
liquidity of $0.2 billion was cancelled as part of this transaction.
Adjusted Net Debt
Movements in Adjusted Net Debt ($m)
(951)
514
244
478
5,417
(1,267)
(69)
292
500
4,644
5,158
Decrease in Adjusted Net Debt excluding leases: $773 million
30 June
2019
Operating
cash flow
Net cash
from APLNG
Capex
Net
acquisitions/
disposals
Net interest
payments
Dividend
FX/Other
30 June
2020
excl. leases
Lease
liabilities
30 June
2020
Operating and Financial Review 26
Adjusted Net Debt excluding leases decreased $773 million, driven by strong APLNG cash distribution and operating cash flow. This was
partially offset by capital expenditure, dividends, interest payments and foreign exchange/other impacts. After recognition of $514 million
in lease liabilities under AASB 16 Leases, Adjusted Net Debt decreased by $259 million to $5,158 million. The increase in reported debt
due to adopting AASB 16 will not have any material impact on the company’s credit metrics as lease liabilities were previously included in
these metrics.
Foreign exchange/other includes on-market purchase of shares ($75 million), payment of lease liabilities ($75 million), settlement of foreign
currency contracts ($55 million) and non-cash translation of unhedged USD debt and fees.
Origin’s objective is to maintain an Adjusted Net Debt/Adjusted Underlying EBITDA ratio of 2.0–3.0x and a gearing target of 20 per cent
to 30 per cent. As at 30 June 2020, this ratio was 2.1x and gearing was 29 per cent, compared to 2.6x and 29 per cent, respectively, at
30 June 2019.
Our long-term credit ratings are BBB (stable) from S&P and Baa2 (stable) from Moody’s.
Debt maturity profile post debt extension
– excluding lease liabilities (A$b)
Debt portfolio management
Average term to maturity increased from 3.0 years at 30 June 2019 to
3.9 years at 30 June 2020, including the bank debt facility extension
in July 2020. The rolling 12-month average interest rate on drawn debt
decreased from 5.9 per cent in FY2019 to 4.8 per cent in FY2020.
2.0
As at 30 June 2020, Origin held $1.2 billion of cash and $2.9 billion
in committed undrawn debt facilities after adjusting for the debt
extension in July 2020. This liquidity position of $4.1 billion is held to
meet near-term debt maturities of $1 billion by December 2020 and
$1.9 billion maturing in October 2021, and to maintain a sufficient
liquidity buffer.
1.5
1.0
0.5
FY21
FY22 FY23 FY24 FY25 FY26 FY27 FY28 FY29 FY30+
Loans and bank guarantees – undrawn
Loans and bank guarantees – drawn
Capital Markets debt and term loan
APLNG funding
During construction of APLNG, shareholders contributed capital via ordinary equity and the investment in preference shares (termed
MRCPS) issued by APLNG. APLNG distributes funds to shareholders firstly via fixed dividends of 6.37 per cent per annum on the MRCPS
balance, recognised as interest income by Origin, and secondly via buy-backs of MRCPS (refer to Section 5.4 above). The fair value of
MRCPS held by Origin at 30 June 2020 was A$2,109 million.
APLNG also funded construction via US$8.5 billion in project finance facilities, signed in 2012. These facilities were partially refinanced in
FY2019. The outstanding balance at 30 June 2020 was US$6,386 million (A$9,307 million), net of unamortised debt fees of US$81 million
(A$118 million). APLNG’s average interest rate associated with its project finance debt portfolio for FY2020 was 3.6 per cent, and FY2021
is estimated to be approximately 3.1 per cent.
As at 30 June 2020, gearing3 in APLNG was 28 per cent, down from 30 per cent at 30 June 2019.
3 Gearing is defined as project finance debt less cash, divided by project finance debt less cash plus equity.
Annual Report 2020
27
6. Review of segment operations
6.1 Energy Markets
Fuel Supply
•
•
Gas
Coal
Transportation
• Flexible contracted
gas transport
arrangements
Generation
•
1 black coal generator
•
•
Australia’s largest
gas-fired fleet
Growing contracted
renewables
Networks
• Regulated
Customers
•
Retail (consumer and SME)
•
Business (commercial
and industrial)
•
Wholesale
Energy Markets operations
Origin’s Energy Markets business comprises Australia’s largest energy retail business by customer accounts, Australia’s largest fleet of
gas-fired peaking power stations supported by a substantial contracted fuel position, a growing supply of contracted renewable energy
and Australia’s largest power station, the black coal–fired Eraring Power Station. Energy Markets reports on an integrated portfolio basis.
Electricity and Natural Gas Gross Profit and retail cost to serve are reported separately, as are the EBITDA of the Solar and Energy Services,
Future Energy and LPG divisions, and share of earnings from the 20 per cent equity holding in Octopus Energy Holdings Limited.
6.1.1 Financial summary
Underlying EBITDA/EBIT
Electricity Gross Profit
Natural Gas Gross Profit
Electricity and Natural Gas cost to serve
LPG EBITDA
Solar and Energy Services EBITDA
Future Energy costs
Share of EBITDA from Octopus Energy
Underlying EBITDA
Underlying EBIT
FY20
($m)
1,187
744
(570)
83
33
(15)
(4)
1,459
974
FY19
($m)
1,390
715
(610)
68
26
(15)
–
1,574
1,173
(110)
(67)
(26)
88
(59)
40
19
Electricity –$203 million
Gas +$29 million
1,574
Change
($m)
Change
(%)
(15)
4
(6)
22
30
–
N/A
(7)
(17)
(203)
29
40
15
8
–
(4)
(115)
(199)
1,459
FY19
Retail pricing
(DMO/VDO)
Volume/
mix
Other
Wholesale
margin
Volume
Cost to serve
Other
FY20
Operating and Financial Review
28
6.1.2 Electricity
Volume summary
Volumes sold
(TWh)
NSW(a)
Queensland
Victoria
South Australia
Total volumes sold
FY20
FY19
Retail
Business
Total
Retail
Business
Total
7.8
4.1
2.9
1.3
16.1
8.7
3.6
3.4
1.7
17.4
16.5
7.7
6.2
3.1
33.5
8.4
4.6
3.1
1.3
17.4
9.4
3.5
4.0
1.9
18.8
17.8
8.1
7.1
3.2
36.2
Change
(TWh)
Change
(%)
(1.3)
(0.4)
(0.9)
(0.1)
(2.7)
(7.3)
(5.0)
(12.7)
(3.1)
(7.5)
(a) Australian Capital Territory customers are included in New South Wales.
Gross Profit summary
Revenue ($m)
Retail (consumer and SME)
Business
Cost of goods sold ($m)
Network costs
Energy procurement costs
Gross Profit ($m)
Gross margin %
FY20
FY19
$m
$/MWh
$m
$/MWh
Change
(%)
Change
($/MWh)
7,509
4,569
2,941
(6,322)
(3,142)
(3,179)
1,187
15.8%
224.0
283.9
168.8
(188.6)
(93.8)
(94.9)
35.4
8,264
5,056
3,208
(6,874)
(3,287)
(3,587)
1,390
16.8%
228.4
290.5
170.7
(189.9)
(90.8)
(99.1)
38.4
(9)
(10)
(8)
8
4
11
(15)
(6)
(4.3)
(6.8)
(1.9)
1.3
(2.9)
4.3
(3.0)
Electricity Gross Profit declined by $203 million4, driven by:
• $3/MWh decrease in unit margins (–$136 million) comprising:
Sources and uses of electricity (TWh)
– –$110 million from the introduction of the DMO and VDO regulated retail pricing tariffs
on 1 July 2019;
– –$21 million driven by costs associated with unplanned outages at the Eraring and
Mortlake plants, net of insurance recoveries;
– –$64 million reflecting higher solar feed-in tariffs and discounts to concession
customers (–$34 million), and lower green scheme prices in Business tariffs (–$30
million); offset by:
– +$59 million margin improvement, including from lower wholesale procurement and
fuel costs, and a $33 million release of a rehabilitation provision, partially offset by lower
Business tariffs.
40
35
30
25
20
15
10
5
• 2.7 TWh volume decline (–$67 million) relating to lower usage from milder weather, solar
uptake and efficiency (–$33 million), COVID-19 impacts (–$26 million) and customer
movements relating to large Business and SME tenders (–$8 million).
Owned and contracted generation of 22.5 TWh was lower by 2.1 TWh, driven primarily by
Eraring Power Station (–2.9 TWh) due to outages and lower output in response to reduced
customer demand from COVID-19, and Mortlake Power Station (–0.3 TWh) reflecting the
outage in the first half. This was partially offset by Darling Downs Power Station (+1.1 TWh)
with more gas available to generation following the roll-off of short-term wholesale gas
trading contracts in FY2019.
Energy procurement costs decreased with lower volumes. Unit procurement costs reduced
by $4.30/MWh, driven by lower wholesale procurement costs, contract prices and fuel
costs, offset by higher solar feed-in tariff rates.
FY19
FY20
FY19
FY20
Sources
Uses
Renewables
Solar FiT
Coal (Eraring)
Gas
Other
Swap contracts
Short position
Retail
Business
Losses
4
Includes a $4 million benefit relating to AASB 16 Leases.
Annual Report 2020
29
Wholesale energy costs
Fuel cost(a)
Generation operating costs
Owned generation(a)
Net pool costs(b)
Bundled renewable PPAs(c)
Market contracts
Solar feed-in tariff
Capacity hedge contracts
Green Schemes (excl. PPAs)
Other
Energy procurement costs
FY20
FY19
TWh
$/MWh
$m
TWh
$/MWh
19.6
19.6
19.6
4.9
2.9
6.0
1.5
50.6
11.0
61.6
61.3
92.1
60.3
117.9
1,132
230
1,363
449
255
508
127
317
569
–
21.8
21.8
21.8
5.0
2.7
7.3
1.2
51.9
10.6
62.4
90.5
93.1
69.6
103.3
35.0(d)
90.9
3,587
38.0(d)
94.4
$m
992
216
1,208
303
264
362
181
342
506
14
3,179
(a) Includes volume from internal generation and contracted from Pelican Point.
(b) Net pool costs includes gross pool purchase costs net of pool revenue from generation, gross and net settled PPAs, and other contracts.
(c) Bundled PPAs includes cost of electricity and renewable certificates. Market contracts include swap and energy hedge contracts.
(d) Volume differs from sales volume due to energy losses of 1.3 TWh (FY2019: 1.8 TWh).
Electricity supply
Nameplate
capacity
(MW)
FY20
FY19
Change
Output
Pool revenue
Output
Pool revenue
Output
Pool revenue
Type(a)
(GWh)
($m) ($/MWh)
(GWh)
($m) ($/MWh)
(GWh)
($m) ($/MWh)
Eraring
Units 1–4
GT
Darling Downs
Osborne(b)
Uranquinty
Mortlake
Mount Stuart
Quarantine
Ladbroke Grove
Roma
Shoalhaven
2,922
2,880
42
644
180
664
566
423
230
80
80
240
Black Coal
OCGT
CCGT
CCGT
OCGT
OCGT
OCGT
OCGT
OCGT
OCGT
Pump/hydro
13,634
–
2,067
703
422
932
4
188
155
17
156
1,065
–
130
58
75
91
0
29
19
2
26
79
–
79
93
125
106
103
153
123
109
135
16,513
–
931
759
333
1,204
9
194
157
24
157
1,494
–
92
105
53
207
1
45
29
3
20
90
–
98
138
160
172
132
232
182
130
130
(2,879)
–
1,137
(56)
89
(272)
(5)
(6)
(2)
(7)
(1)
(429)
–
39
(47)
22
(116)
(1)
(16)
(10)
(1)
6
Internal generation
6,029
18,279
1,495
82
20,281
2,050
101
(2,002)
(555)
Pelican Point
Renewable PPAs
240
1,207
CCGT
Solar/wind
1,317
2,871
1,548
2,744
(231)
127
(11)
–
(19)
(45)
(35)
(66)
(29)
(79)
(59)
(21)
6
(19)
Owned and
contracted
generation
7,476
22,467
24,574
(2,106)
(a) OCGT = open cycle gas turbine; CCGT = combined cycle gas turbine.
(b) Origin has a 50 per cent interest in the 180 MW plant and contracts 100 per cent of the output.
Operating and Financial Review 30
6.1.3 Natural Gas
Volume summary
Volumes sold (PJ)
Retail
Business
Total
Retail
Business
Total
FY20
FY19
NSW(a)
Queensland
Victoria
South Australia(b)
11.0
3.1
25.2
5.7
22.8
66.9
58.3
10.6
33.8
70.0
83.6
16.2
External volumes sold
45.0
158.6
203.6
10.1
3.3
22.4
5.6
41.4
19.7
92.3
57.5
11.0
29.8
95.5
79.9
16.7
180.5
222.0
Internal sales (generation)
Total volumes sold
55.6
259.2
49.4
271.3
Change
(PJ)
Change
(%)
4.0
(25.6)
3.7
(0.4)
(18.3)
6.2
(12.1)
13
(27)
5
(2)
(8)
(4)
(a) Australian Capital Territory customers are included in New South Wales.
(b) Northern Territory and Western Australia customers are included in South Australia.
Gross Profit summary
Revenue ($m)
Retail (consumer and SME)
Business
Cost of goods sold ($m)
Network costs
Energy procurement costs
Gross Profit ($m)
Gross margin %
FY20
FY19
$m
$/GJ
$m
$/GJ
Change
(%)
Change
($/GJ)
2,835
1,163
1,673
(2,090)
(796)
(1,294)
744
26.3%
13.9
25.8
10.5
(10.3)
(3.9)
(6.4)
3.7
2,926
1,064
1,862
(2,211)
(739)
(1,472)
715
24.4%
13.2
25.7
10.3
(10.0)
(3.3)
(6.6)
3.2
(3)
9
(10)
5
(8)
12
4
7
0.7
0.2
0.2
(0.3)
(0.6)
0.3
0.4
Natural Gas Gross Profit increased $29 million, driven by:
• $0.4/GJ margin improvement (+$88 million) primarily due to lower average procurement
costs from oil/JKM linked supply contracts and shorter-term purchases; and
• 18.3 PJ decrease in external sales (–$59 million) due to the roll-off of short-term wholesale
trading contracts in Queensland and expiry of C&I contracts and demand impacts from
COVID-19 (–$10 million). This was partially offset by higher Retail volumes due to higher
customer numbers and cooler weather in Victoria.
Sources and uses of gas (PJ)
300
250
200
150
100
50
FY19
FY20
FY19
FY20
Sources
Uses
Oil/JKM linked
Generation
Other fixed price
Business – Wholesale
APLNG – fixed price
Business – C&I
Retail
Annual Report 2020
31
6.1.4 Electricity and Natural Gas cost to serve
FY20
FY19
Change
($)
Change
(%)
Cost to maintain ($ per average customer(a))
Cost to acquire/retain ($ per average customer(a))
Electricity and Natural Gas cost to serve ($ per average customer(a))
Maintenance costs ($m)
Acquisition and retention costs(b) ($m)
Electricity and Natural Gas cost to serve ($m)
(121)
(38)
(159)
(434)
(136)
(570)
(a) Represents cost to serve per average customer account, excluding CES accounts.
(b) Customer wins (FY2020: 491,000; FY2019: 527,000) and retains (FY2020: 1,396,000; FY2019: 1,796,000).
Labour
Bad and doubtful debts
Other variable costs
Retail and Business
Wholesale
Corporate services and IT
Electricity and Natural Gas cost to serve
FY20
($m)
(150)
(113)
(125)
(388)
(51)
(131)
(570)
(126)
(43)
(169)
(455)
(155)
(610)
FY19
($m)
(173)
(80)
(158)
(411)
(62)
(136)
(610)
5
5
10
21
19
40
(4)
(11)
(6)
(5)
(12)
(6)
Change
($m)
Change
(%)
23
(33)
33
23
12
5
40
(13)
41
(21)
(6)
(19)
(4)
(6)
In FY2020, we undertook a number of measures to support customers financially impacted by COVID-19, including pausing late payment
fees, default listings and disconnections, and providing payment extensions at a cost of $5 million. Notwithstanding these measures and
the broader government and business support in place, we recognised an increase in our bad and doubtful debt provision of $38 million5
related to the risks associated with COVID-19.
Overall, Electricity and Natural Gas cost to serve reduced by $40 million, driven by operating cost savings of $58 million and lower
leasing charges of $25 million associated with adopting AASB 16 Leases. This was partially offset by $43 million related to the impacts of
COVID-19 detailed above. Bad debt expense as a percentage of total Electricity and Natural Gas revenue increased to 1.09 per cent in
FY2020, up from 0.71 per cent in FY2019.
(19)
(34)
(5)
43
(25)
610
Transformation activities – $58 million
Increasing digitisation
•
• Targeted marketing and optimised channels
• Transforming customer journeys
• Leaner operational structure
• Automated processes and outsourcing
• Corporate services and IT recontracting
and lower headcount
570
FY19
Cost to
acquire
Back office
functions
Corporate
and IT
Impacts of
COVID-19
Leases
FY20
We are on track to deliver the target of $100 million cost reduction by FY2021 from a baseline in FY2018. Planning is underway for a
further reduction of $100–$150 million in cash savings by FY2024 following successful implementation of the Octopus Energy’s Kraken
platform and operating model.
5 The total increase in bad and doubtful debt provision relating to COVID-19 risks was $40 million, of which $38 million impacted electricity and gas cost to serve and the
remainder impacted the Solar and Energy services division.
Operating and Financial Review 32
Customer accounts
As at
30 June 2020
Customer
accounts (’000)(c)
Electricity
NSW(a)
Queensland
Victoria
South Australia(b)
Total
Average
1,191
645
556
239
2,631
2,624
Natural
Gas
335
181
479
225
1,220
1,204
Total
Electricity
30 June 2019
Natural
Gas
Total
Change
1,526
825
1,035
464
3,851
3,827
1,193
660
558
229
2,639
2,645
312
182
474
223
1,191
1,157
1,505
842
1,032
451
3,830
3,802
22
(16)
3
13
21
25
(a) Australian Capital Territory customers are included in New South Wales.
(b) Northern Territory and Western Australia customers are included in South Australia.
(c) Includes 257,000 CES customers (FY2019: 233,000).
Although price dispersion and in situ churn have reduced following the
introduction of the DMO and VDO, the market remains highly competitive and we
continue to take a disciplined approach to share and customer lifetime value.
Origin churn decreased to 13.4 per cent during the period, compared to market
churn of 18.4 per cent.
Period end customers rose by 21,000 overall. Electricity customers fell by 8,000,
reflecting a reduction in SMEs of 20,000, primarily relating to large tenders.
This was partially offset by growth in embedded network customers as the CES
business continues to grow. Natural Gas customers increased by 29,000, driven
primarily by gains in New South Wales.
Broadband customer accounts increased by 12,000 during the year to a total of
20,000 customer accounts at 30 June 2020.
30
25
20
15
10
5
–
(5)
(10)
(15)
(20)
Customer movement (’000)
6.1.5 LPG
Volumes (kT)
Revenue ($m)
Cost of goods sold ($m)
Gross Profit ($m)
Operating costs ($m)
Underlying EBITDA ($m)
NSW
QLD
VIC
SA
Electricity
Gas
FY20
FY19
Change
417
608
(417)
191
(108)
83
426
674
(470)
204
(136)
68
(9)
(66)
54
(13)
28
15
Change
(%)
(2)
(10)
(11)
(6)
(20)
22
Origin is one of Australia’s largest LPG and propane suppliers, procuring and distributing LPG to residential and business locations across
Australia and the Pacific. As at 30 June 2020, Origin had 363,000 LPG customer accounts, up from 362,000 customer accounts at
30 June 2019.
Gross Profit decreased by $13 million, driven by the impact of COVID-19 on demand, primarily in the Pacific. Both revenue and cost of
goods sold decreased due to lower international commodity pricing, which is a key component of pricing to customers. Operating costs
decreased $27 million, due to the impact of adopting AASB 16 Leases ($30 million). Underlying operating costs were stable.
Annual Report 2020 33
6.1.6 Solar and Energy Services
Revenue
CES Gross Profit
Solar Gross Profit
Other Gross Profit
Gross Profit
Operating costs
Underlying EBITDA
FY20
($m)
298
75
31
5
111
(77)
33
FY19
($m)
Change
($m)
Change
(%)
216
57
26
6
89
(64)
26
82
18
5
(1)
22
(13)
8
38
32
19
(17)
25
20
27
Origin provides installation of solar photovoltaic (PV) systems and batteries to residential and business customers, and ongoing support
and maintenance services. Community Energy Services supplies both electricity and gas to apartment owners and occupiers, and body
corporates through embedded networks and serviced hot water.
Underlying EBITDA increased by $8 million, primarily driven by growth in CES Gross Profit (+$18 million), in particular the acquisition
of OC Energy in February 2019. This was partially offset by increased operating costs (–$14 million), driven primarily by the OC Energy
acquisition, and includes a $3 million benefit due to the impact of adopting AASB 16 Leases.
6.1.7 Future Energy
Operating costs
Investments
FY20
($m)
(15)
(15)
FY19
($m)
(15)
(35)
Change
($m)
Change
(%)
–
(20)
N/A
(56)
Future Energy is focused on new business models to connect distributed assets and data to customers. We have developed a VPP
platform that is able to orchestrate millions of distributed assets using artificial intelligence. The VPP has more than 85 MW connected
today from more than 11,000 customers and we expect it to grow as the benefits to customers and the grid are realised. We have also
developed a leading digital and analytics capability and are actively investing in technology for new customer solutions, both in front of
and behind the meter.
Operating costs remained flat during the period. The business continues to make small investments in trialling new energy solutions.
6.1.8 Octopus Energy
Origin has acquired a 20 per cent interest in Octopus Energy and a licence in Australia to its market-leading customer platform, Kraken.
Over the next 24 to 30 months, Origin will transfer its retail electricity and gas customer accounts to the Kraken platform and adopt
Octopus Energy’s leading operating model with targeted cash savings of $70–80 million in FY2022 increasing to $100–150 million
annually from FY2024.
We are making good progress in customising the Kraken platform for the Australian market and are on track to have our first customer
cohort migrated by the end of the calendar year. Base functionality for NSW is well progressed and we have moved a small group of ‘family
and friends’ onto the platform for further testing.
Our first group of Energy Specialists have been trained on the UK Kraken platform and are supporting Octopus Energy’s UK customers.
These Energy Specialists are gaining valuable experience in using Kraken and will be transitioning to the Australian platform as we start to
migrate the first customer cohort.
The $4 million loss as shown in Section 6.1.1 represents our share of EBITDA from Octopus Energy from 1 May to 30 June 2020. The loss in
these months represents warmer weather reducing gas demand and increasing net wholesale costs.
Operating and Financial Review 34
6.2 Integrated Gas
Share of APLNG (see Section 6.2.1)
Integrated Gas – Other (see Section 6.2.2)
Underlying EBITDA
Underlying depreciation and amortisation
Underlying share of ITDA from APLNG
Underlying EBIT
6.2.1 Share of APLNG
FY20
($m)
1,915
(174)
1,741
(29)
(1,296)
416
FY19
($m)
2,123
(231)
1,892
(18)
(1,504)
370
Change
($m)
Change
(%)
(208)
57
(151)
(11)
208
46
(10)
(25)
(8)
61
(14)
12
Exploration and
appraisal
Drilling and
gathering
Processing and
transportation
Domestic
customers
Liquefaction and
export customers
Origin has a 37.5 per cent shareholding in APLNG, an equity accounted incorporated joint venture. APLNG operates Australia’s largest
CSG to LNG export project (by nameplate capacity) with the country’s largest 2P CSG reserves.6 Origin is the operator of the upstream
CSG exploration and appraisal, development and production activities. ConocoPhillips is the operator of the 9 mtpa two-train LNG
liquefaction facility at Gladstone in Queensland.
As APLNG is an equity accounted incorporated joint venture, Integrated Gas reports its share of APLNG EBITDA. The share of APLNG
ITDA is recorded as one-line item between EBITDA and EBIT.
APLNG acquired various CSG interests from Tri-Star in 2002 that are subject to reversionary rights and an ongoing royalty interest in
favour of Tri-Star. These interests represent approximately 20 per cent of APLNG’s 2P CSG reserves and approximately 19 per cent of 3P
(proved plus probable plus possible) CSG reserves (as at 30 June 2020). Refer to Section 7 for disclosure relating to Tri-Star litigation
associated with these CSG interests.
Financial summary – APLNG
Profit and Loss
($m)
Commodity revenue and other income(a)
Operating expenses
Underlying EBITDA
Depreciation and amortisation
MRCPS interest expense
Project finance interest expense
Other financing expense
Interest income
Income tax expense
Underlying ITDA(b)
Underlying Profit
FY20
FY19
APLNG
100%
7,100
(1,992)
5,108
(1,863)
(463)
(372)
(102)
40
(708)
Origin
share
2,662
(747)
1,915
(699)
(174)
(140)
(37)
15
(266)
APLNG
100%
7,443
(1,781)
5,662
(2,116)
(602)
(590)
(72)
51
(699)
Origin
share
2,791
(668)
2,123
(794)
(226)
(221)
(27)
19
(262)
(3,468)
(1,301)
(4,027)
(1,510)
1,640
614
1,635
613
(a) Includes commodity revenue plus other income of $19 million (Origin share) (FY2019: $2 million) primarily related to a release of the restoration provision from the
relinquishment of the Gilbert Gully permit during FY2020.
(b) See Origin Financial Statement note B2.1 for details relating to a $5 million difference between APLNG ITDA and Origin’s reported share.
6
As per EnergyQuest Energy Quarterly, June 2020.
Annual Report 2020
35
Origin’s share of APLNG Underlying EBITDA decreased by $208 million including a $107 million decrease relating to the change in
accounting treatment for dewatering and workover costs (previously capitalised and now directly expensed as incurred). This was partially
offset by a $13 million increase related to adopting AASB 16 Leases. Excluding the above accounting impacts, Origin’s share of APLNG
Underlying EBITDA decreased $114 million, driven by:
• commodity and other revenue decreasing by $129 million as result of a higher proportion of LNG sales into a weaker spot market as well
as lower domestic sales volumes and lower average price; and
• operating expenses reducing $15 million (after excluding the above accounting impacts of $94 million), primarily driven by lower
purchases ($55 million) and other cost reductions ($15 million). This was partially offset by higher royalties and tariffs ($26 million),
exploration write-off ($21 million) and higher downstream operating costs ($8 million). See below for further details.
The decrease in Origin’s share of depreciation and amortisation reflects the removal of amortisation related to workovers and dewatering of
$152 million, partially offset by the impact of a lower AUD/USD exchange rate.
Origin’s share of MRCPS interest expense decreased by $52 million due to a lower MRCPS balance following buy-backs by APLNG. This
was partially offset by the impact of a lower AUD/USD exchange rate. Project finance interest decreased by $81 million due to a lower
average interest rate from refinancing activities, partly offset by the impact of a lower AUD/USD exchange rate. See Section 5.6 for details
relating to APLNG funding.
APLNG volume summary
Volume and price summary
Production volumes (PJ)
Operated
Non-operated
Total production
Purchases
Changes in upstream gas inventory/other
Liquefaction/downstream inventory/other
Sales volumes (PJ)
Domestic gas sales volumes
LNG spot sales volumes
LNG contract sales volumes
Commodity revenue ($m)
Natural Gas sales
LNG sales
Realised price
Natural Gas ($A/GJ)
LNG (A$/GJ)
LNG (US$/mmbtu)
FY20
FY19
APLNG
100%
Origin
share
APLNG
100%
Origin
share
203
62
265
7
(6)
(16)
251
70
12
169
2,643
323
2,320
542
165
708
17
(15)
(42)
668
187
32
449
7,049
861
6,188
4.61
12.86
9.12
522
157
679
32
1
(36)
676
195
17
464
7,436
983
6,453
5.04
13.42
10.12
196
59
255
12
0
(13)
254
73
7
174
2,789
369
2,420
Origin’s share of APLNG production increased 10 PJ to 265 PJ in FY2020, with improved performance across operated and non-operated
assets driven by stronger field and facility performance and the Eurombah Reedy Creek Interconnect pipeline (ERIC) online from July
2019, improving utilisation of processing capacity. This was partially offset by reduced operated production in the final quarter in response
to lower demand due to COVID-19.
Origin’s FY2020 share of APLNG commodity revenue decreased 5 per cent to $2,643 million with increased production offset by
lower purchases and building up of inventory. The average realised LNG price decreased 4 per cent to A$12.86/GJ, reflecting a higher
proportion of spot LNG sales. The average realised domestic gas price decreased 9 per cent to $4.61/GJ, driven by reduced short-term
sales prices.
Operating and Financial Review 36
Cash flow – APLNG 100%
A$m
Underlying EBITDA
Non-cash items in underlying EBITDA
Change in working capital
Other
Operating cash flow*
Capital expenditure*
Capitalised de-watering costs*
Interest income*
Asset purchases (including Ironbark)/sale proceeds*
Loan repaid by/(advanced to) Origin
Loans paid by other shareholders
Investing cash flow
Project finance interest and transaction costs*
Repayment of project finance*
Other financing activities*
Repayment of lease liabilities*
Interest on lease liabilities*
MRCPS interest
MRCPS buy-back
Financing cash flow
Net increase/(decrease) in cash and cash equivalents
Effect of exchange rate changes on cash*
Net increase/(decrease) in cash including foreign exchange movement
FY20
($m)
5,108
66
64
4
5,242
(1,038)
–
40
(245)
8
6
(1,229)
(382)
(731)
(45)
(80)
(19)
(480)
(2,918)
(4,655)
(642)
104
(538)
FY19
($m)
5,662
(4)
(34)
(88)
5,536
(1,277)
(101)
50
30
31
9
(1,258)
(513)
(808)
(85)
–
–
(611)
(1,987)
(4,004)
274
113
387
Distributable cash flow*
2,846
2,945
Change
($m)
Change
(%)
(554)
70
98
92
(294)
239
101
(10)
(275)
(23)
(3)
29
131
77
40
(80)
(19)
131
(931)
(651)
(916)
(9)
(925)
(99)
(10)
N/A
(288)
(105)
(5)
(19)
(100)
(20)
N/A
(74)
(33)
(2)
(26)
(10)
(47)
N/A
N/A
(21)
47
16
(334)
(8)
(239)
(3)
*
Included in distributable cash flow. Distributable cash flow represents the net increase in cash including foreign exchange movements before MRCPS interest and buy-
backs and transactions with shareholders.
APLNG generated distributable cash flow of $2,846 million (Origin’s 37.5 per cent share: $1,067 million) at an effective oil price of
US$68/bbl (FY2019: US$73/bbl) after servicing project finance interest and principal. Cash distributions to Origin were higher at
$1,275 million in FY2020, reflecting partial draw down of cash retained at 30 June 2019. APLNG’s cash balance at 30 June 2020 was
$1,072 million ($1,610 million at 30 June 2019).
Annual Report 2020 37
Operating cash costs – APLNG 100%
Purchases
Royalties and tariffs(a)
Operated opex(b)
Non-operated opex
Downstream opex
APLNG Corporate/other
Dewatering(b)
Workovers
Total operating expenses per Profit and Loss
Add capitalised de-watering costs
Other cash items
Total operating cash costs
FY20
($m)
(89)
(502)
(561)
(202)
(248)
(105)
(106)
(179)
(1,992)
–
(63)
(2,055)
FY19
($m)
(235)
(433)
(562)
(197)
(228)
(126)
–
–
(1,781)
(101)
(61)
(1,943)
Change
($m)
Change
(%)
146
(69)
1
(5)
(20)
21
(106)
(179)
(211)
101
2
(112)
(62)
16
(0)
3
9
(17)
N/A
N/A
12
(100)
(3)
6
(a) Reflects actual royalties paid. At break-even prices royalties and tariffs would have amounted to $96 million (FY2019: $139 million).
(b) FY2020 unit operating costs of $1.0/GJ reflects operated opex ($561 million) less pipeline and major turnaround costs ($68 million) plus operated dewatering costs
($76 million) and 542 PJ operated production.
Operating expenses increased $211 million, of which $285 million relates to dewatering and workover costs previously capitalised. The
remaining decrease of $74 million was primarily driven by lower purchases ($146 million), partially offset by higher royalties and tariffs
($69 million) as a result of a higher royalty rate and increased production.
APLNG Corporate/other reduced $21 million, reflecting lower costs due to gas inventory movements ($69 million) and a benefit due to
adopting AASB 16 Leases ($35 million). This was partially offset by the exploration write-offs ($56 million), foreign exchange impacts
($22 million) and corporate costs and other ($5 million).
Capital expenditure – APLNG 100%
Operated upstream – Sustain
Operated upstream – Infrastructure
Exploration and appraisal
Operated stay in business (SIB)
Downstream
Non-operated
Workovers
Total capital expenditure
Working capital movement
Leases classified as financing cash flow
Total capital expenditure per cash flow
FY20
($m)
(483)
(83)
(88)
(63)
(0)
(205)
–
(922)
(164)
48
FY19
($m)
(515)
(122)
(102)
(16)
(39)
(262)
(237)
(1,293)
16
–
(1,038)
(1,277)
Change
($m)
Change
(%)
32
39
14
(47)
39
57
237
371
(180)
48
239
(6)
(32)
(14)
294
(100)
(22)
(100)
(29)
(1,125)
N/A
(19)
Capital expenditure decreased by $371 million, of which $237 million relates to workover costs now expensed. The remaining $134 million
is driven by a $71 million decrease in operated development costs with completion of the ERIC pipeline, $14 million reduced exploration,
$57 million lower non-operated spend due to a reduced level of development activity, $39 million lower downstream spend driven by
a $50 million benefit related to settlement of a project construction claim, partially offset by an increase in SIB of $47 million related to
purchase of spares for maintenance.
Operated upstream – Sustain includes expenditure for drilling, completions, fracture stimulation, gathering network, surface connection,
land access and development infrastructure, which occurs over multiple years and is directly related to sustaining production over
the medium term. In FY2020, 260 operated wells were drilled (versus 251 in FY2019) including 239 Surat vertical wells (versus 243 in
FY2019). 74 wells were fracture stimulated (versus 91 in FY2019) and 267 wells were brought online (vs 266 in FY2019).
Working capital increased by $164 million, primarily due to lower capex creditors as a result of lower activity in FY2020.
Operating and Financial Review 38
6.2.2 Integrated Gas – Other
This segment comprises Origin Integrated Gas activities that are separate from APLNG, and includes unconventional exploration interests
in the Beetaloo Basin, the south west Queensland Cooper–Eromanga Basin and a potential conventional development resource in the
offshore Browse Basin. It also includes overhead costs (net of recoveries) incurred as upstream operator and corporate service provider to
APLNG, costs associated with growth initiatives such as hydrogen and small-scale LNG, and costs incurred in managing Origin’s exposure
to LNG pricing risk and impacts of LNG trading positions held by Origin.
Beetaloo Basin (Northern Territory)
Origin has a 77.5 per cent interest in three exploration permits over 18,500 km2 in the Beetaloo Basin. An increase of 7.5 per cent from the
previous 70 per cent interest occurred on 7 April 2020, as part of changes to the joint venture agreement with partner Falcon Oil and Gas.
Stage 2 appraisal is underway, targeting two independent shale liquids-rich gas plays. Two horizontal appraisal wells are planned
to be drilled, fracture stimulated and put on extended production test, with the objective of flowing liquids-rich gas to the surface.
Work continued with the regulators and Native Title holders to ensure operations are conducted safely and with transparency around the
necessary approvals and consents.
• Kyalla liquids-rich gas play – The Kyalla 117 well has been drilled to a total measured depth of 3,809 metres, which includes a
1,579-metre lateral section. Results obtained to date demonstrate good reservoir continuity, conductive natural fractures and
continuous gas shows.
In March 2020, operations were paused in response to the COVID-19 pandemic. The Ensign rig has been secured and maintained
locally and by mid-May all activities were completed on the Kyalla 117 well site.
Subject to COVID-19-related conditions, fracture stimulation of Kyalla 117 is expected to resume in Q3/Q4 calendar year 2020, with
extended production testing of the well to follow. Results from the production test are expected by the end of the first quarter of
calendar year 2021. These results will inform options to either further evaluate this play or commence activities in the Velkerri play.
• Velkerri liquids-rich gas play – Construction of the Velkerri 76 well lease pad was completed in early December 2019 and
environmental approval to drill and fracture stimulate the Velkerri Flank well was granted in late December 2019.
Cooper–Eromanga Basin (Queensland)
Origin entered into agreements with Bridgeport Energy to farm into a 75 per cent equity position and operatorship of five permits located
in the Cooper–Eromanga Basin in south west Queensland. Origin was included on title in June 2020 and drilling of the first well (Stage 1A
vertical) is due to commence in Q4 calendar year 2020. The staged farm-in work program involves drilling up to five exploration wells, to
be completed by the end of 2024 targeting both unconventional liquids and gas. Origin will carry Bridgeport’s cost up to $12 million.
Financial summary
Origin only commodity hedging and trading
Other Origin only costs
Underlying EBITDA
Underlying depreciation and amortisation/ITDA
Interest income – MRCPS
Underlying Profit/(Loss)
FY20
($m)
(92)
(82)
(174)
(24)
174
(23)
FY19
($m)
(199)
(32)
(231)
(12)
226
(17)
Change
($m)
Change
(%)
107
(50)
57
(12)
(52)
6
(54)
156
(25)
99
(23)
(35)
Refer to the table following for a breakdown of Origin only commodity hedging and trading costs.
Other Origin only costs increased $50 million, including a benefit of $11 million from adopting AASB 16 Leases. The remaining $61 million
increase is primarily driven by costs associated with an agreement to reduce Origin’s share of overriding royalty in the Beetaloo Basin
($15 million), a higher proportion of non-recoverable costs, and higher insurance costs.
Annual Report 2020 39
FY2020 hedging and trading summary
FY2020 hedging and trading positions realised a $92 million loss compared to a $199 million loss in FY2019.
Based on open hedge and trading positions at current forward market prices7, we estimate a net gain on oil hedging and LNG trading in
FY2021 of $50 million.
$m
Hedge premium expense
Gain/(loss) on oil hedging
Gain/(loss) on LNG hedging/trading
Total
(a) Based on forward prices as at 17 August 2020.
Oil hedging
FY19
actual
FY20
actual
FY21
estimate(a)
(34)
(81)
(84)
(199)
(29)
8
(72)
(92)
(9)
99
(40)
50
Origin has entered into oil hedging instruments to manage its share of APLNG oil price risk based on the primary principle of protecting
the Company’s investment grade credit rating and cash flows during volatile market periods.
For FY2021, Origin’s share of APLNG-related Japan Customs-cleared Crude (JCC) oil price exposure is estimated to be approximately
22 mmboe. As at 31 July 2020, we estimate that 11.4 mmboe has been priced at approximately US$41/bbl before any hedging, based on
the contract lags.
Origin has separately hedged 6.4 mmbbl primarily using swaps, producer collars and put options of which 3.7 mmbbl has been realised as
at 31 July 2020 at an average price of approximately US$55/bbl (see table below).
Hedge instruments
Brent AUD swaps
Brent USD swaps
Brent producer collars
Brent puts
Total hedged
LNG hedging and trading
Realised as at 31 July 2020
Remaining unrealised
Volume
Average price
Volume
Average price
3.1 mmbbl
–
0.4 mmbbl
0.2 mmbbl
3.7 mmbbl
A$88/bbl
–
US$35–90/bbl
US$35/bbl
1.3 mmbbl
0.4 mmbbl
0.4 mmbbl
0.6 mmbbl
2.7 mmbbl
A$66/bbl
US$57/bbl
US$35–90/bbl
US$35/bbl
Uncontracted gas volumes produced by APLNG are sold to the domestic and spot LNG markets. To manage price risk associated with
LNG spot volumes, Origin entered into forward fixed price hedge contracts with the hedge position fully closed out at a cost of $60 million
in FY2020. There are no LNG hedge positions relating to APLNG’s uncontracted sales exposure beyond FY2020.
In 2013, Origin established a Henry Hub linked contract to purchase 0.25 mtpa from Cameron LNG for a period of 20 years, with the first
cargo delivered to Origin in June 2020. In FY2020, we recognised a non-cash charge of $455 million post-tax relating to an onerous
contract provision associated with Cameron LNG. The non-cash charge will be excluded from Underlying Profit in FY2020, with future
realised losses or gains accounted for in Underlying Profit. In 2016, Origin established a contract with ENN Energy Trading Company
Limited to sell 0.28 mtpa on a Brent oil-linked basis commencing in FY2019 and ending in December 2023. These contracts and
derivative hedge contracts that manage the price risk associated with the physical LNG contracts form part of an LNG trading portfolio.
We estimate a net loss of $40 million in FY2021 for the combined LNG trading and derivatives portfolio, based on current forward prices.7
7
As at 17 August 2020.
Operating and Financial Review 40
7. Risks related to Origin’s future financial prospects
The scope of operations and activities means that Origin is exposed to risks that can have a material impact on our future financial
prospects. Material risks, and the Company’s approach to managing them, are summarised below.
Risk management framework
Overseen by the Board and the Board Risk Committee, Origin’s risk management framework supports the identification, management
and reporting of material risks. Risks are identified that have the potential to impact the delivery of business plans and objectives. Risks are
assessed using a risk toolkit that considers the level of consequence and likelihood of occurrence using consistent risk assessment criteria.
The risk framework incorporates a ‘three lines of defence’ model for managing risks and controls in areas such as health and safety,
environment (including climate change), finance, reputation and brand, legal and compliance, and social impacts. All employees are
responsible for making risk-based decisions and managing risk within approved risk appetite and specific limits.
The Board reviews Origin’s material risks each quarter and assesses the effectiveness of the Company’s risk management framework
annually, in accordance with the ASX Corporate Governance Principles and Recommendations.
Three lines of defence
Line of defence
Responsibility
Primary accountability
First line
Lines of business
Second line
Oversight functions
Third line
Internal audit
Identifies, assesses, records, prioritises, manages and monitors risks. Management
Provides the risk management framework, tools and
systems to support effective risk management.
Management
Provides assurance on the effectiveness of governance,
risk management and internal controls.
Board, Board Committees and Management
Our risk framework supports the identification and management of emerging risks and escalating threats. During FY2020, COVID-19
emerged as a key threat to our operational and financial performance, requiring an ongoing response and management across many of
our existing material risks to minimise impacts. Our priorities continue to focus on the health and safety of our people, customers and the
communities we operate in. We are ensuring continuity of our operations and supporting activities, including our supply chain, to provide
our essential services to our customers and maintain our financial resilience in response to changes in global markets.
