2021 Annual ReportWhere all good change startsKurt LoganInstrumentation and Electrical TechnicianIntegrated Gas Contents
1
Contents
A message from Scott and Frank
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
Share and Shareholder Information
Exploration and Production Permits and Data
Annual Reserves Report
Five-year Financial History
Glossary and Interpretation
2
4
5
6
8
10
48
52
76
78
143
146
148
152
154
2
Annual Report 2021
A message from
Scott and Frank
“This year we focused on our position
as a leader for positive change
with our Where all good change
starts campaign.”
Welcome to the 2021 Annual Report
Origin’s purpose, Getting energy right for our customers,
communities and planet, drives everything we do as an
organisation. This purpose has guided us over the past 12 months
as, despite the many challenges of the COVID-19 pandemic, our
people went the extra mile to ensure we could provide affordable
and reliable energy to our customers. We thank our teams for
this dedication.
This year we focused on our position as a leader for positive change
with our Where all good change starts campaign. Origin’s strategy
is all about that positive change as we connect our customers to the
energy and technologies of the future and lead the transition to a
low-carbon economy.
To lead that change, Origin has a team of close to 5,000 people
across Australia and the Pacific. That team includes Kurt Logan, who
features on the front cover of this report. Kurt is a technician at our
Condabri facility in Queensland, which as part of our Australia Pacific
LNG joint venture, supplies around 30 per cent of Australia’s east
coast gas demand.
Progress on our commitments
Origin’s FY2021 financial performance reflected a strong
operational position against the headwinds of volatile commodities
markets for electricity, natural gas and oil. Against this backdrop
of economic uncertainty resulting from the pandemic, we
demonstrated the strength of our diversified model: Integrated Gas
with its gas production and exploration and Energy Markets with its
position in generation and as a multi-product retailer with energy
and broadband services.
Our focus on capital discipline and cost management allowed
us to balance the priorities of paying down debt and delivering
dividends to shareholders, while continuing to invest in targeted
growth opportunities.
For the full year, Origin announced a statutory loss of $2,291 million,
primarily comprising $2,247 million in non-cash charges, including
impairments and a deferred tax liability. Our Underlying Profit of
$318 million reflected lower commodity prices in the Energy Markets
and Integrated Gas divisions. This was partially offset by lower
operating costs for Australia Pacific LNG, retail cost savings, lower
interest expense and oil hedging gains.
Origin’s Free Cash Flow remained robust at $1,140 million, enabling
debt reduction of $519 million, while allowing for investment in
growth and an unfranked final dividend of 7.5 cents per share.
In the gas growth assets, we continued exploration activities in the
prospective Beetaloo and Canning basins. Our future fuels activities
gathered momentum, with a number of hydrogen feasibility projects
including a green ammonia export project in Tasmania’s Bell Bay
expected to be completed by the end of 2021.
A message from Scott and Frank
3
Origin is progressing work on updating our existing emissions
reduction targets consistent with a 1.5 degree pathway. Our long-
term aim is to achieve net zero Scope 1 and Scope 2 emissions
by 2050, and as part of that ambition we introduced a short-term
target to reduce our Scope 1 emissions by an average of 10 per cent
per annum between FY2021 and FY2023, from a 2017 baseline.
This target is linked to executive remuneration, and in FY2021 we
achieved an 11 per cent decline in Scope 1 emissions compared to
the baseline.
Our business performance
In Integrated Gas, Australia Pacific LNG maintained production
of 263 petajoules (Origin share) driven by outstanding field
performance, associated capital expenditure reductions and further
improvements in operational efficiency. Underlying EBITDA was
$1,135 million - a 35 per cent reduction on the prior year, primarily
due to lower realised oil prices that were partially offset by
lower costs.
Australia Pacific LNG’s performance was a standout, safely curtailing
output when the market was subdued, and rapidly ramping up
production when demand recovered. In FY2021, Australia Pacific
LNG matched previous daily production records and shipped a
record 130 cargoes for the year.
Across Energy Markets, lower electricity gross profit was driven
primarily by the impact of lower wholesale prices on tariffs, higher
network and metering costs, and assistance provided to customers
adversely affected by the pandemic. This was partially offset by a
reduction in the cost of energy. Lower gas margins were driven by
a combination of lower gas tariffs, the roll-off of long-term capacity
contracts and higher supply costs. Underlying EBITDA for Energy
Markets was $991 million, down 32 per cent on the prior year.
In our Retail business our Strategic Net Promoter Score reached a
record high and customer accounts increased by 30,000 through
our Everyday Rewards plan and growth segments, including solar,
broadband and community energy services. Our investment in
Octopus Energy continues to exceed expectations. The rollout
of the Octopus customer service platform, Kraken, gathered
momentum with more than 250,000 customers benefiting from
improved customer service. We continue to lead the industry on
cost performance, achieving $110 million in savings since 2018 and
we will achieve further savings as the Kraken rollout progresses.
Outlook
In our full-year results, we gave guidance to Underlying EBITDA
in FY2022 of between $1,850–$2,150 million, compared to
$2,048 million in FY2021. This reflects weaker performance from
Energy Markets largely offset by an expected stronger contribution
from Australia Pacific LNG.
We anticipate that challenging conditions for our Energy Markets
business will continue this year, ahead of a rebound in FY2023 if
current forward prices continue and flow through to tariffs.
Australia Pacific LNG is expected to achieve a distribution breakeven
of between US$20–US$25 a barrel. With realised prices expected
to improve in FY2022 due to the lag in oil price flowing through
to long-term contract prices, it is estimated that net cash flows
from Australia Pacific LNG to Origin will be greater than $1 billion
in FY2022.
As always, guidance is provided on the basis that market conditions
and the regulatory environment do not materially change, and is
subject to the potential ongoing impacts of COVID-19 on demand
and customer affordability.
Looking forward
Scott Perkins became Chairman at our Annual General Meeting in
October 2020, after five years as a director. We were pleased to
welcome Ilana Atlas, Mick McCormack and Joan Withers to the
Board as independent Non-executive Directors. Their contribution
to the Board has already proven invaluable. We thank Gordon Cairns,
our previous Chairman, and Teresa Engelhard for their dedication to
Origin during their directorships.
As we enter Origin’s third decade, we are excited by the possibilities
that will come with the energy transition and look forward to
supporting our customers while continuing to play our part in
reducing Australia’s emissions. Origin’s business model is well
placed to prosper in a low-carbon world. As shareholders we hope
you share our excitement for the future.
We look forward to welcoming many of you to this year’s Annual
General Meeting on 20 October, which will again be held virtually in
response to the COVID-19 pandemic.
Thank you for your continued support.
Scott Perkins
Chairman
Frank Calabria
Chief Executive Officer
4
Annual Report 2021
About Origin
Leading integrated
energy company
4.3 million
customer accounts
5,000
employees
Listed on the Australian Securities
Exchange in 2000
Electricity, gas, LPG and
broadband customers across
Australia and the Pacific
Inclusivity in the workplace;
leading parental support
Climate transition embedded
in our strategy
Powering
Australia
37.5% interest in Australia
Pacific LNG
Australia's first approved
science-based emissions targets
7,500 MW generation portfolio,
including 1,400 MW owned
and contracted renewables
and storage
Exporting to Asia; supplies
~30% of Australian east coast
gas demand
Supporting
Australian communities
Driving future
energy innovation
Exploration and
development
The Origin Energy Foundation has
contributed more than $32 million
over 11 years
20% interest in Octopus Energy,
investing in new technology,
start-ups and future fuels
Positions in three large prospective
onshore basins: the Beetaloo,
Canning and Cooper-Eromanga
Bringingto everything we say and do.good energy Where We Operate
5
Where We Operate
Canning BasinSouth East QueenslandPacific countries LPGBowen/ Surat basinsBrisbaneGladstoneRabaulLaeSantoHoniaraPort VilaSuvaLautokaLabasaApiaPago PagoRarotongaPort MoresbyGasPumped hydroSolar (contracted)Wind (contracted)CoalWind (contracted, not complete)LPG seaboard terminalElectricity customer accountsNatural gas customer accountsOrigin/JV upstream acreageAPLNG upstream acreageProduction facilityAPLNG pipelineExploration & production acreageGenerationBeetaloo BasinAdelaideMelbourneHobartBrisbaneBowen/ Surat Cooper Eromanga BasinbasinsGladstoneLNG ExportBrowse BasinSydney566k492k1,175k350k637k178k246k215k14kCanning BasinSouth East QueenslandPacific countries LPGBowen/ Surat basinsBrisbaneGladstoneRabaulLaeSantoHoniaraPort VilaSuvaLautokaLabasaApiaPago PagoRarotongaPort MoresbyGasPumped hydroSolar (contracted)Wind (contracted)CoalWind (contracted, not complete)LPG seaboard terminalElectricity customer accountsNatural gas customer accountsOrigin/JV upstream acreageAPLNG upstream acreageProduction facilityAPLNG pipelineExploration & production acreageGenerationBeetaloo BasinAdelaideMelbourneHobartBrisbaneBowen/ Surat Cooper Eromanga BasinbasinsGladstoneLNG ExportBrowse BasinSydney566k492k1,175k350k637k178k246k215k14kCanning BasinSouth East QueenslandPacific countries LPGBowen/ Surat basinsBrisbaneGladstoneRabaulLaeSantoHoniaraPort VilaSuvaLautokaLabasaApiaPago PagoRarotongaPort MoresbyGasPumped hydroSolar (contracted)Wind (contracted)CoalWind (contracted, not complete)LPG seaboard terminalElectricity customer accountsNatural gas customer accountsOrigin/JV upstream acreageAPLNG upstream acreageProduction facilityAPLNG pipelineExploration & production acreageGenerationBeetaloo BasinAdelaideMelbourneHobartBrisbaneBowen/ Surat Cooper Eromanga BasinbasinsGladstoneLNG ExportBrowse BasinSydney566k492k1,175k350k637k178k246k215k14kCanning BasinSouth East QueenslandPacific countries LPGBowen/ Surat basinsBrisbaneGladstoneRabaulLaeSantoHoniaraPort VilaSuvaLautokaLabasaApiaPago PagoRarotongaPort MoresbyGasPumped hydroSolar (contracted)Wind (contracted)CoalWind (contracted, not complete)LPG seaboard terminalElectricity customer accountsNatural gas customer accountsOrigin/JV upstream acreageAPLNG upstream acreageProduction facilityAPLNG pipelineExploration & production acreageGenerationBeetaloo BasinAdelaideMelbourneHobartBrisbaneBowen/ Surat Cooper Eromanga BasinbasinsGladstoneLNG ExportBrowse BasinSydney566k492k1,175k350k637k178k246k215k14k 6
Board of
Directors
Annual Report 2021
Scott Perkins
John Akehurst
Ilana Atlas
Maxine Brenner
Frank Calabria
Independent
Non-executive Chairman
Independent
Non-executive Director
Independent
Non-executive Director
Independent
Non-executive Director
Managing Director &
Chief Executive Officer
Tenure 5 years, 11 months
Tenure 12 years, 4 months
Tenure 6 months
Tenure 7 years, 9 months
Tenure 4 years, 10 months
Scott Perkins joined the
Board in September
2015 and was appointed
Chairman in October 2020.
He is Chairman of the
Nomination Committee
and a member of the
Audit, Remuneration and
People, Health, Safety
and Environment and
Risk committees.
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
Group 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.
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.
Ilana Atlas joined the Board
in February 2021.
Ilana is a Non-executive
Director of ANZ Banking
Group Limited (since 2014),
Scentre Group Limited
(since May 2021), Scentre
Management Limited (since
May 2021), RE1 Limited
(since May 2021), and RE2
Limited (since May 2021).
She is the Chair of Jawun
and on the Board of the
Paul Ramsay Foundation
and Paul Ramsay Holdings
Pty Ltd.
Ilana was previously the
Chair of Coca-Cola Amatil
Limited (2017 - 2021). She
was a Director of Coca-
Cola Amatil Limited (2011 –
2021), Treasury Corporation
of New South Wales
(2013 – 2017), Westfield
Group (2011 – 2014) and
Suncorp (2011 – 2014).
Her last executive role was
Group Executive, People,
at Westpac, where she
was responsible for human
resources, corporate affairs
and sustainability. Prior to
that role, she was Group
Secretary and General
Counsel. Before her 10-year
career at Westpac, Ilana
was a partner in law firm
Mallesons Stephen Jaques
(now known as King & Wood
Mallesons). Ilana has held
a number of management
roles in the firm including
Executive Partner, People
and Information, and
Managing Partner.
Ilana holds a Bachelor of
Jurisprudence (Honours)
and Bachelor of Laws
(Honours) from the
University of Western
Australia and Masters of
Laws from the University
of Sydney.
Maxine Brenner joined the
Board in November 2013.
She is Chairman of the Risk
Committee and a member
of the Audit, Remuneration
and People 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) Non-
executive Director of Qantas
Airways Ltd (since August
2013) and Woolworths
Group Limited (since
1 December 2020). She
is also a member of the
University of NSW Council.
Maxine’s former
directorships include
Growthpoint Properties
Australia, Treasury
Corporation of NSW,
Bulmer Australia Ltd,
Neverfail Springwater Ltd
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
a Fellow of the Chartered
Accountants Australia and
New Zealand and a Fellow
of the Financial Services
Institute of Australasia.
Board of Directors
7
Greg Lalicker
Mick McCormack
Bruce Morgan
Steven Sargent
Joan Withers
Independent
Non-executive Director
Independent
Non-executive Director
Independent
Non-executive Director
Independent
Non-executive Director
Independent
Non-executive Director
Tenure 2 years, 5 months
Tenure 8 months
Tenure 8 years, 9 months
Tenure 6 years, 3 months
Tenure 10 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 USA.
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 has a Master of
Business Administration and
a law degree.
Mick McCormack joined
the Board in December
2020. He is a member
of the Health, Safety
and Environment and
the Remuneration and
People committees.
Mr McCormack is Chairman
of Central Petroleum
Limited and Non-executive
Director of Austal Limited.
He is also Chairman of
the Australian Brandenburg
Orchestra Foundation and
a director of the
Clontarf Foundation.