Material risks
The risks identified in this section have the potential to materially affect Origin’s ability to meet its business objectives and impact its future
financial prospects. These risks are not exhaustive and are not arranged in order of significance.
Annual Report 2020 41
Strategic risks
Strategic risks arise from uncertainties that may emerge in the medium to longer term and, while they may not necessarily impact
short-term profits, can have an immediate impact on the value of the Company. These strategic risks are managed through continuous
monitoring and review of emerging and escalating risks, ongoing planning and resource allocation, and evaluation by management and
the Board.
Risk
Consequences
Management
Competition
Origin operates in a highly competitive retail environment,
which can result in pressure on margins and customer losses.
Competition also impacts Origin’s wholesale business,
with generators competing for capacity and fuel and the
potential for gas markets to be impacted by new domestic gas
resources, LNG imports and the volume of gas exports.
Technological
developments/
disruption
Distributed generation is empowering consumers to own,
generate and store electricity, consuming less energy from
the grid. Technology is allowing consumers to understand and
manage their power usage through smart appliances, having
the potential to disrupt the existing utility relationship with
consumers.
Technology also allows customers to have increased
awareness of the impact of when they consume energy and
where that energy may be sourced from.
Advances in technology and the abundance of low-cost data
acquisition, communication and control has the potential to
create new business models and introduce new competitors.
Changes in demand
for energy
Any decrease in energy demand driven by price, consumer
behaviour, mandatory energy efficiency schemes, government
policy, weather or other factors can reduce Origin’s revenues
and adversely affect Origin’s future financial performance.
Regulatory policy
Conversely, failure to adequately prepare for any increases
in future energy demands, including the emergence of new
sources of demand, may restrict Origin in optimising our future
financial opportunities.
Origin has broad exposure to regulatory policy change and
other government interventions. Changes in these areas
can impact financial outcomes and, in some cases, change
the commercial viability of existing or proposed projects or
operations. Specific areas subject to review and development
include government subsidies for building new generation
or transmission capacity, direct government investment in
generation, energy market design, climate change policies,
domestic gas market interventions, retail price and consumer
protection regulation, and royalties and taxation policy.
• Our strategy to mitigate the impact of this risk on our
Retail business is to effectively manage customer
lifetime value and build customer loyalty and trust by
delivering simple, seamless and personalised customer
experiences, and offering innovative and differentiated
products and services. Partnering with Octopus Energy,
with its proven technology, should drive a differentiated,
market-leading customer experience.
• We endeavour to mitigate the impact of this risk on
our wholesale business by sourcing competitively
priced fuel to operate our generation fleet and through
efficient operations optimising flexibility in our fuel,
transportation and generation portfolio.
• Origin actively monitors and participates in
technological developments through local and global
start-up accelerator programs, trialling new energy
technology and exploring investments in new products
or business models.
• In parallel, Origin is growing its distributed generation
and home energy services businesses. It is working
to mitigate the impact of this risk on its core energy
businesses by offering superior service and innovative
products and reducing cost to serve.
• Origin is partially mitigating the impact of this risk
by applying advanced data analytics capability to
smart meter data to better predict customer demand
and enable Origin to develop data-based customer
propositions.
• Our strategy of growing our gas reserves, increasing our
supply of renewables, and investing in new technology
supports Origin’s ability to meet future increases in
energy demand.
• Origin contributes to the policy process at federal, state
and territory governments by actively participating in
public policy debate, proactively engaging with policy
makers and participating in public forums, industry
associations, think tanks and research.
• Origin advocates directly with key members of
governments, opposition parties and bureaucrats
to achieve sound policy outcomes aligned with our
commercial objectives. Origin also makes formal
submissions to relevant government policy inquiries.
• Origin actively promotes the customer and economic
benefits publicly that flow from our activities in
deregulated energy markets.
Operating and Financial Review 42
Risk
Consequences
Management
Climate change
Climate change impacts many parts of Origin’s business.
• Our strategy for transitioning to a carbon–constrained
Key risks and opportunities include:
• those related to the transition to a low-carbon economy,
such as the ongoing decarbonisation of energy markets,
decreased demand for fossil fuels in some markets,
reduced lifespan of carbon-intensive assets, changes to
energy market dynamics caused by the intermittency of
renewables, changing government regulation and climate
change policy, and community demand for lower-carbon
sources of energy; and
• those related to the physical impact of a changing climate,
including the impact of changing weather patterns on
the demand for energy, and the resilience of our assets to
changing and more severe weather conditions.
There is also increased risk of climate change-related litigation
against Origin and/or regulatory bodies that grant licences
or approvals to Origin, which could potentially result in more
onerous licence/approval conditions, non-renewal of licences/
approvals or other adverse consequences.
future is focused on growth in renewables, gas
and cleaner, smarter customer solutions. For
Energy Markets, Origin has prepared for a range
of decarbonisation scenarios, including scenarios
consistent with the Paris Agreement’s goal of holding
the rise in global temperatures to a 50 per cent chance
of below 1.5°C.
• Origin has committed to significantly growing its
supply of renewable generation, including 1,200 MW
of committed large-scale solar and wind energy since
March 2016.
• Origin uses the flexibility in its gas supply and peaking
generation capacity to manage the intermittency of
renewables.
• Origin is using the framework recommended by the
Financial Stability Board’s Taskforce on Climate-related
Financial Disclosures (TCFD) for governance oversight
and reporting of our climate change risks.
• Origin has committed to science-based targets to halve
Scope 1 and 2 greenhouse gas emissions and reducing
value chain Scope 3 emissions8 by 25 per cent by 2032.
• Origin is planning to update its existing science-based
targets to a 1.5°C pathway with an aim to achieve net
zero emissions by 2050.
• Origin has committed to a new short-term emissions
target to reduce Scope 1 emissions by 10 per cent on
average over FY2021–23 from a FY2017 baseline.
Financial risks
Financial risks are the risks that directly impact the financial performance and resilience of Origin.
Risk
Consequences
Management
Commodity
Foreign exchange
and interest rates
Origin has a long-term exposure to international oil, LNG
and gas prices through the sale and purchase of domestic
gas, LNG and LPG, and its investment in APLNG. Pricing
can be volatile and downward price movements can impact
cash flow, financial performance, reserves and asset carrying
values. Some of Origin’s long-term domestic gas purchase
agreements and APLNG’s LNG sale agreements contain
periodic price reviews. Following each review, pricing may be
adjusted upwards or downwards, or it may remain unchanged.
Prices and volumes for electricity that Origin sources to on-sell
to customers are volatile and are influenced by many factors
that are difficult to predict. Long-term fluctuations in coal
and gas prices also impact the margins of Origin’s generation
portfolio.
Origin has exposures through principal debt and interest
payments associated with foreign currency and Australian
dollar borrowings, the sale and purchase of gas, LNG and LPG,
and through its investments in APLNG and the Company’s
other foreign operations. Interest rate and foreign exchange
movements could lead to a decrease in Australian dollar
revenues or increased payments in Australian dollar terms.
• Commodity exposure limits are set by the Board to
manage the overall financial exposure that Origin is
prepared to take.
• Origin’s commodity risk management process monitors
and reports performance against defined limits.
• Commodity price risk is managed through a
combination of physical positions and derivatives
contracts.
• For each periodic price review, a negotiation strategy
is developed, which takes into account external market
advice and uses both external and in-house expertise.
• Risk limits are set by the Board to manage the
overall exposure.
• Origin’s treasury risk management process monitors and
reports performance against defined limits.
• Foreign exchange and interest rate risks are managed
through a combination of physical positions and
derivatives.
Liquidity and access
to capital markets
Origin’s business, prospects and financial flexibility could be
adversely affected by a failure to appropriately manage its
liquidity position, or if markets are not available at the time of
any financing or refinancing requirement.
• Origin actively manages its liquidity position
through cash flow forecasting and maintenance of
minimum levels of liquidity as determined under
Board-approved limits.
Credit and
counterparty
Some counterparties may fail to fulfil their obligations (in
whole or part) under major contracts.
• Counterparty risk assessments are regularly undertaken
and, where appropriate, credit support is obtained to
manage counterparty risk.
8
Incurred within the domestic market; excluding LPG and corporate as their emissions are not material.
Annual Report 2020 43
Operational risks
Operational risks arise from inadequate or failed internal processes, people or systems, or from external events.
Risk
Consequences
Management
Safe and reliable
operations
Origin has exposure to reliability or major accident events
that may impact our licence to operate or financial prospects.
This includes loss of containment, cyber-attack and security
incidents, unsafe operations, and natural hazards, events that
may result in harm to our people, environmental damage,
additional costs, production loss, third-party impacts, and
impact to our reputation.
• Core operations are subject to a comprehensive
framework of controls and operational performance
monitoring to manage the design, operational and
technical integrity of our assets and associated
operational activities. Origin’s standards and controls
are designed to ensure we meet regulatory and industry
standards in all operations.
A production outage or constraint, network or IT systems
outage, would affect Origin’s ability to deliver electricity and
gas to its customers.
A serious incident or a prolonged outage may also damage
Origin’s financial prospects and reputation.
An environmental incident or Origin’s failure to consider and
adequately mitigate environmental, social and socio-economic
impacts on communities and the environment has the potential
to cause environmental impact, community action, regulatory
intervention, legal action, reduced access to resources
and markets, impacts to Origin’s reputation and increased
operating costs.
Community concerns regarding environmental and social
impacts associated with our activities may also give rise to
unrest among community stakeholder groups and activists,
which may impact the company’s reputation.
A third party’s actions may also result in delays in Origin
carrying out its approved development and operational
activities. NGOs, landholders, community members and
other affected parties can seek to prevent or delay Origin’s
activities through court litigation, preventing access to land and
extending approval pathway timeframes.
A cyber security incident could lead to a breach of privacy, loss
of and/or corruption of commercially sensitive data, and/or a
disruption of critical business processes. This may adversely
impact customers and the Company’s business activities.
Environmental
and social
Cyber security
APLNG gas reserves,
resources and
deliverability
There is uncertainty about the productivity, and therefore
economic viability, of resources and developed and
undeveloped reserves. As a result, there is a risk that actual
production may vary from that estimated, and in the longer
term, that there will be insufficient reserves to supply the full
duration and volumes to meet contractual commitments.
As at 30 June 2020, APLNG’s total resources are estimated
to be greater than its contractual supply commitments on a
volume basis. However, under certain scenarios of production
and deliverability of gas over time, there is a risk that the rate of
gas delivery required to meet APLNG’s committed gas supply
agreements may not be able to be met for the later years in the
life of existing contracts.
• Origin personnel are appropriately trained and licensed
to perform their operational activities.
• Origin maintains an extensive insurance program
to mitigate consequences by transferring financial
risk exposure to third parties, where commercially
appropriate.
• Origin engages with communities to understand,
mitigate and report on environmental and social risks
associated with its projects and operations.
• At a minimum, the management of environmental
and social risks meets regulatory requirements.
Where practical, their management extends to the
improvement of environmental values and the creation
of socio-economic benefits.
• A dedicated Board Committee oversees health, safety
and environment risk. The Committee receives regular
reporting of the highest-rated environmental risks
and mitigants, and reviews significant incidents and
near misses.
• Origin engages with its stakeholders prior to seeking
relevant approvals for its development and operational
activities, and this engagement continues through the
life of the project and during operations.
• A dedicated cyber risk team is responsible for
implementing a Board-approved cyber strategy and
continuously improving controls.
• External cyber security specialists are regularly
employed to assess our cyber security profile, including
penetration testing.
• Employees undertake compulsory cyber awareness
training, including how to identify phishing emails and
keep data safe; and are subject to a regular program of
random testing.
• APLNG employs established industry procedures to
identify and consider areas for exploration to mature
contingent and prospective resources.
• APLNG monitors reservoir performance and adjusts
development plans accordingly. APLNG continually
takes steps to further strengthen the supply base such
as lowering costs and identifying new plays.
• APLNG is progressing an exploration campaign that,
if successful, could increase long-term supply.
• APLNG continues to review business development
opportunities for long-term gas supply, and has the
ability to substitute gas or LNG to meet contractual
requirements if required.
Operating and Financial Review 44
Risk
Conduct
Consequences
Management
Unlawful, unethical or inappropriate conduct that falls
short of community expectations could result in penalties,
reputational/brand damage, loss of customers and adverse
financial impacts.
• Origin’s people are trained on the laws and regulations
that apply to their activities and operations, and on
the processes that underpin compliance with laws and
regulations.
Origin’s financial prospects and reputation/brand are
underpinned by complying with laws and other regulatory
obligations (such as privacy, competition and insider trading)
and meeting stakeholder commitments.
Joint venture
Third-party joint venture operators may have economic or
other business interests that are inconsistent with Origin’s own
and may take actions contrary to the Company’s objectives,
interests or standards. This may lead to potential financial,
reputational and environmental damage in the event of a
serious incident.
• Origin’s Purpose, Values, Behaviours and Code
of Conduct guide conduct and decision making
across Origin.
• All Origin’s people are trained every two years in Origin’s
Code of Conduct, and we conduct training for insider
trading, privacy, and competition and consumer law
every year.
• Conduct risk and compliance are identified as material
risks within Origin’s risk management framework and
are regularly reported to the Board Risk Committee.
Business units are accountable for controls specific to
the different parts of Origin’s business and are subject
to assurance activities, including Internal Audit.
• Origin applies a number of governance and
management standards across its various joint
venture interests to provide a consistent approach to
managing them.
• Origin actively monitors and participates in its joint
ventures through participation in their respective boards
and governance committees.
APLNG reversion
In 2002, APLNG acquired various CSG interests from Tri-Star that are subject to reversionary rights and an ongoing royalty in favour of
Tri-Star. If triggered, the reversionary rights require APLNG to transfer back to Tri-Star a 45 per cent interest in those CSG interests for no
additional consideration. The reversion trigger will occur when the revenue from the sale of petroleum from those CSG interests, plus any
other revenue derived from or in connection with those CSG interests, exceeds the aggregate of all expenditure relating to those CSG
interests plus interest on that expenditure, royalty payments and the original acquisition price.
The affected CSG interests represent approximately 19 per cent of APLNG’s 3P CSG reserves (as at 30 June 2020), and approximately
20 per cent of APLNG’s 2P CSG reserves (as at 30 June 2020).
Tri-Star served proceedings on APLNG in 2015 (‘reversion proceeding’) claiming that reversion occurred as early as 1 November 2008
following ConocoPhillips’ investment in APLNG, on the assertion that the equity subscription monies paid by ConocoPhillips, or a portion
of them, was revenue for purposes of the reversion trigger. Tri-Star has also claimed in the alternative that reversion occurred in 2011 or
2012 following Sinopec’s investment in APLNG. These claims are referred to in this document as Tri-Star’s ‘past reversion’ claims.
Tri-Star has made other claims in the reversion proceeding against APLNG including by a further amended statement of claim filed by
Tri-Star with the leave of the court in September 2019. These relate to other aspects of the reversion trigger (including as to the calculation
of interest, calculation of revenue and the nature and quantum of APLNG’s expenditures that can be included), the calculation of the
royalty payable by APLNG to Tri-Star, rights in respect of infrastructure, and claims relating to gas sold by APLNG following the alleged
reversion dates.
APLNG denies these claims and filed its initial defence and counter-claim in April 2016. APLNG filed its amended defence and counter-
claim (responding to Tri-Star’s September 2019 amended statement of claim) in May 2020.
If Tri-Star’s past reversion claims are successful, then Tri-Star may be entitled to an order that reversion occurred as early as 1 November
2008. If the court determines that reversion has occurred, then APLNG may no longer have access to the reserves and resources that
are subject to Tri-Star’s reversionary interests and may need to source alternative supplies of gas (including from third parties) to meet its
contracted commitments. There are also likely to be a number of further complex issues that would need to be resolved as a consequence
of any such finding in favour of Tri-Star. These matters will need to be determined by the court (either in the current or in separate
proceedings) or by agreement between the parties, and they include:
• the terms under which some of the affected CSG interests will be operated where currently there are no joint operating
agreements in place;
• the amount of Tri-Star’s contribution to the costs incurred by APLNG in exploring and developing the affected CSG interests
between the date of reversion and the date of judgment, which APLNG has stated in its defence and counter-claim are in the order of
$4.56 billion (as at 31 December 2019) if reversion occurred on 1 November 2008;
Annual Report 2020 45
• the consequences of APLNG having dealt with Tri-Star’s reversionary interests between the date of reversion and the date of judgment,
including the gas produced from them. Tri-Star has:
– estimated the value of such gas which it has been unable to take since the alleged reversion, calculated by reference to the sale of
gas as LNG and gas to domestic customers, to be approximately $3.37 billion (as at 31 March 2019) and approximately $1.3 billion
per annum thereafter. In the alternative, Tri-Star claims that the value of such gas should be assessed by reference to the revenue
derived by APLNG or its affiliates from LNG sales since the alleged reversion, being approximately $2.5 billion, (as at March 2019), or
$2.4 billion (as at March 2019) if the proceeds from sale of LNG is determined to be calculated net of liquefaction costs; and
– alleged that it should be paid the value of such gas or is otherwise entitled to set-off the value of such gas from any amount owing
to APLNG arising from APLNG’s counter-claim for contribution to the costs incurred by APLNG in exploring and developing the
affected CSG interests between the date of reversion and the date of judgment; and
•
if reversion occurred:
– the extent of the reversionary interests principally with respect to Tri-Star’s ownership and/or rights to use or access certain project
infrastructure; and
– the repayment by Tri-Star of the ongoing royalty which has been paid by APLNG since reversion, as a result of its mistake as to the
occurrence of the reversion trigger.
If APLNG is successful in defending Tri-Star’s past reversion claims in the reversion proceeding, the potential for reversion to otherwise
occur in the future in accordance with the reversion trigger will remain.
Tri-Star has also commenced proceedings against APLNG (‘markets proceeding’) which allege that APLNG breached three CSG joint
operating agreements by failing to offer Tri-Star (and the other minority participants in those agreements) an opportunity to participate
in the “markets” alleged to be constituted by certain of its LNG and domestic gas sales agreements, including the Sinopec and Kansai
LNG sale agreements entered into by APLNG in 2011 and 2012. Tri-Star has alleged that it should have been offered participation in those
sales agreements for its share of production from those three CSG joint ventures referable to both its small participating interests and its
reversionary interests in those joint ventures. Tri-Star is seeking, amongst other things, damages and/or an order that APLNG offer Tri-Star
(and the other minority participants in those CSG joint operating agreements) the opportunity to participate in those sales agreements for
their proportionate share of production from those three CSG joint ventures.
In September 2019, Tri-Star, with the leave of the court, filed a further amended statement of claim in the markets proceeding. Tri-Star has
in its amended statement of claim, sought additional relief in respect of:
• the nature and scope of the obligations of APLNG as operator pursuant to the CSG joint operating agreements;
• Tri-Star’s ownership and/or rights to use or access certain project infrastructure; and
• APLNG’s entitlement as operator to charge (both historically and in the future) certain categories of costs under the relevant CSG joint
operating agreements.
APLNG intends to defend the claims in both proceedings. APLNG filed its defence and counter-claim in the markets proceedings
(responding to Tri-Star’s September 2019 amended statement of claim) in April 2020.
Tri-Star is required to file its:
• amended reply and answer in the reversion proceeding by 30 November 2020; and
• reply and answer in the markets proceeding by 18 December 2020.
Once the pleadings have closed, the usual court process would involve a period of document disclosure, potentially court-ordered
mediation and then finally a hearing. The timing for each of these steps is difficult to predict at this stage. APLNG expects that the two
proceedings will be managed in parallel.
If APLNG is not successful in defending all or some of the claims being made in the proceedings by Tri-Star, APLNG’s financial
performance may be materially adversely impacted and the amount and timing of cash flows from APLNG to its shareholders, including
Origin, may be significantly affected.
Operating and Financial Review 46
8. Important information
Forward looking statements
This Operating and Financial Review (OFR) contains forward looking statements, including statements of current intention, statements of
opinion and predictions as to possible future events and future financial prospects. Such statements are not statements of fact and there
can be no certainty of outcome in relation to the matters to which the statements relate. Forward looking statements involve known and
unknown risks, uncertainties, assumptions and other important factors that could cause the actual outcomes to be materially different from
the events or results expressed or implied by such statements, and the outcomes are not all within the control of Origin. Statements about
past performance are not necessarily indicative of future performance.
Neither the Company nor any of its subsidiaries, affiliates and associated companies (or any of their respective officers, employees or
agents) (the ‘Relevant Persons’) makes any representation, assurance or guarantee as to the accuracy or likelihood of fulfilment of any
forward looking statement or any outcomes expressed or implied in any forward looking statement. The forward looking statements in
this OFR reflect views held only at the date of this report and except as required by applicable law or the ASX Listing Rules, the Relevant
Persons disclaim any obligation or undertaking to publicly update any forward looking statements, or discussion of future financial
prospects, whether as a result of new information or future events.
Non-IFRS financial measures
This OFR and Directors’ Report refers to Origin’s financial results, including Origin’s Statutory Profit and Underlying Profit. Origin’s Statutory
Profit contains a number of items that when excluded provide a different perspective on the financial and operational performance of
the business. Income Statement amounts, presented on an underlying basis such as Underlying Profit, are non-IFRS financial measures,
and exclude the impact of these items consistent with the manner in which senior management reviews the financial and operating
performance of the business. Each underlying measure disclosed has been adjusted to remove the impact of these items on a consistent
basis. A reconciliation and description of the items that contribute to the difference between Statutory Profit and Underlying Profit is
provided in Section 5.1 of this OFR.
Certain other non-IFRS financial measures are also included in this OFR. These non-IFRS financial measures are used internally by
management to assess the performance of Origin’s business and make decisions on allocation of resources. Further information
regarding the non-IFRS financial measures is included in the Glossary of this OFR. Non-IFRS financial measures have not been subject
to audit or review. Certain comparative amounts from the prior corresponding period have been re-presented to conform to the current
period’s presentation.
Annual Report 2020 47
Appendices
Appendix 1: FY2020 impact of leasing standard
AASB 16 Leases has been adopted from 1 July 2019. The effect of this standard is to bring Origin’s leases, primarily commercial offices,
LPG terminals, power-generating assets and fleet vehicles, on to the balance sheet.
A lease liability of $514 million and a right-of-use (ROU) asset of $467 million have been recognised in the balance sheet at 30 June 2020.
In the profit and loss, the ROU asset is depreciated and interest expense is recognised on the lease liability. Previously, lease payments
were expensed within Underlying EBITDA. In the cash flow, lease payments are recognised as financing cash flows, split between principal
and interest payments. Previously, lease payments were classified as operating cash flows.
Renewable power purchase agreement treatment
A net derivative liability of $512 million associated with Origin’s renewable PPAs, previously accounted for as financial instruments and
fair valued, has been judged to meet the lease definition under AASB 16 Leases and so has been declassified as a financial instrument.
However, due to the variable nature of the payments, the lease liability and ROU asset are recognised at nil value and payments continue
to be recognised as operating costs.
There has been no change to comparative information. Refer to the Overview section of the Origin Energy Financial Statements for further
information.
The table below removes the impact of AASB 16 Leases from Origin’s FY2020 Profit and Loss for comparative purposes.
FY20
reported
($m)
Lease adj.
($m)
FY20
excl. lease adj.
($m)
FY19
reported
($m)
Change
($m)
Change
(%)
Energy Markets
Integrated Gas – Share of APLNG
Integrated Gas – Other
Corporate
Underlying EBITDA
Underlying depreciation and
amortisation
Underlying share of ITDA
Underlying EBIT
Underlying interest income – MRCPS
Underlying net financing costs – Other
Underlying Profit before income tax
and non-controlling interests
Underlying income tax expense
Non-controlling interests’ share of
Underlying Profit
Underlying Profit
Operating cash flow
Investing cash flow
Financing cash flow
1,459
1,915
(174)
(59)
3,141
(509)
(1,303)
1,329
174
(300)
1,203
(177)
(3)
1,023
951
862
(2,118)
(62)(a)
(13)
(11)
(11)
(97)
80
22
5
–
18
22
(4)
–
18
91
–
(91)
1,397
1,902
(185)
(70)
3,044
(429)
(1,281)
1,334
174
(282)
1,225
(181)
(3)
1,574
2,123
(231)
(234)
3,232
(419)
(1,504)
1,308
226
(380)
1,154
(123)
(3)
1,041
1,028
(177)
(221)
46
164
(188)
(10)
223
26
(52)
98
71
(58)
–
13
1,042
862
(2,209)
1,325
589
(520)
(283)
273
(1,689)
(11)
(10)
(20)
(70)
(6)
2
(15)
2
(23)
(26)
6
47
–
1
(21)
46
325
(a) LPG ($30 million), cost to serve ($25 million), Solar and Energy Services ($3 million) and Electricity ($4 million).
Operating and Financial Review 48
Appendix 2: FY2020 dewatering and workover treatment – APLNG 100%
From 1 July 2019, APLNG dewatering and workover costs have been expensed rather than capitalised and amortised. Following a period
of embedding steady state operations, these costs are considered ongoing and operational in nature going forward, the change in
application of accounting practice reflects this. During commissioning of the project and in the lead up to steady state operations, these
amounts were capitalised as they represented costs incurred to bring the assets into their intended state of use.
From 1 July 2019, dewatering and workover costs are recognised in the Income Statement as operating expenses within Underlying
EBITDA. Previously, future downhole costs for dewatering and workovers were estimated and amortised on a units of production basis.
In the cash flow, dewatering and workover costs are recognised within operating cash flow, previously recognised as capital expenditure
within investing cash flows.
There has been no change to comparative information. The following table shows FY2019 profit and loss with the treatment change for
comparative purposes only.
FY20
reported
($m)
FY19
reported
($m)
Dewatering
workover
adjustment
($m)
FY19
adjusted
($m)
Change
($m)
Change
(%)
Commodity and other revenue
Operating expenses(a)
Underlying EBITDA
Depreciation and amortisation
Net financing costs
Income tax expense
7,100
(1,992)
5,108
(1,863)
(897)
(708)
7,443
(1,781)
5,662
(2,116)
(1,213)
(699)
Underlying ITDA from APLNG
(3,468)
(4,027)
Underlying Profit
1,640
1,635
Operating cash flow
Investing cash flow
Financing cash flow
5,242
(1,229)
(4,655)
5,536
(1,258)
(4,004)
–
(338)
(338)
406
–
(21)
385
47
(338)
338
–
7,443
(2,119)
5,324
(1,710)
(1,213)
(720)
(3,642)
1,682
5,198
(920)
(4,004)
(343)
127
(216)
(153)
316
12
174
(42)
44
(309)
(651)
(a) Adjustment comprises workover costs of $237 million and dewatering costs of $101 million in FY2019.
(5)
(6)
(4)
9
(26)
(2)
(5)
(2)
1
34
16
Annual Report 2020 Directors’
Report
For the year ended 30 June 2020
49
In accordance with the Corporations Act
2001 (Cth), the Directors of Origin Energy
Limited (Company) report on the Company
and the consolidated entity Origin Energy
Group (Origin), being the Company and
its controlled entities for the year ended
30 June 2020.
The Operating and Financial Review and
Remuneration Report form part of this
Directors’ Report.
1. Principal activities, review
of operations and significant
change in state of affairs
During the year, the principal activity
of Origin was the operation of energy
businesses including exploration and
production of natural gas, electricity
generation, wholesale and retail sale of
electricity and gas, and sale of liquefied
natural gas. There have been no significant
changes in the nature of those activities
during the year and no significant changes
in the state of affairs of the Company
during the year.
The Operating and Financial Review, which
forms part of this Directors’ Report, contains
a review of operations during the year and
the results of those operations, the financial
position of Origin, its business strategies,
and prospects for future financial years.
2. Events subsequent to
balance date
4. Directors and
Company Secretary
Other than the matters described below, no
matters or circumstances have arisen since
30 June 2020, which have significantly
affected, or may significantly affect, the
Company’s operations, the results of those
operations or the Company’s state of affairs
in future financial years.
The Directors of the Company at any time
during or since the end of the financial year,
their qualifications, experience and special
responsibilities are set out on page 8.
The qualifications and experience of the
Company Secretary is also set out below:
On 2 July 2020, the Group extended
$1.1 billion of bank debt facilities from a
FY2023 maturity date to a new maturity
date in FY2025. A further $0.2 billion of
surplus liquidity was cancelled as part of
this transaction.
Gordon Cairns
Independent Non-executive Chairman
John Akehurst
Independent Non-executive Director
Maxine Brenner
Independent Non-executive Director
On 20 August 2020, the Directors
determined a final dividend of 10 cents per
share, unfranked, on ordinary shares. The
dividend will be paid on 2 October 2020.
Frank Calabria
Managing Director and
Chief Executive Officer
3. Dividends
Teresa Engelhard
Independent Non-executive Director
a) Dividends paid during the year by the
Company were as follows
Greg Lalicker
Independent Non-executive Director
15 cents per ordinary share,
fully franked, for the half year
ended 31 December 2019,
paid 27 March 2020
$ million
264
Bruce Morgan
Independent Non-executive Director
Scott Perkins
Independent Non-executive Director
b) In respect of the current financial year,
the Directors have determined a final
dividend as follows:
10 cents per ordinary share,
unfranked, for the year ended
30 June 2020, payable
2 October 2020.
$ million
176
The Dividend Reinvestment Plan (DRP) will
apply to this final dividend at no discount.
Steven Sargent
Independent Non-executive Director
Helen Hardy
Company Secretary
Helen Hardy joined Origin in March 2010.
She was previously General Manager,
Company Secretariat of a large ASX-listed
company, and has advised on governance,
financial reporting and corporate law at
PwC and Freehills. Helen is a Chartered
Accountant, Chartered Secretary and a
Graduate Member of the Australian Institute
of Company Directors. Helen is a fellow of
the Governance Institute of Australia and is
the Chair of its NSW Council and a member
of its Legislative Review Committee
and Communication Committee. She
holds a Bachelor of Laws and a Bachelor
of Commerce from the University of
Melbourne, a Graduate Diploma in Applied
Corporate Governance and is admitted
to legal practice in New South Wales
and Victoria.
50
5. Directors’ meetings
The number of Directors’ meetings, including Board committee meetings, and the number of meetings attended by each Director during
the financial year, are shown in the table below:
Board meetings
Committee meetings
Scheduled
Additional
Audit
Health,
Safety and
Environment
(HSE)
Nomination
Remuneration
& People
Risk
Directors
J Akehurst
M Brenner
G Cairns
F Calabria
T Engelhard
G Lalicker
B Morgan
S Perkins
S Sargent
H
10
10
10
10
10
10
10
10
10
A
10
10
10
10
10
10
10
10
10
H
3
3
3
3
3
3
3
3
3
A
3
3
3
3
3
3
3
3
3
H
–
4
4
–
4
–
4
4
–
A
–
4
4
–
4
–
4
4
–
H
5
–
5
5
2
–
5
2
5
A
5
–
5
5
2
–
5
2
5
H
3
3
3
–
–
–
3
3
–
A
3
3
3
–
–
–
3
3
–
H
–
–
5
–
5
–
–
5
5
A
–
–
5
–
5
–
–
5
5
H
5
5
5
–
–
–
5
5
2
A
5
5
5
–
–
–
5
5
2
H
A
Number of scheduled meetings held during the time that the Director held office or was a member of the committee during the year.
Number of meetings attended.
The Board held 10 scheduled meetings, including a one-day strategic review meeting and three additional meetings to deal with urgent
matters. There were also four Board or Committee workshops to consider matters of particular relevance. In addition, the Board conducted
visits of Company operations at various sites and met with operational management during the year.
6. Directors’ interests in shares, Options and Rights
The relevant interests of each Director as at 30 June 2020 in the shares and Options or Rights over such instruments issued by the
companies within the consolidated entity and other related bodies corporate at the date of this report are as follows:
Director
G Cairns
F Calabria
J Akehurst
M Brenner
T Engelhard
G Lalicker
B Morgan
S Sargent
S Perkins
Ordinary shares held
directly and indirectly
Options over
ordinary shares
Deferred Share
Rights (DSR)
over ordinary shares
Performance Share Rights
(PSR) over ordinary shares
Restricted
shares
163,660
187,340
71,200
28,367
34,421
100,000
47,143
31,429
30,000
–
632,9951
–
–
–
–
–
–
–
–
110,7792
–
–
–
–
–
–
–
–
958,8722
–
–
–
–
–
–
–
–
249,9262
–
–
–
–
–
–
–
Exercise price for Options and Rights:
1 231,707: $5.67; 401,288: $7.37.
2 Nil.
No Director other than the Managing Director and Chief Executive Officer participates in the Company’s Equity Incentive Plan.
Securities granted by Origin
Non-executive Directors do not receive Options or Rights as part of their remuneration. The following securities were granted to the
five most highly remunerated officers (other than Directors) of the Company during the year ended 30 June 2020:
J Briskin
G Jarvis
M Schubert
L Tremaine
A Lucas
PSRs
125,762
134,146
134,146
167,682
119,055
Restricted
shares
46,689
164,370
52,275
95,090
53,035
Annual Report 2020
Directors' Report
51
Each of these awards was made in
accordance with the Company’s Equity
Incentive Plan as part of the relevant
executive’s remuneration. Further details
on Options and Rights granted during
the financial year, and unissued shares
under Options and Rights, are included in
Section 7 of the Remuneration Report.
No Options or Rights were granted since
the end of the financial year.
Origin shares issued on the exercise
of Options and Rights
Options
No Options granted under the Equity
Incentive Plan were exercised during or
since the year ended 30 June 2020, so
no ordinary shares in Origin were issued
as a result.
Rights
1,705,133 ordinary shares of Origin were
allocated from the Origin Energy Limited
Employee Share Trust during the year
ended 30 June 2020 on the vesting
and exercise of DSRs granted under the
Equity Incentive Plan. No amounts were
payable on the vesting of those DSRs and,
accordingly, no amounts remain unpaid in
respect of any of those shares.
Since 30 June 2020, 76,202 ordinary
shares were allocated from the Origin
Energy Limited Employee Share Trust on
the vesting of DSRs granted under the
Equity Incentive Plan.
All shares in the Origin Energy Limited
Employee Share Trust were purchased
on market.
7. Environmental regulation
and performance
The Company’s operations are subject
to environmental regulation under
Commonwealth, State, and Territory
legislation. For the year ended 30 June
2020, regulators were notified of a
total of 31 environmental reportable
non-compliances, including voluntary
notifications. Of these, two incidents
resulted in environmental impacts with
a moderate short-term impact to the
environment. All other environmental
incidents had a minor consequence
and were appropriately investigated. In
FY2020, the Company received two formal
environmental notices from a regulator
arising from Origin’s activities. One of these
notices resulted in a $15,000 fine for an
infringement at the Eraring Power Station
within the Energy Markets generation
business. The other notice related to a
$431 fine for a late submission of an annual
return. Remedial actions have been taken
or are being undertaken in response to
the incidents and notices. All incidents are
investigated, and lessons learned captured
and shared across the Company.
Our Integrated Gas business is currently
being investigated by the Queensland
Department of Environment and Science
for a coal seam gas residue release at our
Ramyard and Woleebee sites in early 2020.
Clean-up notices were issued in FY2021 but
there have been no enforcement actions
issued at the time of this Report. Origin is
currently working with the regulator on the
remediation activities.
8. Indemnities and insurance
for Directors and Officers
Under its Constitution, the Company may
indemnify current and past Directors and
Officers for losses or liabilities incurred
by them as a Director or Officer of the
Company or its related bodies corporate
to the extent allowed under law. The
Constitution also permits the Company
to purchase and maintain a Directors’ and
Officers’ insurance policy. No indemnity has
been granted to an auditor of the Company
in their capacity as auditor of the Company.
The Company has entered into agreements
with current Directors and certain former
Directors whereby it will indemnify those
Directors from all losses or liabilities in
accordance with the terms of, and subject
to the limits set by, the Constitution.
The agreements stipulate that the Company
will meet the full amount of any such
liability, including costs and expenses to the
extent allowed under law. The Company
is not aware of any liability having arisen,
and no claim has been made against the
Company during or since the year ended
30 June 2020 under these agreements.
During the year, the Company has paid
insurance premiums in respect of Directors’
and Officers’ liability, and legal expense
insurance contracts for the year ended
30 June 2020.
The insurance contracts insure against
certain liability (subject to exclusions) of
persons who are or have been Directors or
Officers of the Company and its controlled
entities. A condition of the contracts is that
the nature of the liability indemnified and
the premium payable not be disclosed.
10. Non-audit services
The amounts paid or payable to EY for
non-audit services provided during the
year was $1,075,000 (shown to the nearest
thousand dollars). Amounts paid to EY are
included in note G7 to the full financial
statements.
Based on written advice received from
the Audit Committee Chairman pursuant
to a resolution passed by the Audit
Committee, the Board has formed the
view that the provision of those non-audit
services by EY is compatible with, and did
not compromise, the general standards
of independence for auditors imposed
by the Corporations Act 2001 (Cth). The
Board’s reasons for concluding that the
non-audit services provided by EY did not
compromise its independence are:
• all non-audit services provided were
subjected to the Company’s corporate
governance procedures and were either
below the pre-approved limits imposed
by the Audit Committee or separately
approved by the Audit Committee;
• all non-audit services provided did
not, and do not, undermine the
general principles relating to auditor
independence as they did not involve
reviewing or auditing the auditor’s
own work, acting in a management
or decision making capacity for the
Company, acting as an advocate for the
Company or jointly sharing risks and
rewards; and
• there were no known conflict of interest
situations nor any other circumstance
arising out of a relationship between
Origin (including its Directors and
Officers) and EY which may impact on
auditor independence.
11. Proceedings on behalf of
the Company
The Company is not aware of any
proceedings being brought on behalf of
the Company, nor any applications having
been made in respect of the Company
under section 237 of the Corporations Act
2001 (Cth).
9. Auditor independence
12. Rounding of amounts
There is no former partner or director of
EY, the Company’s auditors, who is or
was at any time during the year ended
30 June 2020 an officer of the Origin
Energy Group. The auditor’s independence
declaration for the financial year (made
under section 307C of the Corporations
Act 2001 (Cth)) is attached to and forms
part of this Report.
The Company is of a kind referred to in
ASIC Corporations (Rounding in Financial/
Directors’ Reports) Instrument 2016/191
dated 24 March 2016 and, in accordance
with that class order, amounts in the
financial report and Directors’ Report have
been rounded off to the nearest million
dollars unless otherwise stated.
13. Remuneration
The Remuneration Report forms part of this
Directors’ Report.
52
Remuneration
Report
For the year ended 30 June 2020
The Remuneration Report (Report) for the year ended 30 June 2020 (FY2020) forms part of the Directors’ Report. It has been prepared
in accordance with the Corporations Act 2001 (Cth) (the Act) and accounting standards, and audited as required by section 308(3C)
of the Act.
Letter from the Chairman of the Remuneration and People Committee
On behalf of the Remuneration and People Committee (RPC) and the Board, I am pleased to present the
Remuneration Report for FY2020.
Given the challenging economic and business
circumstances, the annual remuneration review – which
would have been conducted at the end of FY2020 for
employees generally, as well as Executive KMP – was
deferred on a Company-wide basis.
FY2020 remuneration framework
There were no changes to the basic architecture of the
remuneration framework during the year. We:
• strengthened and formalised processes that ensure
alignment with our purpose, strategy, values and
behaviours, enhancing the behavioural assessment
mechanism to bring additional rigour to the process
for modifying STI scorecard outcomes, up or down,
based on the individual’s approach and behaviour;
• reweighted STI metrics towards those influenced by
management, which align with long-term decision
making and lead to increased shareholder value (see
Section 4.2 for details);
• ensured financial and non-financial risks were
systematically considered in the overall assessment of
STI outcomes; and
• took into account formal feedback from the Chairs of
the Health, Safety and Environment (HSE), Risk, Audit
and RPC committees in determining and approving
final performance outcomes for Executive KMP.
There were no changes to the structure of
Non-executive Director (NED) fees.
FY2020 remuneration outcomes
Remuneration outcomes for FY2020 reflected a
continued improvement in operational performance
notwithstanding the challenging external
environment due to the COVID-19 pandemic and its
associated economic impacts, including a decline in
commodity prices.
The Short Term Incentive (STI) scorecard outcomes
for the year reflected above-target results and in
some metrics approached stretch targets. The Chief
Executive Officer’s (CEO’s) STI outcome was 83.5 per
cent of maximum (FY2019: 68.2 per cent) and the
aggregate STI outcome for Executive Key Management
Personnel (KMP) was 84.1 per cent of maximum
(FY2019: 73.7 per cent).
No awards vested under the Long Term Incentive (LTI)
Plan during the year. A partial vesting of FY2017 LTI
awards is expected in FY2021.
When STI targets were set at the beginning of
FY2020, the Company could not have foreseen
the challenges that arose from a severe bushfire
season and the COVID-19 pandemic. Yet the targets
were met or exceeded even as the Executive team
managed a rapid and effective response, maintaining
energy supplies and supporting impacted customers;
safeguarding employees and communities; and working
collaboratively with all levels of government to support
policy objectives.
During these challenges, our Executive team was
not distracted from achieving strong operational
performance. Our Engagement Score rose to the top
quartile with a record high result of 75. Safety outcomes
improved by 40 per cent as measured by the Total
Recordable Injury Frequency Rate (TRIFR). Our people’s
safety is our primary focus and we continue to strive
for zero harm. Over the year, we also recorded our
highest-ever customer Strategic Net Promoter Score
(sNPS) and reputation (RepTrak) measures. All areas of
STI performance exceeded expectations and enabled
Origin to maintain its dividends for shareholders.
Annual Report 2020 53
FY2020 remuneration levels
As foreshadowed in the 2019 Remuneration Report,
increases in Executive KMP Fixed Remuneration (FR)
at the beginning of FY2020 averaged 1.9 per cent
compared with approximately 2.4 per cent for the
broader organisation.
During FY2020, we reviewed benchmarking for our
three operational Executive General Managers (EGM
Energy Supply & Operations, EGM Integrated Gas
and EGM Retail) to reflect changes in the scope and
complexity of their roles. Our policy is to have key
talent remunerated at the median of comparable
roles after three years, subject to performance. The
final phase of that process was completed during the
year, incorporating the revised benchmarking, and
all Executive KMP – except the CEO, see below – are
now remunerated in line with this policy. Some of the
Executive KMP moved to a 60 per cent STI deferral level
during the year.
There were no changes to the policy for NED fees
for FY2020.
FY2021 remuneration
As noted, the Company’s general annual remuneration
review due to be conducted at the end of FY2020
was deferred, and no standard uplifts will occur early
in FY2021 for employees generally or for the CEO or
Executive KMP.