Mr McCormack was
previously Managing
Director and CEO of
APA Group (2004-2019)
and has more than 37
years of experience in the
energy and infrastructure
sectors, including gas-fired
and renewable energy
power generation, gas
processing, LNG and
underground storage. Prior
to joining APA in 2000,
Mr McCormack held various
senior management roles
with AGL Energy.
Mr McCormack holds
a Masters of Business
Administration from the
University of Queensland,
a Graduate Diploma of
Engineering from Monash
University, and a Bachelor
of Applied Science from the
University of Queensland.
Joan Withers joined the
Board in October 2020. She
is a member of the Audit and
Risk committees.
Joan has spent over
25 years working in the
media industry holding CEO
positions at both Fairfax
NZ Ltd and The Radio
Network and she also
has significant corporate
governance experience.
She is currently Chair
of The Warehouse Group
Ltd (since 2016), director
of ANZ Bank NZ Ltd
(since July 2013) and Sky
Network TV Ltd (since
2019). She has previously
held Chair positions
at Auckland International
Airport (1997 – 2013),
Mercury NZ Ltd (2009 –
2019) and TVNZ (2015 –
2017). She has also held
directorships on the boards
of some of New Zealand’s
largest companies including
Meridian Energy Ltd and
Tourism Holdings Ltd. Prior
to her appointment as CEO
of Fairfax NZ Ltd, Joan
was a director on the
Australian board of John
Fairfax Holdings Ltd.
Joan holds a Masters
Degree in Business
Administration from The
University of Auckland.
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, Risk and
Nomination 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.
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.
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 was a Director
of Caltex Australia Ltd
(2013-2020) and served
as Chairman of the Board
of PricewaterhouseCoopers
(PwC) Australia
(2005-2012). In 2009, he
was elected as a member
of the PwC International
Board, serving a four-year
term. He was previously
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.
8
Annual Report 2021
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 General Manager,
Wholesale, Trading and Business
Sales in February 2011. 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, with responsibility 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 as General Manager,
Energy Risk Management in
February 2011. 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
Samantha Stevens
Lawrie Tremaine
Executive General Manager,
People and Culture
Executive General Manager,
Corporate Affairs
Chief Financial Officer
Sharon Ridgway joined Origin in
2009 and has been responsible
for leading the People and
Culture function since December
2016. Sharon’s team provide
strategic support to the business
in key areas such as engagement,
diversity, talent management and
culture change. Prior to Origin,
Sharon developed a wide range
of experience across operational
and human resources roles whilst
working in Dixons, a large
European electrical retailer.
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 25 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 holds the position
of Chief Financial Officer. Lawrie
leads the teams responsible for
all finance activities, corporate
strategy and 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.
10
Annual Report 2021
Operating and Financial Review
For the full year ended 30 June 2021
This report forms part of the Directors’ Report.
1 Highlights
Our purpose underpins everything we do: 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
FY2021, we:
• continued supporting residential and small business customers in financial
distress due to impacts of the COVID-19 pandemic, including protection
from disconnection and default listing;
• provided relief to most of our electricity customers in New South Wales,
Queensland, South Australia and Victoria, with lower electricity prices;
•
•
•
supported customers experiencing financial hardship, with more than
35,300 payment plans successfully completed through our Power On
hardship program;
improved our Strategic Net Promoter Score (NPS) by four points to +6 as at
30 June 2021;
successfully migrated more than 250,000 customer accounts to the
Kraken platform;
• delivered over $1 million in rewards to the more than 56,000 Origin
Spike customers;
•
increased the number of green energy customers from 117,000 to 260,000
with the launch of Origin's new Origin Go product, which enables customers
to benefit from 25 per cent GreenPower and 100 per cent Green Gas at no
additional cost; and
• APLNG continues to supply ~30 per cent of domestic east coast market.
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.
We spent $270 million directly and indirectly with regional suppliers, or 18 per
cent of our total spend, up from 14 per cent in FY2020.
Our Stretch Reconciliation Action Plan (Stretch RAP) includes a commitment
to increase the participation of Aboriginal and Torres Strait Islander businesses
in Origin’s supply chain. In FY2021, our spend with Indigenous suppliers was
$10 million, exceeding our Stretch RAP target of $6.5 million and FY2020
performance of $5.3 million.
We continue to work closely with the Northern Land Council to engage with
and maintain the support of our Native Title holders in the Beetaloo Basin.
During the year, some of our Native Title holders visited the Kyalla well site
near Daly Waters during fracking operations. We also undertook sacred site
clearance and avoidance surveys for future work, and participated in meetings
on country about our upcoming work program.
Through grants, 8,400 hours of employee volunteering, and our workplace
giving program, the Origin Energy Foundation contributed over $3 million to
the community in FY2021. This included a $100,000 grant to the Grattan
Institute to research the impacts of home-schooling, due to COVID-19, on
disadvantaged students.
For the second year running, Origin Energy was named Australia’s Best
Workplace to Give Back, topping GoodCompany’s list of the Top 40 Best
Workplaces to Give Back 2020. Origin and its employees donated more than
$690,000 to over 250 Australia not-for-profit organisations in FY2021.
Customers
Strategic NPS
22
FY20
66
FY21
35,300
Customer payment plans
successfully completed through
our Power On hardship program
Communities
>$3M
Contributed to the community
by the Origin Energy Foundation
Regional procurement spend
as a % of total spend
14%14%
18%18%
FY20
FY21
Operating and Financial Review
11
Planet
Greenhouse gas emissions
(equity basis, mt CO2-e)
17.817.8
16.416.4
FY20
FY21
Scope 1
Scope 2
74 MW
Solar installations, up from
61 MW in FY2020
People
74%
Staff engagement
(top quartile for AU/NZ)
Total Recordable Injury
Frequency Rate (TRIFR)
2.62.6
2.72.7
FY20
FY21
Getting energy right for the planet
We put in place Australia's first approved science-based emissions reduction
targets in 2017, committing to lowering Scope 1 and 2 emissions by 50 per cent
and Scope 3 emissions by 25 per cent by 2032. We aim to achieve net zero
Scope 1 and 2 emissions by 2050. Work is progressing on updated emissions
reduction targets in line with a 1.5°C pathway.
We have announced our intention to put our climate reporting to a non-
binding, advisory vote of shareholders at our 2022 Annual General Meeting.
During FY2021, we:
•
•
•
reduced our Scope 1 and 2 equity emissions by 1.4 million tonnes, or
8 per cent;
installed 74 MW of solar on Australian homes and businesses, up from
61 MW in FY2020;
launched Origin 360 EV Fleet, the first full-service electric vehicle (EV) fleet
management solution of its kind in Australia;
• progressed our renewable hydrogen and renewable ammonia opportunities,
including a feasibility study in Bell Bay, Tasmania;
• were certified carbon neutral by Climate Active for our Green Gas and Green
LPG products; and
• entered into a new agreement to supply 900,000 tonnes of ash from
Eraring Power Station to mining company Glencore over the next two and a
half years, almost doubling Eraring's ash re-use program.
Our disclosures under the Task Force on Climate-related Financial Disclosure
guidelines will be set out in our Climate Change Management Approach, to be
released in September 2021.
Our people
Our people are one of our greatest strengths, and having a diverse and inclusive
workplace is key to the success of our business. We have made significant
changes to the way we work in response to the COVID-19 pandemic, and
Origin’s culture has strengthened during this time. During FY2021, we:
• maintained a steady engagement score of 74 per cent, keeping Origin in the
top quartile across Australia and New Zealand;
• kept Actual Serious Incidents steady at four, with 52 Learning Incidents,
ahead of our target of 30;
• maintained a steady TRIFR score of 2.7, compared to 2.6 in FY2020;
• achieved our target of 33 per cent of women in senior roles in FY2021, an
increase from 32 per cent in the previous reporting period;
• were certified a Great Place to Work by the Great Place to Work Institute, the
global authority on workplace culture; and
• were named in LinkedIn’s annual list of Australia’s 'Top Companies' – ranked
at number 19.
In July 2021, Origin became a signatory to 40:40 Vision, an investor-led
initiative targeting gender balance in executive leadership by 2030. As part
of the 40:40 Vision initiative, we have committed to achieve gender balance
(40:40:20) in executive leadership by 2030.
We have focused on supporting the mental health and well being of our people
in FY2021 and continued to develop a range of resources and programs.
We also launched a range of diversity learning programs for our people
in FY2021, including the Embrace Pride@Origin Learning Platform and our
cultural awareness learning framework to build awareness of Aboriginal and
Torres Strait Islander cultures, histories and achievements.
12
Annual Report 2021
Financial performance
Statutory Profit ($m)
Underlying Profit ($m)
Underlying EBITDA
8383
1,023
1,023
3,141
3,141
(2,291)
(2,291)
318318
2,048
2,048
FY20
FY21
FY20
FY21
FY20
FY21
Free Cash Flow
(before major growth) ($m)
1,644
1,644
Adjusted Net Debt ($m)
Final Dividend
1,1401,140
5,158
5,158
4,639
4,639
FY20
FY21
Jun-20
Jun-21
Lease Liabilities
7.5 cps
Unfranked
20cps total FY2021 dividend
(31% of FY2021 Free Cash Flow)
FY2021 was characterised by the impacts of COVID-19 on energy demand and prices across our key commodities: electricity, natural
gas and oil. The impact in domestic energy markets was exacerbated by mild summer weather, continued growth in renewables and
regulatory uncertainty.
Underlying Profit was lower at $318 million with Energy Markets impacted by lower wholesale prices, one-off network costs, roll-off of
legacy contracts, higher gas supply costs, and increased amortisation expense. Earnings from APLNG were impacted by a lower realised oil
price, partially offset by lower operating costs, depreciation and amortisation, interest expense and Origin hedging gains. Statutory Loss of
$2,291 million reflected non-cash impairment charges, recognition of a deferred tax liability in respect of our investment in APLNG, unrealised
losses on fair value and FX movements, and costs relating to a decision to defer the surrender of large-scale generation certificates (LGCs).
During the period our operations continued to perform reliably and efficiently. Our generation fleet met all demand requirements with minimal
unforced outages, managing through recent volatility driven by unplanned outages within the NEM and colder weather through the June
2021 quarter. APLNG responded to recovering market demand with record daily production achieved on two occasions in FY2021. APLNG
also delivered record low unit costs driven by strong field performance and operational efficiencies. APLNG's realised oil price reduced to
US$43/bbl as the price lag in its long-term LNG contracts meant that the April and May 2020 low crude oil prices flowed through into FY2021.
Free Cash Flow remained robust at $1,140 million, driven by a high cash conversion in Energy Markets due to lower working capital
requirements, $709 million cash distributions from APLNG, lower capital expenditure, and lower interest and tax payments. This enabled debt
reduction of $519 million while allowing for investment in growth and dividends to shareholders. Adjusted Net Debt/Adjusted Underlying
EBITDA was 2.9x, at the upper end of our 2.0-3.0x target range, as foreshadowed.
Our strategic partnership with Octopus Energy to radically transform our retail operations is progressing, with 250,000 customer accounts
migrated to the new Kraken platform by June 2021. Through our 20 per cent shareholding, Origin also benefits from Octopus's continuing
growth trajectory, with UK customer accounts growing at more than 100,000 per month on average since our investment and through
Octopus's entry into the Japanese market in partnership with Tokyo Gas.
We progressed upstream exploration and appraisal in the Beetaloo and Cooper-Eromanga basins and in late 2020 we announced a farm in
to seven permits in the prospective Canning Basin.
Operating and Financial Review
13
Energy Markets performance
Underlying EBITDA
Operating cash flow
$991M
$1,018M
Down $468m or 32% vs FY2020
Down $289m vs FY2020 with cash
to EBITDA conversion of 103%
4.8%
Underlying ROCE
Down 5.2% vs FY2020
Cost to serve
Customer accounts
Retail X
$489M
4,266k
250k
Down $81M or 14% vs FY2020
Up 30k vs June 2020
Achieved $110m cost out since FY2018
Successful migrations to
the new Kraken platform
While wholesale energy prices have rallied in recent months, the impacts of lower demand due to COVID-19, rooftop solar uptake and
energy efficiency, as well as increased large-scale renewable penetration all contributed to lower prices for the majority of FY2021. The
reduction in Energy Markets' Underlying EBITDA was primarily due to this decline in wholesale prices, as well as impacts of increased network
and metering costs not recovered in regulated tariffs, higher gas supply costs and the roll-off of certain gas supply and transport capacity
sales contracts. This was partially offset by reduced retail costs with our savings target achieved, and increased earnings from Solar and
Energy Services, and Octopus Energy. Operating cash flow decreased in the period, reflecting the lower EBITDA; however, EBITDA to cash
conversion was strong at 103 per cent.
Our peaking generation portfolio is well positioned for the energy transition and we continue to explore opportunities that would further
improve our flexibility and capacity, including grid-scale storage and pumped hydro. We are also changing the way we run Eraring to better
position it for increasing renewables. While current market and policy conditions make investment challenging, our longer-term view remains
that as coal generation exits, new firm and flexible generation capacity will be required to complement increasing renewable generation. We
will look to partner with governments and other market participants as opportunities arise.
Our gas portfolio remains a strength with scale and flexibility to move gas to where it is needed most. In May, we announced 91 PJ in gas supply
and transport agreements to materially increase supply to customers in southern markets out to 2025.
In a competitive retail market, we increased customer accounts by 30,000 and maintained a churn rate of 4.8 per cent below the market,
for electricity and gas customers. We continue to see growth in Community Energy Services (CES), Solar, Storage and Broadband. Our
broadband product has been boosted by a new partnership with Aussie Broadband.
We delivered on our $100 million savings target, having reduced cost to serve by $110 million since FY2018, of which $81 million was achieved
in FY2021.1 Our retail transformation program is focused on leading customer experience at the lowest cost, growing new revenue streams
and offering simplified, rewarding and flexible products. We achieved our highest ever strategic NPS of +6 as at 30 June 2021 and we continue
to provide support to customers impacted by COVID-19.
Our partnership with Octopus Energy will accelerate our strategy to deliver superior customer experience at low cost, while opening
up growth opportunities. We have established a new business (Retail X) to undertake a bottom-up build of Octopus’s operating model,
technology platform (Kraken) and distinctive culture. We migrated 250,000 customer accounts to Retail X in FY2021 and are targeting further
capital and operating cost savings of $100 to $150 million by FY2024, from FY2018 baseline.
1 Adjusted for changes in lease accounting.
14
Annual Report 2021
Integrated Gas performance
Underlying EBITDA
$1,135M
Cash distributions
from APLNG
$709M
Down $606m or 35% vs FY2020
Down $566m or 44% vs FY2020
Underlying EBIT down $228m
4.8%
Underlying ROCE
Down from 8.2%
in FY2020
APLNG
production (37.5%)
263PJ
Average realised LNG price
US$6.2/
MMBTU
Record low capex
and opex1/GJ
$2.8/GJ
Down 1% vs FY2020
Down 32% vs FY2020
19% improvement vs FY2020
Down 39% in A$ terms at $7.8/GJ
Strong field performance and operating efficiencies enabled APLNG to maintain stable production despite a significant reduction in planned
development activity and costs. APLNG demonstrated its operational flexibility by curtailing production early in the year in response to lower
demand, followed by a ramp-up to record daily production as market demand increased later in the year. With continued improvement in
utilisation of processing capacity driven by Eurombah Reedy Creek Interconnect (ERIC) pipeline and Talinga Orana Gas Gathering Station
(TOGGS), and a high level of facility reliability, the remainder of the year saw production levels similar to FY2020.
APLNG achieved record low capital and operating expenditure, decreasing by more than $940 million or 32 per cent compared with FY2020.
This was driven by strong field performance enabling reduced development activity with fewer drilling rigs, along with lower infrastructure
spend, as well as lower gas purchases, royalties, tariffs and exploration spend. Total capital and operating expenditure in FY2021 was $2.8/GJ.1
APLNG matched its previous operated daily production record of 1,614 TJ/day on two occasions, shipped its 600th LNG cargo, and delivered
a record 130 cargoes in FY2021.
Origin’s share of APLNG 2P (proved plus probable) reserves2 increased by 247 PJ or 6 per cent before production, representing reserves
replacement of 94 per cent during FY2021, driven by higher estimated recoveries from producing fields and maturation of resources
to reserves.
Despite APLNG's strong operational performance, Integrated Gas's Underlying EBITDA reduced primarily due a decline in the realised oil
price from US$68/bbl (A$101/bbl) in FY2020 to US$43/bbl (A$58/bbl) in FY2021, partially offset by Origin oil hedging gains.
Other highlights across Integrated Gas during the period included:
•
fracture stimulation and initial flowback and production testing undertaken at the Kyalla 117 well in the Beetaloo Basin with encouraging
results that met the objective to flow liquid-rich gas. Operations were temporarily paused in July to investigate a potential downhole flow
restriction, with an extended production test planned to commence in FY2022. Velkerri 76 well was spudded and a further production test
at the Amungee NW 1H well, drilled in 2016, commenced in August;
• drilling the Obelix-2 vertical exploration well to test the maturity of the Toolebuc Formation in the Cooper-Eromanga Basin, with positive
initial analysis of log and core data;
• announcing a farm-in with Buru Energy for a 40-50 per cent equity share in seven permits in the prospective Canning Basin, where Origin
will fund an estimated $35 million work program over two years; and
• progressing a number of hydrogen and renewable fuels projects, including a feasibility study into an export-scale renewable ammonia plant
in Tasmania’s Bell Bay, an export-scale project in Townsville with the signing of a Memorandum of Understanding (MOU) with the Port of
Townsville, and the Western Sydney Green Gas Project. In addition, a joint feasibility study on opportunities to develop the supply chain
for export-scale renewable ammonia with the signing of MOUs with Mitsui O.S.K. Lines Ltd. (MOL) and POSCO.
1 Opex excludes purchases and reflects royalties at the breakeven oil price.
2 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. Refer to Section 7 for
disclosure relating to Tri-Star litigation associated with these CSG interests.
Operating and Financial Review
15
2 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 supply 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 FY2021, approximately 76 per cent of APLNG
gas volume was sold as LNG (of which 90 per cent was under long-term oil-linked contracts). The remaining 24 per cent was sold domestically
via a mix of long-term and short-term contracts.
Origin is focused on supporting our customers through the energy transition with a growing portfolio of clean energy solutions and
technologies, including solar, batteries, e-mobility, hydrogen, carbon offsets and demand management, all of which are expected to grow in
scale as the energy system decarbonises.
Market outlook
The energy market is transforming, and the rate of change is accelerating. Renewable energy continues to grow both in our homes and on
the grid, placing downward pressure on wholesale electricity prices and changing the shape of energy supply and demand throughout the
day and over the year. Governments are increasingly intervening in markets through direct investments and pricing outcomes which places
further pressure on prices and private investments in the sector. Our customers’ expectations are also changing dramatically, demanding
integrated energy and emissions offerings and becoming market participants themselves with a wider choice of technologies to use, store
and manage energy.
FY2021 saw a disconnect between domestic east coast gas prices and the regional JKM index as domestic markets were temporarily
oversupplied and regional markets tightened with an extreme Northern hemisphere winter and supply constraints. This, along with the impact
of COVID-19, led to lower domestic sales volumes and prices, and higher supply costs linked to JKM. The impact is expected to flow into
FY2022; however we expect east coast gas prices to reconnect with the regional JKM index over the medium term.
International oil and LNG markets rebounded from the low COVID-19 levels experienced last year, reflecting tightened supply and demand
dynamics. The LNG market is also benefiting from short-term market tightness driven by the severe Northern hemisphere winter and supply
bottlenecks however this is expected to normalise over the next 12 months.
In the longer term, we continue to expect global trends towards decarbonisation, decentralisation and digitisation to shape energy markets.
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 in the near term;
• current supply constraints in global LNG markets to ease over the next 12 months as liquefaction utilisation rates rise and new supply
commences production; 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 capture value in a future shaped by these global trends.
16
Annual Report 2021
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.
Electrification and demand for emerging
technologies, including hydrogen and
carbon management, are expected to grow
to support decarbonisation.
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, with
focus on orchestration and integrated risk
management expected to grow.
The right energy
We believe our generation and fuel supply portfolios provide flexibility to adapt and prosper in a
changing energy market.
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 batteries and pumped hydro,
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.
Accelerate towards clean energy Low cost operator and developer of gas resourcesEmbracing a decentralised and digital futureLeading customer experience and solutionsUnderpinned by a commitment to capital disciplineThe right customer solutionsThe right energyThe right technologiesAccelerate towardsclean energy
Operating and Financial Review
17
Our Integrated Gas business is expected to benefit from stronger oil and LNG prices in the near term.
Strong field performance and operatorship enabled APLNG to reduce development activity and costs
while continuing to meet the needs of customers. APLNG remains focused on key value drivers such as
workover and well unit rate savings, and production optimisation.
Beyond APLNG, our strategy is to scale our 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, with appraisal of two independent liquids-rich gas plays
underway and plans to retest a dry gas play. We are considering farm-down options for Beetaloo in
parallel to our appraisal activities.
We have a 75 per cent interest and operatorship of five permits located in the Cooper-Eromanga Basin
in south west Queensland, and have recently acquired 100 per cent interest in one additional permit. In
December 2020, we farmed-in to a 40-50 per cent equity share in seven permits in the Canning Basin.
Additional prospective conventional and unconventional oil and gas plays are planned to be tested in
these areas.
The right technologies
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 EV chargers. Through this platform, we have more than 159 MW from 79,000 connected services.
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. The program has yielded a number of important
partnerships, including with US based OhmConnect, the startup behind our behavioural demand
response program, Spike, which launched in August 2020.
Origin is also pursuing opportunities in low-carbon technologies such as hydrogen, e-mobility, and
carbon management.
In terms of hydrogen, Origin’s integrated energy position provides it with a competitive strength in
producing renewable hydrogen and ammonia using renewable energy and sustainable water. 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 have launched a smart
charging trial with ARENA aimed at optimising the charging of EVs to create value for customers and
the energy markets as well as Origin 360 EV Fleet, Australia’s first fully managed end-to-end EV fleet
management proposition.
The right customer solutions
Origin is one of Australia’s largest energy retailers 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.
Low cost operator and developer of gas resourcesEmbracing a decentralised and digital futureLeading customer experience and solutions
18
Annual Report 2021
3 FY2022 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 the potential ongoing impacts of COVID-19 and this guidance is subject to any further
material impact on demand and customer affordability.
Origin Energy - Underlying EBITDA
Energy Markets Underlying EBITDA
Integrated Gas & Corporate Underlying EBITDA
Origin Energy - Capex and investments
Capex (excluding investments)
Investments
Integrated Gas - APLNG 100%
Production
Capex and opex, excluding purchases2
Unit capex + opex, excluding purchases2
Distribution breakeven3
A$m
A$m
A$m
A$m
A$m
PJ
A$b
A$/GJ
US$/boe
FY21
FY22 guidance
2,048
1,850 - 2,150
991
1,057
450 - 600
1,400 - 1,550
(339)
(161)
(370) - (410)
(210) - (220)1
701
2.0
2.8
22
685 - 710
2.1 - 2.3
3.0 - 3.4
20 - 25
1 FY2022 investments guidance includes ~$135 million (£70 million) consideration, in relation to our investment in Octopus Energy, brought forward from FY2023 due to a 6
month lagged average Brent price of >US$50/bbl from August 2021.
2 Opex excludes purchases and reflects royalties at the breakeven oil price.
3 FY2022 AUD/USD rate 0.75 (FY2021: 0.75)
Origin Energy - consolidated
FY2022 Origin Underlying EBITDA is estimated to be $1,850 - $2,150 million, based on an APLNG realised oil price of US$68/bbl and
AUD/USD rate of 0.75.
Approximately 50 per cent of APLNG’s FY2022 oil exposure has been priced at US$68/bbl based on long-term LNG contract lags, as at
28 July 2021. A change of US$10/bbl for the remaining 50 per cent is estimated to impact Origin Underlying EBITDA by ~A$120 million.
Interest expense is estimated to reduce by a further $40-60 million in FY2022.
Capital expenditure is estimated to be $370 - $410 million, including $75 - $85 million exploration and appraisal spend primarily relating
to Beetaloo and Canning basins. This excludes $210 - $220 million in investments relating primarily to the Octopus equity investment.
Energy Markets
We estimate Energy Markets Underlying EBITDA to be lower than FY2021 at $450 - $600 million, driven by:
• Electricity Gross Profit reduction of $400 - $480 million primarily driven by a ~$20/MWh reduction in wholesale electricity prices flowing
into customer tariffs, higher generation fuel costs and continued impacts of rooftop solar uptake and energy efficiencies. This is partially
offset by lower wholesale electricity procurement costs with low-cost renewable supply coming online and capacity hedge contracts
rolling off;
• Natural Gas Gross Profit reduction of up to $50 million, reflecting higher procurement costs as a result of price reviews and increases in
the JKM-linked supply costs, as well as lower volumes and prices on commercial and industrial sales, offset by repricing of retail customer
tariffs; and
• Cost to serve expected to be relatively stable, having achieved $110 million reduction from FY2018. Further savings associated with the
adoption of Octopus’ Kraken platform and operating model are expected over FY2023-24.
We expect a recovery in Energy Markets Underlying EBITDA in FY2023 of an estimated $150 - $250 million1, to $600 - $850 million provided
current forward commodity prices continue and flow into customer tariffs.
Integrated Gas
We estimate continued stable production in FY2022 of 685 - 710 PJ (APLNG 100 per cent), reflecting strong field performance.
We estimate total APLNG capex and opex of $2.1 - $2.3 billion, higher than FY2021, reflecting planned downstream maintenance, higher
non-operated development and infrastructure spend, increased E&A activity and workover, and higher power costs.
APLNG is targeting FY2022 distribution breakeven of US$20 - 25/boe, including approximately US$11/boe in project finance costs, with
increased activity costs expected to be offset by higher non-oil linked revenue.
Based on an APLNG realised oil price of US$68/bbl in FY2022, cash flows to Origin are estimated to be greater than $1 billion2, net of oil
hedging. At 28 July 2021, Origin estimates that approximately half of APLNG’s FY2022 JCC oil price exposure has been priced at US$68/bbl,
based on the long-term LNG contract lags. See Section 5.2.2 for details of Integrated Gas oil hedging and LNG trading.
1 Based on current forward prices for key commodities such as electricity, coal and oil. Assuming JKM prices reduce by US$2-US$3/mmbtu from current forward prices, and
assuming no material change in sales volumes and other costs.
2 Assuming an average AUD/USD rate of 0.75 and assuming all APLNG debt serviceability tests are met. Origin hedges losses estimated to be $134 million based on the same
assumptions. As at 28 July 2021, ~31 mmboe (or 50%) of APLNG’s FY2022 oil price exposure priced at ~US$68/bblbefore hedging.
Operating and Financial Review
4 Financial update
4.1 Reconciliation from Statutory to Underlying Profit
Statutory Profit/(Loss) - total operations
Items Excluded from Underlying Profit (post-tax)
Increase/(decrease) in fair value and foreign exchange movements
Oil and gas
Electricity
FX and interest rate
Other financial asset/liabilities
FX gain/(loss) on foreign-denominated financing
Impairment, disposals, business restructuring and other
Total Items Excluded from Underlying Profit (post-tax)
Underlying Profit
FY21
($m)
(2,291)
(259)
(231)
(38)
13
(114)
111
(2,350)
(2,609)
318
FY20
($m)
83
275
153
85
(46)
86
(3)
(1,215)
(940)
1,023
Change
($m)
(2,374)
(534)
(384)
(123)
59
(200)
114
(1,135)
(1,669)
(705)
19
Change
(%)
(2,860)
(194)
(251)
(144)
(127)
(233)
(3,810)
93
178
(69)
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 5.2.2 for details of Origin’s APLNG-related oil hedging.
• 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.
• Foreign exchange and interest rate derivatives manage exposures 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.
• 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 cash distributions.