In the normal course of events, the Board would have
considered adjusting the CEO’s remuneration for
FY2021 in order to close the policy gap referred to
above. However, the CEO asked, and the Board has
agreed, to defer consideration of his remuneration for
another year. The Board considered this request very
carefully in the light of the CEO’s strong performance
and the Board’s commitment to remunerating in line
with policy and agreed that, in the context of the
broader deferral of remuneration reviews and the
uncertain external environment, it was appropriate to
defer the review until FY2022.
The Board, in consultation with its external advisor,
undertook a comprehensive assessment of the
remuneration framework during FY2020, with a
specific focus on ensuring that the LTI Plan (LTIP)
structure is fit for purpose. There is increasing concern
the LTIP is not adequately achieving its objectives
of attracting executive talent, retaining key leaders,
aligning with shareholders’ interests and contributing
to the generation of executive share ownership. The
review concluded that the LTIP is not well suited to
the commodity nature or investment profile of the
energy industry, and that organisations facing similar
business contexts in Australia and the UK have been
adopting superior plans. Origin is particularly impacted
by rapidly changing market and operating conditions
because it has exposures to these issues in upstream
and downstream businesses, unlike most organisations
domestically or internationally. Furthermore, the
review concluded that our current LTIP is failing to
adequately achieve any of its objectives in terms of
attracting, retaining or generating executive share
ownership. During FY2020, the Board implemented
special arrangements to secure and retain key talent,
which would not have been necessary if the LTIP had
been fit for purpose. To date, no Executive who had
commenced with the Company in the last decade
had received any shares through the LTIP mechanism,
posing a fundamental challenge to the objective of
building share ownership.
The Board considers that Long Term Share Plan (LTSP)
models based around Restricted Shares with longer
deferral periods are better suited to our business and
has been evaluating the opportunities to move in this
direction. I look forward to sharing our conclusions in
due course.
Finally, there will be no changes to the structure or level
of NED fees for FY2021.
Steven Sargent
Chairman, Remuneration and People Committee
Remuneration Report 54
Report structure
The report is divided into the following sections:
1 Key Management Personnel
2 Remuneration link with Company performance and strategy
3 Remuneration framework details
4 Company performance and remuneration outcomes
5 Governance
6 Non-executive Director fees
7 Statutory tables and disclosures
1. Key Management Personnel
The report discloses the remuneration arrangements and outcomes for people listed below: individuals who have been determined as Key
Management Personnel (KMP) as defined by AASB 124 Related Party Disclosures. Members of the RPC are identified in the last column.
Name
Role
Appointment
RPC
d
r
a
o
B
G Cairns
J Akehurst
M Brenner
T Engelhard
G Lalicker
B Morgan
S Perkins*
S Sargent*
F Calabria
L Tremaine
J Briskin
G Jarvis
e
v
i
t
u
c
e
x
e
-
n
o
N
e
v
i
t
u
c
e
x
E
Chairman, independent
Independent
Independent
Independent
Independent
Independent
Independent
Independent
Chief Executive Officer
Chief Financial Officer
23 October 2013
29 April 2009
15 November 2013
1 May 2017
1 March 2019
16 November 2012
1 September 2015
29 May 2015
19 October 2016
10 July 2017
✓
✓
✓
Chair
Executive General Manager (EGM), Retail
5 December 2016
EGM Energy Supply & Operations
5 December 2016
M Schubert
EGM Integrated Gas
1 May 2017
* Scott Perkins was Chair of the RPC until 31 December 2019; Steven Sargent became RPC Chair from 1 January 2020. Steven is also Chair of the Origin Energy Foundation.
The term ‘Other Executive KMP’ (abbreviated as ‘Other’ in tables and charts) refers to Executive KMP excluding the CEO.
‘Executive team’ is a broader reference to the Executive Leadership Team (ELT).
Annual Report 2020
55
2. Remuneration link with Company performance and strategy
2.1 Overview of remuneration framework
Our remuneration framework is designed to support the Company’s strategy and to reward our people for its successful execution. It is
designed around three principles, summarised in the diagram below.
Strategy
Connecting customers to the energy and technologies of the future
Leading customer experience and solutions; accelerating towards clean energy; embracing a decentralised and digital future; striving to be a
low-cost operator; developing resources to meet growing gas demand; and maintaining disciplined capital management.
Remuneration principles
Attract and retain the right people
Pay fairly
Drive focus and discretionary effort
The framework secures high-calibre
individuals from diverse backgrounds
and industries, with the talent to
execute the strategy.
The framework is market competitive.
Outcomes are a function of Company
performance, reflect our behavioural
expectations and our values, and align
with shareholder expectations.
The framework encourages Executives to
think and act like owners and to deliver against
long-term strategies and the short-term
business priorities that are expected to drive
long-term outcomes.
Element
Performance measures
Link to principles and strategy
Remuneration framework
Fixed Remuneration (FR)
Comprises cash salary, superannuation
and benefits.
Details in Section 3.1
Variable Remuneration (VR)
The majority of remuneration is variable
and delivered in deferred equity to
reward performance and to align
Executive and shareholder interests.
Details in Sections 3.2 and 3.6
Short Term Incentive (STI)
Annual incentive opportunity,
40–50 per cent paid in cash,
50–60 per cent paid in shares
restricted for two years.
Details in Sections 3.3 and 3.5
Long Term Incentive (LTI)
Granted as performance share
rights allocated at face value.
These vest at three years and are
deferred for a total of four years.
Details in Sections 3.4 and 3.5
Determined by the scope of the role and
its responsibilities and benchmarked
annually against similar roles.
Set at competitive levels to attract and retain
the right people and to pay fairly.
Performance targets set one year
in advance across a balanced
scorecard (generally 60–65 per cent
financial metrics and 35–40 per cent
non-financial metrics) with an overriding
conduct/behaviour assessment.
Annual targets to drive execution of business
plans: financial performance, operating
efficiency, customer experience, safety,
and measures supporting the attraction and
retention of the right people.
Performance targets set three
years in advance, using an internal
measure (Origin’s Return on Capital
Employed (ROCE)) and an external
measure (Origin’s relative total
shareholder return).
Designed to encourage long-term focus, and
build and retain share ownership.
Remuneration Report 56
2.2 Behavioural assessment
Origin believes that observance of our values and behaviours and the quality of the relationships with our customers and the broader
community are inextricably linked to the creation of shareholder value.
A formal behavioural assessment forms part of our performance management framework. It is based on the Behaviourally Anchored
Rating Scale (BARS) methodology that assesses an individual’s performance against specific examples of behaviour required for different
roles and levels, rather than against generic descriptors. This adds qualitative and quantitative information into the appraisal process. The
behavioural assessment can result in incentive outcomes being adjusted up or down, within the prescribed maximum amount.
2.3 Minimum shareholding requirement for Executive KMP
A key objective of the remuneration framework is to promote employee share ownership and to encourage employees to think and act
as owners. Equity is therefore a key element of remuneration, representing at least half of STI awards and the whole of LTI awards. This is
supplemented by other share plan arrangements, including salary sacrifice, share purchase and matching plans (see Section 3.7).
Executive KMP are required to build and maintain a minimum shareholding in the Company, defined as the equivalent of two times FR
for the CEO, and as FR for Other Executive KMP. From time to time, the Board determines the minimum shareholding requirement (MSR)
as a number of shares based on FR and share price.1 The MSR is currently set at 620,000 shares for the CEO and 130,000 for Other
Executive KMP.
Until the MSR is reached, disposals are prohibited except as reasonably required to meet Employee Share Scheme taxation liabilities.
Once the MSR is reached, disposals are prohibited where they would take the holding below the MSR level, except in extraordinary
circumstances approved by the Board. The governance mechanism is through trading restrictions over and above any other trading
restrictions that apply.
Shares (restricted and unrestricted) and Deferred Share Rights (DSR) (without performance conditions) may be counted towards the MSR,
but rights that are subject to performance conditions (including Performance Share Rights) may not be counted.
3. Remuneration framework details
3.1 Fixed Remuneration
FR comprises cash salary, employer contributions to superannuation and salary sacrifice benefits. It takes into account the size and
complexity of the role, and the skills and experience required for success in the role.
FR is reviewed annually, but increases are not guaranteed. Roles are benchmarked to the median of corresponding roles in the reference
market, currently made up of approximately 50 organisations listed on the Australian Securities Exchange (ASX).2 In the absence of special
factors, new or newly promoted incumbents generally commence below this reference point and move to the median over time. FR may
be positioned above this reference point where it is appropriate for key talent retention purposes or where it is necessary to attract and
secure key skills to fill a business-critical role. Accordingly, the median positioning may vary between approximately the 40th and 60th
percentiles (P40 and P60) of the reference market.
3.2 Total Remuneration
Total Remuneration (TR) is the sum of FR and VR. The range of possible VR values is from nil for no award of STI or LTI to a maximum of the
total of STI awarded at the maximum level plus the present-day values of the full face value of the LTI award, assuming that 100 per cent of
the LTI award will vest.
Deferred equity elements (Deferred STI, and LTI) represent present-day values as it is not possible to predict future share prices, which can
reduce or increase the ultimate value.
TR at target (TRT) includes an STI awarded at the target level (see Section 3.3) plus the present-day full face value of the LTI award,
assuming that 50 per cent of the LTI will vest, being the ‘risked expected value’ of Origin’s LTI awards (as detailed in Section 3.4).
TR minimum
TRT
TR maximum (TRM)
=
=
=
FR
FR
FR
+
+
+
No STI awarded
STI awarded at the target level
STI awarded at the maximum level
+
+
+
No LTI awarded
Full face value awarded; assumes that
50 per cent of the LTI will vest
Full face value awarded; assumes that
100 per cent of the LTI will vest
TRT is benchmarked to the median of equivalent TRT in the reference market, and the remuneration ‘mix’ (see Section 3.6) makes it
possible for TRM (outcomes at their maximum) to achieve the top quartile in the TRT reference market.
1 Generally considering the weighted average share price over the prior year.
2 By way of a guideline, these 50 organisations are the largest by average market capitalisation over two years, after excluding the six largest, Macquarie Group, and those
of foreign domicile, and always including AGL, Oil Search, Santos and Woodside.
Annual Report 2020 57
3.3 FY2020 Short Term Incentive Plan details
The following is a detailed description of how the STI Plan (STIP) operates.
Parameter
Details
Award basis
The annual performance cycle is 1 July to 30 June. Individual balanced scorecards are agreed, with shared Group objectives
and targeted divisional objectives. Objectives are set across financial categories (generally 60 to 65 per cent of the
weightings) and non-financial categories (generally 35 to 40 per cent). The CEO’s FY2020 scorecard details and outcomes
are shown in Section 4.2.
Scorecard operation
Individual objectives on the scorecard are referenced to three performance levels: threshold, target and stretch (with pro-
rating between each).
Threshold performance represents the lower limit of rewardable outcome for an individual objective – one that represents
a satisfactory outcome, often achieving year-on-year improvement and contribution towards delivery of annual plans but
short of the target level. Threshold performance corresponds to 20 per cent of maximum (33 per cent of target).
Target represents the expectation for achieving robust annual plans.
Stretch performance represents the delivery of exceptional outcomes well above expectations (the maximum,
corresponding to 167 per cent of target).
) Maximum 100%
m
u
m
i
x
a
m
Target 60%
f
o
%
(
t
l
u
s
e
R
Threshold 20%
Minimum 0%
Threshold
Target
Stretch
Increasing performance level →
167%
100%
33%
)
t
e
g
r
a
t
f
o
%
(
t
l
u
s
e
R
Opportunity level
The opportunity level for all Executive KMP was set to a standard for FY2020,
with 100 per cent FR at target and a maximum of 167 per cent FR.
FY20 STI opportunity (% of FR)
Minimum
Target
Maximum
0
100
167
Award calculation
STIP award
($)
=
$ FR
(at 30 June)
✕
STIP
opportunity
(% of FR)
✕
Balanced
scorecard
outcome
(% )
↑
Discretionary modifier
incorporating
behavioural
assessment
Assessment
Achievement and performance against each Executive’s balanced scorecard is assessed annually as part of the Company’s
broader performance review process.
The review includes a behavioural assessment under the BARS methodology (see Section 2.2). Directors consider this
assessment together with a broader consideration of how outcomes have been achieved, including regulatory compliance,
and financial and non-financial risk management. This may lead to a modification of the formulaic scorecard outcome,
downward or upward, with the opportunity maximum operating as a cap.
Remuneration Report
58
Parameter
Details
Delivery and timing
40 to 50 per cent cash, paid in August to September following the end of the financial year.
50 to 60 per cent awarded in the form of Restricted Shares (RS) subject to a two-year holding lock, allocated as soon as
practicable after Board approval, which is generally at the end of August following the end of the financial year.
Prior to FY2018, Deferred STI was awarded in the form of DSRs.
RS allocation
Number of RSs = Deferred STI amount divided by the 30-day volume weighted average price (VWAP) to 30 June, rounded
to the nearest whole number.
Service conditions
Unless the Board determines otherwise, the whole of the STI award is forfeited if the Executive resigns or is dismissed for
cause during the performance year, and any RSs held from prior awards are also forfeited if in their restriction period.
Release
RSs in respect of FY2020 STI awards will be released on the second trading day following the release of full-year financial
results for FY2022, subject to the service conditions being met and the service period completed (or else as described
under ‘Cessation of employment’ below).
Dividends
As the STI has been earned and awarded, RSs carry dividend entitlements and voting rights.
Cessation of
employment
No STI award is made where the service conditions have not been met in full, except where the Board decides otherwise.
Typically such cases are limited to death, disability, redundancy or genuine retirement (good leaver circumstances). In such
circumstances an STI award in respect of the current year may be wholly in cash, and restrictions on prior RSs may be lifted.
Sourcing of RSs
The Board’s practice is to purchase shares on market but it may issue shares or make the award in alternative forms,
including cash or deferred cash.
Governance and MSR After restrictions on RSs are lifted, trading is subject to the MSR (see Section 2.3) and to the malus and clawback provisions
in Section 5.5.
3.4 FY2020 Long Term Incentive Plan details
The following is a detailed description of how the LTIP operates.
Parameter
Award basis
Details
LTIP awards are conditional grants of equity that may vest in the future, subject to the Company meeting or exceeding
performance conditions, and subject also to the Executive meeting service and personal conduct and performance
requirements. Awards are considered annually.
Opportunity and
value range
The LTIP opportunity level reflects the capacity of the role to influence long-term sustainable growth and performance,
and is set with reference to market benchmarks (see Section 3.2). It represents the face value of an equity award and is not
discounted for hurdles or for dividends forgone.
An award may be granted at a face value anywhere between zero and the maximum in the table below (the Award
Face Value).
Executive KMP
CEO
Other
Face value LTIP opportunity (% of FR)
Minimum
Maximum
0
0
180
120
The actual value of an LTIP award depends on the level of vesting and the share price at the time of vesting, neither of which
can be determined in advance.
The minimum value is zero assuming that none of the award vests, or none is awarded.
The maximum value represents the present-day value assuming that 100 per cent of the award vests, ignoring the risks of
achieving performance conditions and service requirements.
The target value represents the risked or expected value, taking into account the likelihood of achieving the performance
conditions. For market-based hurdles, such as Total Shareholder Return (TSR), this can be obtained actuarially. For
non-market hurdles, it can be obtained from operational forecasts and estimation of the degree of difficulty in achieving
the hurdles, or sometimes from historical results. Origin has determined its vesting expectation is approximately 50 per cent
for both its relative TSR and ROCE conditions.3
Behaviour assessment The RPC may take the behaviour assessment referred to in Section 3.3 into account when recommending LTIP awards, or
when considering the application of the governance provisions to awards made (see Section 5.5).
3 Expected vesting is a function of the probabilities of achieving each of all possible outcomes. It is typically lower than, and should not be confused with, the probability of
any vest occurring.
Annual Report 2020 59
Parameter
Details
Delivery and timing
Performance Share Rights (PSRs): A PSR is a right to a fully paid ordinary share in the Company. PSRs are granted at no cost
because they are awarded as remuneration.
CEO: The LTIP award is submitted for approval at the Annual General Meeting (AGM) following the end of the financial year,
and the equity grant is made as soon as practicable after shareholder approval.
Other Executive KMP: LTIP grants are made as soon as practicable after Board approval, which is generally at the end of
August following the end of the financial year.
PSR allocation
Number of PSRs = LTIP Award Face Value divided by the 30-day VWAP to 30 June, rounded to the nearest whole number.
Performance period
and deferral length
The performance period is three financial years (FY2020–22) which, subject to vesting, is followed by a holding lock of one
year. The lock on any vested shares will be lifted in August 2023, on the second trading day after the release of the FY2023
full-year results. The total deferral period from grant is approximately four years.
Service conditions
Unless the Board determines otherwise, unvested PSRs are forfeited if the Executive resigns or is dismissed for cause prior
to the end of the relevant vesting period.
Performance
conditions
There are two performance conditions, equally weighted.4 One, Relative Total Shareholder Return (RTSR), is an external
hurdle; the other, ROCE, is an internal hurdle.
External performance
condition and vesting
RTSR measures the Company’s TSR performance relative to a reference group of companies assuming reinvestment of
dividends.
It has been chosen because it aligns Executive reward with shareholder returns. It does not reward general market uplifts;
vesting only occurs when Origin outperforms a market reference group. The reference group is based on a group of 50
ASX-listed companies because this represents the most meaningful group with which Origin competes for shareholder
investment and Executive talent.5 There is an insufficient number of operationally similar competitors to provide a useful
‘selected’ comparator group.
Share prices are determined using three-month VWAPs on the start and end of the performance period.
Vesting occurs only if Origin’s TSR over the performance period ranks it higher than the 50th percentile (P50) of the
reference group. Half of the PSRs vest on satisfying that condition, and all of the PSRs vest if Origin ranks at or above the
75th percentile (P75). Straight-line pro-rata vesting applies between these two points.
Internal performance
condition and vesting
ROCE has been chosen because it is a profitability ratio that measures the efficiency of profit generation from capital
employed. It predicts superior shareholder returns over the long term and reflects the importance of prudent capital
allocation to generate sufficient returns.
The ROCE tranche is divided into two equally weighted parts, each its own hurdle – Energy Markets (EM) and Integrated
Gas (IG) – recognising the differing capital characteristics, risk profiles and growth profiles of each of these businesses. The
average ROCE over three years must equal or exceed the average of three annual targets, which are reflective of delivering
the weighted average cost of capital for each business.
The starting point for the ROCE calculation is statutory earnings before interest and tax (EBIT) divided by average capital
employed for the relevant business. Statutory EBIT is adjusted for fair value and foreign exchange movements in financial
instruments, which are highly volatile and outside the control of management. Other adjustments to the ROCE calculation
may be made in limited circumstances where the Board considers it appropriate to do so. For example, it may be
appropriate to adjust EBIT when it is adversely impacted by short-term factors associated with value-creating initiatives (for
example, acquisitions).
Vesting is independent for the EM and IG parts. In each case, half of the relevant PSRs will vest if the target is met, and all of
the relevant PSRs will vest if the target is exceeded by two percentage points or more. Straight-line pro-rata vesting applies
between these two points. Full vesting occurs only when both targets are exceeded by two percentage points or more.
Dividends
PSRs carry no dividend entitlements or voting rights. Vested shares (including RSs) carry dividend entitlements and
voting rights.
Cessation of
employment
Unvested LTIP awards will lapse on the date of cessation, unless the Board determines otherwise. Typically such cases are
limited to death, disability, redundancy or genuine retirement (good leaver circumstances).
In such circumstances, LTIP awards may be held on foot subject to their original performance conditions and other terms
and conditions being met (except for the waived service condition), or dealt with in an appropriate manner as determined
by the Board. The restriction on vested shares may be lifted at the date of cessation in good leaver circumstances.
Sourcing
Upon vesting of a part or all of an LTIP award, the Board’s preferred approach is to purchase shares on market, but it may
issue shares or make the award in alternative forms, including cash or deferred cash.
Governance and MSR After restrictions are lifted on RSs arising from LTIP vesting, trading is subject to the MSR (see Section 2.3) and to the malus
and clawback provisions in Section 5.5.
4 Where the number of PSRs to be allocated is an uneven number, the number allocated to the ROCE tranche is rounded to the nearest even number, and the balance of
PSRs is allocated to the RTSR tranche.
5 The reference group is set at the commencement of the performance period. For FY2020, it comprised AGL, Amcor, AMP, Ampol (Caltex), ANZ, APA Group, Aristocrat
Leisure, ASX Limited, Aurizon, BHP, Brambles, Cochlear, Coles, Commonwealth Bank of Australia, Computershare, CSL Limited, Dexus, Fortescue, Goodman Group, GPT
Group, IAG, James Hardie, Lendlease, Macquarie, Medibank Private, Mirvac, National Australia Bank, Newcrest, Oil Search, Qantas, QBE, Ramsay Health Care, Rio Tinto,
Santos, Scentre Group, Sonic Healthcare, South32, Stockland, Suncorp, Sydney Airport, Tabcorp, Telstra, Transurban, Treasury Wine Estates, Vicinity Centres, Wesfarmers,
Westpac Banking Corporation, Woodside and Woolworths. Companies are not replaced (for example, as a consequence of merger, acquisition or delisting) unless the
Board determines otherwise.
Remuneration Report 60
3.5 Remuneration cycle timelines
The following chart summarises the remuneration cycle and timelines.
FY2020
Jul
2020
Oct
2020
Aug
2021
Aug
2022
Aug
2023
Aug
2024
Aug
2025
→
Fixed remuneration
paid through year
1 July 2019–
30 June 2020
STIP
performance against
annual targets
→ Cash
40–50%
1 July 2019–
30 June 2020
→
Deferred STI
50–60%
Restricted
Shares
allocated
LTIP
3-year
performance hurdles
LTIP allocation
confirmed;
performance
period starts
Performance
Share Rights
granted
Release after 2 years
MSR
Vest after 3 years
Holding lock
MSR
3.6 Remuneration range and mix
The following chart shows the potential remuneration range and corresponding component mix for FY2020.
FR
STI cash
Deferred STI
LTI
CEO
100%
Minimum
Other*
100%
CEO
34.5%
17.2%
17.2%
31.0%
Other*
38.4% 17.3% 21.2% 23.1%
CEO
22.4%
18.7%
18.7%
40.2%
Target
Maximum
Other*
25.8%
19.4%
23.8%
31.0%
*The average of Other Executive KMP.
TR
($’000)
1,831
939
5,310
2,442
8,185
3,635
Deferred equity (Deferred STI plus LTI) makes up a substantial part of TR. At target outcomes, it comprises almost half
(CEO: 48.2 per cent; Other Executive KMP: 44.2 per cent) and at maximum outcomes it is more than half (CEO: 58.9 per cent;
Other Executive KMP: 54.7 per cent).
3.7 Other equity/share plans
The Company operates a universal Employee Share Plan in which all full-time and part-time employees can choose to be eligible for
awards of up to $1,000 worth of Company shares annually, or else participate in a salary sacrifice scheme to purchase up to $4,800 of
shares annually.
Under the $1,000 scheme, shares are restricted for three years or until cessation of employment, whichever occurs first. Shares purchased
under the sacrifice scheme are restricted for up to two years or until cessation of employment, whichever occurs first.
For every two shares purchased under the salary sacrifice scheme within a 12-month cycle, participants are granted one matching share
right at no cost. The matching share rights vest two years after the cycle began, provided that the participant remains employed by the
Company at this time. Each matching share right generally entitles the participant to one fully paid ordinary share in the Company, or in
certain limited circumstances a cash equivalent payment. The matching share rights do not have any performance hurdles as they have
been granted to encourage broad participation in the scheme across the Company, and to encourage employee share ownership. All
shares are currently purchased on market.
Annual Report 2020
61
Directors are not eligible to participate in the above schemes, but may participate in the NED Share Acquisition Plan by sacrificing Board
fees. This plan is intended to facilitate share acquisition, enabling new Directors to meet their MSR obligations. All NEDs currently meet
their MSR and no shares were acquired under the scheme in FY2020.
Directors regularly assess the risk of the Company losing high-performing key people who manage core activities or have skills that are
being actively solicited in the market. Where appropriate, the Board may consider the selected use of deferred payment arrangements
to reduce the risk of such critical loss. From time to time, it may be necessary to offer sign-on equity to offset or mirror unvested equity,
which a prospective executive must forfeit to take up employment with Origin.
4. Company performance and remuneration outcomes
This section summarises remuneration outcomes for FY2020 and provides commentary on their alignment with Company outcomes.
4.1 Five-year Company performance and remuneration outcomes
The table below summarises key financial and non-financial performance for the Company from FY2016 to FY2020, grouped and
compared with short-term and long-term remuneration outcomes.
Five-year key performance metrics FY2016–201
Operational measures
Underlying earnings per share (EPS) (cents)
Underlying EPS (continuing activities)2 (cents)
Net cash from/(used in) operating and investing activities
(NCOIA) ($m)
Energy Markets Underlying EBITDA ($m)
Integrated Gas Underlying EBITDA (total operations) ($m)
Adjusted net debt ($m)3
sNPS4
TRIFR5
Female representation in senior roles6 (%)
Origin Engagement Score7
STI award outcomes
Percentage of maximum8 (%)
Return measures
Closing share price at end of June ($)
Weighted average share price during the year9 ($)
Dividends10 (cents per share)
Annual TSR (%)
Three-year TSR11 (CAGR % p.a.)
Group Statutory EBIT ($m)
Group Statutory EBIT (continuing activities)2 ($m)
LTI outcomes
LTI vesting percentage in the year12 (%)
FY16
FY17
FY18
FY19
FY20
23.2
18.1
1,215
1,330
386
9,131
(16)
4.2
27
53
31.3
22.8
1,378
1,492
1,104
8,111
(16)
3.2
29
58
58.2
47.7
2,645
1,811
1,521
6,496
(13)
2.2
32
61
58.4
58.4
1,914
1,574
1,892
5,417
(6)
4.5
30
61
58.1
58.1
1,813
1,459
1,741
5,158
2
2.6
32
75
26.3
63.3
88.7
73.7
84.1
5.75
5.67
10.0
(42.0)
(18.5)
(411)
47
6.86
6.39
0.0
19.3
(14.2)
(1,958)
(1,746)
10.03
8.55
0.0
46.2
(2.6)
480
473
7.31
7.64
25.0
(26.1)
12.0
1,432
1,432
5.84
6.80
25.0
(17.7)
(8.0)
305
305
0
0
0
0
0
1 Except as noted in (2) below, FY2018 and prior year financials shown are those as previously reported. They have not been restated for the presentation of certain
electricity hedge premiums, which are included in underlying profit from FY2019, or for the reclassification of futures collateral balances to operating cash flows
(previously in financing cash flows in prior periods). A restatement for these factors for FY2018 only was provided in the FY2019 Consolidated Financial Statements at
note A1 Segments and in the Statement of cash flows, for indicative comparison purposes only.
2 Excludes Contact Energy (FY2016) and Lattice Energy (FY2016–18).
3 Adjusted Net Debt for FY2020 includes first recognition of lease liability ($514 million) under AASB 16 Leases.
4 sNPS is measured at the business level and is an industry-recognised measure of customer advocacy.
5 TRIFR is the total number injuries resulting in lost time, restricted work duties or medical treatment per million hours worked.
6 Senior roles refers to those with Korn Ferry Hay grade classifications above a level that currently corresponds to a TRT (see Section 3.2) of approximately $180,000 p.a.
7 Employee engagement is measured as a score through an annual Company-wide survey conducted independently.
8 This is the total dollar value of STI awarded for Executive KMP as a percentage of their total maximum STI. The percentage of STI forfeited is this amount subtracted from
100 per cent.
9 For FY2016, the weighted average share price incorporates a restatement for the bonus element of the rights issue completed in October 2015. The opening share price
on 1 July 2015 was $10.47.
10 Dividends represent the interim plus final dividends determined for each financial year. For FY2020, this includes the final dividend determined on 20 August 2020 to be
paid on 2 October 2020. The amounts paid within each financial year are 35c, 0c, 0c, 10c and 30c, respectively.
11 TSR calculations use the three-month VWAP share price to 30 June, reflecting the testing methodology for relative TSR ranking.
12 No LTI rights vested during FY2020. Options and rights awarded in October 2015 were all forfeited.
Remuneration Report 62
The remuneration outcomes for FY2020 reflect financial performance approaching stretch levels, and are above target for non-financial
performance.
The table shows that overall awarded STI outcomes for Executive KMP were 84.1 per cent of maximum for FY2020, and have varied
between 26.3 per cent and 88.7 per cent of maximum over the last five years, underlining the variability of STI outcomes with Company
performance.
No LTI vested during the year. All Options and all PSRs awarded in October 2015 were forfeited.
The specific performance metrics for the CEO scorecard, together with individual results for FY2020 STI, are provided in the table
on page 63.
The Board has adopted governing principles to apply when considering adjustments to financial measures that are used for remuneration
purposes. Targets set at the beginning of the year may be subject to events materially outside the course of business and outside the
control of the current management, in which case discretion may be required to vary targets or outcomes to reflect the intended purpose
and/or actual results and achievements. The governing principles emphasise fairness and symmetry: fairness to shareholders and
Executives, and symmetry of treatment between favourable and unfavourable events.
In addition to delivering very good operational and financial outcomes against targets set at the beginning of the year, the executive team
responded rapidly and performed extremely well to the series of emergency activities triggered in the second half by the bushfire and
COVID-19 emergencies, as identified in the Letter from the Chairman at the beginning of this Report.
Annual Report 2020 63
4.2 STI awards and scorecard details for FY2020
STI awards are calculated on the basis of a balanced scorecard using the concepts of setting requirements at threshold, target and stretch
achievement levels. The CEO’s FY2020 scorecard was weighted 65 per cent to financial measures and 35 per cent to non-financial
metrics (customer, people and strategic). The details and results are set out below.
CEO FY2020 STI scorecard
Targets and results
Measure, rationale and performance
Weight
Threshold
Target
Stretch
Outcome
Origin EPS (underlying) (cps)
Measure of Origin’s earnings and profitability
Origin NCOIA ($m)
Measure of effective cash flow generation
Energy Markets EBITDA ($m)
Measure of operating performance of the Energy Markets business
APLNG production rate (PJ)
Ability to keep Australia Pacific LNG (APLNG) assets producing at
their maximum capacity (*FY2021–22 average annual)
APLNG find and develop cost ($/GJ)
Measure of competitiveness
APLNG production unit cost ($/GJ)
Measure of competitiveness
Integrated Gas free cash flow ($m)
Measure of effective cash flow generation in Integrated Gas
(excluding impact of oil price changes or foreign exchange)
Financial measures sub-total
Voice of the customer
15%
10%
17.5%
5.6%
5.6%
5.6%
5.7%
65%
Strategic, interaction and episodic NPS each achieved stretch targets
at record levels
10%
Customer innovation
Measures of readiness of new customer solutions, including control
systems/Internet of Things, Retail 2020 transformation and Business
Energy strategy execution
Safety and People measures
Employee engagement achieved stretch (record) level, group HSE
(preventive and safety) targets were exceeded, and the percentage of
women in senior roles met target
Non-financial measures sub-total
TOTAL
Adjusted total6
5%
20%
35%
100%
49.5
|
1,055
|
1,401
|
680
|
1.52
|
2.05
|
989
|
33
|
33
|
33
|
33
|
33
|
33
|
6 On a final review of all results, management made modest downward adjustments to the final outcomes.
52.7
|
1,157
|
1,426
|
692
|
1.19
|
1.93
|
1,459
1,070
|
1,086
100
|
100
|
100
|
100
|
100
|
100
|
58.9
58.1
1,342
1,813
1,501
710
707.6
1.10
1.10
1.85
1.87
1,157
158% tgt
167% tgt
129% tgt
158% tgt
167% tgt
150% tgt
112% tgt
167
147.9% tgt
88.6% max
147.9
167
167
167
167
167
167
134
137.1
145.3
147.0
167% tgt
134% tgt
137% tgt
145.1% tgt
86.9% max
147.0% tgt
88.0% max
139.5% tgt
83.5% max
Remuneration Report
64
Underlying earnings per share exceeded our target due to a stronger than target result at APLNG, driven by record production and
favourable commodity prices, and a higher than target result from Energy Markets, driven by strong performance in our gas business.
Strong cash generation was driven by a record cash distribution of $1,275 million from APLNG, and proceeds from the sale of Ironbark of
$231 million.
APLNG delivered record production, reflecting improved field performance with higher well availability and facility reliability. APLNG
production costs were better than target due to improved field performance, resulting in lower gas purchases and lower costs associated
with well workovers.
Our sNPS score increased to +2, the highest of any Tier 1 provider. We have simplified our product suite and continue to streamline and
digitise the customer journey. Customers are increasingly choosing to engage with us through digital channels: 68 per cent of customers
now use e-billing, and service call volumes reduced by a further 8 per cent this year. We are on track to achieve our target of reducing
the cost to serve by $100 million from FY2018 to FY2021, and are growing our Solar, Community Energy Services (CES) and Broadband
businesses. We expect our acquisition of a 20 per cent stake in the fast-growing UK retailer and technology company Octopus Energy will
further streamline and improve the customer journey.
Our personal safety improved, with our TRIFR falling from 4.4 in FY2019 to 2.6 in FY2020. Our Actual Serious Incidents and Potential
Serious Incidents measures, which cover all aspects of HSE performance, both improved from last year.
Remuneration awards were approved after consideration of a range of other non-formulaic inputs, including advice from the Risk and
Audit committees, providing assurance that management behaviours have been consistent with the Code of Conduct and with the
Company’s principles, values and risk appetite (see Section 2.2).
The majority of the CEO’s scorecard objectives are shared across Other Executive KMP. However, their weightings will differ according
to their specific divisional metrics. This will lead to a degree of variability in outcomes across Executive KMP. For FY2020, the overall
scorecard outcomes ranged between 82.3 per cent and 86.8 per cent of maximum, as summarised below.
Executive KMP
F Calabria
L Tremaine
J Briskin
G Jarvis
M Schubert
STI award
% of maximum
% forfeited
$’000
83.5
83.7
82.3
86.8
84.9
16.5
16.3
17.7
13.2
15.1
2,554
1,421
1,237
1,333
1,304
4.3 Total pay received in FY2020
In line with general market practice, a non-AASB presentation of actual pay received in FY2020 is provided below, as a summary of real or
‘take home’ pay. AASB statutory remuneration is presented in Table 7-1.
Executive KMP
FR received
STI cash1
DSRs
vested2
LTI
vested3
Actual pay
received
F Calabria
L Tremaine
J Briskin
G Jarvis
M Schubert
1,831
1,017
835
867
867
1,277
711
495
666
522
478
688
171
191
139
0
0
0
0
0
3,586
2,416
1,501
1,724
1,528
1 STI cash represents 40 to 50 per cent of the FY2020 STI award, with the balance (50 to 60 per cent) deferred into equity.
2 DSRs vested were from Deferred STI grants awarded in 2016 and 2017. The value represents the number of shares vested multiplied by Origin’s closing share price at the
time of vesting.
3 LTI vested represents the value of LTI awards from prior years that vested wholly or partially during the year. Options and PSRs awarded in October 2015 were forfeited
during the year with nil vesting.
Annual Report 2020 65
5. Governance
5.1 Role of the Remuneration and People Committee
The RPC supports the Board by overseeing Origin’s remuneration policies and practices. It operates under a Charter (published on the
Company’s website at originenergy.com.au). The RPC met formally five times during the reporting period.
Including its Chairman, the RPC has four members, all of whom are independent NEDs (see Section 1 for details). The RPC’s Charter
requires a minimum of three NEDs. In addition, there is a standing invitation to all Board members to attend the RPC’s meetings.
Management may attend RPC meetings by invitation but a member of management will not be present when their own remuneration is
under discussion.
The following diagram sets out the role of the RPC and its operational relationships with the Board, management, stakeholders and
external advisors.
Board
The Board approves:
• Executive remuneration policy
• remuneration for the CEO and ELT
• STI and LTI targets and hurdles
• NED fees
• CEO and ELT succession and appointments
Remuneration and People Committee
The RPC makes recommendations to the Board on the
matters subject to its approval (listed above). The RPC
approves remuneration scales, movements and equity
allocations for employees other than the CEO and ELT.
In addition, the RPC stewards and advises the Board
and management on remuneration and people matters
including:
• future leader talent pipelines and
development processes
• people strategies and culture development
• corporate governance and risk matters relating
to people and remuneration (including conduct,
diversity and gender pay equity)
• effectiveness of the remuneration policy and its
implementation
Management
Management provides relevant data and information
for RPC consideration (practice insights, and
legal, tax, accounting and actuarial advice) and
makes recommendations to the RPC concerning
remuneration and people matters.
Information exchange with other Board
committees, notably the Audit and Risk
committees, to ensure that all relevant matters are
considered before the RPC makes remuneration
recommendations and decisions.
Consultation with external stakeholders and
shareholders
Regular dialogue with shareholders and
proxy advisors.
Independent remuneration advisors
The RPC appoints an external independent advisor
to assist it with market and governance issues,
benchmarking, best practice observations and
general advice.
Remuneration Report 66
5.2 Remuneration advisors
The RPC engages external advisors from time to time to conduct benchmarking, advise on regulatory and market developments, and
review proposals and reports. Protocols have been established for engaging and dealing with external advisors, including those defined as
remuneration consultants for the purposes of the Corporations Act 2001 (Cth) (the Act). These protocols are to ensure independence and
avoid conflicts of interest.
The protocols require that remuneration advisors are directly engaged by the RPC and act on instruction from its Chairman. Reports
must be delivered directly to the RPC Chairman. The advisor is prohibited from communicating with Company management except as
authorised by the Chairman, and even then limited to the provision or validation of factual and policy data. The advisor must furnish a
statement confirming the absence of any undue influence from management.
The RPC generally seeks information rather than specific remuneration recommendations within the definition of the Act, and this was the
case during FY2020. Guerdon Associates was appointed its advisor during FY2020; however, Guerdon Associates did not provide any
remuneration recommendations as defined under the Act.
In addition, the RPC makes use of general market trend information from a variety of commercial and industry sources and has access to
in-house remuneration professionals who provide it with guidance and analysis on request.
The recommendations that the RPC makes to the Board are based on its own independent assessment of the advice and information
received from these multiple sources, using its experience and having careful regard to the principles and objectives of the remuneration
framework, Company performance, shareholder and community expectations, and good governance.
5.3 Conduct, accountability and risk management
As identified in Section 2.2, a BARS methodology for behaviour and conduct assessment is an integral part of the Company’s performance
management framework and modification of formulaic incentive calculations.
In addition to the BARS tool, the full Board consults with the Chairman of the Audit Committee and the Chief Risk Officer when it formally
reviews ELT performance and conduct each year.
In addition to considerations of personal behaviour and conduct, the RPC is guided by a set of overarching principles to apply in assessing
items or events that impact risk (including non-financial risk) or performance (both positive and negative). This ensures a consistent
approach to determining whether discretionary adjustments to incentive outcomes are warranted, to achieve fairness to Executives and
shareholders. The RPC and the Board have wide discretionary tools to prevent the award (or retention) of inappropriate benefits, including
malus and clawback.
Malus
Malus refers to the reduction or cancellation of advised awards, or of unvested/unreleased equity or shares; or to a determination to reduce
the level of vesting that would otherwise apply, or to extend the existing period of a holding lock or trading restriction.
The Board has, from time to time, applied malus. For example, it awarded zero STI and LTI allocations for some Executives in FY2015
and FY2016 to ensure that outcomes were aligned with the overall circumstances of the Company, even though some of the relevant
performance conditions had been met and preliminary award advice had been given.
Clawback
Clawback is a reference to the recovery of benefits after they have been paid, vested or released. The Board has power to exercise
clawback to recover or cancel shares arising from equity awards, and to recover cash proceeds from the sale of such shares, or to recover
cash awards. Recovery may be limited by law or regulation. There have been no circumstances to date in which the Board has sought to
apply clawback.
Fraud, dishonesty, gross misconduct, negligence, breach of duties and other serious matters will have consequences additional to the
sanctions and provisions referred to above.
5.4 Change of control
The Board may determine that all or a specified number of unvested securities will vest or cease to be subject to restrictions where there is
a change of control event.
5.5 Capital reorganisation
On a capital reorganisation, the number of unvested share rights and Options held by participants may be adjusted in a manner
determined by the Board, to minimise or eliminate any material advantage or disadvantage to the participant. If new awards are granted,
they will, unless the Board determines otherwise, be subject to the same terms and conditions as the original awards.
Annual Report 2020 67
6. Non-executive Director fees
6.1 Remuneration policy and structure for Non-executive Directors
NED remuneration comprises fixed fees with no incentive-based payments. This ensures that NEDs are able to independently and
objectively assess both Executive and Company performance.
Board and committee fees take into account market rates for similar positions at relevant Australian organisations (those of comparable size
and complexity) and fairly reflect the time commitments and responsibilities involved. The aggregate cap for overall NED remuneration
remains at $3,200,000 p.a., as approved by shareholders on 18 October 2017.
The Origin Chairman receives a single fee that includes committee activities, while other NEDs receive a NED Base Fee and separate
fees for their roles on specific committees (other than the Nomination Committee, which is considered within the NED Base Fee). All fees
include superannuation contributions.
The table below summarises the structure and level of NED fees. No change to the fee structure or quantum is proposed for FY2021.
NED and committee fees ($’000)
Office
Board – Chairman (inclusive of committee fees)
NED Base Fee (exclusive of committee fees)
Audit – Chairman
Audit – Member
RPC – Chairman
RPC – Member
HSE – Chairman
HSE – Member
Risk – Chairman
Risk – Member
Nomination – Chairman
Nomination – Member
Origin Foundation – Chairman
FY2020
and FY2021
677
196
57
29
47
23.5
47
23.5
47
23.5
nil
nil
nil
6.2 Minimum shareholding requirement for Non-executive Directors
To align the interests of the Board and shareholders, NEDs are required to build and then maintain a minimum shareholding in the
Company. The MSR reference for the Chairman is 200 per cent of the NED Base Fee, and for all other NEDs it is 100 per cent of the NED
Base Fee. The Board sets the MSR from time to time as a number determined by reference to the NED Base Fee and share price7 (currently
set at 28,000 shares, and 56,000 for the Chairman).
NEDs are expected to reach the MSR within three years of their appointment and maintain it thereafter while in office. At the date of this
report, all NEDs were above the relevant MSR level. Details of NED shareholdings are included in Table 7-3.
A NED Share Plan (NEDSP) was approved by shareholders at the 2018 AGM. The NEDSP is a salary sacrifice plan that allows NEDs to
sacrifice up to 50 per cent of their annual NED Base Fee to acquire share rights. Each share right is a right to receive a fully paid ordinary
share in Origin, subject to the terms of the grant. The plan is intended to facilitate the acquisition of shares for new Directors to ensure they
meet the obligations imposed under the MSR. As at the date of the report, and noting that all NEDs have met their MSR obligations, no
share rights have been purchased and no shares allotted under the NEDSP.
7
Generally considering the weighted average share price over the prior year.
Remuneration Report 68
7. Statutory tables and disclosures
Table 7-1: Executive KMP and NED statutory remuneration ($’000)
Short term
Long term
PEB1
FR1
Base
salary
Super-
annuation
Non-
monetary
3
benefits
Cash
STI
Leave
6
2 accrual
Matching
share
rights
Share based
Totals
Deferred STI4
LTI5
RS
DSR
Total
accounting
remuneration
At
risk
(%)
Share
based
(%)
41
1,277
39 1,025
(65)
68
–
–
1,053
601
180
303
Executive Director
F Calabria
2020
1,768
2019
1,710
Other Executive KMP
J Briskin
G Jarvis
M Schubert8
L Tremaine
2020
2019
2020
2019
2020
2019
2020
2019
806
715
820
730
843
752
991
934
21
21
21
21
21
22
21
21
21
21
15
16
34
32
178
12
26
42
495
334
666
394
522
374
711
681
25
28
72
72
44
19
61
41
Executive total
2020 5,228
2019
4,841
105
106
294 3,671
141 2,808
137
228
NEDs
J Akehurst
M Brenner
G Cairns
T Engelhard
G Lalicker7
B Morgan
S Perkins
S Sargent
2020
2019
2020
2019
2020
2019
2020
2019
2020
2019
2020
2019
2020
2019
2020
2019
245
233
251
241
666
642
239
220
175
54
279
268
274
266
244
212
21
21
21
21
11
21
21
21
21
7
21
21
21
21
21
21
NED total
2020 2,373
2019
2,136
158
154
0.2
0.2
0.2
0.2
18
16
16
0.2
0.2
0.1
0.2
0.2
18
0.2
0.2
0.2
53
17
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
812
812
171
143
199
191
193
179
242
245
5,087
4,579
1,980
1,510
2,305
1,727
2,273
1,623
2,912
2,996
438
194
481
218
465
208
649
407
9
59
10
68
7
58
209
624
3,086
415
1,617
1,628
1,112 1,570
14,557
12,435
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
266
254
272
262
695
679
276
241
196
61
300
289
313
287
265
233
2,583
2,306
65
60
56
48
59
51
52
51
62
65
60
57
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
40
37
31
26
30
28
29
27
38
43
35
35
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
0.6
–
1.7
0.6
–
–
1.7
0.6
4
1.2
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
1 FR comprises base remuneration and superannuation (post-employment benefit (PEB)).
2 STI cash represents one half of the STI award. STI cash is paid after the end of the financial year to which it relates but is allocated to the earning year. The balance of the
STI award is Deferred STI.
3 Non-monetary benefits include insurance premiums and fringe benefits such as car parking and expenses associated with travel.
4 Deferred STI is that portion of the accounting value of equity granted or to be granted (RSs and/or DSRs) under the STI plan for the current and prior periods attributable
to the reporting period. In the following reporting periods, the accumulated expense is adjusted for the number of instruments then expected to be released or vested. In
good leaver circumstances, a bring-forward of future-period accounting expense may occur where a cessation of employment occurs before the normal vesting date.
5 LTI includes all long-term incentives (those not awarded under the STI Plan) and represents that portion of the accounting value of the awards made, or to be made, for
the current and prior periods, which is attributable to the reporting period. See Note G3 for details on share-based remuneration accounting.
6 Movement in leave provision over the reporting period. Negative movement indicates that leave taken during the year exceeded leave accrued during the current
year. FY2019 leave movements have been restated to include annual leave accruals for the relevant reporting period.
7 For FY2019, the pro-rata period for G Laliker was 1 March 2019 to 30 June 2019.
8 A review of prior-year fringe benefits tax returns is being undertaken as at the date of preparation of this Report, which may conclude that the accommodation benefits
associated with travel between the Melbourne home base at the time and the Brisbane office in prior years were higher than previously reported and possibly comparable
with the value shown here for FY2020.
Annual Report 2020 69
Abbreviations in tables 7-2 through 7-4
DSR – Deferred Share Rights
PSR – Performance Share Rights (with performance conditions)
PSR (TSR) – Performance Share Rights, relative TSR performance condition
PSR (ROCE) – Performance Share Rights, ROCE performance condition
RS – Restricted Shares (including those held in trust under the Deferred STI arrangements)
MR – Matching Share Rights under the Employee Share Purchase and Matching Rights Plan (see Section 3.7)
Table 7-2: Details of equity grants made during the reporting period
Equity rights and restricted shares granted to Executive KMP during the reporting period are listed below. There is nil cost to recipients.
Type
Number
granted
Grant date
fair value ($)1
Exercise
price ($)
Grant
date
Vest
date2
Expiry
date3
Executive Director
F Calabria
Other Executive KMP
J Briskin
G Jarvis
M Schubert
L Tremaine
PSR (TSR)
PSR (ROCE)
RS
PSR (TSR)
PSR (ROCE)
RS
MR
PSR (TSR)
PSRs (ROCE)
RS
RS4
MR
PSR (TSR)
PSR (ROCE)
RS
PSR (TSR)
PSR (ROCE)
RS
MR
226,371
226,371
143,242
62,881
62,881
46,689
190
67,073
67,073
55,000
109,370
346
67,073
67,073
52,275
83,841
83,841
95,090
346
4.49
7.25
8.12
3.82
6.77
7.63
0.47
3.82
6.77
7.63
5.53
0.47
3.82
6.77
7.63
3.82
6.77
7.63
0.47
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
16-Oct-19
16-Oct-19
16-Oct-19
22-Aug-22
22-Aug-22
23-Aug-21
22-Aug-22
22-Aug-22
–
30-Aug-19
30-Aug-19
30-Aug-19
27-Sep-19
30-Aug-19
30-Aug-19
30-Aug-19
8-May-20
27-Sep-19
30-Aug-19
30-Aug-19
30-Aug-19
30-Aug-19
30-Aug-19
30-Aug-19
27-Sep-19
22-Aug-22
22-Aug-22
23-Aug-21
23-Aug-21
22-Aug-22
22-Aug-22
23-Aug-21
2021–25
31-Oct-21
22-Aug-22
22-Aug-22
23-Aug-21
22-Aug-22
22-Aug-22
23-Aug-21
31-Oct-21
22-Aug-22
22-Aug-22
–
–
22-Aug-22
22-Aug-22
–
2021–25
–
22-Aug-22
22-Aug-22
–
22-Aug-22
22-Aug-22
–
–
1 For MRs, the fair value is per $1 contributed by the Executive.
2 For PSRs, the expiry date is the same as the vesting date. On vesting, PSRs convert to shares with a holding lock of a further one-year period. For RSs, the vest date refers
to the date when the trading restriction is lifted.
3 Rights may expire earlier. To the extent that they fail to meet the relevant performance conditions, they will lapse on the vesting date.
4 RSs subject to tenure conditions (see Section 3.7) vesting in five equal (by number) tranches on 30 April in each of the five years from 2021 to 2025.
Remuneration Report 70
Table 7-3: Details of, and movements in, equity rights and ordinary shares of the Company
The following table summarises holdings and movements of rights and ordinary shares held (directly, indirectly or beneficially, including
by related parties) over the reporting period (or KMP portion of the period), including grants, transactions and forfeits, by value and by
number. See Table 7-4 for further details of the terms and conditions of those rights.
Type
Held at
start1
Granted2/acquired3
Vested
Exercised
Forfeited5/
disposed6
Number
Value ($)
Number
Number
Value4 ($)
Number
Held
at end1,7
Executive Director
F Calabria
Options
PSR
DSR
RS
Shares
Other Executive KMP
Options
J Briskin
PSR
DSR
RS
MR
Shares
G Jarvis
Options
PSR
DSR
RS
MR
Shares
M Schubert Options
L Tremaine
PSR
DSR
RS
Shares
Options
PSR
DSR
RS
MR
Shares
NEDs8
Shares
J Akehurst
Shares
M Brenner
G Cairns
Shares
T Engelhard Shares
Shares
G Lalicker
Shares
B Morgan
Shares
S Perkins
Shares
S Sargent
1,203,145
563,869
176,002
106,684
232,117
86,910
142,214
23,340
33,435
0
40,722
250,427
142,678
25,993
35,375
163
36,061
237,410
138,626
18,945
33,717
55,973
81,441
146,864
170,015
72,500
163
166,309
71,200
28,367
163,660
34,421
100,000
47,143
30,000
31,429
–
452,742
–
143,242
65,223
–
125,762
–
46,689
190
23,852
–
134,146
–
164,370
346
29,623
–
134,146
–
52,275
19,077
–
167,682
–
95,090
346
94,505
0
0
0
0
0
0
0
0
–
2,657,596
–
1,163,125
–
–
665,910
–
356,237
1,743
–
–
710,303
–
1,024,466
2,310
–
–
710,303
–
398,858
–
–
887,876
–
725,537
2,310
–
–
–
–
–
–
–
–
–
0
0
65,223
0
–
0
0
23,340
0
0
–
0
0
25,993
0
0
–
0
–
18,945
0
–
0
0
93,813
0
0
–
–
–
–
–
–
–
–
–
0
0
65,223
0
–
0
0
23,340
0
0
–
0
0
25,993
0
0
–
0
–
18,945
0
–
0
0
93,813
0
0
–
–
–
–
–
–
–
–
–
0
0
478,085
0
–
0
0
171,082
0
–
–
0
0
190,529
0
0
–
0
–
138,867
0
–
0
0
687,649
0
0
–
–
–
–
–
–
–
–
–
570,150
57,739
0
0
110,000
0
17,090
0
0
0
0
85,500
25,976
0
0
0
–
83,250
25,292
0
0
23,636
0
0
0
0
0
50,000
0
0
0
0
0
0
0
0
632,995
958,872
110,779
249,926
187,340
86,910
250,886
0
80,124
190
64,574
164,927
250,848
0
199,745
509
65,684
154,160
247,480
0
85,992
51,414
81,441
314,546
76,202
167,590
509
210,814
71,200
28,367
163,660
34,421
100,000
47,143
30,000
31,429
1 The number of instruments that held at the start/end of the reporting period.
2 Rights to equity and restricted shares in the Company granted to Executive KMP during the reporting period under the Equity Incentive Plan, as listed in Table 7-2. These
were provided at no cost to the recipients.
3 Purchases and transfers in. For Other Executive KMP this includes allotments of fully paid ordinary shares granted or acquired under the Employee Share Plan, and shares
received upon the vesting and exercise of DSRs. Executive Directors do not participate in the General Employee Share Plan (GESP) or the MSP.
4 After vesting and after payment of any exercise price (the exercise price for DSRs is nil). The value of rights exercised is calculated as the closing market price of the
Company’s shares on the ASX on the date of exercise, after deducting any exercise price. The exercise price for PSRs and DSRs is nil. DSRs vesting in the period were
granted on 30 August 2016 (vested 26 August 2019), 30 August 2017 (vested 10 July 2019) and 18 October 2017 (vested 26 August 2019).
5 Forfeited Options and PSRs were granted in October 2015.
6 Sales and transfers out.
7 Rights are automatically exercised on vesting. There were no vested Options as at the end of the period. Other than rights and RSs disclosed elsewhere in this Report, no
other equity instruments, including shares in the Company, were granted to KMP during the period.
8 NEDs are not issued shares under any incentive or equity plans. Acquisitions include purchases of shares on market, or pursuant to the Company’s dividend reinvestment
plan or the August 2015 Entitlement Offer.
Annual Report 2020 71
Table 7-4: Summary of share rights granted
The table below lists all the share rights outstanding at 30 June 2020 that have been granted to current or former employees (including
Executive Directors and Executive KMP) under equity-based incentive plans. Equity-based incentives are not granted to NEDs. No terms
of equity-settled share-based transactions have been altered or modified subsequent to grant. Share rights that failed to meet their
performance hurdles on vesting dates prior to 30 June 2020 have all lapsed.
Granted
Legacy Options
30 August 2016
19 October 2016
30 August 2017
30 August 2017
18 October 2017
PSRs
30 August 2016
19 October 2016
30 August 2017
30 August 2017
18 October 2017
10 September 2018
17 October 2018
30 August 2019
16 October 2019
DSRs
30 August 2016
30 August 2017
30 August 2017
18 October 2017
18 October 2017
MRs
26 September 2018
27 September 2019
Number
outstanding
Number
outstanding
held by KMP
Exercise
price
Earliest
vest date1
Last possible
expiry date2
1,421,289
450,000
81,441
905,363
401,288
1,166,540
129,558
841,583
24,415
126,866
1,355,077
312,245
1,848,417
452,742
19,667
76,202
26,057
45,556
45,556
373,806
–
81,441
263,898
401,288
143,777
–
24,415
83,432
126,866
317,419
312,245
561,736
452,742
19,667
76,202
–
45,556
45,556
130,065
98,476
312
570
$5.67
$5.21
$7.37
$7.37
$7.37
23 August 2021
23 August 2021
23 August 2021
22 August 2022
22 August 2022
28 August 2026
28 August 2026
28 August 2026
23 August 2027
23 August 2027
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
24 August 2020
24 August 2020
24 August 2020
23 August 2021
23 August 2021
23 August 2021
23 August 2021
22 August 2022
22 August 2022
24 August 2020
24 August 2020
24 August 2020
23 August 2021
23 August 2021
23 August 2021
23 August 2021
22 August 2022
22 August 2022
24 August 2020
10 July 2020
24 August 2020
24 August 2020
23 August 2021
24 August 2020
10 July 2020
24 August 2020
24 August 2020
23 August 2021
31 October 2020
31 October 2021
31 October 2020
31 October 2021
1 The vest date for PSRs granted since 2018 does not include the trading restriction of approximately one year that applies to the shares allocated on vesting.
2 The expiry date is the same as the vesting date where the terms of the grant apply automatic exercise on vesting. Where there is no automatic exercise on vesting, the
expiry date is the last possible expiry. Rights and Options may expire earlier; for example, to the extent that they do not meet their performance conditions, they will lapse
on the vesting date.
Remuneration Report 72
Table 7-5: Executive service agreements
The main terms of executive service agreements at 30 June 2020 are set out in the table below.
Item
CEO
Basis of contract
Ongoing
Other Executive KMP
Ongoing
Notice period
– 12 months by either party
– Six months (three months for J Briskin) by either party
Termination
benefits for cause
Termination benefits
for resignation
Termination benefits
for other than
resignation or cause
– Shorter notice may apply by agreement
– Shorter notice may apply by agreement
– No notice in defined circumstances1
– No notice in defined circumstances1
Statutory entitlements only
Statutory entitlements only
Notice as above or payment in lieu of notice that is not
worked; current-year STI forfeited; unvested equity
lapses; and statutory entitlements.
Notice as above or payment in lieu of notice that is not
worked; current-year STI forfeited; unvested equity lapses; and
statutory entitlements.
Notice worked (or payment in lieu of any portion not
worked); pro rata STI for the period worked (no deferral
applicable); all unvested equity lapses unless held on
foot in accordance with Equity Incentive Plan Rules2;
and statutory entitlements.
Notice worked (or payment in lieu of any portion not worked);
pro rata STI for the period worked (no deferral applicable); all
unvested equity lapses unless held on foot in accordance with
Equity Incentive Plan Rules2; and statutory entitlements.
For redundancy, payment in accordance with the Company’s
general redundancy policy of three weeks FR per year of service,
with a minimum of 18 weeks and a maximum of 78 weeks.
Remuneration
Remuneration is reviewed annually or as required to
maintain alignment with policy and benchmarks.
Remuneration is reviewed annually or as required to maintain
alignment with policy and benchmarks.
1 These circumstances include but are not limited to serious or persistent or wilful misconduct, breach of contract, or conduct likely to seriously injure the reputation of
the Company.
2 For example, in cases of death, disability, genuine retirement or extraordinary circumstances, as approved by the Board.
Loans to KMP
No loans have been made, guaranteed or secured, directly or indirectly, by the Company or any of its subsidiaries, at any time throughout
the year, to any KMP including to a KMP related party.
Signed in accordance with a resolution of Directors.
Gordon Cairns
Chairman
Sydney, 20 August 2020
Annual Report 2020 Lead Auditor’s
Independence Declaration
73
A member firm of Ernst & Young Global Limited Liability limited by a scheme approved under Professional Standards Legislation Ernst & Young 200 George Street Sydney NSW 2000 Australia GPO Box 2646 Sydney NSW 2001 Tel: +61 2 9248 5555 Fax: +61 2 9248 5959 ey.com/au Auditor’s Independence Declaration to the Directors of Origin Energy Limited As lead auditor for the audit of the financial report of Origin Energy Limited for the financial year ended 30 June 2020, 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; and b) no contraventions of any applicable code of professional conduct in relation to the audit. This declaration is in respect of Origin Energy Limited and the entities it controlled during the financial year. Ernst & Young Andrew Price Partner Sydney 20 August 2020 74
Annual Report 2020
Financial Statements
30 June 2020
75
Primary statements
Income statement
Statement of comprehensive income
C
Operating assets
and liabilities
C1 Trade and other receivables
G Other information
G1 Contingent liabilities
G2 Commitments
Statement of financial position
C2 Exploration and evaluation assets
G3 Share-based payments
Statement of changes in equity
C3 Property, plant and equipment
G4 Related party disclosures
Statement of cash flows
Notes to the financial
statements
Overview
A Results for the year
A1 Segments
A2 Revenue
A3 Other income
A4 Expenses
A5 Results of equity accounted investees
A6 Earnings per share
A7 Dividends
B
Investment in
equity accounted
joint ventures and
associates
B1
Interests in equity accounted joint
ventures and associates
B2
Investment in APLNG
B3
Investment in Octopus Energy
Holdings Limited
B4
Transactions between the Group and
equity accounted investees
C4
Intangible assets
C5 Trade and other payables
C6 Provisions
G5 Key management personnel
G6 Notes to the statement of cash flows
G7 Auditors’ remuneration
C7 Other financial assets and liabilities
G8 Master netting or similar agreements
G9 Deed of Cross Guarantee
G10 Parent entity disclosures
G11 Subsequent events
Directors’ declaration
Independent
auditor’s report
D
Capital, funding and
risk management
D1 Capital management
D2
Interest-bearing liabilities
D3 Contributed equity
D4 Financial risk management
D5
Fair value of financial assets and
liabilities
E Taxation
E1
Income tax expense
E2 Deferred tax
F Group structure
F1 Controlled entities
F2 Business combinations
F3
Joint arrangements and investments in
associates
76
Income statement
For the year ended 30 June
Revenue
Other income
Expenses
Results of equity accounted investees
Interest income
Interest expense
Profit before income tax
Income tax expense
Profit for the year
Profit for the year attributable to:
Members of the parent entity
Non-controlling interests
Profit for the year
Earnings per share
Basic earnings per share
Diluted earnings per share
Note
A2
A3
A4
A5
A3
A4
E1
2020
$m
13,157
54
(13,514)
608
190
(316)
179
(93)
86
83
3
86
2019
$m
14,727
26
(13,953)
632
234
(388)
1,278
(64)
1,214
1,211
3
1,214
A6
A6
4.7 cents
4.7 cents
68.8 cents
68.7 cents
The income statement should be read in conjunction with the accompanying notes set out on pages 81 to 130.
Annual Report 2020 Statement of comprehensive income
For the year ended 30 June
Profit for the year
Other comprehensive income
Items that will not be reclassified to profit or loss, net of tax
Investment valuation changes
Items that can be reclassified to profit or loss, net of tax
Translation of foreign operations
Cash flow hedges:
Reclassified to income statement
Effective portion of change in fair value
Total other comprehensive income, net of tax
Total comprehensive income for the year
Total comprehensive income attributable to:
Members of the parent entity
Non-controlling interests
Total comprehensive income for the year
77
Note
2020
$m
2019
$m
86
1,214
E1
E1
3
5
125
4
(493)
(361)
(275)
(279)
4
(275)
341
(122)
223
447
1,661
1,662
(1)
1,661
The statement of comprehensive income should be read in conjunction with the accompanying notes set out on pages 81 to 130.
Financial Statements 78
Statement of financial position
as at 30 June
Current assets
Cash and cash equivalents
Trade and other receivables
Inventories
Derivatives
Other financial assets
Income tax receivable
Assets classified as held for sale
Other assets
Total current assets
Non-current assets
Trade and other receivables
Derivatives
Other financial assets
Investments accounted for using the equity method
Property, plant and equipment (PP&E)
Exploration and evaluation assets
Intangible assets
Deferred tax assets
Other assets
Total non-current assets
Total assets
Current liabilities
Trade and other payables
Payables to joint ventures
Interest-bearing liabilities
Derivatives
Other financial liabilities
Provision for income tax
Employee benefits
Provisions
Liabilities classified as held for sale
Total current liabilities
Non-current liabilities
Trade and other payables
Interest-bearing liabilities
Derivatives
Other financial liabilities
Employee benefits
Provisions
Total non-current liabilities
Total liabilities
Net assets
Equity
Contributed equity
Reserves
Retained earnings
Total parent entity interest
Non-controlling interests
Total equity
Note
2020
$m
2019
$m
C1
D4
C7
C1
D4
C7
A5
C3
C2
C4
E2
C5
D2
D4
C7
C6
C5
D2
D4
C7
C6
D3
1,240
1,959
164
630
479
89
–
105
4,666
18
528
2,225
7,360
4,331
190
5,420
315
40
1,546
2,324
137
472
318
–
254
112
5,163
7
962
3,152
6,960
3,597
98
5,381
380
43
20,427
20,580
25,093
25,743
1,934
202
1,401
466
237
–
234
163
–
4,637
193
5,451
749
16
33
1,313
7,755
12,392
12,701
7,145
716
4,819
12,680
21
12,701
2,006
204
948
384
308
160
189
45
23
4,267
2
6,648
1,119
–
31
527
8,327
12,594
13,149
7,125
1,089
4,915
13,129
20
13,149
The statement of financial position should be read in conjunction with the accompanying notes set out on pages 81 to 130.
Annual Report 2020 Statement of changes in equity
For the year ended 30 June
79
$m
Balance as at
30 June 2019
Adoption of AASB 16
(refer to Overview)
Balance as at
1 July 2019
Profit for the year
Translation of foreign
operations
Cash flow hedges
Investment
valuation changes
Total other
comprehensive income
Total comprehensive
income for the year
Dividends provided
for or paid
Movement in
contributed equity
(refer to note D3)
Share-based payments
Total transactions
with owners recorded
directly in equity
Balance as at
30 June 2020
Balance as at
30 June 2018
Adoption of AASB 9
Balance as at
1 July 2018
Profit for the year
Translation of foreign
operations
Cash flow hedges
Investment
valuation changes
Total other
comprehensive income
Total comprehensive
income for the year
Dividends provided
for or paid
Movement in
contributed equity (refer
to note D3)
Share-based payments
Total transactions
with owners recorded
directly in equity
Balance as at
30 June 2019
Contributed
equity
Share-based
payments
reserve
Foreign
currency
translation
reserve
Hedge
reserve
Fair
value
reserve
Retained
earnings
Non-
controlling
interests
Total
equity
7,125
234
736
–
–
–
114
–
114
–
–
(489)
–
736
–
124
–
–
124
(489)
124
(489)
–
–
–
–
–
–
–
–
7,125
–
234
–
–
–
–
–
–
–
20
–
–
–
–
–
–
–
–
(11)
20
(11)
7,145
223
860
(375)
7,150
–
7,150
–
–
–
–
–
–
–
247
–
247
–
–
–
–
–
–
–
(25)
–
–
(13)
(25)
(13)
391
–
391
–
345
–
–
345
345
–
–
–
–
13
–
13
–
–
101
–
101
101
–
–
–
–
7,125
234
736
114
5
–
5
–
–
–
3
3
3
–
–
–
–
8
(22)
22
–
–
–
–
5
5
5
–
–
–
–
5
4,915
20
13,149
349
–
349
5,264
83
20
3
13,498
86
–
–
–
–
83
(528)
–
–
1
–
–
1
4
(3)
–
–
125
(489)
3
(361)
(275)
(531)
20
(11)
(528)
(3)
(522)
4,819
21
12,701
4,025
(145)
3,880
1,211
–
–
–
–
1,211
(176)
–
–
24
–
24
3
(4)
–
–
(4)
(1)
(3)
–
–
11,828
(123)
11,705
1,214
341
101
5
447
1,661
(179)
(25)
(13)
(176)
(3)
(217)
4,915
20
13,149
The statement of changes in equity should be read in conjunction with the accompanying notes set out on pages 81 to 130.
Financial Statements 80
Statement of cash flows
For the year ended 30 June
Cash flows from operating activities
Receipts from customers
Payments to suppliers and employees
Cash generated from operations
Income taxes paid, net of refunds received
Net cash from operating activities
Cash flows from investing activities
Acquisition of PP&E
Acquisition of exploration and development assets
Acquisition of other assets
Acquisition of OC Energy(1)
Acquisition of other investments
Interest received from other parties
Net proceeds from sale of non-current assets
Australia Pacific LNG (APLNG) investing cash flows
– Receipt of Mandatorily Redeemable Cumulative Preference Shares (MRCPS) interest
– Proceeds from APLNG buy-back of MRCPS
Net cash from investing activities
Cash flows from financing activities
Proceeds from borrowings
Repayment of borrowings
Joint venture operator cash call movements
Settlement of foreign currency contracts
Interest paid(2)
Repayment of lease principal
Dividends paid to shareholders of Origin Energy Ltd, net of Dividend Reinvestment Plan (DRP)
Dividends paid to non-controlling interests
Repayment of Debt Service Reserve Account (DSRA) loan to equity accounted investees
Purchase of shares on market (treasury shares)
Net cash used in financing activities
Net (decrease)/increase in cash and cash equivalents
Cash and cash equivalents at the beginning of the period
Effect of exchange rate changes on cash
Cash and cash equivalents at the end of the period
Note
2020
$m
2019
$m
G6
14,766
(13,600)
1,166
(215)
951
(290)
(85)
(125)
(14)
(151)
18
234
181
1,094
862
1,273
(2,446)
56
(55)
(310)
(75)
(475)
(3)
(8)
(75)
(2,118)
(305)
1,546
(1)
1,240
16,552
(15,117)
1,435
(110)
1,325
(190)
(18)
(133)
(29)
(35)
2
18
229
745
589
2,063
(1,878)
7
(64)
(375)
–
(162)
(3)
(31)
(77)
(520)
1,394
150
2
1,546
(1) The Group acquired OC Energy in the prior year. The cash outflow of $14 million in the current year relates to deferred consideration on the acquisition. The prior year
cash outflow of $29 million was net of cash acquired as part of the transaction.
(2) Includes $16 million of interest payments on leases in the current year as a result of the adoption of AASB 16 Leases.
The statement of cash flows should be read in conjunction with the accompanying notes set out on pages 81 to 130.
Annual Report 2020
81
The Group adopted AASB 16 using the
modified retrospective approach. Under
this approach, the cumulative effect of
adopting the new standard was recognised
as an adjustment to the opening balance
of retained earnings on 1 July 2019. No
restatement of comparative information is
required. The Group has taken advantage of
recognition exemptions for leases that are
less than 12 months and leases for which
the underlying asset is of low value.
The lease liabilities recognised on transition
were measured at the present value of the
remaining lease payments, discounted
using the Group’s incremental borrowing
rate at 1 July 2019. The associated right-
of-use (ROU) assets for major commercial
offices and certain LPG terminals were
measured on a retrospective basis as if
the new rules had always applied. The
remaining ROU assets were measured at an
amount equal to the lease liability, adjusted
by the amount of any prepaid or accrued
lease payments as at 30 June 2019.
The Group has applied the following
practical expedients on transition
to AASB 16:
• use of a single discount rate for a
portfolio of leases with reasonably similar
characteristics;
• reliance on previous onerous lease
assessments. The initial ROU asset
has been adjusted by the provision
for onerous leases recognised in the
statement of financial position at
30 June 2019;
• exclusion of leases with a remaining
lease term of less than 12 months from
1 July 2019;
• exclusion of initial direct costs from
measurement of the ROU asset; and
• use of hindsight when determining the
lease term for contracts containing
optional periods.
Notes to the financial statements
The Group’s operating
environment and COVID-19
The Group’s operating environment has
been impacted by a significant reduction in
commodity prices as well as the COVID-19
pandemic. These factors combined
have had wider impacts on consumers,
businesses and the overall economy. The
Group entered the 2020 financial year in a
financially resilient position with significantly
reduced upstream costs at APLNG, and
materially reduced debt. This has enabled
the Group to respond to the pandemic
with a focus on safely maintaining energy
supply and supporting customers who have
been financially affected. To date, there has
been no material impact on Origin’s energy
supply operations and fuel availability.
The economic impacts of the changes in
the Group’s operating environment due
to oil price and COVID-19 impacts have
implications for various line items in the
financial statements, including revenue and
receivables, equity accounted investments
(APLNG), carrying value of non-current
assets, provisions, derivatives and other
non-financial assets/liabilities.
Use of judgements and
estimates relating to COVID-19
In the process of applying the Group’s
accounting policies, management has
made a number of judgements and applied
estimates in relation to changes in the
Group’s operating environment and the
impact of the reduction in commodity
prices and COVID-19. The judgements and
estimates that are material to the financial
report are discussed in the following notes:
• A2 – Revenue
• B2 – Investment in APLNG
• C1 – Trade and other receivables
• C3 – Property, plant and equipment
• C4 – Intangible assets
• C6 – Provisions
Adoption of AASB 16 Leases
AASB 16 Leases became effective for the
Group on 1 July 2019 and requires lessees
to account for all leases under a single
on–balance sheet model. The Group’s
operating lease portfolio predominantly
comprises commercial offices, LPG
terminals, power generating assets and
fleet vehicles.
Overview
Origin Energy Limited (the Company) is a
for-profit company domiciled in Australia.
The address of the Company’s registered
office is Level 32, Tower 1, 100 Barangaroo
Avenue, Barangaroo NSW 2000. The
nature of the operations and principal
activities of the Company and its controlled
entities (the Group or Origin) are described
in the segment information in note A1.
On 20 August 2020, the Directors resolved
to authorise the issue of these consolidated
general purpose financial statements for the
year ended 30 June 2020.
Basis of preparation
The financial statements have
been prepared:
•
in accordance with the requirements
of the Corporations Act 2001 (Cth),
Australian Accounting Standards and
other authoritative pronouncements of
the Australian Accounting Standards
Board (AASB), and International
Financial Reporting Standards as
issued by the International Accounting
Standards Board; and
• on a historical cost basis, except for
derivatives and other financial assets and
liabilities that are measured at fair value.
The financial statements:
• are presented in Australian dollars;
• are rounded to the nearest million
dollars, unless otherwise stated, in
accordance with Australian Securities
and Investments Commission (ASIC)
Corporations (Rounding in Financial/
Directors’ Reports) Instrument
2016/191; and
• do not early adopt any Accounting
Standards and Interpretations that have
been issued or amended but are not
yet effective.
Use of judgements
and estimates
Preparing the financial statements in
conformity with Australian Accounting
Standards requires management to make
judgements and apply estimates and
assumptions that affect the reported
amounts of assets, liabilities, income and
expenses. The estimates and associated
assumptions, which are based on
historical experience and various other
factors believed to be reasonable under
the circumstances, form the basis of
judgements about carrying values of
assets and liabilities that are not readily
apparent from other sources. Actual
results may differ from these estimates.
Throughout the notes to the financial
statements, further information is provided
about key management judgements and
estimates that we consider material to the
financial statements.
Financial Statements 82
Overview (continued)
Adoption of AASB 16 Leases (continued)
Key judgements and estimates applied on adoption of AASB 16 Leases
Management judgement has been applied in the application of AASB 16 to the Group’s renewable power purchase agreements (PPAs).
Where the use of an asset, such as a wind or solar farm, is considered to be pre-determined, the arrangement is a lease if either the
customer has the right to direct the operations of the asset in a manner it determines or the customer designed the asset. Management
has determined that Origin’s decision-making rights under its PPAs give the Group the ability to direct the operations of the power
plants and that owners are prevented from using the assets in any other way. Accordingly, the renewable PPAs through which the
Group takes substantially all the output have been classified as leases under AASB 16.
If the renewable PPAs had not been deemed leases, net electricity derivative liabilities of $449 million would have been recognised in
the statement of financial position at 30 June 2020. Additionally, a $63 million gain would have been treated as an item excluded from
underlying profit, consistent with other fair value movements.
Regardless of whether the Group’s renewable PPAs are classified as leases, recognition and measurement of the realised component,
being the amount incurred for electricity purchased during the period, is the same. Consistent with prior periods, the realised
component is recognised in expenses (refer to note A4) within the income statement. To determine the value of the electricity
derivatives that would be recognised were the Group’s renewable PPAs not classified as leases, significant management judgement
is required to estimate future generation profiles and forward electricity spot prices relative to the terms of the individual contract for
periods up to 15 years.
Payments under the Group’s leases of renewable power plants are entirely variable as they depend on the amount of energy produced
in each period. Such leases have nil lease liability balances and thus nil ROU asset balances. All payments made under these leases are
recognised within operating expenses as incurred.
Transition impact at 1 July 2019
The impact on the Group’s statement of financial position at 1 July 2019 is summarised below.
As at 1 July 2019
PP&E
ROU assets
Derivative assets(1)
Deferred tax assets
Other assets
Lease liabilities
Derivative liabilities(1)
Provisions(2)
Retained earnings (net of tax)
$m
Debit/(credit)
(75)
445
(128)
(149)
(6)
(478)
640
100
(349)
(1) Derivative assets and liabilities derecognised on adoption of AASB 16 as they relate to PPAs classified as leases under the new standard.
(2) Onerous lease provisions are now reflected within the carrying value of ROU assets.
A reconciliation of the Group’s undiscounted operating lease commitments at 30 June 2019 to lease liabilities recognised on transition at
1 July 2019 is set out below.
As at 1 July 2019
Operating lease commitments disclosed at 30 June 2019
Adjusted for:
Discounting at the date of initial application using the Group’s incremental borrowing rate
Different treatment of extension options
Finance lease liabilities on statement of financial position at 30 June 2019
Other
Lease liability recognised as at 1 July 2019
The Group’s weighted average incremental borrowing rate applied on 1 July 2019 was 3.1 per cent.
$m
543
(113)
49
7
(1)
485
Annual Report 2020 83
Items excluded from the calculation of
underlying profit are reported to the
Managing Director as not representing the
underlying performance of the business
and thus are excluded from underlying
profit or underlying EBITDA. These items
are determined after consideration of the
nature of the item, the significance of the
amount and the consistency in treatment
from period to period.
The nature of items excluded from
underlying profit and underlying
EBITDA are:
• changes in the fair value of financial
instruments not in accounting hedge
relationships, to remove the significant
volatility caused by timing mismatches
in valuing financial instruments and the
related underlying transactions. The
valuation changes are subsequently
recognised in underlying earnings when
the underlying transactions are settled;
• realised and unrealised foreign exchange
gains/losses on debt held to hedge
USD-denominated APLNG MRCPS, for
which fair value changes are excluded
from underlying profit;
• redundancies and other costs in relation
to business restructuring, transformation
or integration activities;
• gains/losses on the sale or acquisition of
an asset/entity;
• transaction costs incurred in relation to
the sale or acquisition of an entity;
•
impairments of assets; and
• significant onerous contracts.
A Results for the year
This section highlights the performance of
the Group for the year, including results by
operating segment, income and expenses,
results of equity accounted investees,
earnings per share and dividends.
A1 Segments
The Group’s operating segments are
presented on a basis that is consistent
with the information provided internally
to the Managing Director, who is the chief
operating decision maker. This reflects the
way the Group’s businesses are managed,
rather than the legal structure of the Group.
The reporting segments are organised
according to the nature of the activities
undertaken and are detailed below.
• Energy Markets: Energy retailing and
wholesaling, power generation and LPG
operations predominantly in Australia.
Also includes Origin’s investment in
Octopus Energy Holdings Limited
(Octopus Energy).
• Integrated Gas: Origin’s investment
in APLNG, growth assets business
and management of LNG hedging
and trading activities. For greater
transparency, the investment in APLNG
is presented separately from the residual
component of the segment in the
following disclosures.
• Corporate: Various business
development and support activities that
are not allocated to operating segments.
Underlying profit and underlying EBITDA
are the primary alternative performance
measures used by the Managing
Director for the purpose of assessing the
performance of each operating segment
and the Group. Underlying profit and
underlying EBITDA are non-statutory
(non-IFRS) measures. The objective of
measuring and reporting underlying profit
and underlying EBITDA is to provide a more
meaningful and consistent representation
of financial performance by removing
items that distort performance or are
non-recurring in nature.
Financial Statements 84
A1 Segments (continued)
Segment result for the year ended 30 June
Energy Markets
Share of APLNG
Other(6)
Corporate
Consolidated
Integrated Gas
$m
Ref.
2020
2019
2020
2019
2020
2019
2020
2019
2020
2019
External revenue
12,888
14,293
–
–
269
434
–
–
13,157
14,727
EBITDA
Depreciation and amortisation
Share of ITDA of equity
accounted investees
EBIT
Interest income(1)
Interest expense(2)
Income tax expense(3)
Non-controlling interests (NCI)
Statutory profit/(loss)
attributable to members of the
parent entity
Reconciliation of statutory
profit/(loss) to segment result
and underlying profit/(loss)
Fair value and foreign
exchange movements
Disposals, impairments,
onerous contracts and business
restructuring
Tax and NCI on items excluded
from underlying profit
1,521
(477)
1,492
(401)
1,915
–
2,142
–
(1,185)
(29)
(7)
–
(1,301)
(1,516)
5
2
(18)
6
1,037
1,091
614
626
(1,209)
174
(10)
226
(134)
(3)
(275)
–
2,117
(509)
3,361
(419)
–
–
(1,303)
(1,510)
(137)
16
(316)
(93)
(3)
(275)
8
(388)
(64)
(3)
305
190
(316)
(93)
(3)
1,432
234
(388)
(64)
(3)
1,037
1,091
614
626
(1,035)
216
(533)
(722)
83
1,211
(a)
83
(61)
–
–
384
271
(73)
(11)
394
199
(b)
(20)
(21)
–
13
(1,396)
(38)
(2)
(29)
(1,418)
(75)
84
9
59
19
84
59
(940)
183
Total significant items
63
(82)
–
13
(1,012)
233
Segment underlying
profit/(loss)(4)(5)
Underlying EBITDA(4)(5)
974
1,173
614
613
(23)
(17)
(542)
(741)
1,023
1,028
1,459
1,574
1,915
2,123
(174)
(231)
(59)
(234)
3,141
3,232
(1) Interest income earned on MRCPS has been allocated to the Integrated Gas – Other segment.
(2) Interest expense related to general financing is allocated to the Corporate segment.
(3) Income tax expense for entities in the Origin tax consolidated group is allocated to the Corporate segment.
(4) Underlying profit and underlying EBITDA are non-statutory (non-IFRS) measures.
(5) Underlying EBITDA equals segment underlying profit/(loss) adjusted for: depreciation and amortisation; share of ITDA of equity accounted investees; interest income/
(expense); income tax expense; and NCI.
(6) EBITDA in the Integrated Gas – Other segment in the current period includes an impairment expense of $746 million related to the Group’s equity accounted investment
in APLNG (refer to note B2.2) and an onerous contract expense of $650 million related to the Cameron LNG purchase contract (refer to note C6).
Annual Report 2020 85
A1 Segments (continued)
$m
Gross
Tax and NCI
Gross
Tax and NCI
2020
2019
(a) Fair value and foreign exchange movements
Increase/(decrease) in fair value of derivatives
Net gain from financial instruments measured at fair value
Exchange loss on foreign-denominated debt
Fair value and foreign exchange movements
(b) Disposals, impairments, onerous contracts and business restructuring
Capital tax loss recognition – Ironbark
Gain on sale of Denison – share of APLNG(1)
Gain on sale – Origin LPG (Vietnam) LLC
Gain on sale – Energia Austral SpA
Loss on sale – Dandenong Cogent assets
Disposals
Integrated Gas impairments and impairment reversals
Impairment – APLNG equity accounted investment(2)
Impairment – Ironbark permit areas
Impairment reversal – Heytesbury permit areas
Corporate impairments
Impairment – goodwill and other intangibles on Pleiades investment in Chile
Impairments
Onerous contracts – Cameron
Onerous contracts
One-off building lease exit costs
Restructuring costs
Transaction costs
Finalisation of tax position – Lattice Energy divestment
Business restructuring
Total disposals, impairments, onerous contracts and
business restructuring
275
123
(4)
394
–
–
–
–
–
–
(746)
–
–
–
(746)
(650)
(650)
–
(9)
(13)
–
(22)
(83)
(37)
1
(119)
–
–
–
–
–
–
–
–
–
–
–
195
195
–
3
5
–
8
(1,418)
203
(102)
391
(90)
199
–
13
5
5
(2)
21
–
(49)
13
(3)
(39)
–
–
(19)
(29)
(9)
–
(57)
(75)
(1) The prior period amount is presented post-tax as the Group equity accounts for its share of net profit after tax of APLNG. Refer note B2.1.
(2) Refer to note B2.2.
30
(117)
27
(60)
68
–
(1)
(1)
–
66
–
15
(4)
–
11
–
–
6
8
3
25
42
119
Financial Statements 86
A1 Segments (continued)
Segment assets and liabilities as at 30 June
Integrated Gas
Energy
Markets
Share of
APLNG
Other
Corporate
Total
continuing
operations
Total assets
and liabilities
held for sale
Consolidated
$m
2020
2019 2020
2019 2020
2019 2020
2019
2020
2019 2020
2019 2020
2019
12,567 12,378
–
–
687
276
214
133
13,468
12,787
–
254
13,468
13,041
381
–
7,862
7,103
(884)
(143)
1
–
7,360
6,960
–
–
7,360
6,960
Total assets
12,948 12,378
7,862
7,103
1,912
3,178
2,371
2,830
25,093
25,489
2,109
3,045
2,156
2,697
4,265
5,742
–
–
–
4,265
5,742
254 25,093
25,743
(3,414) (3,299)
–
–
(1,155)
(369)
(726)
(821)
(5,295) (4,489)
–
(23)
(5,295)
(4,512)
Assets
Segment assets
Investments accounted
for using the equity
method (refer
to note A5)
Cash, funding-related
derivatives and
tax assets
Liabilities
Segment liabilities
Financial liabilities,
interest-bearing
liabilities, funding-
related derivatives and
tax liabilities
Total liabilities
(3,414) (3,299)
–
–
(1,155)
(369) (7,823) (8,903) (12,392) (12,571)
Net assets
9,534
9,079
7,862
7,103
757
2,809 (5,452) (6,073)
12,701
12,918
Additions of non-
current assets(1)
519
382
–
–
95
30
12
7
626
419
(7,097) (8,082)
(7,097) (8,082)
–
–
–
–
–
(7,097)
(8,082)
(23) (12,392) (12,594)
231
12,701
13,149
–
626
419
(1) The Energy Markets segment includes $128 million relating to the investment in Octopus Energy and $13 million relating to the build of the Kraken technology platform
following the agreement entered into with Octopus Energy (2019: $58 million relating to the acquisition of OC Energy Pty Ltd).