Impairment, disposals, business restructuring and other 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:
• $1,578 million non-cash impairment charges relating to Energy Markets goodwill and generation assets primarily as a result of lower
wholesale commodity prices and higher near-term gas supply costs;
• $669 million deferred tax expense, reflecting the expectation of future distributions from APLNG (see below for details);
• $198 million net cost relating to a decision to defer the surrender of a portion of Origin’s calendar year 2020 and 2021 large-scale
generation certificates (see 4.3 below and the Appendix for further details);
• $123 million benefit relating primarily to a revaluation of the Cameron LNG onerous contract provision associated with stronger near-term
assumptions for LNG prices relative to Henry Hub prices and an increase in long-term assumptions for US Treasury bond rates. The realised
loss for the period associated with Cameron LNG is recognised in Underlying Profit; and
• $28 million other primarily relating to losses on disposal and restructuring, transformation and transaction costs.
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.
20
Annual Report 2021
4.2 Recognition of deferred tax liability - investment in APLNG
An improved outlook for APLNG is expected to drive higher distributable cash flow in the near term and this is expected to result in the MRCPS
securities held by Origin being fully redeemed by FY2023, after which APLNG is expected to begin distributing ordinary dividends. The
ordinary dividends will be unfranked until APLNG starts paying income tax, which is not expected until later in the decade given existing tax
losses held by APLNG.
Typically, when in receipt of unfranked dividends, the income tax expense would be recognised in the year the dividend is received. However,
as Origin had an unrecognised deferred tax liability in respect of our investment in APLNG, accounting standards require recognition of a
deferred tax expense provided certain criteria are met.
A deferred tax liability arises when the accounting cost base of an asset is higher than the tax cost base, resulting from a temporary difference.
The carrying value of our investment in APLNG is significantly higher than the tax cost base, primarily as a result of our equity accounted share
of retained profits to date.
Consistent with accounting standards, the deferred tax liability has not been recognised historically because
1. Origin is able to control the timing of distributions from APLNG which would reverse the temporary difference; and
2.
it has not been probable that the temporary difference will reverse in the foreseeable future via dividends paid from current retained
earnings, capital returns or a disposal.
As it is now probable that APLNG will begin to distribute cash to shareholders via dividends in the coming years, Origin has recognised a
deferred tax liability of $669 million in FY2021 representing 30 per cent of the dividends expected to be paid in the foreseeable future from
the existing equity accounted retained earnings based on current market assumptions, including future oil prices.
Recognition of the deferred tax liability only impacts the timing of accounting for the tax expense and has no impact on the underlying
economics or cash flows. There is a remaining unrecognised deferred tax liability at 30 June 2021 of $810 million which may be partly or fully
recognised in the future.
Going forward, when Origin receives unfranked dividends from APLNG, the proportion paid from earnings in that year will still incur tax
expense, and the balance attributable to retained earnings will result in partial utilisation of the deferred tax liability.
4.3 Accounting for large-scale generation certificate trading strategy
Supply and demand for large-scale generation certificates (LGCs) is driven by the rate of new renewable projects coming online, voluntary
demand for carbon offsets as well as the compliance obligations under the Large-scale Renewable Energy Target (LRET). Renewable project
delays and generation curtailments have led to a near-term tightening of the LGC market. However, it is expected that the 33 TWh legislated
target will be exceeded and longer term the market will be oversupplied. The Clean Energy Regulator has acknowledged this and provides
the option for parties to shift demand from periods of tight supply by deferring the surrender of certificates to later years. Under the scheme,
parties can defer up to 10 per cent of their obligation at no additional cost and can defer more than 10 per cent by incurring a shortfall charge
of $65 per certificate that is refundable provided the LGCs are surrendered within three years. The refund is currently tax assessable; however
legislative change is before Parliament that would make refunds non-assessable (such that it is aligned to treatment of the shortfall charge).
This presents an economic opportunity with the LGC forward curve in backwardation and, as previously disclosed, Origin elected to defer
surrender of 2.5 million 2020 calendar year certificates in February 2021. Origin now expects to also defer approximately 3.1 million 2021
calendar year certificates due for surrender in February 2022.
During FY2021, Origin incurred non-deductible shortfall charges of $262 million, of which $160 million was paid in relation to the under
surrender of 2.5 million 2020 calendar year certificates and a further $102 million was accrued in relation to the first half of 2021 calendar year.
Included in FY2021 Underlying Profit is a cost of $64 million reflecting the estimated future surrender cost, based on a weighted average of
the current forward price and purchases to date, comprising:
• $46 million relating to 2020 calendar year (~2.5 million certificates at $19 each, reflecting the forward price for the 2023 calendar year and
purchases to date); and
• $18 million relating to the first half of 2021 calendar year (~1.55 million certificates at $12 each, reflecting the forward price for the 2024
calendar year and purchases to date).
The balance of $198 million is excluded from Underlying Profit. See Appendix for further details.
Subject to changes in volume and forward price estimates, we expect to incur a further $102 million in the first half of FY2022 relating to the
shortfall charge for the second half of calendar 20211 and an estimated cost of $18 million will be recognised in FY2022 Underlying Profit.1
Future surrender cost will continue to be reassessed each reporting period.
1 Based on volume and price estimates at 30 June 2021.
Operating and Financial Review
4.4 Underlying Profit
Energy Markets
Integrated Gas - Share of APLNG
Integrated Gas - Other
Corporate
Underlying EBITDA
Underlying depreciation and amortisation (D&A)
Underlying share of ITDA of equity accounted investees
Underlying EBIT
Underlying interest income - MRCPS
Underlying interest income - Other
Underlying interest expense
Underlying profit before income tax and non-controlling interests
Underlying income tax expense
Non-controlling interests’ share of Underlying Profit
Underlying Profit
Underlying EPS
Underlying ROCE
21
Change
(%)
(32)
(40)
(94)
32
(35)
8
(26)
(59)
(39)
(81)
(23)
(66)
(51)
(33)
(69)
(69)
(4.3)
FY21
($m)
991
1,145
(10)
(78)
2,048
(550)
(958)
540
106
3
(242)
407
(87)
(2)
318
18.1cps
4.5%
FY20
($m)
1,459
1,915
(174)
(59)
3,141
(509)
(1,303)
1,329
174
16
(316)
1,203
(177)
(3)
1,023
58.1cps
8.8%
Change
($m)
(468)
(770)
164
(19)
(1,093)
(41)
345
(789)
(68)
(13)
74
(796)
90
1
(705)
(40.0cps)
Refer to Sections 5.1 and 5.2 respectively for Energy Markets and Integrated Gas analysis.
Corporate costs increased by $19 million, primarily reflecting one-off enterprise resource planning (ERP) implementation costs ($12 million).
Underlying D&A increased by $41 million, driven by decommissioning of retail IT systems and increased generation restoration provisions.
Underlying share of ITDA decreased $345 million, driven by lower ITDA from APLNG ($380 million), comprising lower tax expense
($171 million), lower net interest expense ($98 million), and lower depreciation and amortisation ($111 million); partly offset by the increase in
ITDA from the full year impact of Origin’s 20 per cent equity share of Octopus Energy ($34 million).
Underlying MRCPS interest income decreased $68 million with a lower principal balance following buy-backs by APLNG, and a higher
AUD/USD exchange rate.
Underlying net interest expense decreased $61 million, reflecting a lower net debt balance and refinancing activities.
4.5 Cash flows
Operating cash flow
Underlying EBITDA
Underlying equity accounted share of EBITDA (non-cash)
Other non-cash items in Underlying EBITDA
Underlying EBITDA adjusted for non cash items
Change in working capital
Energy Markets - excluding futures exchange collateral
Energy Markets - electricity futures exchange collateral
Integrated Gas - excluding APLNG
Corporate
Other
Tax (paid)/refunded
Cash flow from operating activities
FY21
($m)
2,048
(1,153)
114
1,009
68
(29)
110
(2)
(11)
(144)
31
964
FY20
($m)
3,141
(1,911)
157
1,387
(222)
74
(340)
29
15
-
(215)
951
Change
($m)
(1,093)
758
(43)
(378)
290
(103)
450
(31)
(26)
(144)
246
13
Change
(%)
(35)
(40)
(27)
(27)
(131)
(139)
(132)
(107)
(173)
n/a
(114)
1
Operating cash flow increased $13 million, reflecting lower working capital requirements and lower tax paid, partially offset by a decrease in
Underlying EBITDA adjusted for non-cash items ($378 million) and other cash items ($144 million) including the 2020 LGC shortfall charge.
Underlying equity accounted share of EBITDA (non-cash) reflects share of APLNG ($1,145 million) and share of Octopus Energy ($9 million).
Other non-cash items include provisions for bad and doubtful debts (+$88 million), share-based remuneration (+$24 million) and exploration
expense (+$1 million).
22
Annual Report 2021
Working capital decreased $68 million in the period, primarily in Energy Markets with higher electricity pool prices at the end of the
year resulting in a positive movement in electricity futures collateral (+$110 million) and positive net creditor movements in wholesale
(+$60 million), as well as lower coal inventory (+$51 million), partially offset by higher green inventory (-$132 million).
Electricity futures collateral relates to cash deposited with the futures exchange associated with forward electricity hedge positions.
Investing cash flow
Capital expenditure
Distribution from APLNG
Interest received from other parties
Investments/acquisitions
Disposals
Cash flow from investing activities
FY21
($m)
(339)
709
3
(161)
7
219
FY20
($m)
(500)
1,275
18
(165)
234
862
Change
($m)
Change
(%)
161
(566)
(15)
4
(227)
(643)
(32)
(44)
(83)
(2)
(97)
(75)
We continue to tightly manage our capital spend, with FY2021 capital expenditure of $339 million down 32 per cent, and comprising:
• generation maintenance and sustaining capital ($63 million), primarily at Eraring ($35 million) and Shoalhaven ($9 million);
• other sustaining capital ($136 million) including spend in preparation for the move to five-minute settlement of pool prices ($34 million),
LPG ($24 million), and Origin ERP system replacement ($38 million);
• productivity/growth ($94 million) including deferred and contingent licensing payment to Octopus Energy ($36 million), and other Kraken
implementation costs ($14 million), CES ($14 million); and
• exploration and appraisal spend ($46 million) primarily related to the appraisal program in the Beetaloo Basin.
Cash distributions from APLNG amounted to $709 million comprising $110 million of MRCPS interest (down from $181 million in FY2020)
and $599 million of MRCPS buy-backs (down from $1,094 million in FY2020). Disposals in the prior period relate primarily to the sale of the
Ironbark CSG acreage.
Interest received decreased, reflecting a lower cash balance following repayment of maturing debt obligations.
Investments include deferred and contingent consideration for the equity interest in Octopus Energy ($141 million) and for OC Energy
($11 million), as well as investments in Future Energy ($5 million) and LPG ($5 million).
Financing cash flow
Net proceeds/(repayment) of debt
Operator cash call movements
On-market purchase of employee shares
Close out of foreign currency contracts
APLNG loan (repayment)/proceeds1
Interest paid
Payment of lease liabilities
Dividends paid
Total cash flow from financing activities
Effect of exchange rate changes on cash
FY21
($m)
(1,042)
(90)
(96)
(65)
(3)
(234)
(76)
(343)
(1,949)
(2)
FY20
($m)
(1,173)
56
(75)
(55)
(8)
(310)
(75)
(478)
(2,118)
(1)
Change
($m)
Change
(%)
131
(146)
(21)
(10)
5
76
(1)
135
169
(1)
(11)
(261)
28
18
(63)
(25)
1
(28)
(8)
100
1 APLNG loan (repayment)/proceeds represents cash (used by)/generated by APLNG as part of its normal business operations deposited to a project finance debt service
reserve accounts. Upon issuance of a bank guarantee to APLNG by Origin the cash was distributed to Origin by way of a loan.
Repayment of debt reflects capital market debt repaid from cash held and from Free Cash Flow.
Operator cash call movements represent the movement in funds held and other balances relating to Origin's role as the upstream operator
of APLNG.
On-market purchase of shares represents the purchase of shares to satisfy employee share remuneration schemes and the Dividend
Reinvestment Plan (DRP).
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 2021 was $93 million.
Operating and Financial Review
23
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 of APLNG.
The Octopus Energy equity investment and Kraken licence implementation costs are considered major growth and $191 million of investing
cash outflows has been excluded from FY2021 Free Cash Flow.
($m)
Underlying EBITDA
Non-cash items
Change in working capital
Other
Tax (paid) /refunded
Operating cash flow
Capital expenditure
Cash distribution from APLNG
(Acquisitions)/disposals
Interest received
Investing cash flow
Interest paid
Free Cash Flow including major growth
Major growth spend
Free Cash Flow
4.6 Shareholder returns
Energy Markets
Integrated Gas
- Share
of APLNG
Integrated
Gas - Other
Corporate
Total
FY21
FY20
FY21
FY20
FY21
FY20
FY21
FY20
FY21
FY20
991
1,459
1,145
1,915
(10)
(174)
(59)
2,048
3,141
137
(1,145)
(1,915)
89
81
(266)
(143)
(23)
-
-
1,018
1,307
(263)
(395)
-
-
(155)
(165)
-
-
(418)
(560)
-
600
191
791
-
747
141
888
6
(2)
(4)
-
11
29
24
-
(10)
(60)
(109)
(94)
709
1,275
-
-
234
-
(78)
11
(11)
3
31
-
1
3
13
15
(1)
(215)
(1,039)
(1,753)
68
(222)
(144)
31
-
(215)
951
(44)
(247)
964
(16)
(10)
(339)
(500)
-
-
18
8
709
(154)
3
219
1,275
69
18
862
649
1,414
(12)
-
-
(234)
(310)
(234)
(310)
638
1,305
(289)
(549)
949
1,503
-
-
-
-
191
141
638
1,305
(289)
(549)
1,140
1,644
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
The board has determined to pay an unfranked final dividend of 7.5 cents per share. This brings Origin’s total distributions to shareholders for
FY2021 to 20.0 cents per share, representing 31 per cent of free cash flow. The final dividend will be paid on 1 October 2021 to shareholders
registered as at 8 September 2021.
During the period, $191 million was incurred in respect of the investment in Octopus Energy and the costs associated with the Kraken
system implementation. 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 the near term.
Origin will seek to deliver sustainable shareholder returns through the business cycle and will target a payout range of 30 per cent to 50 per
cent of Free Cash Flow per annum in the form of ordinary dividends and/or on-market share buy-backs. Free Cash Flow is defined as cash
from operating activities and investing activities (excluding major growth projects), less interest paid. Remaining cash flow 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 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.
24
Annual Report 2021
4.7 Capital management
During FY2021, the following capital management initiatives were completed:
• Repaid and extended the tenor of our debt facilities:
– repaid €750 million (A$950 million) 2.8 per cent effective interest rate debt;
– repaid US$65 million (A$86 million) 4.4 per cent fixed interest rate debt;
– extended the tenor of A$1.1 billion of bank debt from FY2023 to FY2025; and
– extended the tenor of a US$200 million (A$266 million) bank guarantee facility from FY2023 to FY2025.
• Cancelled $0.2 billion in undrawn bank loan facilities that were surplus to requirements.
Adjusted Net Debt
Movements in Adjusted Net Debt ($m)
(964)
(964)
343343
8787
(709)
(709)
339339
154154
231231
5,158
5,158
4,639
4,639
30 June 2020
Operating cash
flow
Net cash from
APLNG
Capex
Net acquisitions /
disposals
Net interest
payments
Dividend
FX/Other
30 June 2021
Adjusted Net Debt decreased $519 million, driven by strong operating cash flow and APLNG cash distributions. This was partially offset by
capital expenditure, investment in growth, interest payments and dividends to shareholders.
Foreign exchange/other primarily reflects the non-cash translation of unhedged USD debt and fees, partially offset by on-market purchase
of shares ($96 million), operator cash call movements ($90 million), and settlement of foreign currency contracts ($65 million).
Origin’s objective is to maintain an Adjusted Net Debt/Adjusted Underlying EBITDA ratio of 2.0-3.0x and a gearing1 target of 20 per cent
to 30 per cent. As previously foreshadowed, at 30 June 2021 these ratios were 2.9x and 32 per cent respectively, reflecting the reduction
in EBITDA associated with lower prices across our key commodities; electricity, natural gas and oil. With continued strong cash flows from
both our businesses and signs of recovery in each of these commodities, we remain focused on maintaining our target capital structure and
achieving net debt below $4 billion over the medium term.
As our Adjusted Net Debt balance has declined from a peak of $13.1 billion as at 30 June 2015 to $4.6 billion, the quantum of debt capital
we need to refinance in any year is lower. This reduced debt refinancing activity going forward means one investment-grade credit rating is
sufficient for our debt capital requirements. During the year, we reduced our credit rating providers from two to one. Our long-term credit
profile is Baa2 (stable) from Moody’s.
1 Gearing is Adjusted Net Debt divided by Adjusted Net Debt plus Equity.
Operating and Financial Review
25
Debt maturity profile
- excluding lease liabilities (A$b)
Debt portfolio management
Average term to maturity decreased from 3.9 years at 30 June 2020
to 3.4 years at 30 June 2021. The rolling 12-month average interest
rate on drawn debt decreased from 4.8 per cent in FY2020 to 4.3
per cent in FY2021.
As at 30 June 2021, Origin held $0.4 billion1 of cash and $2.8 billion
in committed undrawn debt facilities. This liquidity position of
$3.3 billion is held to meet near-term debt and lease liability payment
obligations of $1.8 billion (net of $0.1 billion fair value adjustments)
and to maintain a sufficient liquidity buffer.
2.0
1.5
1.0
0.5
0
FY22
FY23
FY24
FY25
FY26
FY27
FY28
FY29 FY30+
Capital Markets
Debt & Term Loan
Loans and Bank
Guarantees - Drawn
Loans and Bank
Guarantees -
Undrawn
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 4.5 above. The fair value of MRCPS held by
Origin at 30 June 2021 was A$1,296 million.
APLNG also funded construction via US$8.5 billion (100% APLNG) in project finance facilities. These facilities were partially refinanced in
FY2019. The outstanding balance at 30 June 2021 was US$5,908 million (A$7,860 million), net of unamortised debt fees of US$65 million
(A$86 million). APLNG’s average interest rate associated with its project finance debt portfolio for FY2021 was 3.0 per cent.
Gearing2 in APLNG was 26 per cent as of 30 June 2021, down from 28 per cent at 30 June 2020.
APLNG project finance debt amortisation profile
Closing balance as at 30 June
(US$m)
Bank loan (variable)1
2021
1,972
US Exim
USPP
Total
1 Based on current forward interest rates
2022
2023
2024
2025
2026
2027
2028
2029
2030
1,689
1,407
2,001
1,772
1,519
1,153
1,247
871
965
587
679
265
382
-
162
2,000
2,000
2,000
1,940
1,887
1,787
1,690
1,437
5,973
5,461
4,927
4,340
3,722
3,052
2,337
1,599
-
-
930
930
-
-
297
297
1 Excludes $30 million cash held on behalf of APLNG as upstream operator.
2 Gearing is defined as project finance debt less cash, divided by project finance debt less cash plus equity.
26
Annual Report 2021
5 Review of segment operations
5.1 Energy Markets
Origin’s Energy Markets business comprises one of Australia’s largest energy retail businesses by customer accounts, Australia’s largest fleet
of gas-fired peaking power stations supported by a substantial contracted fuel position, a growing supply of contracted renewable energy
and Australia’s largest power station, the black coal-fired Eraring Power Station.
Energy Markets reports on an integrated portfolio basis. Electricity and Natural Gas Gross Profit and cost to serve are reported separately,
as are the EBITDA of the Solar and Energy Services, Future Energy and LPG divisions, and our 20 per cent share of earnings from
Octopus Energy.
5.1.1 Financial summary
Electricity Gross Profit
Natural Gas Gross Profit
Electricity and Natural Gas cost to serve
LPG EBITDA
Solar and Energy Services EBITDA
Future Energy EBITDA
Share of EBITDA from Octopus Energy
Underlying EBITDA
Underlying EBIT
FY21
($m)
899
447
(489)
89
55
(19)
9
991
432
FY20
($m)
1,187
744
(570)
83
33
(15)
(4)
1,459
974
Change
($m)
(288)
(297)
81
6
22
(4)
13
(468)
(542)
Change
(%)
(24)
(40)
(14)
7
66
28
(303)
(32)
(56)
Fuel Supply•••GasCoalLPGTransportation •Flexible contracted gas transport arrangements Generation •••1 black coal generatorAustralia’s largestgas-fired fleetGrowing contracted renewables•••Retail (consumer and SME)Business (commercial and industrial)Wholesale Networks •RegulatedCustomers Energy Markets operationsElectricity –$288 millionGas -$297 millionFY2020VolumesWhole-sale pricesCost of energyNetwork costs / otherVolumesWhole-sale pricesH2 JKMContract roll off & price reviewsCost to serveOctopus, S&ES, LPG, Future EnergyFY20211,458(321)(76)8101(25)(105)(51)(116)8136991 Operating and Financial Review
27
5.1.2 Electricity
Volume summary
Volumes sold
(TWh)
NSW1
Queensland
Victoria
South Australia
Total volumes sold
FY21
Retail
Business
7.9
4.3
2.8
1.3
16.3
8.6
3.7
3.2
1.8
17.3
Total
16.4
8.0
6.1
3.1
33.5
FY20
Retail
Business
7.8
4.1
2.9
1.3
16.1
8.7
3.6
3.4
1.7
17.4
Total
16.5
7.7
6.2
3.1
33.5
Change
(TWh)
Change
(%)
(0.1)
0.3
(0.2)
0.0
0.0
(0.7)
3.6
(2.7)
0.7
0.1
1 Australian Capital Territory customers are included in New South Wales.
Gross Profit summary
Revenue
Retail (residential/SME)
Business
Cost of goods sold
Network costs
Energy procurement costs
Gross Profit
Gross margin %
FY21
$m
7,136
4,381
2,754
(6,237)
(3,156)
(3,081)
899
12.6%
$/MWh
212.7
269.6
159.3
(185.9)
(94.1)
(91.9)
26.8
FY20
$m
7,509
4,567
2,941
(6,322)
(3,142)
(3,179)
1,187
15.8%
$/MWh
224.0
283.9
168.7
(188.6)
(93.8)
(94.9)
35.4
Change
(%)
Change
($/MWh)
(5)
(4)
(6)
1
(0)
3
(24)
(20)
(11.3)
(14.3)
(9.3)
2.7
(0.3)
3.0
(8.6)
Electricity Gross Profit declined by $288 million driven by:
Sources and uses of electricity (TWh)
40
30
20
10
0
• $8.6/MWh decrease in unit margins (-$296 million):
– -$220 million relating to lower wholesale electricity and
renewable certificate prices, with a reduction in customer
tariffs (-$321 million) partially offset by cost improvements
(+$101 million), primarily relating to net pool and swap costs
and lower green scheme costs; and
– -$76 million due to increased network costs (-$42 million) and
metering costs (-$13 million) not recovered in regulated tariffs,
and ongoing costs associated with customer support during
COVID-19 and competition (-$21 million).
• Volumes were stable, reflecting an increase in retail of 0.2 TWh,
offset by a 0.1 TWh decrease in business, with +$8 million impact
to Gross Profit. Higher residential demand related to working
from home was partly offset by lower usage due to solar and
energy efficiencies. Lower business volumes due to COVID-19
were partly offset by new contract wins.
Owned and contracted generation output of 20 TWh was lower
by 2 TWh, driven primarily by lower gas generation (-1.7 TWh) due
to lower pool prices, lower demand and elevated gas generation
in FY2020 to cover an outage at Eraring Power Station. Output at
Eraring was lower (-0.4 TWh), reflecting lower wholesale prices.
Both were partially offset by increased generation from renewable
PPAs (+0.1 TWh) and solar feed-in tariffs (+0.4 TWh). Refer to
Electricity Supply table below.
Approximately 16 TWh per annum (or ~50 per cent) of our electricity
supply costs are relatively fixed, subject to recontracting coal from
FY2023, representing Eraring and the bundled renewable PPAs.
Energy procurement costs decreased overall, driven by lower fuel
costs with less gas-fired generation, lower pool costs and lower
capacity hedge costs. These were partially offset by an increase in
market contracts with more volume hedged and higher unit costs
due to the timing of the sale and purchase of swaps.
FY20
Sources
FY21
Sources
FY20
Uses
FY21
Uses
Renewables
Solar FiT
Coal (Eraring)
Gas
Other
Swap contracts
Short position
Business
Retail
Losses
28
Annual Report 2021
Wholesale energy costs
Fuel cost1
Generation operating costs
Owned generation1
Net pool costs2
Bundled renewable PPAs3
Market contracts3
Solar feed-in tariff
Capacity hedge contracts
Green schemes (excl. PPAs)
Other
FY21
FY20
$m
837
240
1,078
230
282
485
203
308
484
12
TWh
$/MWh
17.5
17.5
17.5
5.1
3.0
7.7
1.9
47.9
13.8
61.7
45.5
95.3
62.9
106.1
$m
992
216
1,208
303
264
362
181
342
506
14
TWh
$/MWh
19.6
19.6
19.6
4.9
2.9
6.0
1.5
50.6
11.0
61.6
61.3
92.1
59.9
117.9
Energy procurement costs
3,081
35.14
87.9
3,179
35.04
90.9
1
Includes volume from internal generation and contracted from Pelican Point.
2 Net pool costs includes gross pool purchase costs net of pool revenue from generation, gross and net settled PPAs, and other contracts.
3 Bundled PPAs includes cost of electricity and renewable certificates. Market contracts include swap and energy hedge contracts.
4 Volume differs from sales volume due to energy losses of 1.6 TWh (FY2020: 1.5 TWh).
Electricity supply
Nameplate
capacity
FY21
FY20
Change
Output
Pool revenue
Output
Pool revenue
Output
Pool revenue
(MW) Type1
(GWh)
($m)
($/MWh)
(GWh)
($m)
($/MWh)
(GWh)
($m)
($/MWh)
Eraring
Units 1-4
GT
Darling Downs
Osborne2
Uranquinty
Mortlake
Mount Stuart
Quarantine
Ladbroke Grove
Roma
Shoalhaven
2,922
2,880 Black Coal
13,276
1,008
76
13,634
1,065
42 OCGT
644 CCGT
180 CCGT
664 OCGT
584 OCGT
423 OCGT
230 OCGT
80 OCGT
80 OCGT
240 Pump/hydro
-
1,696
379
142
512
35
129
82
47
122
-
147
22
36
43
22
16
9
10
10
-
2,067
-
130
703
422
932
4
188
155
17
156
58
75
91
0
29
19
2
26
-
87
58
255
85
619
125
106
219
79
81
79
-
79
93
125
106
103
153
123
109
135
(358)
(57)
-
(371)
(324)
(280)
(420)
32
(59)
(73)
30
(35)
-
17
(36)
(39)
(48)
22
(13)
(10)
8
(16)
(3)
-
8
(36)
130
(22)
516
(28)
(17)
110
(56)
(1)
Internal generation
6,047
16,420
1,323
18,279
1,495
82
(1,859)
(172)
Pelican Point
240 CCGT
Renewable PPAs
1,207 Solar / Wind
1,050
2,959
1,317
2,871
(267)
88
Owned and
contracted
generation
7,494
20,429
22,467
(2,038)
1 OCGT = open cycle gas turbine; CCGT = combined cycle gas turbine.
2 Origin has a 50 per cent interest in the 180 MW plant and contracts 100 per cent of the output.
Operating and Financial Review
29
5.1.3 Natural Gas
Volume summary
Volume sold (PJ)
Retail
Business
FY21
NSW1
Queensland
Victoria
South Australia2
External volumes sold
Internal sales (generation)
Total volumes sold
12.1
3.3
24.8
5.7
45.9
24.1
66.8
46.3
9.8
147.0
Total
36.2
70.1
71.1
15.5
192.9
38.4
231.3
1 Australian Capital Territory customers are included in New South Wales.
2 Northern Territory and Western Australia customers are included in South Australia.
FY20
Retail
Business
11.0
3.1
25.2
5.7
45.0
22.8
66.9
58.3
10.6
158.6
Total
33.8
70.0
83.6
16.3
203.6
55.6
259.2
Change
(PJ)
Change
(%)
2.4
0.1
(12.4)
(0.8)
(10.7)
(17.2)
(27.9)
7
0
(15)
(5)
(5)
(31)
(11)
Gross Profit summary
Revenue
Retail (residential/SME)
Business
Cost of goods sold
Network costs
Energy procurement costs
Gross Profit
Gross margin %
FY21
$m
2,455
1,148
1,307
(2,008)
(789)
(1,218)
447
18.2%
$/GJ
12.7
25.0
8.9
(10.4)
(4.1)
(6.3)
2.3
FY20
$m
2,835
1,163
1,672
(2,090)
(796)
(1,294)
744
26.3%
$/GJ
13.9
25.8
10.5
(10.3)
(3.9)
(6.4)
3.7
Change
(%)
Change
($/GJ)
(13)
(1)
(22)
4
1
6
(40)
(31)
(1.2)
(0.8)
(1.7)
(0.1)
(0.2)
0.0
(1.3)
Natural Gas Gross Profit decreased $297 million driven by:
Sources and uses of gas (PJ)
•
•
•
•
•
-$105 million primarily due to lower customer tariffs, including
oil-linked sales;
-$51 million higher JKM-linked supply costs in the second half;
-$78 million due to the roll-off of long-term supply and transport
capacity contracts;
-$38 million reflecting supply contract price reviews; and
10.7 PJ decrease in external sales volume (-$25 million)
due to expiration of business contracts and COVID-19
impacts, partly offset by increased retail customers and higher
residential demand.