Geographical information
Detailed below is revenue based on the location of the customer and non-current assets (excluding derivatives, other financial assets and
deferred tax assets) based on the location of the assets.
For the year ended 30 June
Australia
Other
External revenue
As at 30 June
Australia
Other
Non-current assets(1)
(1) The prior period excludes amounts that were classified as held for sale at 30 June 2019.
2020
$m
2019
$m
13,067
90
13,157
14,612
115
14,727
17,317
42
16,050
36
17,359
16,086
Annual Report 2020
A2 Revenue
$m
2020
Sale of electricity
Sale of gas
Pool revenue
Other revenue
$m
2019
Sale of electricity
Sale of gas
Pool revenue
Other revenue
Retail
4,569
1,163
–
45
5,777
5,056
1,064
–
44
6,164
Business and
Wholesale
2,941
1,673
1,527
64
6,205
3,208
1,862
2,117
52
7,239
Solar and
Energy
Services
Integrated
Gas
81
99
–
118
298
34
90
–
92
216
–
269
–
–
269
–
434
–
–
434
LPG
–
606
–
2
608
–
674
–
–
674
87
Total
7,591
3,810
1,527
229
13,157
8,298
4,124
2,117
188
14,727
The Group’s primary revenue streams relate to the sale of electricity and natural gas to retail (Residential and Small to Medium Enterprises),
business and wholesale customers, and the sale of generated electricity into the National Electricity Market (NEM).
Key judgements and estimates: The Group recognises revenue from electricity and gas sales once the energy has been consumed
by the customer. When determining revenue for the financial period, management estimates the volume of energy supplied since a
customer’s last bill. The estimation of unbilled consumption requires judgement and is based on various assumptions including:
• volume and timing of energy consumed by customers;
• allocation of estimated electricity and gas volumes to various pricing plans;
• discounts linked to customer payment patterns; and
•
loss factors.
Management also uses unbilled consumption volumes to accrue network expenses incurred by the Group for unread customer
electricity and gas meters.
The government-imposed lockdown and social distancing restrictions in response to COVID-19 have generally resulted in increased
residential household energy consumption as more people stay at home, while businesses have reduced energy consumption in certain
industries. Given the unprecedented operating environment, the calculation of unbilled revenue requires significant judgement in
estimating the level of energy consumption by customers during the unbilled period to 30 June 2020. The Group uses a backcasting
model and volume-matching process to provide a reliable estimate of unbilled revenue as at 30 June 2020. Refer to note C1 for the
Group’s consideration of the COVID-19 impact on its cash collection of trade receivables and unbilled revenue.
Retail contracts
Retail electricity service is generally marketed through standard service offers that provide customers with discounts on published tariff
rates. Contracts have no fixed duration, generally require no minimum consumption, and can be terminated by the customer at any time
without significant penalty. The supply of energy is considered a single performance obligation for which revenue is recognised upon
delivery to customers at the offered rate. Where customers are eligible to receive additional behavioural discounts, Origin considers this to
be variable consideration, which is estimated as part of the unbilled process.
Business and wholesale contracts
Contracts with business and wholesale customers are generally medium to long term, higher-volume arrangements with fixed or index-
linked energy rates that have been commercially negotiated. The nature and accounting treatment of this revenue stream is largely
consistent with retail sales. Some business and wholesale sales arrangements also include the transfer of renewable energy certificates
(RECs), which represent an additional performance obligation. Revenue is recognised for these contracts when Origin has the ‘right to
invoice’ the customer for consideration that corresponds directly with the value of units of energy delivered to the customer.
Pool revenue
Pool revenue relates to sales by Origin generation assets into the NEM, as well as revenue associated with gross settled PPAs. Origin has
assessed it is acting as the principal in relation to transactions with the NEM and therefore recognises pool sales on a ‘gross’ basis. Revenue
from these sales is recognised at the spot price achieved when control of the electricity passes to the grid.
LPG and LNG sales
Revenue from the sale of LPG (from Origin’s Energy Markets segment) and LNG (from Origin’s Integrated Gas segment) is recognised
at the point in time that the customer takes physical possession of the commodity. Revenue is recognised at an amount that reflects the
consideration expected to be received.
Financial Statements 88
A3 Other income
Net gain on sale of assets
Fees and services, and other income(1)
Other income
Interest earned from other parties(2)
Interest earned on APLNG MRCPS (refer to note B4)
Interest income
2020
$m
1
53
54
16
174
190
2019
$m
–
26
26
8
226
234
(1) The current period amount includes $39 million relating to insurance proceeds received to 30 June 2020 for the Mortlake generator asset failure in July 2019.
(2) Interest income is measured using an effective interest rate method and recognised as it accrues.
A4 Expenses
Expenses
Cost of sales
Employee expenses(1)
Depreciation and amortisation
Impairment of non-current assets(2)
Impairment of trade receivables (net of bad debts recovered)
(Increase)/decrease in fair value of derivatives
Net gain from financial instruments measured at fair value
Net foreign exchange (gain)/loss
Onerous contract expense(3)
Other(4)(5)
Expenses
Interest on borrowings
Interest on lease liabilities
Unwind of discounting on long-term provisions
Interest expense
2020
$m
2019
$m
10,732
662
509
764
124
(275)
(123)
(15)
650
486
13,514
296
18
2
316
12,254
664
419
39
84
102
(391)
89
–
693
13,953
385
–
3
388
(1) Includes contributions to defined contribution superannuation funds of $62 million (2019: $61 million).
(2) In the current period, a $746 million impairment was recognised relating to the Group’s equity accounted investment in APLNG (refer to note B2.2), as well as a
$19 million impairment relating to the Mortlake generator asset write-off following the electrical fault experienced in July 2019. This was offset by a $1 million impairment
reversal relating to the Group’s investment in PNG Energy Development Limited joint venture. (2019: A $49 million impairment was recognised in relation to the Ironbark
permit assets, offset by a $13 million impairment reversal in relation to the Heytesbury permit areas, following classification as held for sale. An additional $3 million
impairment of goodwill and other intangibles on the Pleiades investment in Chile was recognised.)
(3) Refer to note C6.
(4) Includes $83 million of cost recoveries (2019: $124 million), which were previously netted against the cost of sales line.
(5) The comparative amount includes operating lease rental expense of $81 million.
Annual Report 2020 A5 Results of equity accounted investees
$m
2020
Octopus Energy(1)
Gasbot Pty Limited(2)
Total associates
APLNG(3)(4)
PNG Energy Developments Limited
Total joint ventures
Total
2019
APLNG(3)(4)
PNG Energy Developments Limited
Total joint ventures
Total
$m
as at
Octopus Energy(1)
APLNG(3)
PNG Energy Developments Limited
Gasbot Pty Limited(2)
89
Share of
EBITDA
Share of
ITDA
Share of net
(loss)/profit
(4)
–
(4)
1,915
–
1,915
1,911
2,142
–
2,142
2,142
(7)
–
(7)
(1,296)
–
(1,296)
(1,303)
(1,510)
–
(1,510)
(1,510)
(11)
–
(11)
619
–
619
608
632
–
632
632
Equity accounted investment
carrying amount
2020
2019
380
6,978
1
1
7,360
–
6,960
–
–
6,960
(1) The Group acquired a 20 per cent interest in Octopus Energy effective 1 May 2020. Included in Octopus Energy’s share of net profit is $5 million (Origin share) of
depreciation, relating to the fair value attributed to assets at the acquisition date. Refer to note B3.
(2) During the period, the Group acquired a 35 per cent interest in Gasbot Pty Limited and has significant influence over the entity.
(3) APLNG’s summary financial information is separately disclosed in note B2.
(4) Included in the Group’s share of net profit is $5 million (2019: $6 million) of MRCPS interest income, in line with the depreciation of the capitalised interest in APLNG’s
result. MRCPS interest was capitalised by APLNG during the construction period, and therefore eliminated by the Group against its equity accounted investment at
that time. Refer to note B2.1.
Financial Statements 90
A6 Earnings per share
Weighted average number of shares on issue – basic(1)
Weighted average number of shares on issue – diluted(2)
STATUTORY PROFIT
Earnings per share based on statutory consolidated profit
Statutory profit – $m
Basic earnings per share
Diluted earnings per share
UNDERLYING PROFIT
Earnings per share based on underlying consolidated profit
Underlying profit – $m(3)
Underlying basic earnings per share
Underlying diluted earnings per share
2020
2019
1,759,801,186
1,764,776,000
1,758,935,655
1,762,450,733
83
4.7 cents
4.7 cents
1,211
68.8 cents
68.7 cents
1,023
58.1 cents
58.0 cents
1,028
58.4 cents
58.3 cents
(1) The basic earnings per share calculation uses the weighted average number of shares on issue during the period excluding treasury shares held.
(2) The diluted earnings per share calculation uses the weighted average number of shares on issue during the period excluding treasury shares held and is adjusted to
reflect the number of shares which would be issued if outstanding Options, Performance Share Rights (PSRs), Deferred Share Rights (DSRs), Restricted Shares (RSs) and
Matching Share Rights (MSRs) were to be exercised (2020: 4,974,814; 2019: 3,515,078).
(3) Refer to note A1 for a reconciliation of statutory profit to underlying consolidated profit.
A7 Dividends
The Directors have determined to pay an unfranked final dividend of 10 cents per share, payable on 2 October 2020. Dividends paid
during the year ended 30 June are detailed below.
Final dividend of 15 cents per share, in respect of FY2019, fully franked at 30 per cent, paid 27 September 2019
(2019: Nil final dividend)
Interim dividend of 15 cents per share, in respect of FY2020, fully franked at 30 per cent, paid 27 March 2020
(2019: 10 cents per share, fully franked at 30 per cent, paid 29 March 2019)
Total dividends provided for or paid
Dividend franking account
Franking credits available to shareholders of Origin Energy Limited for subsequent financial years are
shown below.
Australian franking credits available at 30 per cent(1)
New Zealand franking credits available at 28 per cent (in NZD)
(1) Franking credits will arise from tax payments during FY2021 and the franking account will not be in deficit by 30 June 2021.
2020
$m
264
264
528
2019
$m
–
176
176
(57)
304
205
304
Annual Report 2020 91
B Investment in equity accounted joint ventures and associates
This section provides information on the Group’s equity accounted investments including financial information relating to APLNG and
Octopus Energy.
B1 Interests in equity accounted joint ventures and associates
Joint ventures and associates
Octopus Energy(1)
APLNG(2)
KUBU Energy Resources (Pty) Limited
PNG Energy Developments Limited
Gasbot Pty Limited
Reporting date
Country of
incorporation
2020
2019
Ownership interest (per cent)
30 April
30 June
30 June
31 December
30 June
United Kingdom
Australia
Botswana
PNG
Australia
20.0
37.5
50.0
50.0
35.0
–
37.5
50.0
50.0
–
(1) Octopus Energy is a separate legal entity. The Group’s 20 per cent investment is equity accounted as a result of the Group’s active participation on the Board and the
Group’s ability to impact decision making, leading to the assessment that significant influence exists.
(2) APLNG is a separate legal entity. Operating, management and funding decisions require the unanimous support of the Foundation Shareholders, which includes the
Group and ConocoPhillips. Accordingly, joint control exists and the Group has classified the investment in APLNG as a joint venture.
Of the above interests in joint ventures and associates, only APLNG and Octopus Energy have a material impact to the Group at
30 June 2020.
B2 Investment in APLNG
This section provides information on financial information related to the Group’s investment in the equity accounted joint venture APLNG.
B2.1 Summary APLNG income statement
for the year ended 30 June
2020
2019
$m
Operating revenue
Operating expenses
EBITDA
Depreciation and amortisation expense
Interest income
Interest expense – MRCPS
Other interest expense
Income tax expense
ITDA
Statutory result for the year
Other comprehensive income
Statutory total comprehensive income(1)
Items excluded from segment result
Gain on sale of assets – Denison
Items excluded from segment result (net of tax)
Underlying profit for the year(2)
Underlying EBITDA for the year(2)
Total
APLNG
Origin
interest
Total
APLNG
Origin
interest
7,100
(1,992)
5,108
(1,863)
40
(463)
(474)
(708)
7,491
(1,781)
5,710
(2,116)
51
(602)
(662)
(711)
1,915
(699)
15
(174)
(177)
(266)
2,142
(794)
19
(226)
(248)
(267)
(3,468)
(1,301)
(4,040)
(1,516)
1,640
–
1,640
–
–
1,640
5,108
614
–
614
–
–
614
1,915
1,670
–
1,670
35
35
1,635
5,662
626
–
626
13
13
613
2,123
(1) Excluded from the above is $5 million (2019: $6 million) (Origin share) of MRCPS interest income that has been recognised by Origin in line with the depreciation of the
capitalised interest in APLNG’s result above. MRCPS interest was capitalised by APLNG during the construction period, and therefore eliminated by Origin against its
equity accounted investment at that time. This adjustment is disclosed under the ‘Integrated Gas – Other’ segment on the ‘share of ITDA of equity accounted investees’
line in note A1.
(2) Underlying profit and underlying EBITDA are non-statutory (non-IFRS) measures.
Income and expense amounts are converted from USD to AUD using the average rate prevailing for the relevant period.
Financial Statements 92
B2.2 Carrying amount of investment in APLNG
Impact of oil prices and COVID-19 on carrying value of investments accounted for using the equity method
The carrying amount of the Group’s equity accounted investment in APLNG is reviewed at each reporting date to determine whether
there is any indication of impairment. Where an indicator of impairment exists, a formal estimate of the recoverable amount is made. The
Group’s assessment of the recoverable amount uses a discounted cash flow methodology and considers a range of macroeconomic and
project assumptions, including oil and LNG price, AUD/USD exchange rates, discount rates and costs over the asset’s life. The principal
change since the Group’s last assessment at 31 December 2019 is a reduction in oil price assumptions over the near term and a revised
long-term Brent crude oil price assumption of US$60/bbl (real FY2020) from FY2026, partially offset by cost reductions from improved
field and operating performance. As a result, the Group recognised an impairment charge of $746 million against the carrying value of its
investment in APLNG as at 30 June 2020 (2019: $nil).
The recoverable amount of the investment requires significant judgement and is sensitive to changes in key assumptions. A change in
assumption could result in a significantly higher or lower impairment charge recognised at 30 June 2020. The assumptions and the
sensitivity of the investment to assumption changes are described below.
Oil prices (Brent oil nominal, US$/bbl) used by the Group in its impairment assessment are shown below.
2021
2022
2023
2024
2025
2026(1)
30 June 2020
40
45
50
55
61
66
(1) Escalated at 2 per cent from 2026.
Forecasts of the foreign exchange rate for foreign currencies, where relevant, are estimated with reference to observable external market
data and forward values, including analysis of broker and consensus estimates.
The future estimated AUD/USD rates applied by APLNG are shown below.
2021
2022
2023
2024
2025
2026
30 June 2020
0.69
0.69
0.69
0.70
0.70
0.70
The post-tax discount rate applied, determined as APLNG’s weighted average cost of capital, adjusted for risks where appropriate,
is 7.4 per cent (2019: 7.4 per cent).
The APLNG valuation is determined based on an assessment of fair value less costs of disposal (based on level 3 fair value hierarchy). Key
assumptions in APLNG’s valuation are reserves, future production profiles, foreign exchange, commodity prices, operating costs and any
future development costs necessary to produce the reserves.
Estimated unconventional reserve quantities in APLNG are based on interpretations of geological and geophysical models, and assessment
of the technical feasibility and commercial viability of producing the reserves. Reserve estimates are prepared that conform to guidelines
prepared by the Society of Petroleum Engineers. These assessments require assumptions to be made regarding future development and
production cost, commodity prices, exchange rates and fiscal regimes. The estimates of reserves may change from period to period as the
economic assumptions used to estimate the reserves can change from period to period, and as additional geological data is generated
during the course of operations. Estimated reserve quantities include a Probabilistic Resource Assessment approach.
Estimates of future commodity prices are highly judgemental, particularly with the sudden reduction in pricing during the last quarter of
the financial year. The reduced prices are expected to impact FY2021 due to the effect of lagged oil pricing.
The Group’s estimate as at 30 June 2020 is based on its best estimate of future market prices with reference to external industry and
market analysts’ forecasts, current spot prices and forward curves. Future commodity prices for impairment testing are reviewed on a
six-monthly basis. Where volumes are contracted, future prices are based on the contracted price.
Impairment sensitivity
The Group’s assessment of the recoverable amount of its investment in APLNG is most sensitive to changes in oil price, discount rates
and the AUD/USD foreign exchange rate. Key accounting judgements and estimates used in forming the valuation are disclosed in the
previous section.
Reasonably possible changes in circumstances will affect assumptions and the estimated fair value of Origin’s investment in APLNG.
These reasonably possible changes include:
• a decrease in oil prices of USD$1/bbl, which in isolation would lead to a decrease of AU$233 million in the valuation; and
• an increase in the discount rate of 0.3 per cent in isolation or an increase in the AUD/USD FX rate of 2 cents in isolation from the rates
assumed in the valuation would lead to a decrease of A$233 million in the valuation.
Changes in any of the aforementioned assumptions, may be accompanied by changes in other assumptions, which may have an
offsetting impact.
Annual Report 2020 B2.3 Summary APLNG statement of financial position
100 per cent APLNG
as at 30 June
$m
Cash and cash equivalents
Assets classified as held for sale
Other assets
Current assets
Receivables from shareholders
PP&E(1)
Exploration, evaluation and development assets
Other assets
Non-current assets
Total assets
Bank loans – secured
Payable to shareholders (MRCPS)
Other liabilities(2)
Current liabilities
Bank loans – secured
Payable to shareholders (MRCPS)
Other liabilities(3)
Non-current liabilities
Total liabilities
Net assets
Group’s interest of 37.5% of APLNG net assets
Group’s impairment expense
Group’s own costs
MRCPS elimination(4)
Investment in APLNG Pty Ltd(5)
93
2020
2019
1,072
5
775
1,852
370
35,703
531
998
1,610
5
644
2,259
375
35,971
326
1,641
37,602
38,313
39,454
40,572
720
117
689
1,526
8,587
5,398
2,981
16,966
18,492
20,962
7,862
(746)
25
(163)
673
91
761
1,525
9,084
8,078
2,946
20,108
21,633
18,939
7,103
–
25
(168)
6,978
6,960
(1) Includes $429 million of ROU assets in the current period as a result of the adoption of AASB 16 Leases.
(2) Includes $64 million of lease liabilities in the current period as a result of the adoption of AASB 16 Leases.
(3) Includes $193 million of lease liabilities in the current period as a result of the adoption of AASB 16 Leases.
(4) During project construction, when the Group received interest on the MRCPS from APLNG, it recorded the interest as income after eliminating a proportion of this
interest that related to its ownership interest in APLNG. At the same time, when APLNG paid interest to the Group on MRCPS, the amount was capitalised by APLNG.
Therefore, these capitalised interest amounts form part of the cost of APLNG’s assets and these assets have been depreciated since commencement of operations. The
proportion attributable to the Group’s own interest (37.5 per cent) is eliminated through the equity accounted investment balance.
(5) Includes a movement of $145 million in foreign exchange that has been recognised in the foreign currency translation reserve.
Reporting date balances are converted from USD to AUD using an end-of-period exchange rate of 0.6862 (2019: 0.7012).
Financial Statements 94
B2.4 Summary APLNG statement of cash flows
100 per cent APLNG
for the year ended 30 June
$m
Cash flow from operating activities
Receipts from customers
Payments to suppliers and employees
Net cash from operating activities
Cash flows from investing activities
Loan repaid by Origin
Loans repaid by other shareholders
Proceeds from sale of assets
Acquisition of non-current assets
Acquisition of PP&E
Acquisition of exploration and development assets
Other investing activities
Net cash used in investing activities
Cash flows from financing activities
Payments relating to other financing activities
Repayment of lease principal
Payment of interest on lease liabilities
Proceeds from borrowings
Repayment of borrowings
Payments of transaction and interest costs relating to borrowings
Payments for buy-back of MRCPS
Payments of interest on MRCPS
Net cash used in financing activities
Net (decrease)/increase in cash and cash equivalents
Cash and cash equivalents at the beginning of the year
Effect of exchange rate changes on cash
Cash and cash equivalents at the end of the year
2020
2019
7,321
(2,079)
5,242
8
6
–
(245)
(1,001)
(37)
40
7,538
(2,002)
5,536
31
9
30
–
(1,321)
(57)
50
(1,229)
(1,258)
(45)
(80)
(19)
–
(731)
(382)
(2,918)
(480)
(85)
–
–
6,346
(7,154)
(513)
(1,987)
(611)
(4,655)
(4,004)
(642)
1,610
104
1,072
274
1,223
113
1,610
Cash flow amounts are converted from USD to AUD using the exchange rate that approximates the actual rate on the date of the
cash flows.
Annual Report 2020 95
B3 Investment in Octopus Energy Holdings Limited
On 1 May 2020, the Group announced the acquisition of a 20 per cent equity stake in Octopus Energy for a total cash consideration of
£215 million ($412 million), of which £65 million was paid upfront and £150 million is deferred over two financial years. Octopus Energy
is an energy retailer and technology company incorporated in the United Kingdom and is not publicly listed. The investment in Octopus
Energy enables the Group to adopt Octopus Energy’s market-leading operating model and customer platform, Kraken, to fast-track
material improvements in customer experience and costs.
The following table summarises the financial information of Octopus Energy, as included in its financial statements, adjusted for fair value
adjustments at acquisition and differences in accounting policies. The table also reconciles the summarised financial information to the
carrying amount of the Group’s interest in Octopus Energy. The information for FY2020 includes the results of Octopus Energy from 1 May
to 30 June 2020, following the acquisition of the 20 per cent equity stake.
Summary Octopus Energy income statement
for the period from 1 May to 30 June
$m
Statutory and underlying result for the period
Other comprehensive income
Statutory total comprehensive income(1)
2020
Total
Octopus
Energy
(32)
–
(32)
Origin
interest
(6)
–
(6)
(1) Excluded from the above is $5 million (Origin share) of amortisation relating to the fair value attributed to assets at the acquisition date.
Income statement amounts are converted from GBP to AUD using the average rate prevailing for the relevant period.
Summary Octopus Energy statement of financial position
as at 30 June
$m
Current assets(1)
Non-current assets
Current liabilities(2)
Non-current liabilities(2)
Net assets
Group’s interest of 20% of Octopus Energy net assets
Goodwill and fair value adjustments(3)
Group’s own costs
Group’s carrying amount of the investment in Octopus Energy(4)
(1) Current assets includes cash and cash equivalents of $113 million.
(2) Includes current financial liabilities and non-current financial liabilities of $237 million and $197 million respectively.
(3) Includes goodwill and other fair value adjustments on initial recognition of the Group’s equity accounted investment in Octopus Energy.
(4) Includes a movement of $21 million in foreign exchange that has been recognised in the foreign currency translation reserve.
Reporting date balances are converted from GBP to AUD using an end-of-period exchange rate of 0.5584.
The associate has no contingent liabilities or capital commitments as at 30 June 2020.
2020
1,040
163
(852)
(197)
154
31
344
5
380
Financial Statements 96
B4 Transactions between the Group and equity accounted investees
APLNG
Service transactions
The Group provides services to APLNG including corporate services, upstream operating services related to the development and
operation of APLNG’s natural gas assets, and marketing services relating to coal seam gas (CSG). The Group incurs costs in providing
these services and charges APLNG for them in accordance with the terms of the contracts governing those services.
Commodity transactions
Separately, the Group has entered agreements to purchase gas from APLNG (2020: $339 million; 2019: $475 million) and sell gas to
APLNG (2020: $32 million; 2019: $69 million). At 30 June 2020, the Group’s outstanding payable balance for purchases from APLNG was
$33 million (2019: $45 million) and outstanding receivable balance for sales to APLNG was $1 million (2019: $3 million).
Funding transactions
The Group has invested in USD MRCPS issued by APLNG. The MRCPS are the mechanism by which the funding for the CSG to LNG
Project has been provided by the shareholders of APLNG in proportion to their ordinary equity interests. The MRCPS have a 6.37 per cent
fixed-rate dividend obligation based on the relevant observable market interest rates and estimated credit margin at the date of issue.
Dividends are paid twice per year and recognised as interest income as they accrue (refer note A3). During the year Origin’s share of the
MRCPS balance reduced to US$1.4 billion following APLNG share buy-backs of US$0.7 billion. The mandatory redemption date for the
MRCPS is 30 June 2026.
The MRCPS are measured at fair value through profit and loss in Origin’s financial statements as disclosed in note C7. The carrying value
was $2,109 million as at 30 June 2020 (2019: $3,045 million) reflecting the Group’s view that APLNG will utilise cash flows generated
from operations to redeem the MRCPS for their full issue price prior to their mandatory redemption date. In APLNG’s financial statements
the related liability is carried at amortised cost.
Octopus Energy
As part of a broader partnership with Octopus Energy, the Group has entered into an agreement to obtain a licence to utilise Octopus
Energy’s market-leading customer platform, Kraken, in Australia. The total fixed consideration under the agreement is £25 million
($48 million), of which £5 million ($9 million) was paid on execution of the agreement and £20 million (A$38 million) is deferred over two
financial years. The fixed consideration has been recognised as an intangible asset by the Group at 30 June 2020. A further £25 million
($48 million) could also become payable under the agreement but is contingent on the achievement of certain milestones. The contingent
consideration will be capitalised when it becomes payable in the future once the relevant performance criteria have been achieved.
The Group has entered into a further agreement to provide a financial guarantee to Octopus Energy’s financiers in respect of a
working capital facility entered into by Octopus Energy. Under this agreement, Octopus Energy is required to pay a monthly fee to
the Group in respect of the guarantee facility. The guarantee has been accounted for as a Financial Guarantee Contract under AASB 9
Financial Instruments and has been initially recognised at fair value (refer to note C7). During the year, $1 million has been recognised
within other income in respect of the financial guarantee income.
There were no other transactions between the Group and Octopus Energy during the year ended 30 June 2020.
Annual Report 2020 97
C Operating assets and liabilities
This section provides information on the assets used to generate the Group’s trading performance and the liabilities incurred as a result.
C1 Trade and other receivables
The following balances are amounts due from the Group’s customers and other parties.
Current
Trade receivables net of allowance for impairment
Unbilled revenue net of allowance for impairment
Other receivables
Non-current
Trade receivables
Other receivables
2020
$m
618
1,072
269
1,959
8
10
18
2019
$m
735
1,226
363
2,324
7
–
7
Trade and other receivables are initially recorded at the amount billed to customers or other counterparties. Unbilled receivables represent
estimated gas and electricity supplied to customers since their previous bill was issued. The carrying value of all receivables (including
unbilled revenue) reflects the amount anticipated to be collected.
Key judgements and estimates
Recoverability of trade receivables: Judgement is required in determining the level of provisioning for customer debts. Impairment
allowances take into account the age of the debt, historic collection trends and expectations about future economic conditions.
Unbilled revenue: Unbilled gas and electricity revenue is not collectable until customers’ meters are read and invoices issued. Refer to
note A2 for judgement applied in determining the amount of unbilled energy revenue to recognise.
Credit risk and collectability
The Group minimises the concentration of credit risk by undertaking transactions with a large number of customers from across a broad
range of industries. Credit approval processes are in place for large customers and all customers are required to pay in accordance with
agreed payment terms. Depending on the customer segment, settlement terms are generally 14 to 30 days from the date of the invoice.
For some debtors, the Group may also obtain security in the form of deposits, guarantees, deeds of undertaking or letters of credit which
can be called upon if the counterparty defaults.
Debtor collectability is assessed on an ongoing basis and any resulting impairment losses are recognised in the income statement. The
Group applies the simplified approach to providing for trade receivable and unbilled revenue impairment, which requires the ‘expected
lifetime credit losses’ to be recognised when the receivable is initially recognised. To measure expected lifetime credit losses, trade
receivables and unbilled revenue balances have been grouped based on shared credit risk characteristics and ageing profiles. A debtor
balance is written off when recovery is no longer assessed to be possible.
With the emergence of COVID-19, the government introduced lockdowns and other restrictions to combat the spread of the virus, which
has led to job losses and business shutdowns in certain industries. This has placed increased pressure on businesses’ ability to absorb these
impacts, and on consumer budgets. Collectively this impacts the Group’s debt collection performance and any expected credit losses.
In April 2020, the Group announced a disconnection freeze for its residential and small business customers, including a freeze on default
listing of customers in financial stress, and the waiving of all late payment fees during the period. At the date of this report, the Group has
not experienced a significant impact on its debt collection as a result of COVID-19.
Despite this, there remains future credit risk associated with trade receivable amounts due to:
• the impact of the Australian Government stimulus packages and other relief measures coming to an end, including other organisations
such as financial institutions recommencing collection activities;
• the end of the COVID-19 disconnection freeze introduced by the Group, and the length of time for any impacts to be realised in the
customer accounts; and
• more broadly, the unprecedented nature of this event, such that historical performance cannot be used in isolation as an indicator of
the future. The impacts seen in other countries are not comparable due to different consumer patterns, demographics and responses to
COVID-19, including the nature and quantum of government stimulus.
Financial Statements 98
C1 Trade and other receivables (continued)
The Group has performed an assessment of its provision for bad and doubtful debts in accordance with AASB 9 Financial Instruments
considering:
• current collection performance, including the COVID-19 period when lockdown restrictions and government stimulus measures were in
place, and expected credit default frequencies;
• regulatory and economic outlook, including forecast unemployment rates and the timing and quantum of government stimulus
packages and other relief measures provided by banks and landlords; and
• risk profile of customers and industry-specific risk assessments based on actual and forecasted volumes as a measure for credit risk.
These considerations require significant judgement. To ensure a more accurate assessment, the Group has increased the segmentation
of its SME and large business customers in its modelling of the expected credit loss as at 30 June 2020 by customer type and industry
group. Each segment has been reviewed and a credit risk weighting has been applied depending on the extent COVID-19 has impacted
the industry group and the level of significantly aged receivables outstanding. Where possible, publicly available information, such
as expected default rates, has been applied. For residential customers, a higher allowance for impairment is included for those with
significantly aged receivables, including any recent debt associated with those customers.
As at 30 June 2020, the allowance for impairment in respect of trade receivables and unbilled revenue is $162 million (2019: $135 million),
with $40 million of this amount reflecting the increased potential impact of COVID-19.
The average age of trade receivables is 20 days (2019: 21 days). Other receivables are neither past due nor impaired, and relate principally
to generation and hedge contract receivables. The ageing of trade receivables and unbilled revenue at the reporting date is detailed below.
$m
Unbilled revenue
Not yet due
Less than 30 days
31–60 days past due
61–90 days past due
Greater than 91 days
2020
2019
Gross
1,092
387
102
46
40
185
1,852
Impairment
allowance
(20)
(14)
(6)
(8)
(10)
(104)
(162)
Gross
1,233
497
102
65
32
167
Impairment
allowance
(7)
(7)
(7)
(7)
(9)
(98)
2,096
(135)
The movement in the allowance for impairment in respect of trade receivables and unbilled revenue during the year is shown below.
Balance as at 1 July
Adoption of AASB 9
Impairment losses recognised
Amounts written off
Balance as at 30 June
135
–
124
(97)
162
114
21
84
(84)
135
Annual Report 2020 C2 Exploration and evaluation assets
Balance as at 1 July
Additions
Exploration expense
Net impairment loss(1)
Transfers to held for sale(2)
Balance as at 30 June(3)
99
2019
$m
363
33
(2)
(49)
(247)
98
2020
$m
98
92
–
–
–
190
(1) Prior period amount related to impairment of the Ironbark permit areas.
(2) The prior period closing balance excludes $247 million in relation to Ironbark permit areas.
(3) The current period closing balance primarily relates to the Group’s 77.5 per cent share in the Beetaloo Basin joint venture with Falcon Oil & Gas (Beetaloo asset).
The Group acquired an additional 7.5 per cent interest in the joint venture on 7 April 2020, in exchange for increasing its carry of Falcon’s share of costs by $25 million
over the coming years.
The Group holds a number of exploration permits that are grouped into areas of interest according to geographical and geological
attributes. Expenditure incurred in each area of interest is accounted for using the successful efforts method. Under this method all
general exploration and evaluation costs are expensed as incurred except the direct costs of acquiring the rights to explore, drilling
exploratory wells and evaluating the results of drilling. These direct costs are capitalised as exploration and evaluation assets pending
the determination of the success of the well. If a well does not result in a successful discovery, the previously capitalised costs are
immediately expensed.
The carrying amounts of exploration and evaluation assets are reviewed at each reporting date to determine whether any of the following
indicators of impairment are present:
• the right to explore has expired, or will expire in the near future, and is not expected to be renewed;
• further exploration for and evaluation of resources in the specific area is not budgeted or planned for;
• the Group has decided to discontinue activities in the area; or
• there is sufficient data to indicate the carrying value is unlikely to be recovered in full from successful development or by sale.
Where an indicator of impairment exists, the asset’s recoverable amount is estimated. If it is concluded that the carrying value of an
exploration and evaluation asset is unlikely to be recovered by future exploitation or sale, an impairment is recognised in the income
statement for the difference.
Key judgement
Recoverability of exploration and evaluation assets: Assessment of the recoverability of capitalised exploration and evaluation
expenditure requires certain estimates and assumptions to be made as to future events and circumstances, particularly in
relation to whether economic quantities of reserves have been discovered. Such estimates and assumptions may change as new
information becomes available.
Upon approval of the commercial development of a project, the exploration and evaluation asset is classified as a development asset.
Once production commences, development assets are transferred to PP&E.
Financial Statements 100
C3 Property, plant and equipment
Owned
Right of use
Plant and
equipment
Land and
buildings
Capital work
in progress
Plant and
equipment
Land and
buildings
$m
2020
Cost(1)
Accumulated depreciation(1)
Balance as at 30 June 2019
Adoption of AASB 16 Leases(2)
Balance as at 1 July 2019
Additions
Disposals
Modifications to lease terms
Depreciation/amortisation
Impairment(3)
Transfers within PP&E
Effect of movements in foreign
exchange rates
5,774
(2,331)
3,443
3,268
(44)
3,224
267
(1)
–
(295)
(19)
267
–
194
(51)
143
141
–
141
1
–
–
(4)
–
5
–
Balance as at 30 June 2020
3,443
143
2019
Cost
Accumulated depreciation
Balance as at 1 July 2018
Additions
Additions through acquisition of entities
Depreciation/amortisation
Impairment reversal(4)
Transfers within PP&E
Transfers to intangibles
Transfers to held for sale
Effect of movements in foreign
exchange rates
Balance as at 30 June 2019
5,447
(2,179)
3,268
3,284
122
21
(289)
13
148
(3)
(29)
1
3,268
204
(63)
141
149
–
–
(2)
–
–
–
(6)
–
141
278
–
278
188
(31)
157
393
–
–
–
–
(272)
–
278
188
–
188
263
96
–
–
–
(148)
(23)
–
–
188
155
(47)
108
–
127
127
20
(1)
8
(46)
–
–
–
108
–
–
–
–
–
–
–
–
–
–
–
–
–
407
(48)
359
–
318
318
1
–
78
(40)
–
–
2
359
–
–
–
–
–
–
–
–
–
–
–
–
–
Total
6,808
(2,477)
4,331
3,597
370
3,967
682
(2)
86
(385)
(19)
–
2
4,331
5,839
(2,242)
3,597
3,696
218
21
(291)
13
–
(26)
(35)
1
3,597
(1) A fixed asset review during the year resulted in a write-off of certain assets which have a remaining book value of nil and determined to not have any future economic
benefit to the Group. Consequently, $104 million was written off relating to plant and equipment and $16 million relating to land and buildings.
(2) For further information relating to the adoption of AASB 16 Leases, refer to the Overview.
(3) Impairment relating to the Mortlake generator asset write-off following an electrical fault.
(4) Reversal of the Heytesbury impairment of $13 million.
Owned PP&E
PP&E is recorded at cost less accumulated depreciation, depletion, amortisation and impairment charges. Cost includes the estimated
future cost of required closure and rehabilitation.
The carrying amounts of assets are reviewed to determine if there is any indication of impairment. If any such indication exists, the asset’s
recoverable amount is estimated and if required, an impairment is recognised in the income statement.
Annual Report 2020 101
C3 Property, plant and equipment (continued)
Depreciation is calculated on a straight-line basis so as to write off the cost of each asset over its expected useful life. Leasehold
improvements are amortised over the period of the relevant lease or estimated useful life, whichever is shorter. Land and capital work in
progress are not depreciated.
The estimated useful lives used in the calculation of depreciation are shown below.
Buildings, including leasehold improvements
10 to 50 years
Plant and equipment
3 to 30 years
At 30 June 2020, the Group reassessed the carrying amounts of its non-current assets for indicators of impairment.
Estimates of recoverable amounts are based on an asset’s value-in-use or fair value less costs to sell, whichever is higher. The recoverable
amount of these assets is most sensitive to those assumptions highlighted in the key judgements and estimates below.
Leased PP&E
The Group’s leased assets include commercial offices, power stations, LPG terminals and shipping vessels, motor vehicles and other items
of equipment.
ROU assets are recognised at commencement of a lease. ROU assets are initially valued at the corresponding lease liability amount
adjusted for any payments already made, lease incentives received, or initial direct costs incurred when entering into the lease. Where the
Group is required to restore the ROU asset at the end of the lease, the cost of restoration is also included in the value of the ROU asset.
ROU assets are depreciated on a straight-line basis over the shorter of the lease term or the useful life of the ROU asset. The carrying
amounts of ROU assets are reviewed to determine if there is any indication of impairment. If any such indication exists, the asset’s
recoverable amount is estimated, and if required, an impairment is recognised in the income statement.
Payments under the Group’s leases of renewable power plants are entirely variable as they depend on the amount of energy produced
each period. Such leases have nil lease liability balances and thus nil ROU asset balances. All payments made under these leases are
disclosed as variable lease expense within note A4.
Refer to note D2 for discussion of the recognition and measurement of associated lease liability balances.
Key judgements and estimates
During the year, management reviewed the recoverable amount of its non-current assets, including assessing the impacts of COVID-19.
Significant judgement is required in determining the following key assumptions used to calculate the value-in-use, which has been
updated to reflect the increase in uncertainty and the current risk environment:
• oil prices
• discount rates
• domestic gas prices
• future cash flows
• foreign exchange rates
• expected useful life
• electricity pool prices
Noting this uncertainty, the Group considers the assumptions used in the value-in-use models are appropriate for the purposes of
estimating the recoverable amount of non-current assets as at 30 June 2020.
Recoverability of carrying values: Assets are grouped together into the smallest group of individual assets that generate largely
independent cash inflows (cash generating unit or CGU). A CGU’s recoverable amount comprises the present value of the future
cash flows that will arise from use of the assets. Assessment of a CGU’s recoverable amount requires estimates and assumptions to
be made about highly uncertain external factors such as future commodity prices, foreign exchange rates, discount rates, regulatory
policies, and the outlook for global or regional market supply-and-demand conditions. Such estimates and assumptions may change as
new information becomes available. If it is concluded that the carrying value of a CGU is not likely to be recovered by use or sale, the
relevant amount will be written off to the income statement.
Estimation of commodity prices: The Group’s estimate of future commodity prices is made with reference to internally derived
forecast data, current spot prices, external market analysts’ forecasts and forward curves. Where volumes are contracted, future prices
reflect the contracted price. Future commodity price assumptions impact the recoverability of carrying values and are reviewed at least
twice annually.
Estimation of useful economic lives: A technical assessment of the operating life of an asset requires significant judgement. Useful
lives are amended prospectively when a change in the operating life is determined.
Restoration provisions: An asset’s carrying value includes the estimated future cost of required closure and rehabilitation activities.
Refer to note C6 for a judgement related to restoration provisions.
Lease term: Where lease arrangements contain options to extend the term or terminate the contract, the Group assesses whether it is
‘reasonably certain’ that the option to extend or terminate will be exercised. Consideration is given to all facts and circumstances that
create an economic incentive to extend or terminate the contract. Lease liabilities and ROU assets are measured using the reasonably
certain contract term.
Financial Statements 102
C4 Intangible assets
Goodwill
Software and other intangible assets(1)
Accumulated amortisation(1)
Reconciliations of the carrying amounts of each class of intangible asset are set out below.
$m
Balance as at 1 July 2019
Additions(2)
Disposals
Amortisation expense
Balance as at 30 June 2020
Balance as at 1 July 2018
Additions
Additions through acquisition of entities
Transfers from PP&E
Disposals
Net impairment loss(3)
Amortisation expense
Balance as at 30 June 2019
2020
$m
4,818
1,494
(892)
5,420
Goodwill
Software
and other
intangibles
4,818
–
–
–
4,818
4,820
–
–
–
–
(2)
–
4,818
563
171
(2)
(130)
602
508
119
43
26
(4)
(1)
(128)
563
2019
$m
4,818
1,407
(844)
5,381
Total
5,381
171
(2)
(130)
5,420
5,328
119
43
26
(4)
(3)
(128)
5,381
(1) An intangible asset review during the year resulted in a write-off of certain assets which have a remaining book value of nil and determined to not have any future
economic benefit to the Group. Consequently, $81 million was written off relating to software and other intangible assets.
(2) Additions during the period include amounts relating to the build of the Kraken technology platform following the agreement entered into with Octopus Energy, along
with amounts relating to the implementation of a new Enterprise Resource Planning system for the Group.
(3) Impairment of goodwill and other intangibles on the Pleiades investment in Chile.
Goodwill is stated at cost less any accumulated impairment losses and is not amortised. Software and other intangible assets are stated at
cost less any accumulated impairment losses and accumulated amortisation. Amortisation is recognised as an expense on a straight-line
basis over the estimated useful lives of the intangible assets.