270
240
210
180
150
120
90
60
30
0
FY20
Sources
FY21
Sources
FY20
Uses
FY21
Uses
APLNG - fixed
price
Other fixed
price
Oil/JKM linked
Retail
Business - C&I
Generation
Business -
Wholesale
30
Annual Report 2021
FY20
(121)
(38)
(159)
(434)
(136)
(570)
FY20
($m)
(150)
(113)
(125)
(388)
(51)
(131)
(570)
Change
($)
Change
(%)
21
2
23
76
6
81
(17)
(4)
(14)
(17)
(4)
(14)
Change
($)
Change
(%)
15
30
23
67
(5)
20
81
(10)
(26)
(18)
(17)
11
(15)
(14)
5.1.4 Electricity and Natural Gas cost to serve
Cost to maintain ($ per average customer)1
Cost to acquire/retain ($ per average customer)1
Electricity and Natural Gas cost to serve ($ per average customer)1
Maintenance costs ($m)
Acquisition and retention costs ($m)2
Electricity and Natural Gas cost to serve ($m)
FY21
(100)
(36)
(136)
(359)
(130)
(489)
1 Represents cost to serve per average customer account, excluding CES accounts.
2 Customer wins (FY2021: 484,000; FY2020: 491,000) and retains (FY2021: 1,441,000; FY2020: 1,396,000).
FY21
($m)
(136)
(83)
(102)
(321)
(56)
(112)
(489)
Labour
Bad and doubtful debts
Other variable costs
Retail and Business
Wholesale
Corporate services and IT
Electricity and Natural Gas cost to serve
Overall, Electricity and Natural Gas cost to serve reduced by
$81 million, primarily driven by further operating cost savings as
well as a reduction in bad and doubtful debt expense, with the
$38 million provision increase associated with COVID-19 risk in
FY2020 not repeating.1
Bad debt expense as a percentage of total Electricity and Natural
Gas revenue decreased to 0.9 per cent from 1.1 per cent in FY2020,
which included the $38 million provision related to COVID-19.
We delivered our targeted $100 million cost savings, having
achieved savings of $110 million in cost to serve from a baseline
in FY2018 after adjusting for the impacts of lease accounting.
The next wave of retail transformation is targeting a further
reduction of $100–$150 million in operating and capital cost
savings by FY2024 from a baseline of FY2018, following successful
implementation of Octopus Energy’s Kraken platform and operating
model. Approximately one third of savings is expected to be
capital in nature with some of these savings already achieved. The
remaining two thirds is expected from reduced operating costs to be
achieved over FY2023 - 24.
1 The total increase in bad and doubtful debt provision relating to COVID-19 risks was $40 million, of which $38 million impacted electricity and gas cost to serve and the
remainder impacted the Solar and Energy Services division.
Retail capex Other addressable opex Leases Cost to serve TotalRetail cost base ($m)1,000800600400200–FY18FY21FY24 Target~$200-$250m$110m cost out achieved Operating and Financial Review
31
Customer accounts
Customer accounts ('000) as at
30 June 2021
30 June 2020
Change
2,625
1,175
637
566
246
1,249
350
178
492
228
3,874
3,855
33
359
4,266
2,631
1,191
645
556
239
1,220
335
181
479
225
3,851
3,827
20
365
4,236
(6)
(16)
(8)
10
7
29
15
(3)
13
3
23
28
13
(6)
30
Customer account movement ('000)
Electricity
NSW1
Queensland
Victoria
South Australia2
Natural Gas
NSW1
Queensland
Victoria
South Australia2
Total electricity and natural gas3
Rolling average customer accounts
Broadband
LPG4
Total customer accounts
1 Australian Capital Territory customer accounts are included in New South Wales.
2 Northern Territory and Western Australia customer accounts are included in South Australia.
3 Includes 280,000 CES customer accounts (FY2020: 257,000).
4 June 2020 LPG customer accounts restated to include ~2,500 Asia Pacific customer accounts.
Although price dispersion and in situ churn have reduced following
the introduction of the DMO and VDO, the market remains highly
competitive and we continue to take a disciplined approach to share
and customer lifetime value.
Origin churn decreased to 12.5 per cent during the period,
compared to market churn of 17.3 per cent.
Period end customer accounts rose by 30,000 overall. Electricity
customer accounts fell by 6,000, primarily in New South Wales,
and Natural Gas customer accounts increased by 29,000, driven
primarily by gains in New South Wales and Victoria. Broadband
customer accounts increased by 13,000 during the period to a total
of 33,000 and LPG customer accounts decreased by 6,000 to
359,000 at 30 June 2021.
15
10
5
0
(5)
(10)
(15)
5.1.5 LPG
Volumes (kT)
Revenue ($m)
Cost of goods sold ($m)
Gross Profit ($m)
Operating costs ($m)
Underlying EBITDA ($m)
NSW
QLD
VIC
SA
Electricity
Gas
FY21
389
589
(388)
201
(112)
89
FY20
417
608
(417)
191
(108)
83
Change
Change
(%)
(28)
(19)
29
9
(4)
6
(7)
(3)
(7)
5
4
7
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.
Gross Profit increased by $9 million despite lower volumes for the year. This was driven by changes in product mix and lower cost of goods
sold, particularly relating to foreign exchange gains on shipping payments. Operating costs marginally increased to $112 million, driven by
additional restructuring and site remediation provisions.
32
Annual Report 2021
5.1.6 Solar and Energy Services
Revenue
CES Gross Profit
Solar Gross Profit
Other Gross Profit
Gross Profit
Operating costs
Underlying EBITDA
FY21
($m)
346
82
39
5
126
(70)
55
FY20
($m)
299
75
31
5
111
(77)
33
Change
($m)
Change
(%)
47
7
8
(0)
15
7
22
16
9
26
-
14
(9)
67
Origin provides installation of solar photovoltaic (PV) systems and batteries to residential and business customers, and ongoing support
and maintenance services. CES supplies electricity and gas to apartment owners and occupiers, and body corporates through embedded
networks and serviced hot water.
Underlying EBITDA increased by $22 million. This was driven by growth in Solar Gross Profit (+$8 million), with overall growth in residential
solar installations, a $7 million increase in CES Gross Profit due to continued customer account growth in the embedded networks and
serviced hot water business, and a $7 million reduction in operating costs due to reduced labour costs and bad and doubtful debt expense.
5.1.7 Future Energy
Operating costs
Other income
EBITDA
Investments
FY21
($m)
(25)
6
(19)
(5)
FY20
($m)
(15)
-
(15)
(15)
Change
($m)
Change
(%)
(10)
6
(4)
11
67
N/A
27
(67)
Future Energy is focused on developing and commercialising new products and technologies to engage customers in an increasingly
distributed and data-driven energy landscape. Through the year, we continued to expand the scale and sophistication of our Virtual Power
Plant (VPP), with 159 MW now connected from a range of distributed energy and Internet of Things (IoT) devices, including hot water systems,
solar, batteries, air conditioners and various industrial assets. This represents a new type of instrument in our wholesale portfolio, where we can
aggregate, control and dispatch thousands of distributed assets in response to market conditions and our portfolio position, creating value
for both us and our customers through lower cost of energy.
Of the 79,000 connected services, more than 56,000 are from our Spike program, which was launched in August 2020. Spike is a behavioural
demand response program that rewards customers for reducing their energy usage and has proven to be very engaging with customers, with
more than 843,000 SpikeHour invitations converting to a 67 per cent participation rate. We have also deployed in-app solar and battery
features that provide our customers with powerful insights on how they use and manage energy in their homes.
Operating costs increased during the period, largely due to costs relating to the launch of Spike, along with the scaling of our VPP and demand
response offerings. The business continues to make small investments in trialling new energy solutions as we continue to transition to a low
carbon future.
Other income in the period related to distributions received from equity investments.
Operating and Financial Review
5.1.8 Octopus Energy - Origin share (20 per cent)
Revenue - energy
Revenue - licensing
Cost of sales
Gross Profit
Operating costs
EBITDA
Other expense
Depreciation and amortisation1
Interest expense
Tax expense
NPAT
1
Includes $17.8 million Origin adjustment to amortisation relating to the fair value attributed to intangible assets, including Kraken, on acquisition date.
Octopus customer accounts (100 per cent Octopus)
Energy customer accounts (closing)
Energy customer accounts (average)
Licensed Kraken platform customer accounts migrated to date (closing)
Licensed Kraken platform customer accounts migrated to date (average)
33
FY21
($m)
750
31
(740)
41
(32)
9
(2)
(39)
(4)
4
(32)
FY21
('000)
4,214
3,486
4,726
2,124
Origin’s share of Octopus Energy EBITDA for the period was $9 million, reflecting strong customer growth and ongoing investment in
growth in the UK as well as launching in the United States, New Zealand and German markets. Customer accounts in the underlying UK retail
business have grown on average by ~108,000 per month since our investment in May 2020, to ~4.2 million customer accounts at the end
of June 2021.
Licensing deals with E.On and Origin are progressing well, with ~4.6 million customer accounts migrated at the end of FY2021. To date,
17 million customer accounts are contracted to be migrated to the Kraken platform, with approximately £250 million of licensing revenue
expected over the next three years. Octopus’s partnership with Tokyo Gas, announced in December 2020, will see an Octopus branded
retailer launch in the Japanese market. Octopus continues its growth trajectory and is targeting approximately 100 million customer accounts
by 2027.
34
Annual Report 2021
5.2 Integrated Gas
Share of APLNG (see Section 5.2.1)
Integrated Gas - Other (see Section 5.2.2)
Underlying EBITDA
Underlying depreciation and amortisation
Underlying share of ITDA from APLNG
Underlying EBIT
5.2.1 Share of APLNG
FY21
($m)
1,145
(10)
1,135
(30)
(917)
188
FY20
($m)
1,915
(174)
1,741
(29)
(1,296)
416
Change
($m)
Change
(%)
(770)
164
(606)
(1)
379
(228)
(40)
(94)
(35)
3
(29)
(55)
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.1 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 a 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 2021). Refer to Section 7 for disclosure relating to Tri-Star litigation associated with
these CSG interests.
Financial summary – APLNG
($m)
Commodity revenue and other income1
Operating expenses
Underlying EBITDA
Depreciation and amortisation
MRCPS interest expense
Project finance interest expense
Other financing expense
Interest income
Income tax expense
Underlying ITDA2
Underlying Profit
FY21
FY20
APLNG
100%
4,595
(1,544)
3,051
(1,568)
(282)
(270)
(87)
6
(255)
(2,456)
595
Origin
share
1,723
(578)
1,145
(588)
(106)
(101)
(33)
2
(95)
(921)
224
APLNG
100%
7,100
(1,992)
5,108
(1,863)
(463)
(372)
(102)
40
(708)
(3,468)
1,640
Origin
share
2,662
(747)
1,915
(699)
(174)
(140)
(37)
15
(266)
(1,301)
614
1
Includes commodity revenue plus other income of $16 million (Origin share) primarily related to tolling revenue and FX (FY2020: $19 million Origin share).
2 See Origin Financial Statements note B2.1 for details relating to a $4 million difference between APLNG ITDA and Origin's reported share.
1 As per EnergyQuest EnergyQuarterly, June 2021.
Exploration and appraisal Drilling and gatheringProcessing andtransportation Domestic customersLiquefaction and export customers Operating and Financial Review
35
Origin’s share of APLNG Underlying EBITDA decreased by $770 million, primarily due to lower realised oil prices. The price lag in the LNG
contracts resulted in the April and May 2020 low crude oil prices flowing through into FY2021. Similarly, higher prices experienced this
calendar year to date will predominantly flow through into FY2022.
• Commodity revenue and other income decreased by $939 million, primarily reflecting a realised oil price of US$43/bbl (A$58/bbl)
compared to US$68/bbl (A$101/bbl) in FY2020.
• Operating expenses reduced by $169 million, driven by lower royalties and tariffs as a result of lower revenue, less gas purchased and other
operating cost savings. See below for further details.
Origin’s share of depreciation and amortisation reduced by $111 million, reflecting a lower amortisation unit rate and a higher AUD/USD
exchange rate. Downhole costs are amortised using a units of production method. With the development plan for the year reflecting lower
capital costs, this has translated to a lower amortisation charge.
MRCPS interest expense reduced by $68 million due to a reduction in MRCPS balance following buy-backs by APLNG and a higher AUD/USD
exchange rate. Project finance interest decreased by $39 million due to a lower principal, lower average interest rate and a higher AUD/USD
exchange rate. See Section 4.7 for details relating to APLNG funding.