The average amortisation rate for software and other intangibles (excluding capital work in progress) was 10 per cent (2019: 11 per cent).
Key judgements and estimates
The Group’s goodwill balance relates exclusively to the Energy Markets segment. The recoverable amount of the Energy Markets
goodwill has been determined using a value-in-use model that includes an appropriate terminal value. The value-in-use calculation is
sensitive to a number of key assumptions requiring management judgement, including future commodity prices, regulatory policies, and
the outlook for the market supply-and-demand conditions. Any impacts of COVID-19 have also been considered in formulating these
assumptions. Management does not believe that any reasonably possible changes in these assumptions would result in an impairment.
More information about the key inputs and assumptions in the value-in-use calculation are set out below.
Key inputs/assumptions
Long-term growth rates
Energy Markets
Cash flows are projected for the life of each generation asset or up to 15 years depending on the relevant
business unit.
The Energy Markets business is considered a long-term business and as such projections of long-term cash
flows is appropriate for a more accurate forecast. The growth rate used to extrapolate cash flows beyond
the initial period projected averages 2.5 per cent.
Customer numbers
This is based on a review of actual customer numbers and historical data regarding levels of customer
churn. The historical analysis is considered against current and expected market trends and competition for
customers.
Gross margin and
operating costs
This is based on a review of actual gross margins and cost per customer, and consideration of current and
expected market movements and impacts.
Discount rate
The pre-tax discount rate is 9.6 per cent (2019: 9.7 per cent).
Annual Report 2020 C5 Trade and other payables
Current
Trade payables and accrued expenses
Deferred consideration(1)
Other payables
Non-current
Deferred consideration(1)
Other payables
103
2019
$m
2,005
–
1
2,006
–
2
2
2020
$m
1,827
107
–
1,934
193
–
193
(1) Relates to the £150 million deferred cash consideration for the shares acquired in Octopus Energy on 1 May 2020 (refer to note B3) and £20 million deferred cash
consideration for the Kraken licence agreement with Octopus Energy (refer to note B4). Both amounts are payable over the next two financial years.
C6 Provisions
$m
Balance as at 30 June 2019
Adoption of AASB 16 (refer to Overview)
Balance as at 1 July 2019
Provisions recognised
Provisions released
Payments/utilisation
Unwinding of discounting
Effect of movements in foreign exchange rates
Balance as at 30 June 2020
Current
Non-current
Total provisions
Restoration(1)
Onerous
contracts
Other(2)
Total
428
–
428
274
(39)
(4)
2
–
661
–
–
–
650
–
–
–
(9)
641
144
(100)
44
141
(1)
(10)
–
–
174
572
(100)
472
1,065
(40)
(14)
2
(9)
1,476
163
1,313
1,476
(1) The closing balance includes amounts relating to the restoration of the Eraring Power Station site and other generation gas power station locations. Also included within
this balance are rehabilitation provisions for contamination at existing and legacy operating sites.
(2) The closing balance of other provisions primarily relates to costs for compliance with safety standard requirements relating to the Eraring ash dam wall, costs associated
with the new Myuna Bay Recreation Centre facility, and a make good provision relating to existing property leases.
Restoration provisions are initially recognised at the best estimate of the costs to be incurred in settling the obligation. Where restoration
activities are expected to occur more than 12 months from the reporting period, the provision is discounted using a risk-free rate
that reflects current market assessments of the time value of money. The unwinding of the discount is recognised in each period as
interest expense.
At each reporting date, the restoration provision is remeasured in line with changes in discount rates, and changes to the timing or amount
of costs to be incurred, based on current legal requirements and technology. Any changes in the estimated future costs associated with:
• restoration and dismantling are added to or deducted from the related asset;
• environmental rehabilitation are expensed in the current period.
Key estimate: Restoration, rehabilitation and dismantling costs
The Group estimates the cost of future site restoration activities at the time of installation or construction of an asset, or when an
obligation arises. Restoration often does not occur for many years and thus significant judgement is required as to the extent of work,
cost and timing of future activities.
Financial Statements 104
C6 Provisions (continued)
Onerous contracts
All contracts in which the unavoidable costs of meeting the obligations exceed the economic benefits are deemed onerous and require a
provision to be recognised up front.
As at 30 June 2020, an onerous contract provision of $641 million (US$440 million)(1) pre-tax was recognised in respect of the Cameron
LNG purchase contract, as the forecast sales revenue from the onward supply being estimated to be less than the purchase cost. This is
primarily driven by a weaker demand outlook in the short and medium term as a result of the economic slowdown caused by COVID-19,
and a lower long-term equilibrium price as a result of more competitive US export project economics. The onerous contract provision
is sensitive to a number of key assumptions requiring management judgement, including: future commodity prices, inflation and the
US Treasury risk-free bond rate. The provision valuation as at 30 June 2020 includes a long-term JKM LNG price of US$7.15/mmbtu (real
FY2020) from FY2026, a long-term Henry Hub gas price of US$2.60/mmbtu (real FY2020) from FY2026, and a range of US Treasury
risk-free bond rates that average approximately 0.81 per cent over the term of the contract.
A US$1.00/mmbtu increase in the spread between Henry Hub and JKM prices results in a A$213 million (US$146 million) post-
tax reduction in the charge. A 1 per cent increase applied to the relevant inflation and discount rate would result in a A$79 million
(US$54 million) post-tax reduction in the charge.
The Group will review the provision at each reporting date, and any future increases or decreases in the provision will be recognised
within the Group’s income statement. The non-cash charge during the year ended 30 June 2020 is recognised within statutory profit but
excluded from underlying profit. Future realised losses or gains will be recognised within underlying profit.
(1) The balance sheet onerous contracts provision of US$440 million was converted from USD to AUD using the end-of-period exchange rate of 0.6862. The onerous
contract expense of $650 million in note A4 is US$440 million converted from USD to AUD using the average rate of 0.676 prevailing for the relevant period.
C7 Other financial assets and liabilities
$m
Current
Non-current
Current
Non-current
2020
2019
Other financial assets
Measured at fair value through profit or loss
MRCPS issued by APLNG
Settlement Residue Distribution Agreement units
Environmental scheme certificates
Investment fund units
Debt securities
Measured at fair value through other comprehensive income
Equity securities
Measured at amortised cost
Futures collateral
Other financial liabilities
Measured at fair value through profit or loss
Environmental scheme surrender obligations
Measured at amortised cost
Futures collateral
Financial guarantees(1)
44
34
103
–
–
–
298
479
234
3
–
237
2,065
26
–
55
17
62
–
2,225
–
–
16
16
34
24
244
–
–
–
16
318
241
67
–
308
3,011
30
–
57
2
52
–
3,152
–
–
–
–
(1) Financial guarantee contracts are initially recognised at fair value. Subsequently they are measured at either the amount of any determined loss allowance or at the
amount initially recognised less any cumulative income recognised, whichever is larger. The above financial guarantee relates to the working capital facility entered into
by Octopus Energy with its financiers, as referred to in note B4, for which the Group has provided a guarantee.
Annual Report 2020 105
D Capital, funding and risk management
This section focuses on the Group’s capital structure and related financing costs. Information is also presented about how the Group
manages capital, and the various financial risks to which the Group is exposed through its operating and financing activities.
D1 Capital management
The Group’s objective when managing capital is to make disciplined capital allocation decisions between debt reduction, investment in
growth and distributions to shareholders, and to maintain an optimal capital structure while maintaining access to capital. Management
believes that a strong investment-grade credit rating (BBB/Baa2) and an appropriate level of net debt are required to meet these
objectives. The Group’s current credit rating is BBB (stable outlook) from Standard & Poor’s, and Baa2 (stable outlook) from Moody’s.
Key factors considered in determining the Group’s capital structure and funding strategy at any point in time include expected operating
cash flows, capital expenditure plans, the maturity profile of existing debt facilities, the dividend policy, and the ability to access funding
from banks, capital markets and other sources.
The Group monitors its capital requirements through a number of metrics including the gearing ratio (target range of approximately 20 to
30 per cent) and an adjusted net debt to adjusted underlying EBITDA ratio (target range of 2.0x to 3.0x). These targets are consistent with
attaining a strong investment-grade rating. Underlying EBITDA is a non-statutory (non-IFRS) measure.
The gearing ratio is calculated as adjusted net debt divided by adjusted net debt plus total equity. Net debt, which excludes cash held by
Origin to fund APLNG-related operations, is adjusted to take into account the effect of FX hedging transactions on the Group’s foreign
currency debt obligations. The adjusted net debt to adjusted underlying EBITDA ratio is calculated as adjusted net debt divided by
adjusted underlying EBITDA (Origin’s underlying EBITDA less Origin’s share of APLNG underlying EBITDA plus net cash flow from APLNG)
over the relevant rolling 12-month period.
The Group monitors its current and future funding requirements for at least the next five years and regularly assesses a range of funding
alternatives to meet these requirements in advance of when the funds are required.
Borrowings
Lease liabilities
Total interest-bearing liabilities
Less: Cash and cash equivalents excluding APLNG-related cash(1)
Net debt
Fair value adjustments on FX hedging transactions
Adjusted net debt
Total equity
Total capital
Gearing ratio
Ratio of adjusted net debt to adjusted underlying EBITDA
2020
$m
6,338
514
6,852
(1,164)
5,688
(530)
5,158
12,701
17,859
29%
2.1x
2019
$m
7,590
6
7,596
(1,512)
6,084
(667)
5,417
13,149
18,566
29%
2.6x
(1) This balance excludes $76 million (2019: $34 million) of cash held by Origin, as Upstream Operator, to fund APLNG-related operations.
Significant funding transactions
The Group undertook a number of capital management activities during the year ended 30 June 2020. These activities have strengthened
the capital profile by:
• refinancing existing capital market borrowings to extend the weighted average tenor of the Group’s debt portfolio; and
• reducing or cancelling surplus committed undrawn syndicated bank loan facilities.
A summary of these transactions is shown below.
Debt refinancing
16 September 2019 – repaid the €1 billion hybrid Capital Securities at the first call date. The instrument had a swap value of
A$1,391 million.
17 September 2019 – issued a €600 million 10-year note under the Euro Medium Term Note (EMTN) program. These notes were swapped
to A$973 million.
11 October 2019 – repaid the €500 million seven-year note under the EMTN program. The notes had been swapped to US$646 million
(A$939 million).
11 November 2019 – issued a A$300 million eight-year note under the EMTN program.
28 June 2020 – repaid the NZ$141 million 15-year US Private Placement note. The note was swapped to A$125 million.
Financial Statements 106
D1 Capital management (continued)
Bank loan and guarantee facilities
8 November 2019 – renegotiated the existing A$500 million Bank Guarantee Facility and Reimbursement Agreement to new three-year
A$375 million and five-year A$125 million facilities. The renegotiation also resulted in lower commitment and usage fees.
20 November 2019 – cancelled A$150 million and US$385 million of undrawn syndicated debt facilities.
D2 Interest-bearing liabilities
Current
Capital market borrowings – unsecured
Total current borrowings
Lease liabilities – secured
Total current interest-bearing liabilities
Non-current
Bank loans – unsecured
Capital market borrowings – unsecured(1)
Total non-current borrowings
Lease liabilities – secured
Total non-current interest-bearing liabilities
2020
$m
1,328
1,328
73
1,401
535
4,475
5,010
441
5,451
2019
$m
947
947
1
948
525
6,117
6,642
6
6,648
(1) The prior period includes €1 billion Capital Securities that were redeemed at their first call date of 16 September 2019.
Interest-bearing liabilities are initially recorded at the amount of proceeds received (fair value) less transaction costs. After that date, the
liability is amortised to face value at maturity using an effective interest rate method.
Lease liabilities are initially measured at the present value of future lease payments discounted at the Group’s incremental borrowing rate.
Where a lease includes termination and/or extension options, the impact of these options on the amount of future payments is included
where exercise of such options is considered reasonably certain to occur. Interest expense is charged on outstanding lease liabilities that
reduce over time as periodic payments are made.
The lease liability is remeasured when certain events occur, including changes in the lease term or changes in future lease payments
such as those resulting from inflation-linked indexation or market rate rent reviews. On remeasurement of lease liabilities, a corresponding
adjustment is made to the ROU asset.
Payments under the Group’s leases of renewable power plants are entirely variable as they depend on the amount of energy produced
each period. Such leases have nil lease liability balances and payments totalling $22 million for energy generation have been recognised
within expenses in the financial period. Additionally, $1 million of payments for leases of low-value assets have also been recognised
within expenses.
The contractual maturity of lease liabilities are disclosed within the liquidity table in note D4.
The contractual maturities of non-current borrowings are as set out below.
One to two years
Two to five years
Over five years
Total non-current borrowings
2020
$m
2,069
356
2,585
5,010
2019
$m
1,325
2,405
2,912
6,642
Some of the Group’s borrowings are subject to terms that allow the lender to call on the debt in the event of a breach of covenants. As at
30 June 2020, these terms had not been triggered.
Annual Report 2020
107
D3 Contributed equity
Ordinary share capital
Opening balance(1)
Shares issued in accordance with the DRP
Shares issued in accordance with incentive plans
Less treasury shares:
Opening balance(1)
Shares purchased on market
Utilisation of treasury shares on vesting of employee share
schemes and DRP
2020
2019
2020
2019
Number of shares
$m
1,761,211,071
–
–
1,759,156,516
1,769,296
285,259
1,761,211,071
1,761,211,071
(4,809,617)
(12,291,634)
–
(9,611,526)
13,888,321
4,801,909
(3,212,930)
(4,809,617)
7,163
–
–
7,163
(38)
(75)
95
(18)
7,150
13
–
7,163
–
(77)
39
(38)
Closing balance
1,757,998,141
1,756,401,454
7,145
7,125
(1) The sum of the opening balances of share capital and treasury shares is $7,125 million (2019: $7,150 million) as noted in the statement of changes in equity.
Ordinary shares
Holders of ordinary shares are entitled to receive dividends as determined from time to time and are entitled to one vote per share at
shareholders’ meetings. In the event of the winding up of the Group, ordinary shareholders rank after creditors, and are fully entitled to any
proceeds of liquidation. The Group does not have authorised capital or par value in respect of its issued shares.
Treasury shares
Where the Group or other members of the Group purchase shares in the Company, the consideration paid is deducted from the total
shareholders’ equity and the shares are treated as treasury shares until they are subsequently sold, reissued or cancelled. Treasury shares
are purchased primarily for use on vesting of employee share schemes and the DRP. Shares are accounted for at a weighted average cost.
D4 Financial risk management
Overview
The Group’s day-to-day operations, new investment opportunities and funding activities introduce financial risks, which are actively
managed by the Board Risk Committee. These risks are grouped into the following categories:
• Credit: The risk that a counterparty will not fulfil its financial obligations under a contract or other arrangement.
• Market: The risk that fluctuations in commodity prices, foreign exchange rates and interest rates will adversely impact the
Group’s result.
• Liquidity: The risk that the Group will not be able to meet its financial obligations as they fall due.
Risk
Credit
Sources
Risk management framework
Financial exposure
Sale of goods and
services and hedging
activities
The Board approves credit risk management policies
that determine the level of exposures it is prepared to
accept. It also allocates credit limits to counterparties
based on publicly available credit information from
recognised providers where available.
Notes C1, C7 and D4 disclose the carrying amounts
of financial assets, which represent the Group’s
maximum exposure to credit risk at the reporting date.
The Group utilises International Swaps and Derivative
Association (ISDA) agreements to limit exposure to
credit risk by netting amounts receivable from and
payable to individual counterparties (refer to note G8).
See below for further discussion of market risk.
Analysis of the Group’s liquidity profile as at the
reporting date is presented at the end of this section.
Market
Purchase and sale
of commodities and
funding risks
Liquidity
Ongoing business
obligations and
new investment
opportunities
The Board approves policies that ensure the Group
is not exposed to excess risk from market volatility.
These policies include active hedging of price and
volume exposures within prescribed Profit at Risk and
Value at Risk limits.
The Group centrally manages its liquidity position
through cash flow forecasting and maintenance
of minimum levels of liquidity determined by the
Board. The debt portfolio is periodically reviewed to
ensure there is funding flexibility and an appropriate
maturity profile.
Financial Statements 108
D4 Financial risk management (continued)
Market risk
The scope of the Group’s operations and activities exposes it to multiple markets risks. The table below summarises these risks by nature of
exposure and provides information about the risk mitigation strategies being applied.
Nature
Sources of financial exposure
Risk management strategy
Commodity
price
Future commercial transactions and
recognised assets and liabilities exposed
to changes in electricity, oil, gas, coal or
environmental scheme certificate prices
Due to vertical integration, a significant portion of the Group’s spot electricity
purchases from the National Electricity Market (NEM) are naturally hedged by
generation sales into the NEM at spot prices.
Foreign
exchange
Foreign-denominated borrowings and
investments (e.g. APLNG MRCPS) and future
foreign currency-denominated commercial
transactions
The Group manages its remaining exposure to commodity price fluctuations beyond
Board-approved limits using a mix of commercial contracts (such as fixed-price
purchase contracts) and derivative instruments (described below).
The Group limits its exposure to changes in foreign exchange rates through forward
foreign exchange contracts and cross-currency interest rate swaps.
In certain circumstances, borrowings are left in a foreign currency, or swapped from
one foreign currency to another, to hedge expected future business cash flows in
that currency. Significant foreign-denominated transactions undertaken in the normal
course of operations are managed on a case-by-case basis.
Interest
rate
Variable-rate borrowings (cash flow risk) and
fixed-rate borrowings (fair value risk)
Interest rate exposures are kept within an acceptable range as determined by the
Board. Risk limits are managed through a combination of fixed-rate and fixed-to-
floating interest rate swaps.
Derivatives to manage market risks
Derivative instruments are contracts whose value is derived from an underlying price index (or other variable) that require little or no initial
net investment, and that are settled at a future date.
The Group uses the following types of derivative instruments to mitigate market risk.
Forwards
A contract documenting the underlying reference rate (such as benchmark price or exchange rate) to be paid or received on a
notional principal obligation at a future date.
Futures
An exchange-traded contract to buy or sell an asset for an agreed price at a future date. Futures are net-settled in cash without
physical delivery of the underlying asset.
Swaps
A contract in which two parties exchange a series of cash flows for another (such as fixed-for-floating interest rate).
Options
A contract in which the buyer has the right, but not the obligation, to buy (a call option) or sell (a put option) an instrument at a fixed
price in the future. The seller has the corresponding obligation to fulfil the transaction if the buyer exercises the option.
Structured
electricity
products
A non-standardised contract, generally with an energy market participant, to acquire long-term capacity. These contracts typically
contain features similar to swaps and call options.
Derivatives are carried on the balance sheet at fair value. Movements in the price of the underlying variables, which cause the value of the
contract to fluctuate, are reflected in the fair value of the derivative.
The method of recognising changes in fair value depends on whether the derivative is designated in an ‘accounting’ hedge relationship.
Derivatives not designated as accounting hedges are referred to as ‘economic’ hedges.
Fair value gains and losses attributable to economic hedges are recognised in the income statement and resulted in a $292 million gain for
the year ended 30 June 2020 (2019: $107 million loss). Fair value gains and losses attributable to accounting hedges are discussed in the
Hedge Accounting section.
Annual Report 2020 109
D4 Financial risk management (continued)
$m
Current
Non-current
Current
Non-current
Assets
Liabilities
2020
Economic hedges
Commodity contracts
Foreign exchange and interest rate contracts
Accounting hedges
Commodity contracts
Foreign exchange and interest rate contracts
2019
Economic hedges
Commodity contracts
Foreign exchange and interest rate contracts
Accounting hedges
Commodity contracts
Foreign exchange and interest rate contracts
247
2
249
98
283
381
630
69
6
75
160
237
397
472
258
–
258
43
227
270
528
315
–
315
119
528
647
962
(170)
(72)
(242)
(224)
–
(224)
(466)
(220)
(107)
(327)
(57)
–
(57)
(173)
(124)
(297)
(402)
(50)
(452)
(749)
(848)
(219)
(1,067)
(52)
–
(52)
(384)
(1,119)
Hedge accounting
The Group currently uses two types of hedge accounting relationships as detailed below.
Fair value hedge
Cash flow hedge
Objective
of hedging
arrangement
To hedge our exposure to changes in the fair value
of a recognised asset or liability or unrecognised firm
commitment, caused by interest rate or foreign currency
movements.
To hedge our exposure to variability in the cash flows of a
recognised asset or liability, or a highly probable forecast
transaction caused by commodity price, interest rate, and
foreign currency movements.
Effective
hedge portion
The following are recognised in profit or loss at the
same time:
– all changes in the fair value of the underlying item relating
to the hedged risk; and
– the change in fair value of derivatives.
The effective portion of changes in the fair value of derivatives
designated as cash flow hedges are recognised in the
hedge reserve.
Hedge
ineffectiveness
Certain determinants of fair value, such as credit charges included in derivatives or mismatches between the timing of
the instrument and the underlying item in the hedge relationship, can cause hedge ineffectiveness. Any ineffectiveness is
recognised immediately in profit or loss as a change in the fair value of derivatives.
Hedged item
sold or repaid
The unamortised fair value adjustment is recognised
immediately in profit or loss.
Amounts accumulated in the hedge reserve are transferred
immediately to profit or loss.
Hedging instrument
expires, is sold,
terminated or no
longer qualifies for
hedge accounting
The unamortised fair value adjustment is recognised in profit
or loss when the hedged item is recognised in profit or loss.
This may occur over time if the hedged item is amortised
over the period to maturity.
The amount previously deferred in the hedge reserve is only
transferred to profit or loss when the hedged item is also
recognised in profit or loss.
Financial Statements 110
D4 Financial risk management (continued)
Set out below are the fair values of derivatives designated in hedge accounting relationships at reporting date.
2020
$m
Fair value hedges
Cash flow hedges
Accounting hedges
Fair value hedges
Assets
Liabilities
Current
Non-current
Current
Non-current
283
98
381
175
95
270
–
(224)
(224)
–
(452)
(452)
Certain cross-currency interest rate swaps (CCIRSs) have been designated as fair value hedges of the Group’s euro-denominated debt.
CCIRSs
Nominal hedge volumes
Hedge rates
Timing of cash flows
Carrying amounts
Hedging instrument(1)
Hedged debt(2)
Fair value increase/(decrease)
Hedging instrument
Hedged debt
Hedge ineffectiveness(3)
FX and interest
EUR 1,550m
AUD/EUR
0.69–0.79;
BBSW
Up to Oct 2021
$m
458
(2,575)
$m
(17)
14
(3)
(1) Hedging instruments are included in the derivatives balance on the statement of financial position.
(2) Hedged items are included in Interest-bearing liabilities on the statement of financial position. Included in this value are $38 million of accumulated fair value
hedge adjustments.
(3) Hedge ineffectiveness is recognised within expenses in the income statement as a change in fair value of derivatives.
Cash flow hedges
A number of derivative contracts have been designated as cash flow hedges of the Group’s exposure to foreign exchange, interest rate and
commodity price fluctuations. Designated derivatives include swaps, options, futures and forwards.
The Group’s structured electricity products, though important to the overall risk management strategy, do not qualify for hedge
accounting. As such, they are not represented in the summary information below.
2020
FX & interest
Electricity
Crude oil
Propane
Nominal hedge volumes
EUR 750m
12.3 TWh
10,955k
barrels
150k mt
Hedge rates
$32–$175
US$44–US$72 US$265–US$476
AUD/EUR
0.62–0.81;
Fixed
3.2%–6.6%
Timing of cash flows – up to
Sep 2029
Dec 2023
Jun 2023
Dec 2022
Annual Report 2020 D4 Financial risk management (continued)
Hedge accounting (continued)
Carrying amounts – $m
FX & interest
Electricity
Crude oil
Propane
Hedging instrument(1) – assets
Hedging instrument(1) – liabilities
Hedge reserve(2)
Fair value increase/(decrease) – $m
Hedging instrument
Hedged item
Hedge ineffectiveness(3)
Reconciliation of hedge reserve – $m
Effective portion of hedge gains/(losses)
Transfer of deferred losses/(gains) to:
– Cost of sales
– Finance costs
– Foreign exchange
Tax on above items
Change in hedge reserve (post-tax)
52
(50)
67
(63)
64
1
(63)
–
2
11
15
(35)
34
(289)
255
(394)
394
–
(394)
(30)
–
–
128
(296)
105
(326)
203
(246)
240
(6)
(240)
15
–
–
68
(157)
2
(11)
9
(9)
8
(1)
(8)
7
–
–
–
(1)
111
Total
193
(676)
534
(712)
706
(6)
(705)
(8)
2
11
211
(489)
(1) Hedging instruments are included in the derivatives balance on the statement of financial position.
(2) No hedges have been discontinued or de-designated in the current period.
(3) Hedge ineffectiveness is recognised within expenses in the income statement as a change in fair value of derivatives.
Residual market risk
After hedging, the Group’s financial instruments remain exposed to changes in market pricing. The following is a summary of the
Group’s residual market risk and the sensitivity of financial instrument fair values to reasonably possible changes in market pricing at the
reporting date.
Risk
Residual exposure
Relationship to financial instruments value
USD exchange rate
– MRCPS financial asset
– USD debt
– Euro debt and related USD CCIRSs
– FX and commodity derivatives with USD pricing
Euro exchange rate
– Currency basis on the CCIRSs swapping euro
debt to AUD
Interest rates
– Interest rate swaps
– Long-term derivatives and other financial assets/
liabilities for which discounting is significant
Electricity forward price
– Commodity derivatives including structured
electricity products
Oil forward price
– Commodity derivatives
REC forward price
– REC forwards
– Environmental scheme certificates
– Environmental scheme surrender obligations
A 10 per cent increase/decrease in the USD exchange
rate would decrease/increase fair value by $19 million
(June 2019: $25 million).
A 10 per cent increase/decrease in the euro exchange
rate would decrease/increase fair value by $17 million
(June 2019: $22 million).
A 100 basis point increase/decrease in interest rates
would impact fair value by ($43)/$38 million (June 2019:
($14)/$11 million).
A 10 per cent increase/decrease in electricity
forward prices would increase/decrease fair value by
$93/($95) million (June 2019: $264 million).
A 10 per cent increase/decrease in oil forward prices
would decrease/increase fair value by $54/(52) million
(June 2019: $3 million).
A 10 per cent increase/decrease in renewable energy
certificate forward prices would increase/decrease fair
value by $1 million (June 2019: $16 million).
Financial Statements 112
D4 Financial risk management (continued)
Liquidity risk
The table below sets out the timing of the Group’s payment obligations, as compared to the receipts expected from the Group’s financial
assets, and available undrawn facilities. Amounts are presented on an undiscounted basis and include cash flows not recorded on the
statement of financial position such as interest payments for borrowings.
2020
$m
Bank loans and capital markets borrowings
Lease liabilities
Net other financial assets/liabilities
Derivative liabilities
Derivative assets
Less than
one year
One to
two years
Two to
five years
Over
five years
(1,522)
(99)
82
(1,539)
(782)
918
136
(2,183)
(84)
395
(1,872)
(379)
325
(54)
(589)
(166)
1,494
739
(200)
143
(57)
682
(2,840)
(313)
–
(3,153)
(71)
30
(41)
(3,194)
Net liquidity exposure
(1,403)
(1,926)
The amount of cash and committed undrawn floating rate borrowing facilities expiring beyond one year is $4,059 million.
2019
$m
Bank loans and capital markets borrowings
Lease liabilities
Net other financial assets/liabilities
Derivative liabilities
Derivative assets
Net liquidity exposure
Less than
one year
One to
two years
Two to
five years
Over
five years
(2,692)
(1)
1,321
(1,372)
(582)
708
126
(1,246)
(1,526)
(1)
1,194
(333)
(360)
518
158
(175)
(2,724)
(4)
1,287
(1,441)
(233)
459
226
(1,508)
(4)
–
(1,512)
(471)
304
(167)
(1,215)
(1,679)
The amount of cash and committed undrawn floating rate borrowing facilities expiring beyond one year is $5,301 million.
D5 Fair value of financial assets and liabilities
Financial assets and liabilities measured at fair value are grouped into the following categories based on the level of observable market data
used in determining that fair value:
• Level 1: The fair value of financial instruments traded in active markets (such as exchange-traded derivatives and RECs) is the quoted
market price at the end of the reporting period. These instruments are included in level 1.
• Level 2: The fair value of financial instruments that are not traded in an active market (such as over-the-counter derivatives) is
determined using valuation techniques that maximise the use of observable market data. If all significant inputs required to fair value an
instrument are observable, either directly (as prices) or indirectly (derived from prices), the instrument is included in level 2.
• Level 3: If one or more of the significant inputs required to fair value an instrument is not based on observable market data, the
instrument is included in level 3.
Annual Report 2020 D5 Fair value of financial assets and liabilities (continued)
2020
Derivative financial assets
Other financial assets at fair value
Financial assets carried at fair value
Derivative financial liabilities
Other financial liabilities at fair value
Financial liabilities carried at fair value
2019
Derivative financial assets
Other financial assets at fair value
Financial assets carried at fair value
Derivative financial liabilities
Other financial liabilities at fair value
Financial liabilities carried at fair value
Note
Level 1
$m
Level 2
$m
D4
C7
D4
C7
20
163
183
(202)
(234)
(436)
1,004
72
1,076
(944)
–
(944)
Note
Level 1
$m
Level 2
$m
D4
C7
D4
C7
131
298
429
(30)
(241)
(271)
1,088
57
1,145
(763)
–
(763)
Level 3
$m
134
2,171
2,305
(69)
–
(69)
Level 3
$m
215
3,099
3,314
(710)
–
(710)
The following table shows a reconciliation of movements in the fair value of level 3 instruments during the period.
Balance as at 1 July 2019
PPAs derecognised on adoption of AASB 16 Leases (refer to Overview)
New instruments recognised in the period
Instruments transferred out of level 3
Net cash settlements paid/(received)
Gains/(losses) recognised in other comprehensive income
Gains/(losses) recognised in profit or loss:
– Change in fair value
– Cost of sales
– Interest income
Balance as at 30 June 2020
Valuation techniques used to determine fair values
113
Total
$m
1,158
2,406
3,564
(1,215)
(234)
(1,449)
Total
$m
1,434
3,454
4,888
(1,503)
(241)
(1,744)
$m
2,604
512
5
(2)
(1,214)
6
192
(42)
175
2,236
The various techniques used to value the Group’s financial instruments are summarised in the following table. To the maximum extent
possible, valuations are based on assumptions that are supported by independent and observable market data. For instruments that settle
more than 12 months from the reporting date, cash flows are discounted at the applicable market yield, adjusted to reflect the credit risk of
the specific counterparty.
Instrument
Fair value methodology
Financial instruments traded in
active markets
Interest rate swaps and CCIRS
Quoted market prices at reporting date
Present value of expected future cash flows based on observable yield curves and forward exchange rates
at reporting date
Forward foreign exchange contracts
Present value of future cash flows based on observable forward exchange rates at reporting date
Electricity, oil and other commodity
derivatives (not traded in
active markets)
Present value of expected future cash flows based on observable forward commodity price curves (where
available). The majority of the Group’s level 3 instruments are commodity contracts for which further detail
on the significant unobservable inputs is included below
Other financial instruments
Discounted cash flow analysis
Long-term borrowings
Present value of future contract cash flows
Financial Statements 114
D5 Fair value of financial assets and liabilities (continued)
Fair value measurements using significant unobservable inputs (level 3)
The following is a summary of the Group’s level 3 financial instruments, the significant inputs for which market observable data is
unavailable, and the sensitivity of the estimated fair values to the assumptions applied by management.
Instrument(1)
Unobservable inputs
Relationship to fair value
Electricity derivatives
– Forward electricity spot market price curve
– Forward electricity cap price curve
– Forecast REC prices
– Contract volumes
– Generation operating costs
A 10 per cent increase/decrease in the unobservable inputs would
increase/decrease fair value by $68 million (2019: $299 million).
Oil derivatives
– Forward Japanese Customs-cleared Crude
(JCC) price curve
A 10 per cent increase/decrease in the JCC price would decrease/
increase fair value by $2 million (2019: $15 million).
MRCPS issued by APLNG
– Forecast APLNG free cash flows
A 10 per cent improvement/deterioration in the level of APLNG
forecast cash flows would impact fair value by $1 million (2019:
$3/($4) million.
(1) Excludes $63 million (June 2019: $52 million) of unlisted equity securities, and associated share warrants, for which management has assessed the investment cost to be
a reasonable reflection of fair value at reporting date.
Day 1 fair value adjustments
For certain complex financial instruments, such as the structured electricity products, the fair value that is determined at inception of the
contract using unobservable inputs does not equal the transaction price. When this occurs, the difference is deferred to the statement
of financial position and recognised in the income statement over the life of the contract in a manner consistent with the valuation
methodology initially applied.
Reconciliation of net deferred gain
Balance as at 1 July 2019
Value recognised in the income statement
Value derecognised in the period(1)
New instruments
Balance as at 30 June 2020
Location of net deferred gain
Derivative assets
Derivative liabilities
Balance as at 30 June 2020
$m
573
(55)
(492)
76
102
86
16
102
(1) Net deferred gains derecognised on adoption of AASB 16 as they relate to PPAs classified as leases under the new standard. Refer to the Overview.
Financial instruments measured at amortised cost
Except as noted below, the carrying amounts of financial assets and liabilities measured at amortised cost are reasonable approximations
of their fair values due to their short-term nature.
Carrying value
Fair value
hierarchy level
2020
$m
2019
$m
Fair value
2020
$m
Liabilities
Bank loans – unsecured
Capital markets borrowings – unsecured
Total(1)
2
2
535
4,475
5,010
525
6,117
6,642
557
4,678
5,235
2019
$m
559
6,392
6,951
(1) Non-current interest-bearing liabilities in the statement of financial position include $5,010 million (June 2019: $6,642 million) as disclosed above, and lease liabilities of
$441 million (June 2019: $6 million).
The fair value of these financial instruments reflects the present value of expected future cash flows based on market pricing data for the
relevant underlying interest and foreign exchange rates. Cash flows are discounted at the applicable credit-adjusted market yield.
Annual Report 2020 115
E Taxation
This section provides details of the Group’s income tax expense, current tax provision, deferred tax balances and tax accounting policies.
E1 Income tax expense
Income tax
Current tax expense(1)
Adjustments to current tax expense for previous years(1)
Deferred tax expense/(benefit)
Total income tax expense
Reconciliation between tax expense and pre-tax net profit
Profit before income tax
Income tax using the domestic corporation tax rate of 30 per cent (2019: 30 per cent)
Prima facie income tax expense on pre-tax accounting profit:
– at Australian tax rate of 30 per cent
– adjustment for difference between Australian and overseas tax rates
Income tax expense on pre-tax accounting profit at standard rates
Increase/(decrease) in income tax expense due to:
Share of results of equity accounted investees
Impairment of investment in APLNG
Capital loss recognition
Temporary differences no longer expected to be realised
Other
Over provided in prior years
Total income tax expense
Deferred tax movements recognised directly in other comprehensive income
(including foreign currency translation)
Financial instruments at fair value
Other items
2020
$m
3
(34)
124
93
2019
$m
208
(49)
(95)
64
179
1,278
54
(1)
53
(182)
224
–
–
4
46
(6)
93
(211)
3
(208)
383
(1)
382
(188)
–
(68)
(29)
(12)
(297)
(21)
64
45
–
45
(1) For comparability purposes, the prior year amounts have been reclassified between these two line items to align with the presentation of the current year.
The Company and its wholly owned Australian resident entities that met the membership requirements formed a tax-consolidated group
with effect from 1 July 2003. The head entity within the tax-consolidated group is Origin Energy Limited. Tax funding arrangement
amounts are recognised as inter-entity amounts.
Income tax expense is made up of current tax expense and deferred tax expense. Current tax expense represents the expected tax
payable on the taxable income for the year, using current tax rates and any adjustment to tax payable in respect of previous years. Deferred
tax expense reflects the temporary differences between the accounting carrying amount of an asset or liability in the statement of financial
position and its tax base.
Key judgements
Tax balances: Tax balances reflect a current understanding and interpretation of existing tax laws. Uncertainty arises due to the
possibility that changes in tax law or other future circumstances can impact the tax balances recognised in the financial statements.
Ultimate outcomes may vary.
Deferred taxes: The recognition of deferred tax balances requires judgement as to whether it is probable such balances will be utilised
and/or reversed in the foreseeable future.
Financial Statements 116
E1 Income tax expense (continued)
Income tax expense recognised in other comprehensive income
$m
Investment valuation changes
Cash flow hedges:
Reclassified to income statement
Effective portion of change in fair value
Translation of foreign operations
Other comprehensive income
for the year
E2 Deferred tax
2020
2019
Gross
6
5
(705)
125
Tax
(3)
(1)
212
–
Net
3
4
(493)
125
Gross
5
(172)
318
341
(569)
208
(361)
492
Tax
–
50
(95)
–
(45)
Net
5
(122)
223
341
447
Deferred tax balances arise when there are temporary differences between accounting carrying amounts and the tax bases of assets and
liabilities, other than where:
• the difference arises from the initial recognition of an asset or liability in a transaction that is not a business combination and affects
neither the accounting profit nor taxable profit or loss;
• temporary differences relate to investments in subsidiaries, associates and interests in joint arrangements, to the extent the Group is
able to control the timing of the reversal of the temporary differences and it is probable that they will not reverse in the foreseeable
future; and
• temporary differences arise on initial recognition of goodwill.
Deferred tax assets and liabilities are measured at the tax rates that are expected to apply to the year when the asset is realised or the
liability is settled, based on tax rates and tax laws that have been enacted or substantively enacted at the balance sheet date.
A deferred tax asset is recognised only to the extent that it is probable that future taxable profits will be available against which the asset
can be utilised. Deferred tax assets are reduced if it is no longer probable that the related tax benefit will be realised.
Movement in temporary differences during the year
Asset/(liability)
$m
1 July
2018
Adoption of
AASB 9
Recognised
in income
Recognised
in equity
30 June
2019
Adoption of
AASB 16
Recognised
in income
Recognised
in equity
30 June
2020
Employee benefits
Provisions
Tax value of carry-forward
tax losses recognised
PP&E
Exploration and
evaluation assets
Financial instruments
at fair value
APLNG MRCPS
elimination (refer
to note B2.1)
Business-related
costs (deductible
under s.40-880 ITAA97)
ROU assets
Lease liabilities
Other items
61
146
–
(417)
51
–
6
–
–
–
309
47
52
53
–
2
20
–
–
–
–
–
Net deferred tax assets
277
53
4
56
1
11
69
(26)
(2)
(10)
–
–
(8)
95
–
–
–
–
–
65
208
1
(406)
120
–
(30)
–
23
–
(45)
285
(154)
–
–
–
–
–
50
43
–
2
12
(45)
380
–
–
(134)
144
2
(149)
14
310
45
(120)
(174)
(175)
(1)
(16)
(6)
8
(9)
–
–
–
–
–
79
488
46
(503)
(54)
211
167
–
49
–
–
–
(3)
27
(140)
154
2
315
(124)
208
Annual Report 2020 E2 Deferred tax (continued)
Unrecognised deferred tax assets and liabilities
Deferred tax assets have not been recognised in respect of the following items:
Revenue losses – non-Australian
Capital losses
Petroleum resource rent tax, net of income tax
Acquisition transaction costs
Investment in joint ventures
Intangible assets
Deferred tax liabilities have not been recognised in respect of the following items:
Investment in APLNG(1)
117
2019
$m
32
213
131
57
67
8
508
(1,611)
(1,611)
2020
$m
26
216
118
57
67
8
492
(1,615)
(1,615)
(1) A deferred tax liability has not been recorded in respect of the investment in APLNG as the Group is able to control the timing of the reversal of the temporary difference
through its voting rights and it is not expected that the temporary difference will reverse in the foreseeable future. It is possible that the temporary difference could reverse
partly or in full at some point in the future, if and when unfranked dividends or capital returns are expected to be paid, or if the investment is expected to be disposed of.
Uncertain tax positions
In calculating the taxable profit for the year to 30 June 2020, Origin has included a $468 million tax depreciation claim for the remaining
tax base of the Browse Basin exploration permits. A tax ruling application has been submitted to the Australian Taxation Office to confirm
the appropriateness of the tax treatment. Should the outcome of the ruling be unfavourable and the depreciation claim revert to the
annual claim of $46 million over 15 years, the Origin Tax Consolidated Group would have a taxable profit of $272 million instead of a tax
loss of $150 million. This is because the deferred tax asset balance would increase while the current income tax receivable balance would
decrease by $82 million ($272 million at 30 per cent).
Financial Statements 118
F Group structure
The following section provides information on the Group’s structure and how this impacts the results of the Group as a whole, including
details of joint arrangements, associates, controlled entities, transactions with non-controlling interests, and changes made to the Group
structure during the year.
F1 Controlled entities
The financial statements of the Group include the consolidation of Origin Energy Limited and controlled entities. Controlled entities are the
following entities controlled by the parent entity (Origin Energy Limited).
2020
Ownership
interest
per cent
2019
Ownership
interest
per cent
Incorporated in
Origin Energy Limited
Origin Energy Finance Limited
Huddart Parker Pty Limited <
FRL Pty Ltd <
B.T.S. Pty Ltd <
Origin Energy Power Limited <
Origin Energy SWC Limited <
BESP Pty Ltd
Origin Energy Eraring Pty Limited <
Origin Energy Eraring Services Pty Limited <
Origin Energy Upstream Holdings Pty Ltd
Origin Energy B2 Pty Ltd
Origin Energy Browse Pty Ltd
Origin Energy CSG 2 Pty Limited
Origin Energy ATP 788P Pty Limited
Origin Energy C5 Pty Limited
Origin Energy Upstream Operator Pty Ltd
Origin Energy Holdings Pty Limited <
Origin Energy Retail Limited <
Origin Energy (Vic) Pty Limited <
Gasmart (Vic) Pty Ltd <
Origin Energy (TM) Pty Limited <
Cogent Energy Pty Ltd
Origin Energy Retail No. 1 Pty Limited
Origin Energy Retail No. 2 Pty Limited
Horan & Bird Energy Pty Ltd
Origin Energy Electricity Limited <
Eraring Gentrader Depositor Pty Limited
Sun Retail Pty Ltd <
OE Power Pty Limited <
Origin Energy Uranquinty Power Pty Ltd <
OC Energy Pty Ltd <
Origin Energy International Holdings Pty Limited
Origin Energy Mortlake Terminal Station No. 2 Pty Limited
Origin Energy PNG Ltd #
Origin Energy PNG Holdings Limited #
Origin Energy Tasmania Pty Limited <
The Fiji Gas Co Ltd
Origin Energy Contracting Limited <
Origin Energy LPG Limited <
Origin (LGC) (Aust) Pty Limited <
Origin Energy SA Pty Limited <
Hylemit Pty Limited
Origin Energy LPG Retail (NSW) Pty Limited
Origin Energy WA Pty Limited <
Origin Energy Services Limited <
OEL US Inc.
Origin Energy NSW Pty Limited <
Origin Energy Asset Management Limited <
NSW
Vic
Vic
WA
WA
SA
WA
Vic
NSW
NSW
Vic
Vic
Vic
Vic
Qld
Vic
Vic
Vic
SA
Vic
Vic
Vic
Vic
Vic
Vic
Qld
Vic
Vic
Qld
Vic
Vic
Vic
Vic
Vic
PNG
PNG
Tas
Fiji
Qld
NSW
NSW
SA
Vic
NSW
WA
SA
USA
NSW
SA
100
100
100
100
100
100
100
100
100
100
100
100
100
–
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
66.7
100
100
51
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
66.7
100
100
51
100
100
100
100
100
100
100
100
100
100
100
Annual Report 2020
119
2020
Ownership
interest
per cent
2019
Ownership
interest
per cent
Incorporated in
NT
Vic
Vic
Vic
Solomon Islands
Cook Islands
Vanuatu
Western Samoa
American Samoa
Singapore
SA
SA
Qld
SA
SA
SA
Qld
Qld
Vic
Singapore
Singapore
NSW
Vic
NSW
NZ
Vic
Vic
Vic
Vic
Singapore
Vic
Netherlands
Netherlands
Netherlands
NSW
Vic
NSW
Vic
Vic
Vic
Vic
Vic
Vic
Chile
Chile
Chile
100
100
100
100
80
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
–
–
100
100
100
–
–
–
100
100
100
100
100
100
80
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
F1 Controlled entities (continued)
Origin Energy Pipelines Pty Limited <
Origin Energy Pipelines (SESA) Pty Limited
Origin Energy Pipelines (Vic) Holdings Pty Limited <
Origin Energy Pipelines (Vic) Pty Limited <
Origin Energy Solomons Ltd
Origin Energy Cook Islands Ltd
Origin Energy Vanuatu Ltd
Origin Energy Samoa Ltd
Origin Energy American Samoa Inc
Origin Energy Insurance Singapore Pte Ltd
Angari Pty Limited <
Oil Investments Pty Limited <
Origin Energy Southern Africa Holdings Pty Limited
Origin Energy Zoca 91-08 Pty Limited <
Sagasco NT Pty Ltd <
Sagasco Amadeus Pty Ltd <
Origin Energy Amadeus Pty Limited <
Amadeus United States Pty Limited <
Origin Energy Vietnam Pty Limited
Origin Energy Singapore Holdings Pte Limited
Origin Energy (Song Hong) Pte Limited
Origin Future Energy Pty Limited
Origin Energy Rewards Pty Ltd
Origin Energy Metering Coordinator Pty Ltd
Origin Energy Resources NZ (Rimu) Limited
Origin Energy VIC Holdings Pty Limited <
Origin Energy Capital Ltd <
Origin Energy Finance Company Pty Limited <
OE JV Co Pty Limited <
Origin Energy LNG Holdings Pte Limited
Origin Energy LNG Portfolio Pty Ltd <
Origin Energy Australia Holding BV #
Origin Energy Mt Stuart BV #
OE Mt Stuart General Partnership #
Parbond Pty Limited
Origin Education Foundation Pty Limited
Origin Energy Foundation Ltd
Origin Renewable Energy Investments No 1 Pty Ltd
Origin Renewable Energy Investments No 2 Pty Ltd
Origin Renewable Energy Pty Ltd
Origin Energy Geothermal Holdings Pty Ltd
Origin Energy Geothermal Pty Ltd
Origin Energy Chile Holdings Pty Limited
Origin Energy Chile S.A. #
Origin Energy Geothermal Chile Limitada #
Pleiades S.A
Origin Energy Geothermal Singapore Pte Limited
Singapore
Origin Energy Wind Holdings Pty Ltd
Crystal Brook Wind Farm Pty Limited
Wind Power Pty Ltd
Wind Power Management Pty Ltd
Tuki Wind Farm Pty Ltd
Dundas Tablelands Wind Farm Pty Limited
Origin Energy Hydro Bermuda Limited
Origin Energy Hydro Chile SpA #
Vic
NSW
Vic
Vic
Vic
Vic
Bermuda
Chile
< Entered into ASIC Corporations (Wholly-owned Companies) Instrument 2016/785 and related Deed of Cross Guarantee with Origin Energy Limited.
# Controlled entity has a financial reporting period ending 31 December.
Financial Statements
120
F1 Controlled entities (continued)
Changes in controlled entities
2020
Origin Energy ATP 788P Pty Limited was sold on 5 August 2019.(1)
Origin Energy Geothermal Singapore Pte Limited was deregistered on 27 August 2019.
Origin Foundation Limited changed its name to Origin Energy Foundation Ltd on 23 September 2019.
Pleiades S.A was sold on 25 September 2019.
Wind Power Management Pty Ltd was deregistered on 26 November 2019.
Tuki Wind Farm Pty Ltd was deregistered on 26 November 2019.
Dundas Tablelands Wind Farm Pty Ltd was deregistered on 26 November 2019.
Origin Energy Mortlake Terminal Station No. 1 Pty Limited changed its name to Origin Energy International Holdings Pty Limited on
21 April 2020.
(1) On 5 August 2019 Origin sold its Ironbark asset to APLNG for $231 million. Net nil profit or loss was realised in the period ending 30 June 2020.
F2 Business combinations
2020
There were no significant business combinations during the period.
2019
Acquisition of OC Energy Pty Ltd
On 1 March 2019, the Group acquired 100 per cent of the formerly privately held OC Energy Pty Ltd under a Share Sale Agreement.
Finalisation of the purchase price accounting was completed within the 12-month measurement period, resulting in no significant changes
to the provisional fair values presented in the 30 June 2019 Financial Statements. The fair value of the net assets acquired as part of the
business combination was $59 million.
Purchase consideration of $33 million was paid on the completion date. Considering the acquired cash balance ($4 million), the net cash
impact of the acquisition at the reporting date was $29 million. Further payments of $25 million in total were expected to be made after
the acquisition date. On 28 February 2020, the Group made a payment of $14 million and expects to pay the remaining holdback amount
of $11 million once certain conditions are met. The total consideration is still estimated to be $59 million and the net cash impact after
excluding the acquired cash balance to be $55 million.
F3 Joint arrangements and investments in associates
Joint arrangements are entities over whose activities the Group has joint control, established by contractual agreement and requiring the
consent of two or more parties for strategic, financial and operating decisions. The Group classifies its interests in joint arrangements as
either joint operations or joint ventures, depending on its rights to the assets and obligations for the liabilities of the arrangements.
Associates are entities, other than partnerships, for which the Group exercises significant influence, but no control, over the financial and
operating policies, and which are not intended for sale in the near future.
Of the Group’s interests in joint arrangements and associates, only APLNG and Octopus Energy have a material impact to the Group at
30 June 2020. Refer to Section B.
Interests in unincorporated joint operations
The Group’s interests in unincorporated joint operations are brought to account on a line-by-line basis in the income statement and
statement of financial position. These interests are held on the following assets whose principal activities are oil and/or gas exploration,
development and production; power generation; and geothermal power technology:
• Beetaloo Basin
• Browse Basin
•
Innamincka Deeps Geothermal
On 7 April 2020, the Group acquired an additional 7.5 per cent interest in the Beetaloo Basin through a farm-in arrangement with Falcon
Oil and Gas Australia Limited. This transaction also involved a renegotiation of the Joint Operating Agreement in place, which effectively
gives the Group control over key decisions relating to these permits. The Beetaloo Basin is the only material unincorporated joint operation
as at 30 June 2020.
Annual Report 2020 121
G Other information
This section includes other information to assist in understanding the financial performance and position of the Group, and items required
to be disclosed to comply with accounting standards and other pronouncements.
G1 Contingent liabilities
Discussed below are items where either it is not probable that the Group will have to make future payments or it is not possible to reliably
measure the amount of future payments.
Joint arrangements and associates
As a participant in certain joint arrangements, the Group is liable for its share of liabilities incurred by these arrangements. In some
circumstances the Group may incur more than its proportionate share of such liabilities, but will have the right to recover the excess
liability from the other joint arrangement participants.
The Group continues to provide parent company guarantees in excess of its 37.5 per cent shareholding in APLNG, in respect of certain
historical domestic contracts.
In October 2018, Origin and the other APLNG shareholders agreed to indemnify one of APLNG’s long-term LNG customers (following
that customer’s election to defer delivery of 30 cargoes over six years (2019–24)) should APLNG fail to supply make-up cargoes to that
customer prior to the expiry of the LNG supply contract. The customer will pay APLNG for the deferred cargoes and APLNG expects to
resell the gas to other customers, and deliver the deferred cargoes to the long-term LNG customer between 2025 and the end of the
LNG supply contract. The indemnity was provided severally in accordance with each shareholder’s proportionate shareholding in APLNG.
At the inception of the agreement, any obligation or liability on the part of the shareholders will only be confirmed by the occurrence or
non-occurrence of future events, and cannot be measured with sufficient reliability.
The Group has entered into a further agreement to provide a financial guarantee to Octopus Energy’s financiers in respect of a working
capital facility entered into by Octopus Energy. Under this agreement, the Group is required to make a payment to Octopus Energy’s
financiers should Octopus Energy not make payments under the working capital facility. In return, Octopus Energy is required to pay a
monthly fee to the Group in respect of the guarantee facility. The guarantee has been accounted for as a Financial Guarantee Contract
under AASB 9 and has been initially recognised at fair value (refer to note C7) with reference to the guarantee amount in the facility
agreement. During the year, $1 million has been recognised within other income in respect of the financial guarantee income.
Legal and regulatory
Certain entities within the Group (and joint venture entities, such as APLNG) are subject to various lawsuits and claims as well as audits
and reviews by government, regulatory bodies or other joint venture partners. In most instances it is not possible to reasonably predict the
outcome of these matters or their impact on the Group. Where outcomes can be reasonably predicted, provisions are recorded.
A number of sites owned/operated (or previously owned/operated) by the Group have been identified as potentially contaminated. For
sites where it is likely that a present obligation exists, and it is probable that an outflow of resource will be required to settle the obligation,
such costs have been expensed or provided for.
Warranties and indemnities have also been given and/or received by entities in the Group in relation to environmental liabilities for certain
properties divested and/or acquired.
Capital expenditure
As part of the acquisition of Browse Basin exploration permits in 2015, the Group agreed to pay cash consideration of US$75 million
contingent upon a project Final Investment Decision (FID), and US$75 million contingent upon first production. The Group will pay further
contingent consideration of up to US$50 million upon first production if 2P reserves, at the time of the FID, reach certain thresholds. These
obligations have not been provided for at the reporting date as they are dependent upon uncertain future events not wholly within the
Group’s control.
Bank guarantees
There are no contingent liabilities arising from bank guarantees held by the Group required to be disclosed as at the reporting date, as
these have either been provided for in the accounts or an outflow of economic benefits is considered remote.
The Group’s share of guarantees for certain contractual commitments of its joint ventures is shown at note G2.
Financial Statements 122
G2 Commitments
Detailed below are the Group’s contractual commitments that are not recognised as liabilities as there is no present obligation. On
1 July 2019, the Group adopted AASB 16 Leases, with operating leases now recognised on balance sheet. Refer to the Overview section.
Capital expenditure commitments
Joint venture commitments(1)
Operating lease commitments(2)
2020
$m
109
340
–
2019
$m
63
459
543
(1) Includes $269 million in relation to the Group’s share of APLNG’s capital and joint venture commitments. (2019: $386 million in relation to the Group’s share of APLNG’s
capital, joint venture and operating lease commitments.)
(2) Refer to the Overview for a reconciliation of the lease liability at the transition date of 1 July 2019 relating to AASB 16.
The Group leases PP&E under operating leases. The future minimum lease payments under non-cancellable operating leases are
shown below.
Less than one year
Between one and five years
More than five years
G3 Share-based payments
2020
$m
–
–
–
–
2019
$m
90
223
230
543
This section sets out details of the Group’s share-based remuneration arrangements, including details of the Company’s Equity Incentive
Plan and Employee Share Plan.
The table below shows share-based remuneration expenses that were recognised during the year.
Equity Incentive Plan
Employee Share Plan
Equity Incentive Plan
2020
$m
30
4
34
2019
$m
21
5
26
Eligible employees are granted share-based remuneration under the Origin Energy Limited Equity Incentive Plan. Participation in the plan
is at the Board’s discretion and no individual has a contractual right to participate or to receive any guaranteed benefits. Equity incentives
granted prior to 18 October 2018 were offered in the form of Options and/or Share Rights. Since that date equity incentives are granted in
the form of Share Rights and/or Restricted Shares (RSs). Share Rights do not carry dividend or voting entitlements and RSs do.
(i) Short Term Incentive
Short Term Incentive (STI) includes the award of RSs, which are unrestricted if the employee remains employed with satisfactory
performance for a set period (generally after two years). Once unrestricted, the shares are transferred into the employee’s name at no cost.
The face value of RSs measured at grant date is recognised as an employee expense over the related service period. RSs are forfeited if the
service and performance conditions are not met.(1)
(ii) Long Term Incentive
Long Term Incentive (LTI) includes the award of Performance Share Rights (PSRs), which will only vest if certain company performance
conditions and personal performance standards are met. The PSR grants made in FY2020 have a performance period of three years. Half
of each LTI award is subject to a market hurdle, namely Origin’s Total Shareholder Return (TSR) relative to a Reference Group of ASX-listed
companies identified in the relevant Remuneration Report. The remaining half of each LTI award is subject to an internal hurdle, namely
Return on Capital Employed (ROCE), as set out in the relevant Remuneration Report.
The number of awards that may vest depends on performance against each hurdle, considered separately. For awards subject to the
relative TSR hurdle, vesting only occurs if Origin’s TSR over the performance period ranks higher than the 50th percentile of the Reference
Group. Half of the PSRs vest if that condition is satisfied. All the PSRs vest if Origin ranks at or above the 75th percentile of the Reference
Group. Straight-line pro-rata vesting applies in between these two points.
(1) The Equity Incentive Plan Rules set out exceptional circumstances, such as death, disability, redundancy or genuine retirement, under which RSs vest at cessation unless
the Board determines otherwise. Prior to FY2018, the equity component of STI was awarded in the form of Deferred Share Rights (DSRs).
Annual Report 2020 123
G3 Share-based payments (continued)
For awards granted in FY2017 and FY2018 that are subject to the ROCE hurdle, vesting only occurs if two conditions are satisfied:
• the average of the actual annual ROCE outcomes over the performance period meets or exceeds the average of the annual targets set
in advance by the Board (Gate 1); and
• the actual ROCE in either of the last two years of the performance period meets or exceeds Origin’s pre-tax weighted average cost of
capital (WACC) (Gate 2).
Half of the relevant PSRs will vest if Gate 1 is met and Origin’s pre-tax WACC is met under Gate 2. All the PSRs will vest if Gate 1 is met and
Origin’s pre-tax WACC is exceeded by two percentage points or more under Gate 2. Straight-line pro-rata vesting applies in between.
For awards granted in FY2019 and FY2020 that are subject to the ROCE hurdle, half of the ROCE tranche will be allocated to Energy
Markets and the other half will be allocated to Integrated Gas. Each tranche will be tested separately and vest separately. Vesting for each
tranche only occurs if the average actual annual ROCE outcomes over the performance period for the relevant business meets or exceeds
the average of the annual ROCE targets, which are reflective of delivering WACC for the relevant business. Half of the relevant PSRs will
vest if the ROCE target is met. All the relevant PSRs will vest if the ROCE target is exceeded by two percentage points or more. Straight-
line pro-rata vesting applies in between.
As there is no exercise price for PSRs, once vested they are exercised automatically. When exercised, a vested award is converted into
one fully paid ordinary share that is subject to a post-vesting holding lock for a set period (generally one year) and also carries voting and
dividend entitlements.
The fair value of the awards granted is recognised as an employee expense, with a corresponding increase in equity, over the vesting
period. In exceptional circumstances(1) unvested PSRs may be held ‘on foot’ subject to the specified performance hurdles and other plan
conditions being met, or dealt with in an appropriate manner determined by the Board. For PSRs subject to the relative TSR condition, fair
value is measured at grant date using a Monte Carlo simulation model that takes into account the exercise price, share price at grant date,
price volatility, dividend yield, risk-free interest rate for the term of the security, and the likelihood of meeting the TSR market condition.
The expected volatility reflects the assumption that the historical volatility over a period similar to the life of the options is indicative of
future trends, which may not necessarily be the actual outcome. The amount recognised as an expense is adjusted to reflect the actual
number of awards that vest except where due to non-achievement of the TSR market condition. Set out below are the inputs used to
determine the fair value of the PSRs granted during the year. For PSRs subject to the ROCE condition, the initial fair value at grant date
is the market value of an Origin share less the discounted value of dividends forgone, and the recognised expense is trued up at each
reporting period to the expected outcome as assessed at that time.
(1) The Equity Incentive Plan Rules provide that Rights and RSs are forfeited on cessation of employment unless the Board determines otherwise. The offer terms
provide guidance for the exercise of that discretion, specifically that the Rights and RSs will not normally be forfeited in cases of ‘good leavers’ (such as those ceasing
employment due to death, disability, redundancy or genuine retirement).
Set out below is a summary of PSRs issued during the financial year.
Grant date
Grant date share price
Exercise price
Volatility
Dividend yield(2)
Risk-free rate(3)
Grant date fair value (per award)
PSRs
30 Aug 2019
$7.63
Nil
27%
4.0%
–
$6.77
30 Aug 2019
$7.63
Nil
27%
4.0%
0.70%
$3.82
16 Oct 2019(1)
16 Oct 2019(1)
$8.12
Nil
26%
4.0%
–
$7.25
$8.12
Nil
26%
4.0%
0.70%
$4.49
(1) These PSR tranches relate to specific Key Management Personnel awards required to be approved by shareholder resolution at the time of the Annual General Meeting.
(2) Dividend yield assumptions are based on the average dividend yield rate over the vesting period of three years.
(3) Where the risk-free rate is nil, these PSR tranches are ROCE-tested; therefore, the risk-free rate is not relevant to their valuation.
Financial Statements 124
G3 Share-based payments (continued)
Equity Incentive Plan awards outstanding
Set out below is a summary of awards outstanding at the beginning and end of the financial year.
Outstanding at 1 July 2019
Granted
Exercised/released
Forfeited
Weighted
average
exercise
price
PSRs
DSRs
RSs
$6.51
–
–
–
5,126,670
2,346,098
–
1,229,301
1,920,849
–
1,705,133
2,678
1,867,476
3,005,423
256,173
93,153
Options
5,565,803
–
–
2,306,422
Outstanding at 30 June 2020
3,259,381
$6.33
6,243,467
213,038
4,523,573
Exercisable at 30 June 2020
–
–
–
–
–
Outstanding at 1 July 2018
Granted
Exercised
Forfeited
7,475,601
–
–
1,909,798
$8.84
–
–
$15.65
4,086,642
1,793,349
–
753,321
4,402,736
–
2,380,513
101,374
–
2,059,842
121,425
70,941
Outstanding at 30 June 2019
5,565,803
$6.51
5,126,670
1,920,849
1,867,476
Exercisable at 30 June 2019
–
–
–
–
–
The weighted average share price during 2020 was $6.80 (2019: $7.64). The options outstanding at 30 June 2020 have an exercise price
in the range of $5.21 to $7.37 (2019: $5.21 to $7.37) and a weighted average contractual life of 6.6 years (2019: 7.1 years).
For more information on these share plans and performance rights issued to Key Management Personel, refer to the Remuneration Report.
Employee Share Plan
Under the Employee Share Plan (ESP), all eligible employees have a choice of either participating in the $1,000 General Employee Share
Plan (GESP) or the Matching Share Plan (MSP).
Under the GESP, all employees of the Company who are based in Australia and have been continuously employed as at 1 March of the
performance year, are granted up to $1,000 of fully paid Origin shares conditional on Board approval. The shares are granted for no
consideration. Shares awarded under the GESP are purchased on market, registered in the name of the employee, and are restricted for
three years, or until cessation of employment, whichever occurs first.
Under the MSP, all eligible employees may elect to purchase shares via a salary sacrifice arrangement, which commences on 1 October of
the performance year. The shares under this plan are allotted quarterly and are subject to trading restriction for a set period (generally two
years) or until cessation of employment. The Company matches the purchased shares on a one-for-two basis with allocation of additional
Matching Share Rights (MRs) which vest at the same time when the restriction is lifted for the purchased shares. Vesting of MRs is
conditional on the employee remaining in continuous employment at that time. MRs are forfeited if the service conditions are not met.(1)
(1) The Equity Incentive Plan Rules provide that Rights and Restricted Shares are forfeited on cessation of employment unless the Board determines otherwise. The offer
terms provide guidance for the exercise of that discretion, specifically that the Rights and RSs will not normally forfeit in cases of ‘good leavers’ (such as those ceasing
employment due to death, disability, redundancy or genuine retirement).
Details of the shares awarded under the GESP during the year are set out below.
2020
2019
Grant date
Shares
granted
Cost per
share(1)
Total cost
$’000
3 Sep 2019
528,264
$7.55
528,264
5 Sep 2018
561,126
$8.12
561,126
3,988
3,988
4,556
4,556
(1) The cost per share represents the weighted average market price of the Company’s shares on the grant date.
Annual Report 2020 G3 Share-based payments (continued)
Set out below is a summary of MRs outstanding at the beginning and end of the financial year.
Outstanding at 1 July 2019
Granted
Exercised/released
Forfeited
Expired
Outstanding at 30 June 2020
Exercisable at 30 June 2020
G4 Related party disclosures
125
MRs
73,999
170,353
9,120
6,691
–
228,541
–
The Group’s interests in equity accounted entities and details of transactions with these entities are set out in notes B1 and B4.
Certain Directors of Origin Energy Limited are also directors of other companies that supply Origin Energy Limited with goods and
services or acquire goods or services from Origin Energy Limited. Those transactions are approved by management within delegated
limits of authority, and the Directors do not participate in the decisions to enter into such transactions. If the decision to enter into
those transactions should require approval of the Board, the Director concerned will not vote upon that decision nor take part in the
consideration of it.
G5 Key management personnel
Short-term employee benefits
Post-employment benefits
Other long-term benefits
Share-based payments
2020
$
2019
$
11,619,739
262,538
136,474
5,124,047
9,941,352
255,313
182,927
4,311,013
17,142,798
14,690,605
Loans and other transactions with key management personnel
There were no loans with key management personnel during the year.
Transactions entered into during the year with key management personnel are normal employee, customer or supplier relationships
and have terms and conditions that are no more favourable than dealings in the same circumstances on an arm’s length basis. These
transactions include:
• the receipt of dividends from Origin Energy Limited or participation in the DRP;
• participation in the ESP, Equity Incentive Plan and Non-executive Director Share Plan;
• terms and conditions of employment or directorship appointment;
• reimbursement of expenses incurred in the normal course of employment; and
• purchases of goods and services.
Financial Statements 126
G6 Notes to the statement of cash flows
Cash includes cash on hand, at bank and in short-term deposits, net of outstanding bank overdrafts.
The following table reconciles profit to net cash provided by operating activities.
Profit for the period
Adjustments for non-cash ITDA
Depreciation and amortisation
Net financing costs
Tax expense
Non-cash share of ITDA of equity accounted investees
Adjustments for other non-cash items
(Increase)/decrease in fair value of derivatives
Increase in fair value of financial instruments
Unrealised foreign exchange loss
Impairment of assets
Gain on sale of assets
Impairment losses recognised – trade and other receivables
Non-cash share of EBITDA of equity accounted investees
Exploration expense
Executive share-based payment expense
Changes in assets and liabilities:
– Receivables
– Inventories
– Payables
– Provisions
– Other
– Futures collateral
Tax paid
Total adjustments
Net cash from operating activities
Reconciliation of movements of liabilities to cash flows arising from financing activities
$m
Balance as at 30 June 2019
Adoption of AASB 16 Leases
Balance as at 1 July 2019
Proceeds from borrowings
Modifications to the lease terms
Repayment of borrowings/other liabilities
Foreign exchange adjustments
Reclassification
Other non-cash movements
Balance as at 30 June 2020
Liabilities from financing activities
Current
borrowings
Non-current
borrowings
Lease
liabilities
948
–
948
–
–
(946)
–
1,326
–
1,328
6,648
–
6,648
1,273
–
(1,608)
22
(1,326)
1
5,010
–
478
478
–
111
(75)
–
–
–
514
Other
financial
(assets)/
liabilities
(645)
–
(645)
–
–
108
(6)
–
103
(440)
2020
$m
2019
$m
86
1,214
509
126
93
1,303
(275)
(123)
–
764
(1)
124
(1,911)
3
30
217
(26)
(180)
663
104
(340)
(215)
865
951
419
154
64
1,510
102
(391)
80
39
–
84
(2,142)
2
21
207
58
(175)
179
(115)
125
(110)
111
1,325
Total
6,951
478
7,429
1,273
111
(2,521)
16
–
104
6,412
Annual Report 2020 127
G7 Auditors’ remuneration
During the year, the following fees were paid or payable for services provided by the auditor of the parent entity, its related practices and
non-related audit firms.
Amounts received or due and receivable by the auditor
of the Parent Company and any other entity in the Group for:
Auditing the statutory financial report of the Parent Company covering the Group
Auditing the statutory financial reports of any controlled entities
Fees for other assurance and agreed-upon-procedures services under other legislation or contractual
arrangements
Fees for other services
Tax compliance(2)
Cyber security
Advisory services
Other
Amounts received or due and receivable by affiliates of the auditor of the Parent Company for:
Auditing the statutory financial reports of any controlled entities
Fees for other services
Tax compliance
Advisory services
Other
Total fees to overseas member firms of the Parent Company auditor
Total remuneration to Parent Company auditor
Auditing of statutory financial reports of any controlled entities by other auditors
Total auditors’ remuneration
2020(1)
$’000
2019(1)
$’000
1,750
173
9
767
155
140
4
1,639
69
136
10
–
181
15
2,998
2,050
69
–
–
–
69
204
68
4
7
283
3,067
2,333
247
3,314
96
2,429
(1) Amounts in 2019 relate to KPMG, which was the statutory auditor of the Origin Group including controlled entities. EY was appointed on 16 October 2019 at the last
Annual General Meeting and have been statutory auditor for the 2020 financial year.
(2) This amount relates to the Group’s share of tax compliance work billed. An amount of $701k has been recharged to APLNG in respect of its share and is excluded from
this amount.
Financial Statements 128
G8 Master netting or similar agreements
The Group enters into derivative transactions under ISDA master netting agreements. In general, under such agreements, the amounts
owed by each counterparty on a single day in respect of all transactions outstanding in the same currency are aggregated into a net
amount payable by one party to the other.
Financial assets and liabilities are offset, and the net amount reported in the statement of financial position, where the Group has a legally
enforceable right to offset recognised amounts and there is an intention to settle on a net basis or realise the asset and settle the liability
simultaneously. The Group has also entered into arrangements that do not meet the criteria for offsetting, but still allow for the related
amounts to be offset in certain circumstances, such as a loan default or the termination of a contract.
The following table presents the recognised financial instruments that are offset, or subject to master netting arrangements but not
offset, as at the reporting date. The net amount column shows the impact on the Group’s statement of financial position if all set-off rights
were exercised.
2020
Derivative assets
Derivative liabilities
2019
Derivative assets
Derivative liabilities
Amount
offset in the
statement
of financial
position
$m
Amount
in the
statement
of financial
position
$m
Related
amount
not offset
$m
(385)
385
(320)
320
1,158
(1,215)
1,434
(1,503)
(650)
650
(398)
398
Gross
amount
$m
1,543
(1,600)
1,754
(1,823)
Net
amount
$m
508
(565)
1,036
(1,105)
G9 Deed of Cross Guarantee
The parent entity has entered into a Deed of Cross Guarantee through which the Group guarantees the debts of certain controlled entities
in the event that one of those entities is wound up. The controlled entities that are party to the Deed are shown in note F1.
The following consolidated statement of comprehensive income and retained profits, and statement of financial position, cover the
Company and its controlled entities that are party to the Deed of Cross Guarantee after eliminating all transactions between parties
to the Deed.
For the year ended 30 June
Consolidated statement of comprehensive income and retained profits
Revenue
Other income
Expenses
Share of results of equity accounted investees
Impairment
Interest income
Interest expense
Profit before income tax
Income tax expense
Profit for the year
Other comprehensive income
Total comprehensive income for the year
Retained earnings at the beginning of the year
Adjustments for entities entering the Deed of Cross Guarantee
Retained earnings at the beginning of the year
Impact of AASB 9 adoption
Impact of AASB 16 adoption
Dividends paid
Retained earnings at the end of the year
2020
$m
2019
$m
13,000
47
(12,314)
619
(765)
189
(356)
420
(72)
348
–
348
5,433
2
5,435
–
349
(528)
5,604
14,510
26
(13,606)
632
(360)
234
(453)
983
(119)
864
–
864
4,890
–
4,890
(145)
–
(176)
5,433
Annual Report 2020 129
2020
$m
2019
$m
1,042
2,916
152
510
479
89
104
5,292
2,711
525
1,842
6,979
4,060
5,394
360
40
21,911
27,203
2,273
202
74
448
204
2
153
153
1,455
2,950
126
454
318
–
110
5,413
2,135
962
3,161
6,960
3,337
5,309
227
43
22,134
27,547
2,120
204
137
381
275
160
132
56
3,509
3,465
7,204
1,001
729
21
1,269
10,224
13,733
13,470
7,145
721
5,604
8,227
605
1,115
21
484
10,452
13,917
13,630
7,125
1,072
5,433
13,470
13,630
G9 Deed of Cross Guarantee (continued)
As at 30 June
Statement of financial position
Current assets
Cash and cash equivalents
Trade and other receivables
Inventories
Derivatives
Income tax receivable
Other financial assets
Other assets
Total current assets
Non-current assets
Trade and other receivables
Derivatives
Other financial assets(1)
Investments accounted for using the equity method
PP&E(2)
Intangible assets
Deferred tax assets
Other assets
Total non-current assets
Total assets
Current liabilities
Trade and other payables
Payables to joint ventures
Interest-bearing liabilities(3)
Derivatives
Other financial liabilities
Provision for income tax
Employee benefits
Provisions
Total current liabilities
Non-current liabilities
Trade and other payables
Interest-bearing liabilities(4)
Derivatives
Employee benefits
Provisions
Total non-current liabilities
Total liabilities
Net assets
Equity
Contributed equity
Reserves
Retained earnings
Total equity
(1) Includes investment in subsidiaries relating to entities outside the Deed of Cross Guarantee.
(2) Includes $454 million of ROU assets in the current period as a result of the adoption of AASB 16 Leases. Refer to the Overview.
(3) Includes $68 million of lease liabilities in the current period as a result of the adoption of AASB 16 Leases. Refer to the Overview.
(4) Includes $433 million of lease liabilities in the current period as a result of the adoption of AASB 16 Leases. Refer to the Overview.
Financial Statements 130
G10 Parent entity disclosures
The following table sets out the results and financial position of the parent entity, Origin Energy Limited.
Origin Energy Limited
Profit for the year
Other comprehensive income, net of income tax
Total comprehensive income for the year
Financial position of the parent entity at year end
Current assets
Non-current assets
Total assets
Current liabilities
Non-current liabilities
Total liabilities
Contributed equity
Share-based payments reserve
Foreign currency translation reserve
Hedge reserve
Retained earnings(1)
Total equity
2020
$m
1,167
108
1,275
1,307
19,084
20,391
2,683
5,171
7,854
7,145
223
863
(47)
4,353
2019
$m
1,118
342
1,460
2,668
20,560
23,228
4,677
6,770
11,447
7,125
234
720
(12)
3,714
12,537
11,781
(1) Refer to note A7 for details of dividends provided for or paid of $528 million.
The parent entity has entered into a deed of indemnity for the cross-guarantee of liabilities of a number of controlled entities.
Refer to note F1.
G11 Subsequent events
Other than the matters described below, no item, transaction or event of a material nature has arisen since 30 June 2020 that
would significantly affect the operations of the Group, the results of those operations, or the state of affairs of the Group, in future
financial periods.
Bank debt facility extension
On 2 July 2020, the Group extended A$1.1 billion of bank debt facilities from a FY2023 maturity date to a new maturity date in FY2025.
A further $0.2 billion of surplus liquidity was cancelled as part of this transaction.
Dividends
On 20 August 2020, the Directors determined an unfranked final dividend of 10 cents per share on ordinary shares. The dividend will be
paid on 2 October 2020.
The financial effect of this dividend has not been brought to account in the financial statements for the year ended 30 June 2020 and will
be recognised in subsequent financial statements.
Annual Report 2020 131
Directors’ Declaration
1
In the opinion of the Directors of Origin Energy Limited (the Company):
(a) the consolidated financial statements and notes are in accordance with the
Corporations Act 2001 (Cth), including:
(i) giving a true and fair view of the financial position of the Group as at
30 June 2020 and of its performance, for the year ended on that date; and
(ii) complying with Australian Accounting Standards (including the Australian
Accounting Interpretations) and the Corporations Regulations 2001 (Cth).
(b) the consolidated financial statements also comply with International Financial
Reporting Standards as disclosed in the Overview of the consolidated financial
statements; and
(c) there are reasonable grounds to believe that the Company will be able to pay its
debts as and when they become due and payable.
2
There are reasonable grounds to believe that the Company and the controlled entities
identified in note F1 will be able to meet any obligations or liabilities to which they
are or may become subject to by virtue of the Deed of Cross Guarantee between the
Company and those controlled entities pursuant to ASIC Corporations (Wholly-owned
Companies) Instrument 2016/785.
3
The Directors have been given the declarations required by section 295A of the
Corporations Act 2001 (Cth) from the Chief Executive Officer and the Chief Financial
Officer for the financial year ended 30 June 2020.
Signed in accordance with a resolution of the Directors:
Gordon Cairns
Chairman Director
Sydney, 20 August 2020
132
Independent Auditor’s Report
Annual Report 2020 Ernst & Young200 George StreetSydney NSW 2000 AustraliaGPO Box 2646 Sydney NSW 2001Tel: +61 2 9248 5555Fax: +61 2 9248 5959ey.com/auIndependent Auditor's Report to the Members of Origin Energy Limited Report on the Audit of the Financial Report Opinion We have audited the financial report of Origin Energy Limited (the Company) and its subsidiaries (collectively the Group), which comprises the consolidated statement of financial position as at 30 June 2020, the consolidated income statement, the consolidated statement of comprehensive income, consolidated statement of changes in equity and 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 consolidated financial position of the Group as at 30 June 2020 and of its consolidated financial performance for the year ended on that date; and 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) (the Code) that are relevant to our audit of the financial report in Australia. We have also fulfilled our other ethical 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 Matters 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. 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. Independent Auditor’s Report
133
Carrying Value of the Australian Pacific LNG (APLNG) Equity Accounted Investment Why significant How our audit addressed the key audit matter At 30 June 2020, the Group’s equity accounted investment in APLNG has a carrying value of $6,978 million after an impairment charge was recorded during the year. COVID-19 has resulted in market disruption and has contributed to a significant decline in oil price during the period and lower forecast oil linked, LNG prices relative to prior periods. The Group considers this to be an indicator of impairment in accordance with the Australian Accounting Standards. The Group has estimated the recoverable amount of its investment, using fair value less cost of disposal (FVLCD). The estimate of FVLCD involves significant judgment and is based on modelling a range of forecast assumptions and estimates which are inherently difficult to determine with precision. Such forecasts include future oil and gas prices, foreign exchange rates, discount rates, production and development costs, and reserves and resources. Oil price is a significant assumption used in the impairment testing and is inherently subjective. In times of economic uncertainty, such as the recent market disruption caused by COVID-19, the degree of subjectivity in determining forecast pricing is higher than it might otherwise be. Changes in this assumption can lead to significant changes in the recoverable amount. Refer to Note B2.2 for key assumptions adopted. This resulted in a post-tax impairment charge of $746.0 million being recorded in the Statement of Comprehensive Income. Due to the significance of this investment to relative to total assets and the inherent complexity and level of judgment required in forecasting future cash flows, we considered this to be a key audit matter. In completing our audit procedures, with the assistance of our valuation specialists, we: -Evaluated whether the methodology applied in determining FVLCD complied with the requirements of Australian Accounting Standards. -Assessed the mathematical accuracy of the valuation model, the recoverable amount calculation and the impairment charge recorded. -Assessed the macroeconomic assumptions adopted, including oil price, gas price and foreign exchange, with reference to broker and analyst data and publicly available peer company information. -Evaluated the discount rate adopted with reference to external market data including government bond rates and comparable company data. -Agreed the production profile, operating cost and capital expenditure forecasts in the impairment model to the optimised Upstream Development Plan (“UDP”), prepared by the Group, in its capacity as the operator of APLNG’s upstream joint venture. -Considered the key assumptions in the UDP including: oComparison of forecast operating costs to APLNG’s recent operating cost history; oConsideration of timing and amount of forecast capital costs with reference to: ▪APLNG’s gas production profile, its existing inventory producing wells and forecast development of production wells; and ▪UDPs from previous financial years; oUnderstood APLNG’s process for gas reserve and resource measurement including its internal technical assurance processes and reconciliation to its most recent independent review of reserves and resources as at 30 June 2019; and oEvaluated the competency, independence and objectivity of the internal and external experts used by the Group to measure its gas reserves and resources. 134
Annual Report 2020 -Compared the timing and amount of rehabilitation and abandonment costs included in the Group’s estimate of FVLCD with those used to measure APLNG’s rehabilitation provision at 30 June 2020 and forecast development of production wells. -Considered the relationship between asset carrying values and the Group’s market capitalisation. -Assessed the adequacy of the associated disclosures in the financial report. Cameron LNG Onerous Contract Provision Why significant How our audit addressed the key audit matter The Group has recognised a $641 million onerous contract provision at 30 June 2020 in relation to its longterm Cameron LNG purchase contract. This is due to the forecast sales revenue from the onward supply of LNG being less than purchase cost under the contract, due to the recent decline in gas prices and economic slowdown caused by COVID-19. As disclosed in Note C6 to the financial statements, the present value assessment performed by the Group involves significant judgement and is highly sensitive to long term future commodity pricing assumptions, inflation rates and government bond rates. We considered this to be a key audit matter given the significance of the provision recognised, together with the high degree of judgment involved in forecasting long term sale revenue and purchase costs over the life of the life of the contract. In completing our audit procedures, with the assistance of our valuation specialists, we: -Assessed whether the Group’s methodology for determining present value met the requirements of Australian Accounting Standards in respect of recognition and measurement of the provision. -Considered the terms of the contract to ensure completeness of unavoidable costs under the agreement, as well as their application in the Group’s assessment. -Assessed the gas price assumptions adopted based on broker and analyst forecasts, market research and consideration of an implied long term price, adjusted for liquefaction and shipping costs. -Considered the cost of purchasing and selling the contracted quantity of LNG with reference to budgets provided by the project operator, contractual rates and external market data. -Assessed the discount rate adopted with reference to long term government bonds with tenures consistent with the forecast timing of cash flows. -Assessed the clerical accuracy of present value calculation for modelling integrity. -Assessed the adequacy of the financial report disclosures. Independent Auditor’s Report
135
Unbilled Revenue Why significant How our audit addressed the key audit matter At 30 June 2020, the Group recognised unbilled revenue of $1,852 million. Unbilled revenue represents the value of energy supplied to customers between the date of the last meter read and the reporting date where no bill has been issued to the customer at the end of the reporting period. The estimation of unbilled revenue is considered a key audit matter due to the complex estimation process and significant audit effort required to address the estimation uncertainty involved by the Group. Key factors that require consideration impacting the complex estimation process includes: -Estimation of customer demand which is impacted by weather and an individual customer’s circumstances. -Application of different customer rates across different regulated and unregulated markets. -Changes in energy consumption patterns compared to the same period in the prior year, particularly as a result of COVID-19. The Group’s disclosures in respect of the unbilled revenue estimation process are included in Note A2 of the financial report. Our audit procedures included the following: -Assessed whether the methodology used to recognise unbilled revenue met the requirements of the Australian Accounting Standards. -Assessed the effectiveness of the Group’s controls governing energy purchased, energy sold and the customer pricing process. -Selected a sample of unbilled revenue transactions based on qualitative and quantitative factors and performed the following procedures: oCompared the historical accuracy of the Group’s unbilled revenue estimate to historical subsequent billings. oAnalysed outliers and data anomalies which should be considered in calculating the Group’s unbilled revenue accrual. oReconciled volumes acquired from AEMO against volumes sold and volumes purchased. oCompared the prices applied to customer consumption with historical and current data. -Evaluated the adequacy of the related disclosures in the financial report including those made with respect to judgements and estimates. Impairment allowance – Trade Receivables and Unbilled Receivables Why significant How our audit addressed the key audit matter An impairment allowance in respect of the Group’s trade receivables and unbilled receivables of $162 million has been recorded at 30 June 2020, with $40 million of this amount relating to an increase in collection uncertainty as a result of the impact of COVID-19. Our audit procedures included the following: -Assessed whether the process for recognising impairment of trade receivables and unbilled receivables met the requirements of Australian Accounting Standards. oAnalysed the ageing of trade receivables and unbilled receivables and the collection and credit history of the Group’s customers. 136
Annual Report 2020 The estimation of the Group’s impairment allowance is considered a key audit matter due to the judgement involved in estimating information available with consideration of past events, current conditions and forecasts of future economic conditions, in particular the impact of COVID-19. The Group’s disclosures in respect of its estimation process are included in Note C1 of the financial report. oEvaluated the Group’s assessment of collectability considering the process to achieve recovery, the likely timing of these processes and events that could delay or impact the collectability. oAssessed the current and forecast economic environment applicable to the Group’s customers to analyse the risk of impairment. oPerformed a sensitivity analysis on the Group’s impairment allowance attributed to COVID-19 by recalculating the allowance with reference to forecast market data such as unemployment rates, and expected default frequency rates, specific to the customers size and risk. -Evaluated the adequacy of the related disclosures in the financial report including those made with respect to judgements and estimates. Information Other than the Financial Report and Auditor’s Report Thereon The directors are responsible for the other information. The other information comprises the information included in the Company’s 2020 Annual Report other than 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. In connection with 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 on the other information obtained prior to the date of this auditor’s report, 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. Responsibilities of the Directors for the 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 control 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. Independent Auditor’s Report
137
Auditor's Responsibilities for the Audit of the 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 with the Australian Auditing Standards, we exercise professional judgment and maintain professional scepticism throughout the audit. We also: •Identify 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 that are appropriate in the circumstances, but not for the 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 uncertainty 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 report. 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 the underlying transactions and events in a manner that achieves fair presentation. •Obtain sufficient appropriate audit evidence regarding the financial information of the entities or business activities within the Group to express an opinion on the financial report. We are responsible for the direction, supervision and performance of the Group audit. We remain solely responsible for our audit opinion. We communicate with 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. 138
Annual Report 2020 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 the Audit of the Remuneration Report Opinion on the Remuneration Report We have audited the Remuneration Report included in the directors' report for the year ended 30 June 2020. In our opinion, the Remuneration Report of Origin Energy Limited for the year ended 30 June 2020, complies with section 300A of the Corporations Act 2001. Responsibilities The directors of the Company are responsible for the preparation and presentation of the Remuneration Report in accordance with section 300A of the Corporations Act 2001. Our responsibility is to express an opinion on the Remuneration Report, based on our audit conducted in accordance with Australian Auditing Standards. Ernst & Young Andrew Price Partner Sydney 20 August 2020 139139
140
Share and Shareholder
Information
The information set out below was applicable as at 20 August 2020.