APLNG volume summary
Volumes (PJ)
Operated
Non-operated
Total production
Purchases
Changes in upstream gas inventory/other
Liquefaction/downstream inventory/other
Total sales
Commodity revenue ($m)
Domestic gas
LNG
Sales mix (PJ)
Domestic gas
LNG contract
LNG spot
Realised price
Domestic gas (A$/GJ)
LNG (A$/GJ)
LNG (US$/mmbtu)
Origin
share
202
61
263
2
(4)
(15)
246
252
1,455
59
169
18
FY21
APLNG
100%
537
163
701
6
(12)
(39)
656
672
3,880
158
450
48
4.24
7.79
6.17
Origin
share
203
62
265
7
(6)
(16)
251
323
2,320
70
169
12
FY20
APLNG
100%
542
165
708
17
(15)
(42)
668
861
6,188
187
449
32
4.61
12.86
9.12
Commodity revenue and other income (-$939 million)Movements in Underlying EBITDA ($m)1,91580(945)(71)(3)1691,145FY2020LNG volumeLNG priceDomestic revenueOther incomeOpexFY2021 36
Annual Report 2021
APLNG production was relatively stable, despite a significant reduction in planned development activity and costs, reflecting the quality of
the resource. Strong field capability enabled the flexibility to curtail production early in the year in response to lower demand coupled with
planned maintenance, and then ramping up to record levels as demand increased later in the year.
APLNG sales volumes decreased 2 per cent, primarily reflecting lower purchased gas in the period.
The average realised LNG price decreased 39 per cent to A$7.79/GJ due to a lower realised oil price, partially offset by higher spot LNG
volumes and prices. The average realised domestic gas price decreased 8 per cent to $4.24/GJ, primarily driven by lower realised prices on
oil-linked sales to QGC.
Cash flow – APLNG 100%
Underlying EBITDA
Non-cash items in underlying EBITDA
Change in working capital
Other
Operating cash flow1
Capital expenditure1
Interest income1
Acquisitions/disposals1
Loans (advanced to)/paid by other shareholders
Investing cash flow
Project finance interest and transaction costs1
Repayment of project finance1
Other financing activities1
Repayment of lease liabilities1
Interest on lease liabilities1
MRCPS interest
MRCPS buy-back
Financing cash flow
Net decrease in cash and cash equivalents
Effect of exchange rate changes on cash1
Net decrease in cash and cash equivalents including FX movement
Distributable cash flow1
FY21
($m)
3,051
8
265
(10)
3,314
(459)
8
-
3
(448)
(263)
(672)
(48)
(45)
(19)
(293)
(1,598)
(2,938)
(72)
(95)
(167)
1,721
FY20
($m)
5,108
66
64
4
5,242
(1,038)
40
(245)
14
(1,229)
(382)
(731)
(45)
(80)
(19)
(480)
(2,918)
(4,655)
(642)
104
(538)
2,846
Change
($m)
(2,057)
(58)
201
(14)
(1,928)
579
(32)
245
(11)
781
119
59
(3)
35
-
187
1,320
1,717
570
(199)
371
(1,125)
Change
(%)
(40)
(88)
314
(350)
(37)
(56)
(80)
(100)
(79)
(64)
(31)
(8)
7
(44)
-
(39)
(45)
(37)
(89)
(191)
(69)
(40)
1
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 $1,721 million ($645 million Origin share) at an effective oil price of US$43/bbl after servicing
project finance interest and principal. Cash distributions to Origin were $709 million in FY2021, reflecting a draw down of cash during the
period. The project finance facility requires APLNG to hold an amount of cash to service near-term operational and project finance obligations.
As at 30 June 2021, APLNG held $905 million ($1,072 million at 30 June 2020).
Operating and Financial Review
37
As well as benefiting from improved field performance, as upstream operator of APLNG we have achieved significant reductions in well costs
and unit operating costs in recent years. We continue to target further value accretion by focusing and aligning the business around five key
levers, coupled with our continued focus on reducing Scope 1 and 2 carbon emissions within our operations. These levers are:
1. Reduce well capital costs;
2. Reduce operating costs;
3. Improve well reliability;
4. Optimise production; and
5. Extend production plateau.
Operating expenditure – APLNG 100%
Purchases
Royalties and tariffs1
Upstream operated opex
Upstream non-operated opex
Downstream opex
APLNG Corporate/other
Total operating expenses per Profit and Loss
Other cash items
Total operating cash costs
FY21
($m)
(41)
(180)
(767)
(249)
(221)
(86)
(1,544)
(89)
(1,633)
FY20
($m)
(89)
(502)
(770)
(278)
(248)
(105)
(1,992)
(63)
(2,055)
Change
($m)
Change
(%)
48
322
3
29
27
19
448
(26)
422
(54)
(64)
(0)
(10)
(11)
(18)
(22)
42
(21)
1 Reflects actual royalties paid. At breakeven price, royalties and tariffs would have amounted to $147 million (FY2020: $96 million).
Operating expenses reduced $448 million, primarily driven by lower royalties and pipeline tariffs ($322 million) and lower purchases
($48 million). Upstream non-operated opex decreased $29 million, driven by cost reduction initiatives impacting workover, labour and power
costs. Downstream opex reduced $27 million due to lower shipping costs, reflecting no cargoes sold on a Delivered at Terminal (DAT) basis
in FY2021. APLNG Corporate/other reduced $19 million, reflecting an exploration write-off in the prior period ($56 million) offset by gas
inventory movements ($42 million).
Capital expenditure – APLNG 100%
Operated upstream - Sustain
Operated upstream - Infrastructure
Exploration and appraisal
Downstream
Non-operated
Total capital expenditure
FY21
($m)
(285)
(11)
(23)
(14)
(95)
(429)
FY20
($m)
(546)
(83)
(88)
-
(205)
(922)
Change
Change
($m)
261
72
65
(14)
110
493
(%)
(48)
(87)
(74)
N/A
(54)
(53)
Capital expenditure decreased $493 million, driven by a $261 million decrease in operated sustain costs, reflecting reduced development
activity enabled by improved field performance. Operated infrastructure costs reduced $72 million due to the completion of the Talinga
Orana Gas Gathering Station in the prior period. Exploration and appraisal spend declined $65 million and non-operated spend reduced
$110 million due to reduced activity including the decision by APLNG to not participate in less economic fields. Savings in downstream spend
as a result of fewer purchases of spares for maintenance were offset by a $50 million benefit in the prior period for settlement of a project
construction claim.
Operated upstream - Sustain includes expenditure for drilling, completions, fracture stimulation, the gathering network, surface connection,
capital improvements and land access which occurs over multiple years. In FY2021, 86 operated wells were drilled (versus 260 in FY2020),
18 wells were fracture stimulated (versus 74 in FY2020) and 141 operated wells were commissioned (versus 267 in FY2020).
38
Annual Report 2021
5.2.2 Integrated Gas – Other
This segment comprises Origin Integrated Gas activities that are separate from APLNG, and includes exploration interests in the Beetaloo,
Cooper-Eromanga and Canning basins 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 costs incurred in managing Origin’s exposure to LNG pricing risk and impacts of its LNG trading positions.
Beetaloo Basin (Northern Territory)
Origin has a 77.5 per cent interest in three exploration permits over 18,500 km2 in the Beetaloo Basin. Stage 2 appraisal under the farm-in
arrangement is underway, targeting three independent shale gas plays. Work continues with 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 was drilled to a total measured depth of 3,809 metres, which includes a 1,579 metre
lateral section.
During the period, Origin undertook fracture stimulation and initial flowback and production testing activities with nitrogen lift operations
enabling sustained production for up to ~17 hours without assistance to measure initial flow rates. The Kyalla 117 well successfully met
its primary objective to flow liquids-rich gas from the Kyalla Formation to the surface. Preliminary production test data and petrophysical
data included:
– unassisted gas flow rates ranging from 0.4–0.6 mmscf/d (0.6–0.9 TJ/d);
– highly saline stimulation flowback rates constraining production (water to gas ratios > 1,000 bbl/mmscf);
– liquids-rich gas (65 per cent methane, 19 per cent ethane, 11 per cent propane and butane, 3 per cent C5+); and
– minimal CO2 < 1 per cent.
Recent activity has focused on the continued clean-up of the Kyalla 117 well in preparation for an extended production testing, using
nitrogen to support operations. The well began flowing again without assistance for intermittent periods; however, production has not
been sustained. Operations were temporarily paused to investigate a potential downhole flow restriction, with the results informing the
development of a new go-forward plan.
• Velkerri liquids-rich gas play – Construction of the Velkerri 76 well lease pad was completed and environmental approval to drill and
fracture stimulate the Velkerri Flank well was granted in December 2019. The Velkerri 76 vertical well was spudded in August 2021 to collect
core, log, and Diagnostic Fracture Injection Testing data to assess the prospectivity of liquids rich gas.
• Velkerri dry gas play – The production test of Amungee NW 1H well commenced in August 2021 to assess if all original stages that were
stimulated during the previous test in 2016 are contributing to flow rates.
Cooper-Eromanga Basin (Queensland)
Origin has a 75 per cent interest and operatorship of five permits located in the Cooper-Eromanga Basin in south west Queensland, and has
recently acquired 100 per cent interest in one additional permit. In December 2020, the first vertical exploration well, Obelix-2, was drilled to
test the maturity of the Toolebuc Formation. Log and core data from the well are being evaluated with results on maturity and hydrocarbon
saturations expected in early FY2022 to inform the ongoing work program. 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.
Canning Basin (Western Australia)
Origin entered into agreements in December 2020 with Buru Energy to farm in to a 50 per cent equity share in five permits, and a 40 per cent
equity share in two permits. The CY2021 work program includes the drilling of two wells to assess conventional oil prospects (Currajong and
Rafael) and the acquisition of 2D seismic. The Currajong 1 well was drilled to a total measured depth of 2,340 metres in August 2021. Results
obtained indicate potential oil bearing zones with options for a production test of the well being developed. The Rafael 1 well is expected to
spud in Q1 FY2022.
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)
FY21
($m)
55
(65)
(10)
(26)
106
71
FY20
($m)
(92)
(82)
(174)
(24)
174
(23)
Change
($m)
147
17
164
(2)
(68)
94
Change
(%)
(160)
(21)
(94)
8
(39)
(409)
Refer to the following table for a breakdown of Origin only commodity hedging and trading costs.
Other Origin only costs reduced $17 million, primarily reflecting costs in the prior period associated with an agreement to reduce Origin’s share
of overriding royalty in the Beetaloo Basin.
Operating and Financial Review
39
Commodity hedging and trading summary
FY2021 positions realised a $55 million net gain compared to a $92 million loss in FY2020. Based on open positions at current forward market
prices1, we estimate a net loss on oil hedging and LNG trading in FY2022 of $176 million.
($m)
Oil hedging premium expense
Gain/(loss) on oil hedging
Gain/(loss) on LNG hedging/trading
Total
1 Based on forward prices as at 28 July 2021.
Oil hedging
FY21
actual
(9)
101
(37)
55
FY20
actual
(29)
8
(72)
(92)
FY22
estimate1
(26)
(108)
(42)
(176)
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 FY2022, Origin’s share of APLNG related Japan Customs-cleared Crude (JCC) oil price exposure is estimated to be approximately 23
mmboe. As at 28 July 2021, we estimate that 11.7 mmboe has been priced at approximately US$68/bbl before any hedging, based on the
LNG contract lags.
Origin has separately hedged 9.6 mmbbl, primarily using swaps, producer collars and put options, of which 4.0 mmbbl has been realised as
at 28 July 2021 at an average price of approximately US$63/bbl (see table below). Premium spend for this hedge position is A$26 million to
be incurred in FY2022.
Hedge instruments
Brent AUD swaps
Brent USD swaps
Brent producer collars
Brent puts
Total hedged
Brent USD calls
Realised as at 17 Jul 2021
Remaining unrealised
Volume (mmbbl)
Average price
Volume (mmbbl)
Average price
1.3
1.9
0.2
0.6
4.0
2.9
A$70/bbl
US$45/bbl
US$35-90/bbl
US$43bbl
US$57/bbl
1.3
2.7
0.5
1.1
5.6
2.8
A$75/bbl
US$46/bbl
US$35-90/bbl
US$40/bbl
US$59/bbl
The FY2023 hedge position consists of:
• 4.4 mmbbl hedged at a fixed price of US$54/bbl, with all of this hedged amount participating in market prices above US$63/bbl and
capped at US$78/bbl; and
•
1.6 mmbbl hedged at a floor price of US$35/bbl, with all of this hedged amount participating in market prices up to US$90/bbl.
The total premium spend for this hedge position is A$20 million to be incurred in FY2023.
LNG hedging and trading
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, a non-cash onerous provision of $641 million was recognised, which has been revalued at $397 million as at 30 June 2021,
reflecting stronger near-term assumptions for LNG prices relative to Henry Hub prices, higher US Treasury bond rates, the realised loss for the
period and favourable movements in the AUD/USD rate.
In 2016, Origin established a contract with ENN LNG Trading Company Limited to sell 0.28 mtpa on a Brent oil-linked basis commencing in
FY2019 and ending in December 2023. A non-cash onerous provision of $13 million has been recognised in FY2021 in respect of this contract
reflecting stronger near-term assumptions for LNG prices.
These contracts and derivative hedge contracts that manage the price risk associated with the physical LNG contracts form part of an LNG
trading portfolio.
1 As at 28 July 2021.
40
Annual Report 2021
6 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
First line
Lines of business
Second line
Oversight functions
Third line
Internal audit
Responsibility
Primary accountability
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 FY2021, COVID-19 was a
key threat to our operational and financial performance, requiring 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 the continuity of our operations and supporting activities, including our supply chain, to continue to provide our essential
services to our customers and maintaining our financial resilience to respond 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.
Strategic risks
Strategic risks arise from uncertainties that may emerge in the medium to longer term and, while they may not necessarily impact on short-
term profits, can have an immediate impact on the value of the Company. These Strategic risks are managed through continuous monitoring
and reviewing of emerging and escalating risks, ongoing planning and the allocation of resources, and evaluation from management and
the Board.