Corporate Governance Statement
The Company’s Corporate Governance Statement can be found on its website at https://www.originenergy.com.au/content/dam/origin/
about/investors-media/presentations/cgs_4g.pdf
Substantial shareholders
As at 20 August 2020, the Company received notice of one substantial holder:
AustralianSuper Pty Ltd, holding 109,662,324 shares in the Company’s issued capital.
Number of equity securities holders and voting rights
As at 20 August 2020, there were:
• 145,123 holders of 1,761,211,071 ordinary shares in the Company;
• 24 holders of 3,259,381 Options, 87 holders of 6,234,794 Performance Share Rights, two holders of 136,836 Deferred Share Rights
granted under the Origin Energy Equity Incentive Plan; and
• 612 holders of 225,927 Matching Share Plan Rights granted under the Origin Matching Share Plan.
Voting rights of members
At a meeting of members, each member who is entitled to attend and vote may attend and vote in person or by proxy, attorney or
representative. On a show of hands, every person present who is a member, proxy, attorney or representative, shall have one vote; and on
a poll, every member who is present in person or by proxy, attorney or representative shall have one vote for each fully paid ordinary share
held. No other equity securities hold voting rights.
Please note that the 2020 Annual General Meeting will be held online. This is in line with Australian Government guidelines in relation
to COVID-19.
Analysis of holdings
Fully paid ordinary shares
Holdings ranges
1–1,000
1,001–5,000
5,001–10,000
10,001–100,000
100,001–999,999,999
Totals
Holders
Total units
61,422
60,182
14,518
8,768
233
26,674,625
146,217,075
102,660,545
178,666,677
1,306,992,149
%
1.51
8.30
5.83
10.14
74.21
145,123
1,761,211,071
100.00
Annual Report 2020 Share and Shareholder Information
141
Options
Holdings ranges
1–1,000
1,001–5,000
5,001–10,000
10,001–100,000
100,001–999,999,999
Totals
Deferred share rights
Holdings ranges
1–1,000
1,001–5,000
5,001–10,000
10,001–100,000
100,001–999,999,999
Totals
Performance share rights
Holdings ranges
1–1,000
1,001–5,000
5,001–10,000
10,001–100,000
100,001–999,999,999
Totals
Matching Share Plan matched rights
Holdings ranges
1–1,000
1,001–5,000
5,001–10,000
10,001–100,000
100,001–999,999,999
Totals
Unmarketable parcels
8,481 shareholders held less than a marketable parcel as at 20 August 2020.
Holders
Total units
0
0
0
12
12
24
0
0
0
786,499
2,472,882
3,259,381
Holders
Total units
0
0
0
1
1
2
0
0
0
26,057
110,779
136,836
Holders
Total units
0
0
3
68
16
87
0
0
27,628
2,787,623
3,419,543
6,234,794
Holders
Total units
612
0
0
0
0
612
225,927
0
0
0
0
225,927
%
0.00
0.00
0.00
24.13
75.87
100.00
%
0.00
0.00
0.00
19.04
80.96
100.00
%
0.00
0.00
0.44
44.71
54.85
100.00
%
100.00
0.00
0.00
0.00
0.00
100.00
142
Top 20 holdings
Shareholder
HSBC Custody Nominees (Australia) Limited
J P Morgan Nominees Australia Pty Limited
Citicorp Nominees Pty Limited
National Nominees Limited
BNP Paribas Nominees Pty Ltd
BNP Paribas Noms Pty Ltd
HSBC Custody Nominees (Australia) Limited
Citicorp Nominees Pty Limited
Argo Investments Limited
Australian Foundation Investment Company Limited
HSBC Custody Nominees
Sargon Ct Pty Ltd
BNP Paribas Nominees Pty Ltd Hub24 Custodial Serv Ltd
Netwealth Investments Limited
The Senior Master Of The Supreme Court
Sargon Ct Pty Ltd
Bond Street Custodians Limited
AMP Life Limited
HSBC Custody Nominees (Australia) Limited
BNP Paribas Noms (NZ) Ltd
Total securities of top 20 holdings
Total of securities
Securities exchange listing
Number of shares
% of issued shares
470,968,427
413,943,765
134,129,573
72,753,365
40,391,742
28,202,692
21,021,195
13,168,219
11,351,603
6,000,000
5,746,127
4,930,426
4,526,347
4,176,792
3,758,868
3,145,733
2,920,439
2,836,999
2,071,356
1,957,838
1,248,001,506
1,761,211,071
26.74%
23.50%
7.62%
4.13%
2.29%
1.60%
1.19%
0.75%
0.65%
0.34%
0.33%
0.28%
0.26%
0.24%
0.21%
0.18%
0.17%
0.16%
0.12%
0.11%
70.86%
Origin shares are traded on the Australian Securities Exchange Limited (ASX). The symbol under which Origin shares are traded is ‘ORG’.
Escrowed securities
There are no securities subject to voluntary escrow as at the date of this Report.
On-market buy-back
There is no current on-market buy-back of Origin shares.
On-market purchases for employee equity plans
During the reporting period, 3,868,000 Origin shares were purchased on-market for the purpose of Origin’s employee incentive plans.
The average price per share purchased was $5.76.
Shareholder enquiries
For information about your shareholding, to notify a change of address, to make changes to your dividend payment instructions or for any
other shareholder enquiries, you should contact Origin Energy’s share registry, Boardroom Pty Ltd on 1300 664 446. Please note that
broker-sponsored holders are required to contact their broker to amend their address.
When contacting the share registry, shareholders should quote their security holder reference number, which can be found on the holding
or dividend statements.
Shareholders with internet access can update and obtain information regarding their shareholding online at https://www.originenergy.
com.au/about/investors-media.html
Tax File Number
For resident shareholders who have not provided the share registry with their Tax File Number (TFN) or exemption category details,
tax at the top marginal tax rate (plus Medicare levy) will be deducted from dividends to the extent they are not fully franked. For those
shareholders who have not provided their TFN or exemption category details, forms are available from the share registry. Shareholders are
not obliged to provide this information if they do not wish to do so.
Information on Origin
The main source of information for shareholders is the Annual Report. The Annual Report will be provided to shareholders on request and
free of charge. Shareholders not wishing to receive the Annual Report should advise the share registry in writing so that their names can be
removed from the mailing list. Origin’s website (www.originenergy.com.au) is another source of information for shareholders.
Annual Report 2020 143
144
Exploration and
Production Permits
and Data
1 Surat/Bowen Basin
Queensland
3
WA
2
NT
SA
QLD
4
1
NSW
Origin Energy Interests Other (Non Origin)
Origin permit
APLNG permit
Production facility
Pipeline
Pipeline
TAS
2 Beetaloo Basin
3 Browse Basin
4 Cooper Basin
NT
QLD
SA
WA
Annual Report 2020 Exploration and Production Permits and Data
145
1. Origin’s interests
Origin held interests in the following permits at 30 June 2020.
Basin/Project Area
Interest
Basin/Project Area
Interest
Basin/Project Area
Interest
Australia
Surat Basin/Ironbark (Queensland)
Talinga/Orana
ATP 788P (Shallows)
37.50% *1
ATP 788P (Deeps)
9.38% *1
ATP 692P and PL’s 209,
215, 226, 272, 216,
225, 445(A)
Other Surat Basin
ATP 973P
37.50% *1
ATP 972P and PL’s 469(A),
470 and 471(A)
Denison Trough (Queensland)
PL’s 43, 44, 45, 183
and 218 (Deeps)
18.75% *1
PPL’s 171, 181 and 2032
37.50% *1
PFL 26
37.50% *1
ATP 1191 Farm-out
(Mahalo block), PL’s 1082,1083 11.25%
PL’s 450, 451, 457 and 1012
18.75%
ATP 1191 and PL(A) 1062
18.75%
LNG (Gladstone)
PPL’s 162 and 163
PFL 20
37.50%
37.50%
Kenya/Kenya East/Bellevue/Anya
1
1
1
1
1
PL’s 179, 180, 228, 229
and 263
PL 247
PL’s 257, 273, 274, 275,
278, 279, 442, 466, 474
and 503 (Shallows)
PL 1025
PFL 19
15.23%
11.02%
11.72%
11.72%
11.72%
CSG (Queensland) Fairview/Arcadia
PPL’s 107, 176 and 2014
15.23%
1
1
1
1
1
1
PL 1084
PL 1011
PL 1018
Combabula/Reedy Creek
ATP 606P and PL’s 297, 403,
404, 407, 408, 405, 406(A),
412, 413 and 444(A)
PPL 178
Angry Jungle
ATP 631P and
PL’s 281 and 282
37.50% *1
34.77% *1
33.75% *1
37.50% *1
37.50% *1
34.77% *1
37.50% *1
6.79%
1
ATP 526P, ATP 2012P,
and PL’s 90, 91, 92, 99, 100,
232, 233, 234, 235 and 236,
PL(A) 1017
ATP 745P, ATP 2033 and
PL’s 420, 421 and 440,
PL(A) 1059
Spring Gully
ATP 592P and PL’s 195,
414, 415, 416, 417, 418,
268 and 419(A)
PL 204
PL 200
Peat
8.97%
1
PL 101
Browse Basin (Western Australia)
37.50% *1
TR/7, TR/8, WA-90R,
WA-91R, WA-92R
40.00%
Other Bowen Basin
Beetaloo Basin (Northern Territory)
8.94%
1
ATP 804P
10.99%
1
EP 76, EP 98 and EP117
77.50% *
PL’s 219 and 220
ATP 2047
37.50% *1
18.75%
1
Cooper-Eromanga Basin (Queensland)
ATP’s 736, 737, 738, 2025,
and 2026
75.00% *
35.44% *1
Condabri
37.40% *1
PL’s 265, 266 and 267
37.50% *1
Geothermal (South Australia)
35.89% *1
PL’s 177, 185, 186 and 2000
37.50% *1
PPL 143, 180 and 2026
37.50% *1
GRL 3
Notes:
30.00%
* Operatorship
1
Interest held through 37.5 per cent ownership
of Australian Pacific LNG Joint Venture
146
Annual
Reserves Report
For the year ended 30 June 2020
1. Reserves and resources
This Annual Reserves Report provides an update on the reserves and resources of Origin Energy Limited (Origin) and its share of Australia
Pacific LNG Pty Limited (APLNG), as at 30 June 2020.
1.1 Highlights
APLNG (Origin 37.5 per cent share)
• Strong field performance resulted in an increase in reserves in operated areas. This enabled a decision to not participate in some
low-value non-operated fields. During FY2020, APLNG also delivered record production. A detailed breakdown of movements in
Origin’s share of APLNG 2P (proved plus probable) reserves is as follows:
– 119 PJ upward revision of operated 2P reserves reflecting strong field performance and maturation of resources to reserves;
– 48 PJ increase in operated 2P reserves due to the acquisition of Ironbark from Origin;
– 104 PJ reduction in non-operated 2P reserves due to a decision to not participate in certain non-operated field developments
(–149 PJ), balanced against a 45 PJ reserves increase in other non-operated areas; and
– 265 PJ of production (an increase of 4 per cent on 2019) and underpinned by improved operated and non-operated field
performance. This was due to higher well availability and facility reliability as well as commissioning of the Eurombah Reedy Creek
Interconnect pipeline, which improved utilisation of processing capacity.
• Excluding net reductions in non-operated developments, APLNG appraisal and development drilling, along with development feasibility
assessment, has resulted in 2P reserves replacement of 90 per cent of production in operated fields over the last three years.
• Origin’s share of 1P (proved) reserves has continued to grow, with an increase of 10 per cent or 270 PJ before production as a result of
development drilling. After taking into account production, 1P reserves increased 5 PJ to 2,769 PJ. 1P reserves represent 61 per cent of
total 3P (proved plus probable plus possible) reserves as at 30 June 2020.
• APLNG also continues to mature its strong resource base with further exploration and appraisal activities, as well as technology trials
and a continued focus on reducing operating and capital costs.
Origin (excluding share of APLNG)
• A 129 PJ decrease in other 2P reserves reflects the sale of Ironbark assets to APLNG on 5 August 2019. Ironbark reserves and resources
are included within APLNG reserves at 30 June 2020, of which Origin owns 37.5 per cent.
Annual Report 2020 Annual Reserves Report
147
1.2 2P reserves (Origin share)
2P reserves decreased by 331 PJ (after production) to a total of 4,268 PJ, compared to 30 June 2019.
Origin 2P reserves by area
2P reserves by area (PJ)
2P
30/06/2019
Acquisition/
divestment
New booking/
discovery
Revisions/
extensions
Production
2P
30/06/2020
Australia Pacific LNG
Surat/Bowen (unconventional)
– Spring Gully & Denison asset
– Condabri, Talinga & Orana asset
– Reedy Creek, Combabula & Peat asset
– Non-operated assets
Other
Ironbark (unconventional)
Total
4,470
733
1,405
1,475
857
129
4,599
48
–
48
–
–
(129)
(81)
–
–
–
–
–
–
–
15
(70)
59
131
(104)
–
15
(265)
4,268
(39)
(101)
(63)
(62)
624
1,411
1,542
691
–
–
(265)
4,268
• Summary of 2P reserves movement – key changes include:
– 265 PJ decrease due to production;
– net 81 PJ decrease due to the divestment of Ironbark by Origin to APLNG;
– 119 PJ net positive revision in operated areas, reflecting:
· improved understanding of field behaviour, which resulted in an increase in estimated recovery from producing fields in Combabula,
Condabri, Talinga and Orana, partially offset by a decrease in Spring Gully; and
· the inclusion of new areas to reserves, including the Peat Flank asset (within Reedy Creek, Combabula and Peat) following
successful appraisal activities; and
– 104 PJ reduction in non-operated areas, primarily due to the decision by APLNG to not participate in certain future field
developments (149 PJ), offset by modest increases in reserves from other non-operated areas (45 PJ).
• As at 30 June 2020, developed 2P reserves represented 58 per cent of total 2P reserves.
• As at 30 June 2020, 100 per cent of Origin’s share of 2P reserves are unconventional gas.
Origin 2P reserves by development type
2P reserves by development type (PJ)
Developed
Undeveloped
30/06/2019
Developed
Undeveloped
30/06/2020
Total 2P
Total 2P
Australia Pacific LNG
Surat/Bowen (unconventional)
– Spring Gully & Denison asset
– Condabri, Talinga & Orana asset
– Reedy Creek, Combabula & Peat asset
– Non-operated assets
Other
Ironbark (unconventional)
Total
2,386
2,084
4,470
2,488
1,780
4,268
496
935
577
378
–
2,386
238
469
898
479
129
2,213
733
1,405
1,475
857
129
4,599
442
976
676
394
–
182
435
866
297
–
624
1,411
1,542
691
–
2,488
1,780
4,268
148
1.3 1P reserves (Origin share)
1P reserves increased by 270 PJ or 10 per cent (before production) and increased by 5 PJ after production to 2,769 PJ, when compared to
30 June 2019, due to development drilling.
As at 30 June 2020, developed 1P reserves represented 89 per cent of total 1P reserves. The remaining 11 per cent of 1P reserves
represents wells that have been spudded but not connected and planned wells that are immediately adjacent to drilled wells. 100 per cent
of 1P reserves are unconventional gas.
Origin 1P reserves by area
1P reserves by area (PJ)
1P
30/6/2019
Acquisition/
divestment
New booking/
discovery
Revisions/
extensions
Production
1P
30/6/2020
Australia Pacific LNG
Surat/Bowen (unconventional)
– Spring Gully & Denison asset
– Condabri, Talinga & Orana asset
– Reedy Creek, Combabula & Peat asset
– Non-operated assets
Other
Ironbark (unconventional)
Total
2,764
545
967
651
601
–
2,764
Origin 1P reserves by development type
–
–
–
–
–
–
–
–
–
–
–
–
–
270
(265)
2,769
(49)
160
173
(14)
–
270
(39)
(101)
(63)
(62)
456
1,026
761
526
–
–
(265)
2,769
1P reserves by development type (PJ)
Developed
Undeveloped
30/6/2019
Developed
Undeveloped
30/6/2020
Total 1P
Total 1P
Australia Pacific LNG
Surat/Bowen (unconventional)
– Spring Gully & Denison asset
– Condabri, Talinga & Orana asset
– Reedy Creek, Combabula & Peat asset
– Non-operated assets
Other
Ironbark (unconventional)
Total
2,370
496
935
577
363
–
2,370
1.4 2C Contingent resources for Origin Energy
Beetaloo Basin
394
49
32
74
239
–
394
2,764
2,478
545
967
651
601
–
442
975
674
387
–
2,764
2,478
291
14
51
87
139
–
291
2,769
456
1,026
761
526
–
2,769
A material contingent resource announcement of 6.6 Tscf (gross) or 2.3 Tscf (net) for the Beetaloo Basin was provided on 15 February 2017
to the ASX: https://www.asx.com.au/asxpdf/20170215/pdf/43g0qhh87j71bb.pdf
Origin increased its interest in the Beetaloo Joint Venture to 70 per cent in May 2017 by acquiring Sasol’s 35 per cent share:
https://www.asx.com.au/asxpdf/20170505/pdf/43j1ss71xqbxtc.pdf
During FY2020, Origin further increased its interest in the Beetaloo Joint Venture to 77.5 per cent by acquiring 7.5 per cent of the interest
owned by Falcon Oil and Gas: https://www.asx.com.au/asxpdf/20200407/pdf/44gs08yfdwfrjp.pdf
Refer to the Operating and Financial Review, released on the same date as this report for details of the current status of our Beetaloo
Basin asset.
Annual Report 2020 Annual Reserves Report
149
Appendix A: APLNG reserves and resources
Origin, as APLNG Upstream Operator, has prepared estimates of the reserves and resources held by APLNG for operated assets which are
detailed in this report.
Netherland, Sewell & Associates, Inc. (NSAI) has prepared a consolidated report of the reserves and resources held by APLNG for
non-operated assets. The reserves and resources estimates for the non-operated properties in their report have been independently
estimated by NSAI.
The tables below provide 1P, 2P and 3P reserves and 2C resources for APLNG (100 per cent) and Origin’s 37.5 per cent interest in these
APLNG (operated and non-operated) reserves and resources.
Reserves and resources held by APLNG (100 per cent share)
Reserves/resources classification
30/6/2019
Acquisition/
divestment
New booking/
discovery
Revisions/
extensions
Production
30/6/2020
1P (proven)
2P (proven plus probable)
3P (proven plus probable plus possible)
2C (best estimate contingent resource)
7,372
11,920
12,820
3,107
–
129
192
497
–
–
–
–
719
40
(234)
375
(708)
(708)
(708)
–
7,384
11,381
12,071
3,980
Reserves and resources held by Origin (37.5 per cent in APLNG)
Reserves/resources classification
30/6/2019
Acquisition/
divestment
New booking/
discovery
Revisions/
extensions
Production
30/6/2020
1P (proven)
2P (proven plus probable)
3P (proven plus probable plus possible)
2C (best estimate contingent resource)
2,764
4,470
4,808
1,165
–
48
72
187
–
–
–
–
270
15
(88)
141
(265)
(265)
(265)
–
2,769
4,268
4,526
1,493
See details above for movements in 1P and 2P reserves.
The 234 PJ decrease in APLNG (100 per cent share) 3P reserves, excluding production, is due to decisions to not participate in some
non-operated field developments (–441 PJ), partially offset by improved understanding of estimated recovery in other producing areas.
The 873 PJ increase in APLNG (100 per cent share) 2C resources is primarily due to the acquisition of Ironbark and the decision to not
participate in some non-operated field developments. A number of appraisal activities are presently ongoing that if successful would
convert some further resources to reserves.
150
Appendix B: Notes relating to this report
a. Methodology regarding reserves
c. Reversionary rights
f. Abbreviations
and resources
The Reserves Report has been prepared
to be consistent with the Petroleum
Resources Management System (PRMS)
2018 published by Society of Petroleum
Engineers (SPE). This document may
be downloaded from the SPE website:
https://www.spe.org/en/industry/reserves/
Additionally, this Reserves Report has
been prepared to be consistent with the
ASX reporting guidelines. For all assets,
Origin reports reserves and resources
consistent with SPE guidelines as follows:
proved reserves (1P); proved plus probable
reserves (2P); proved plus probable plus
possible reserves (3P); best estimate
contingent resources (2C). Reserves must
be discovered, recoverable, commercial
and remaining.
The CSG reserves and resources held
within APLNG’s properties have either
been independently prepared by NSAI
or prepared by Origin. The reserves and
resources estimates contained in this report
have been prepared in accordance with
the standards, definitions and guidelines
contained within the Petroleum Resources
Management System (PRMS) and generally
accepted petroleum engineering and
evaluation principles as set out in the SPE
Reserves Auditing Standards.
Origin does not intend to report prospective
or undiscovered resources as defined by
the SPE in any of its areas of interest on an
ongoing basis.
b. Economic test for reserves
The assessment of reserves requires a
commercial test to establish that reserves
can be economically recovered. Within
the commercial test, operating cost and
capital cost estimates are combined with
fiscal regimes and product pricing to
confirm the economic viability of producing
the reserves.
Gas reserves are assessed against existing
contractual arrangements, and local market
conditions, as appropriate. In the case
of gas reserves where contracts are not
in place a forward price scenario based
on monetisation of the reserves through
domestic markets has been used, including
power generation opportunities, direct sales
to LNG and other end users and utilisation
of Origin’s wholesale and retail channels
to market.
For CSG reserves that are intended to
supply the APLNG CSG to LNG project,
the economic test is based on a weighted
average price across domestic, spot and
LNG contracts, less short run marginal costs
for downstream transport and processing.
This price is exposed to changes in the
supply/demand balance in the market
through oil price–linked LNG contracts.
The CSG interests that Australia Pacific
LNG acquired from Tri-Star in 2002 are
subject to reversionary rights. If triggered,
these rights will require Australia Pacific
LNG to transfer back to Tri-Star a 45 per
cent interest in those CSG interests for
no additional consideration. Origin has
assessed the potential impact of these
reversionary rights based on economic tests
consistent with the reserves and resources
referable to the CSG interests, and based
on that assessment does not consider that
the existence of these reversionary rights
impacts the reserves and resources quoted
in this report. Tri-Star has commenced
proceedings against Australia Pacific LNG
claiming that reversion has occurred.
Australia Pacific LNG denies that reversion
has occurred and is defending the claim.1
bbl
Tscf
CSG
kbbls
barrel
trillion standard cubic feet
coal seam gas
kilo barrels = 1,000 barrels
ktonnes
kilo tonnes = 1,000 tonnes
mmboe million barrels of oil equivalent
PJ
PJe
petajoule = 1 x 1015 joules
petajoule equivalent
g. Conversion factors for PJe
CSG
1.038 PJ/Bscf
d. Information regarding the preparation
of this Reserves Report
h. Reference point
Reference points for Origin’s petroleum
reserves and contingent resources are
defined points within Origin’s operations
where normal exploration and production
business ceases, and quantities of the
produced product are measured under
defined conditions prior to custody transfer.
Fuel, flare and vent consumed to the
reference points are excluded.
i. Preparing and aggregating
petroleum resources
Petroleum reserves and contingent
resources are typically prepared by
deterministic methods with support from
probabilistic methods. Petroleum reserves
and contingent resources are aggregated
by arithmetic summation by category
and as a result, proved reserves may be a
conservative estimate due to the portfolio
effects of the arithmetic summation.
Proved plus probable plus possible may
be an optimistic estimate due to the same
aforementioned reasons.
j. Methodology and internal controls
The reserves estimates undergo an
assurance process to ensure that they
are technically reasonable given the
available data and have been prepared
according to our reserves and resources
process, which includes adherence to the
PRMS Guidelines. The assurance process
includes peer reviews of the technical
and commercial assumptions. The annual
reserves report is reviewed by management
with the appropriate technical expertise,
including the Chief Petroleum Engineer and
Integrated Gas General Managers.
The CSG reserves and resources held
within APLNG’s properties have either
been independently prepared by NSAI
or prepared by Origin. All assessments
are based on technical, commercial and
operational data provided by Origin on
behalf of APLNG.
The statements in this report relating to
reserves and resources as of 30 June 2020
for APLNG’s interests in non-operated
assets are based on information in the NSAI
report dated 4 August 2020. The data has
been compiled by Mr John Hattner, a full-
time employee of NSAI. Mr John Hattner
has consented to the statements based
on this information, and to the form and
context in which these statements appear.
The statements in this report relating to
reserves and resources for other assets are
based on, and fairly represent, information
and supporting documentation prepared
by, or under the supervision of, qualified
petroleum reserves and resources
evaluators who are employees of Origin.
This Reserves Statement as a whole has
been approved by Mr Simon Smith FIEAust
CPEng NER RPEQ, who is a full-time
employee of Origin. Mr Simon Smith is
Chief Petroleum Engineer, a qualified
Petroleum Reserves and Resources
Evaluator, a member of the Society of
Petroleum Engineers and has consented
to the form and context in which these
statements appear.
e. Rounding
Information on reserves quoted in this
report are rounded to the nearest whole
number. Some totals in tables in this report
may not add due to rounding. Items that
round to zero are represented by the
number 0, while items that are actually zero
are represented with a dash: ‘-’.
1 Refer to section 7 of the Operating and Financial
Review released to the ASX on 20 August 2020
for further information.
Annual Report 2020 151
152
Five-year
Financial History
A reconcilation between statutory and underlying profit measures can be found in note A1 of the Origin Consolidated Financial Statements.
Income statement ($m)
2020(1)
2019(1)
2018(1)
2017(1)
2016(1)
Total external revenue
13,157
14,727
14,883
14,107
12,174
Underlying
EBITDA(2)
Depreciation and amortisation expense
Share of interest, tax, depreciation and amortisation
of equity accounted investees(3)
EBIT
Net financing costs
Income tax benefit/(expense)
Non-controlling interests
Segment result and underlying consolidated profit
Impact of items excluded from segment result and
underlying consolidated profit net of tax
Statutory
Profit attributable to members of the parent entity
Statement of financial position ($m)
Total assets
Net debt/(cash)
Shareholders’ equity – members/parent entity interest
Adjusted net debt/(cash)(4)
Shareholders’ equity – total
Cash flow
Net cash from operating and investing activities
– total operations ($m)
Key ratios
Statutory basic earnings per share (cents)(5)
Underlying basic earnings per share (cents)(5)
Total dividend per share (cents)(6)
Net debt to net debt plus equity (adjusted) (%)(4)
Underlying EBITDA by segment ($m)
Energy Markets(2)
Integrated Gas
Contact Energy
Corporate
3,141
(509)
(1,303)
1,329
(126)
(177)
(3)
3,232
(419)
(1,504)
1,308
(154)
(123)
(3)
1,023
1,028
3,217
(381)
(1,194)
1,642
(278)
(339)
(3)
1,022
2,530
(477)
(925)
1,128
(296)
(279)
(3)
550
(940)
183
(804)
(2,776)
1,696
(624)
(296)
776
(109)
(286)
(16)
365
(993)
83
1,211
218
(2,226)
(628)
25,093
5,688
12,680
5,158
12,701
25,743
6,084
13,129
5,417
13,149
24,257
7,289
11,804
6,496
11,828
25,199
8,364
11,396
8,111
11,418
28,905
9,470
14,039
9,131
14,060
1,813
1,914
2,645
1,378
1,215
4.7
58.1
25
29
1,459
1,741
68.8
58.4
25
29
1,574
1,892
(59)
(234)
12.4
58.2
–
36
1,811
1,521
–
(115)
(126.9)
31.3
-
42
1,492
1,104
–
(66)
(39.8)
23.2
10
39
1,330
386
61
(81)
General Information
Number of employees (Excluding Contact Energy)
Weighted average number of shares(5)
5,232
5,360
5,565
5,894
5,811
1,759,801,186
1,758,935,655
1,757,442,268
1,754,489,221
1,578,213,157
Integrated Gas(7)
2P reserves (PJe)
Product sales volumes (PJe)
• Liquified Natural Gas (Kt)
• Natural gas and ethane (PJ)
• Crude oil (kbbls)
• Condensate/naphtha (kbbls)
• LPG (kt)
Production volumes (PJe)
4,268
251
3,258
70
–
–
–
4,599
254
3,257
73
–
–
–
4,799
255
3,213
77
–
–
–
265
255
254
5,788
334
2,668
163
1,209
1,615
144
323
6,277
228
659
168
1,629
1,403
127
232
Annual Report 2020 Five-year Financial History
153
Energy Markets
Generation (MW) – owned
Generation dispatched (TWh)
Number of customers (’000)
• Electricity
• Natural gas
• LPG
Electricity (TWh)
Natural gas (PJ)
LPG (Kt)
2020(1)
2019(1)
2018(1)
2017(1)
2016(1)
6,029
18
4,232
2,631
1,220
363
34
204
417
6,029
20
4,192
2,639
1,191
362
36
222
426
5,981
21
4,181
2,666
1,145
370
38
214
450
6,011
20
4,210
2,716
1,112
382
40
188
448
6,011
20
4,217
2,741
1,089
387
38
167
458
(1)
Includes discontinued operations and assets held for sale unless stated otherwise.
(2) FY2019 includes premiums relating to certain electricity hedges within Underlying Profit. The equivalent amounts in prior years have not been restated in the above
table. Had the amounts been adjusted, the impact to underyling EBITDA in each period would have been a reduction in each year is as follows: FY2018 $(160) million;
FY2017 $(141) million; and FY2016 $(139) million.
(3) Origin discloses its equity accounted results in two lines: ‘share of EBITDA of equity accounted investees,’ included in EBITDA; and ‘share of interest, tax, depreciation
and amortisation of equity accounted investees,’ included between EBITDA and EBIT.
(4) Total current and non-current interest-bearing liabilities only, less cash and cash equivalents excluding APLNG related cash, less fair value adjustments on hedged
borrowings.
(5) Prior period adjusted for the bonus element (discount to market price) of the September 2015 rights issue.
(6) Dividends represent the interim and final dividends determined for each financial year. This includes the final dividend for FY2020 determined on 20 August 2020 to be
paid on 2 October 2020. The amounts paid within each financial year are 30c, 10c, 0c, 0c and 35c respectively.
(7) 2018 excludes Lattice Energy (continuing operations basis shown).
154
Glossary and
Interpretation
Statutory financial measures
Non-IFRS financial measures
Statutory financial measures are measures included in the Financial
Statements for the Origin Consolidated Group, which are measured
and disclosed in accordance with applicable Australian Accounting
Standards. Statutory financial measures also include measures that
have been directly calculated from, or disaggregated directly from,
financial information included in the Financial Statements for the
Origin Consolidated Group.
Term
Meaning
Cash flows from
investing activities
Statutory cash flows from investing activities as
disclosed in the Statement of Cash Flows in the
Origin Consolidated Financial Statements.
Cash flows from
operating activities
Statutory cash flows from operating activities as
disclosed in the Statement of Cash Flows in the
Origin Consolidated Financial Statements.
Cash flows used in
financing activities
Statutory cash flows used in financing activities
as disclosed in the Statement of Cash Flows in
the Origin Consolidated Financial Statements.
Net Debt
Non-controlling
interest
Statutory Profit/Loss
Statutory
earnings per share
Total current and non-current interest-bearing
liabilities only, less cash and cash equivalents
excluding cash to fund APLNG day-to-day
operations.
Economic interest in a controlled entity of
the consolidated entity that is not held by
the Parent entity or a controlled entity of the
consolidated entity.
Net profit/loss after tax and non-controlling
interests as disclosed in the Income Statement
in the Origin Consolidated Financial
Statements.
Statutory Profit/Loss divided by weighted
average number of shares as disclosed in the
Income Statement in the Origin Consolidated
Financial Statements.
Non-IFRS financial measures are defined as financial measures that
are presented other than in accordance with all relevant Accounting
Standards. Non-IFRS financial measures are used internally by
management to assess the performance of Origin’s business,
and to make decisions on allocation of resources. The non-IFRS
financial measures have been derived from statutory financial
measures included in the Origin Consolidated Financial Statements,
and are provided in this report, along with the statutory financial
measures, to enable further insight and a different perspective into
the financial performance, including profit and loss and cash flow
outcomes, of the Origin business.
The principal non-IFRS profit and loss measure of Underlying Profit
has been reconciled to Statutory Profit in Section 5.1. The key non-
IFRS financial measures included in this report are defined below.
Term
AASB
Meaning
Australian Accounting Standards Board.
Adjusted Net Debt Net Debt adjusted to remove fair value adjustments
on hedged borrowings.
Adjusted
Underlying EBITDA
Origin Underlying EBITDA – share of APLNG
Underlying EBITDA + net cash from APLNG over
the relevant 12-month period.
Average
interest rate
Interest expense divided by Origin’s average drawn
debt during the period.
cps
Cents per share.
Free Cash Flow
Net cash from operating and investing activities
(excluding major growth projects), less
interest paid.
FY20
(current period)
Year ended 30 June 2020.
FY19 (prior period) Year ended 30 June 2019.
Gearing
Adjusted Net Debt/(Adjusted Net Debt +
Total Equity).
Gross Profit
Revenue less cost of goods sold.
Items excluded
from Underlying
Profit (IEUP)
Items that do not align with the manner in which
the Chief Executive Officer reviews the financial
and operating performance of the business, which
are excluded from Underlying Profit. See Section
5.1 for details.
MRCPS
Non-cash fair
value uplift
Mandatorily Redeemable Cumulative
Preference Shares.
Reflects the impact of the accounting uplift in
the asset base of APLNG, which was recorded on
creation of APLNG and subsequent share issues
to Sinopec. This balance will be depreciated in
APLNG’s Income Statement on an ongoing basis
and, therefore, a dilution adjustment is made to
remove this depreciation.
Share of ITDA
Origin’s share of equity accounted interest, tax,
depreciation and amortisation.
Total
Segment Revenue
Total revenue for the Energy Markets, Integrated
Gas and Corporate segments, as disclosed in note
A1 of the Origin Consolidated Financial Statements.
Underlying EPS
Underlying Profit/Loss divided by weighted
average number of shares.
Annual Report 2020 Glossary and Interpretation
155
Term
Meaning
Term
Meaning
Non-financial terms
Underlying EBITDA Underlying earnings before underlying interest,
1P reserves
Underlying
share of ITDA
Underlying
Profit/Loss
underlying tax, underlying depreciation and
amortisation (EBITDA) as disclosed in note A1 of
the Origin Consolidated Financial Statements.
Share of interest, tax, depreciation and amortisation
of equity accounted investees adjusted for items
excluded from Underlying Profit.
Underlying net profit/loss after tax and non-
controlling interests as disclosed in note A1 of the
Origin Consolidated Financial Statements.
2P reserves
Underlying
ROCE (Return on
Capital Employed)
Calculated as Adjusted EBIT/Average
Capital Employed.
Average Capital Employed = Shareholders Equity
+ Origin Debt + Origin’s Share of APLNG project
finance – non-cash fair value uplift + net derivative
liabilities. The average is a simple average of
opening and closing in any 12-month period.
3P reserves
Adjusted EBIT = Origin Underlying EBIT and
Origin’s share of APLNG Underlying EBIT + Dilution
Adjustment = Statutory Origin EBIT adjusted to
remove the following items: a) items excluded from
underlying earnings; b) Origin’s share of APLNG
underlying interest and tax; and c) the depreciation
of the non-cash fair value uplift adjustment. In
contrast, for remuneration purposes, Origin’s
statutory EBIT is adjusted to remove Origin’s
share of APLNG statutory interest and tax (which
is included in Origin’s reported EBIT) and certain
items excluded from underlying earnings. Gains
and losses on disposals and impairments will only
be excluded subject to Board discretion.
2C resources
Boe
C&I
DMO
ERP
GJ
JCC
Joule
Kansai
kT
Mtpa
MW
MWh
NEM
Proved Reserves are those reserves which
analysis of geological and engineering data
can be estimated with reasonable certainty to
be commercially recoverable. There should
be at least a 90 per cent probability that the
quantities actually recovered will equal or
exceed the estimate.
The sum of Proved plus Probable Reserves.
Probable Reserves are those additional reserves
which analysis of geological and engineering
data indicate are less likely to be recovered than
Proved Reserves but more certain than Possible
Reserves. There should be at least a 50 per cent
possibility that the quantities actually recovered
will equal or exceed the best estimate of Proved
plus Probable Reserves (2P).
Proved plus Probable plus Possible Reserves.
Possible Reserves are those additional Reserves
which analysis of geological and engineering
data suggest are less likely to be recoverable
than Probable Reserves. The total quantities
ultimately recovered from the project have at
least a 10 per cent probability of exceeding
the sum of Proved plus Probable plus
Possible (3P), which is equivalent to the high
estimate scenario.
The best estimate quantity of petroleum
estimated to be potentially recoverable from
known accumulations by application of
development oil and gas projects, but which are
not currently considered to be commercially
recoverable due to one or more contingencies.
The total quantities ultimately recovered
from the project have at least a 50 per cent
probability to equal or exceed the best estimate
for 2C contingent resources.
Barrel of oil equivalent.
Commercial and Industrial.
Default Market Offer.
Enterprise resource planning.
Gigajoule = 109 joules.
Japan Customs-cleared Crude (JCC) is the
average price of crude oil imported to Japan.
APLNG’s long-term LNG sales contracts are
priced based on the JCC index.
Primary measure of energy in the metric system.
When referring to the off-taker under the LNG
Sale and Purchase Agreement (SPA) with
APLNG, means Kansai Electric Power Co. Inc.
kilo tonnes = 1,000 tonnes.
Million tonnes per annum.
Megawatt = 106 watts.
Megawatt hour = 103 kilowatt hours.
National Electricity Market.
156
Term
NPS
PJ
PJe
Meaning
Interpretation
Net Promoter Score (NPS) is a measure of
customers’ propensity to recommend Origin to
friends and family.
Petajoule = 1015 joules.
Petajoules equivalent = an energy measurement
used to represent the equivalent energy in
different products so the amount of energy
contained in these products can be compared.
All comparable results reflect a comparison between the current
period and the prior period, unless otherwise stated.
A reference to APLNG or Australia Pacific LNG is a reference to
Australia Pacific LNG Pty Limited in which Origin holds a 37.5 per
cent shareholding. A reference to Octopus Energy or Octopus is
a reference to Octopus Energy Holdings Limited in which Origin
holds a 20 per cent shareholding. Origin’s shareholding in APLNG
and Octopus Energy is equity accounted.
A reference to $ is a reference to Australian dollars unless
specifically marked otherwise.
All references to debt are a reference to interest-bearing debt only.
Individual items and totals are rounded to the nearest appropriate
number or decimal. Some totals may not add due to rounding of
individual components.
When calculating a percentage change, a positive or negative
percentage change denotes the mathematical movement in
the underlying metric, rather than a positive or a detrimental
impact. Percentage changes on measures for which the numbers
change from negative to positive, or vice versa, are labelled as
not applicable.
PPA
Power Purchase Agreement.
Scope 1 emissions
Direct emissions from sources that are owned
or operated by Origin, in particular electricity
generation and gas development.
Scope 2 emissions
Emissions from the electricity that we consume
to power our offices and operating sites.
Scope 3 emissions
Sinopec
SME
TRIFR
TW
TWh
VDO
Watt
Indirect emissions, other than Scope 2, relating
to Origin’s value chain that we do not own
or control, including wholesale purchases of
electricity from the NEM. LPG and corporate
Scope 3 emissions are excluded as their
emissions are not material.
When referring to the off-taker under the LNG
Sale and Purchase Agreement (SPA) with
APLNG, means China Petroleum & Chemical
Corporation, which has appointed its subsidiary
Unipec Asia Co. Ltd. to act on its behalf under
the LNG SPA.
Small Medium Enterprise.
Total Recordable Incident Frequency Rate.
Terawatt = 1012 watts.
Terawatt hour = 109 kilowatt hours.
Victorian Default Offer.
A measure of power when a one ampere of
current flows under one volt of pressure.
Annual Report 2020 Directory
Registered Office
Level 32, Tower 1
100 Barangaroo Avenue
Barangaroo, NSW 2000
GPO Box 5376
Sydney NSW 2001
T (02) 8345 5000
F (02) 9252 9244
originenergy.com.au
enquiry@originenergy.com.au
Secretary
Helen Hardy
Share Registry
Boardroom Pty Limited
Level 12, 225 George Street
Sydney NSW 2000
GPO Box 3993
Sydney NSW 2001
T Australia 1300 664 446
T
F (02) 9279 0664
International (+61 2) 8016 2896
boardroomlimited.com.au
origin@boardroomlimited.com.au
Auditor
EY
Sources: Water and energy savings are based
on a comparison between a recycled paper
manufactured at Arjowiggins Graphic mills
versus an equivalent virgin fibre paper according
to the latest European BREF data available
(virgin fibre paper manufactured in a non-
integrated paper mill). CO2 emission savings is
the difference between the emissions produced
at an Arjowiggins Graphic mill for a specific
recycled paper compared to the manufacture of
an equivalent virgin fibre paper. Carbon footprint
data evaluated by Labelia Conseil in accordance
with the Bilan Carbone® methodology. Results are
obtained according to technical information and
subject to modification.
Further information about Origin’s
performance can be found on our website:
originenergy.com.au