Risk
Climate change
Consequences
Management
Origin is exposed to risks and opportunities relating to
(i) the transition to a low-carbon economy and (ii) doing
business in a low carbon economy. These include the
continued decarbonisation of energy markets, decreased
demand for fossil fuels, reduced lifespan of carbon-
intensive assets, changes to energy market dynamics
caused by the low variable cost and intermittency of
renewables, changing government regulation including
regulatory intervention, climate change policy, growing
customer demand for lower-carbon sources of energy,
and new technologies and business models responding to
decarbonisation trends.
One of the most immediate climate change risks Origin
faces is reputational and market risk, arising from rapidly
changing stakeholder expectations and perceptions of our
contribution to the transition to a low carbon economy and
delivering on climate change targets and commitments.
This could result in the increasing cost of, or losing access
to, debt and equity capital, and insurance, as well as our
• Our strategy for transitioning to a carbon constrained
future is to focus on and invest in lowering existing and
future carbon emissions across our portfolio.
•
In Energy Markets this includes:
– Exiting coal-fired generation by 2032, at the latest.
– Growing our supply of renewable generation.
– Using the flexibility in our gas supply and peaking
generation capacity to manage the intermittency
of renewables.
– Investing in leading-edge technologies to
drive greater efficiency in operations and
reduce emissions.
•
In Integrated Gas, this includes:
– Reducing and removing operational emissions from
Australia Pacific LNG through upgrading equipment
and changed processes.
Operating and Financial Review
41
Risk
Consequences
Management
social licence to operate and the ability to attract and retain
customers and talent.
There is an increased risk of climate change related
litigation against Origin, including action against Origin
and/or the 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.
Litigation could also be initiated by external stakeholders
relating to investment, greenwashing and governance.
Origin is also exposed to the physical impacts of a
changing climate such as the impact of changing weather
patterns on the demand for energy and the resilience
of our assets and the energy infrastructure we use
to changing and more frequent and severe weather
conditions including floods, droughts, heat waves and
bushfires. This could impact our business operation
as well as that of our value chain and private and
public investment, and result in many of the other risks
mentioned above.
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
Origin is exposed to risks and opportunities to new digital,
and low-carbon technologies.
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.
•
Changes in demand
for energy
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.
The volume or source of energy demanded by customers
could change due to price, consumer behaviour,
community expectations, mandatory energy efficiency
schemes, Government policy, weather and other factors.
This change in demand for energy could:
•
•
reduce Origin’s revenues and adversely affect Origin’s
future financial performance; or
restrict optimising future financial opportunities if
Origin fails to adequately prepare.
– Engaging in early phase activities in carbon capture
and storage, credible carbon offsets and low carbon
customer solutions, including renewable hydrogen
and ammonia.
• Origin's capital allocation process and investment
decisions incorporate a price on carbon. Investment
in projects will be consistent with Origin's
decarbonisation commitments.
• Origin is using the Financial Stability Board’s Taskforce
on Climate-related Financial Disclosures (TCFD) for
governance oversight and reporting of our climate
change risks.
• Origin has science-based targets to halve Scope 1
and 2 greenhouse gas emissions and reduce Scope
3 emission1 by 25% by 2032, from our 2017 baseline,
and we aim to achieve net zero emissions by 2050.
We are in the process of updating our targets to a
1.5°C pathway.
• Origin has a short-term emissions target to reduce
Scope 1 emissions by 10 per cent on average
over FY2021-23 from a FY2017 baseline, linked to
executive remuneration.
Our operational planning and design processes
incorporate extreme weather events, while investment
decisions for major growth projects incorporate potential
financial losses from natural disasters.
• Our strategy to mitigate the impact of this risk
on our retail business is to provide customers with
value for money products with exceptional service
whilst continuously focussing on maintaining our
cost leadership and innovation. The migration of our
business to Octopus' Kraken platform should see Origin
maintain our churn advantage to competitors through
extending leadership in cost, products and service.
• 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 participates and invests in technological
developments through local and global start-up
accelerator programs, trialling new energy technology
and in new products and business models.
In parallel, Origin is growing its distributed
generation and home energy services businesses and
endeavouring 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 pursuing opportunities in low-carbon
technologies such as hydrogen, e-mobility, and
carbon management.
• Our strategy of increasing our supply of renewables,
and investing in new technology supports Origin’s
ability to meet future increases in energy demand.
• Origin is partially mitigating the impact of this risk
by developing data-based customer propositions and
better predicting customer demand through our AI
orchestration platform, which connects and controls
distributed assets and IoT devices, and by applying
advanced data analytics capability.
42
Annual Report 2021
Risk
Consequences
Management
Regulatory policy
Origin has broad exposure to regulatory policy change
and other government interventions. Changes to policy
and other government interventions 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 subsidising building of new generation or
transmission capacity, government direct investment
in generation, energy market design, domestic and
international climate change policies, domestic gas
market interventions, retail price and consumer protection
regulation, and royalties and taxation policy.
• 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.
1
Incurred within the domestic market; excluding LPG and Corporate as their emissions are not material.
Financial risks
Financial risks are the risks that directly impact the financial performance and resilience of Origin.
Risk
Commodity
Foreign exchange and
interest rates
Consequences
Management
Origin has a long-term exposure to international oil, LNG
and gas prices through the sale 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, through 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
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 utilises 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.
Operating and Financial Review
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
Environmental and Social
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.
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 the 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 amongst community stakeholder groups and
activism which may impact the company's reputation. A
third party’s actions may also result in delay 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.
Cyber security
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.
• 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 it meets regulatory and industry
standards in all operations.
• 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.
• Origin has a cultural awareness learning framework to
build awareness of Aboriginal and Torres Strait Islander
cultures, histories and achievements. Origin maintains
and implements Native Title Agreements and Cultural
Heritage Management Plans with Traditional Owners
where appropriate. Engagement with impacted groups
and consideration of cultural heritage protection is
undertaken at ongoing operations and project gates.
• 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 cyber security strategy is in place and is regularly
updated to cater for emerging threats, security
regulation and stakeholder expectations.
• A robust security monitoring and incident response
process exists and is exercised on a regular basis. In the
event of an incident, Origin is supported by an external
incident response and forensics firm.
• Origin undertakes regular independent security
assurance to assess the resilience of our digital channels
and internal security controls.
• 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.
44
Annual Report 2021
Risk
Consequences
Management
APLNG gas reserves,
resources and deliverability
Conduct
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 2021 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.
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 financial prospects and operations are
underpinned by our license to operate which requires
compliance with stakeholder commitments, regulations,
and laws for example privacy, and insider trading.
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.
• 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.
• Origin’s people are trained on the laws and regulations
that apply to their activities and operations or on
the processes that underpin compliance with laws
and regulations.
• Origin’s Purpose, Values, Behaviours and Code
of Conduct guide conduct and decision making
across Origin.
• All Origin’s people are trained in our 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.
Controls specific to the different parts of Origin’s
business are the accountability of Business Units
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.
Operating and Financial Review
45
7 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% 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 2021), and approximately
20 per cent of APLNG’s 2P CSG reserves (as at 30 June 2021).
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, were 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 relating 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 is defending the proceedings.
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; and
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, resulting from 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.
In 2017, Tri-Star commenced separate 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.
In September 2019, Tri-Star made further claims in the markets
proceeding relating to:
•
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.
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. APLNG denies
these claims and is defending these proceedings.
APLNG filed defences and counterclaims in both proceedings in
April and May 2020. In December 2020, Tri-Star filed replies and
answers in the both proceedings. APLNG filed its rejoinders in the
reversion proceeding and the markets proceeding in February and
April 2021 respectively. The pleadings are now closed.
In both proceedings, the court has ordered, by consent, that
the parties confer as to the real issues in dispute, and, in the
reversion proceedings, as to potential separate questions for early
determination. Following that process, the court will make further
orders for the conduct of the two proceedings (which APLNG
expects will continue to be managed in parallel). The usual court
process would involve a period of document disclosure, potentially
court-ordered mediation and then finally a hearing. The process that
will ultimately be followed (and the procedural timetable) is difficult
to predict at this stage.
46
Annual Report 2021
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.
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 4.1 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.
Operating and Financial Review
47
Appendix
Large-scale generation certificate shortfall
Supply and demand for large-scale generation certificates (LGCs) is driven by the rate of new renewable projects coming online as well as the
compliance obligations under the Large-scale Renewable Energy Target (LRET). Renewable project delays and generation curtailments have
led to a near-term tightening of the LGC market; however, it is expected that the 33 TWh legislated target will be exceeded and longer term
the market will be oversupplied.
The Clean Energy Regulator has acknowledged the option for parties to shift demand from periods of tight supply by deferring the surrender
of certificates to later years. Under the scheme, parties can defer up to 10 per cent of their obligation at no additional cost and can defer more
than 10 per cent by incurring a shortfall charge of $65 per certificate that is refundable provided the LGCs are surrendered within three years.
With the forward curve in backwardation, Origin has previously elected to defer surrender of 2.5 million CY2020 certificates in February 2021
and expects to defer approximately 3.1 million CY2021 certificates in February 2022.
FY2021 impact
During FY2021, we have paid a shortfall charge of $160 million in relation to CY2020 certificates and accrued a further $102 million in relation
to CY2021 certificates. A cost of $64 million recognised in FY2021 Underlying Profit reflects the estimated future surrender cost, based on
a weighted average of the current forward price and purchases to date of:
• ~2.5 million 2020 certificates at $19/certificate; and
• ~1.6 million 2021 certificates at $12/certificate (estimate for the first half of CY2021).
The balance of $198 million is excluded from Underlying Profit.
FY2022 impact
Subject to changes in volume and forward price estimates, we expect to incur a further $102 million in relation to the shortfall charge for the
second half of CY2021. A cost of $18 million will be recognised in FY2022 Underlying Profit. The balance of $84 million will be excluded from
Underlying Profit.
The shortfall charge is non-deductible for tax purposes. The refund is currently tax assessable; however, legislative change is before Parliament
which would make refunds non-assessable (such that it is aligned to treatment of the shortfall charge).
CY2020 and CY2021 certificate shortfall recorded in FY2021
Shortfall charge (~4.1 million certificates x $65)
- $160 million paid; $102 million accrued
Expected surrender cost (~2.5 million CY2020 certificates x $19)
Expected surrender cost (~1.6 million CY2021 certificates x $12)
Total FY2021 impact
Remaining CY2021 certificate shortfall (incurred in FY2022)
Shortfall charge accrued (~1.6 million certificates x $65)
Expected surrender cost (~1.6 million certificates x $12)
Total FY2022 impact
CY2020 certificate surrender (incurred in FY2024)
Surrender (~2.5 million certificates x $19)
Shortfall refund (~2.5 million certificates x $65)
Total FY2024 impact
CY2021 certificate surrender (incurred in FY2025)
Surrender (~3.1 million certificates x $12)
Shortfall refund (~3.1 million certificates x $65)
Total FY2025 impact
Total cost of ~5.6 million certificates
Statutory
Profit
($m)
Adjustment
($m)
Underlying
Profit
($m)
(262)
-
-
(262)
(102)
-
(102)
(46)
160
114
(36)
204
168
(82)
262
(46)
(18)
198
102
(18)
84
46
(160)
(114)
36
(204)
(168)
-
(46)
(18)
(64)
-
(18)
(18)
-
-
-
-
-
-
-
(82)
48
Annual Report 2021
Directors’ Report
For the year ended 30 June 2021
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 2021.
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.
John Akehurst
Independent Non-executive Director
Ilana Atlas
(appointed 19 February 2021)
Independent Non-executive Director
Maxine Brenner
Independent Non-executive Director
Gordon Cairns
(Chairman) (retired 20 October 2020)
Independent Non-executive Director
Teresa Engelhard
(retired 20 October 2020)
Independent Non-executive Director
Greg Lalicker
Independent Non-executive Director
Mick McCormack
(appointed 17 December 2020)
Independent Non-executive Director
Bruce Morgan
Independent Non-executive Director
Steven Sargent
Independent Non-executive Director
Joan Withers
(appointed 21 October 2020)
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.
2 Events subsequent to
balance date
Other than the matters described below, no
matters or circumstances have arisen since
30 June 2021, 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.
On 19 August 2021, the Directors
determined a final dividend of 7.5 cents per
share, unfranked, on ordinary shares. The
dividend will be paid on 1 October 2021.
3 Dividends
a. Dividends paid during the year by the
Company were as follows:
$ million
176
220
10.0 cents per ordinary share,
unfranked, for the full year
ended 30 June 2020, paid
2 October 2020
12.5 cents per ordinary share,
unfranked, for the half year
ended 31 December 2020, paid
26 March 2021
b. In respect of the current financial year,
the Directors have determined a final
dividend as follows:
7.5 cents per ordinary share,
unfranked, for the full year
ended 30 June 2021, payable
1 October 2021
$ million
132
The Dividend Reinvestment Plan (DRP) will
apply to this final dividend at no discount.
4 Directors and Company
Secretary
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 pages 6 and
7. The qualifications and experience of the
Company Secretary is also set out below:
Scott Perkins
(Chairman from 20 October 2020)
Independent Non-executive Chairman
Frank Calabria
Managing Director and Chief
Executive Officer
Directors’ Report
49
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:
Directors
J Akehurst
I Atlas3
M Brenner
G Cairns4
F Calabria
T Engelhard4
G Lalicker
B Morgan
M McCormack5
S Perkins
S Sargent
J Withers6
Scheduled
Additional
H1
A2
9
4
9
3
9
3
9
9
5
9
9
6
9
4
9
3
9
3
9
9
5
9
9
6
H
10
1
10
6
10
6
10
10
2
10
10
3
A
10
1
10
6
10
6
10
10
2
10
10
3
Health,
Safety and
Environment
(HSE)
H
5
-
-
2
5
2
-
5
2
5
5
-
A
5
-
-
2
4
2
-
5
2
5
5
-
Audit
H
A
-
-
5
2
-
2
-
5
-
5
-
3
-
-
5
2
-
2
-
5
-
5
-
3
Nomination
Remuneration
& People
Risk
H
A
H
A
H
A
3
-
3
2
-
-
-
3
-
2
3
-
3
-
3
2
-
-
-
3
-
2
3
-
-
-
2
2
-
2
2
-
2
4
4
-
-
-
2
2
-
2
2
-
2
4
4
-
5
-
5
2
-
-
-
5
-
5
5
3
5
-
5
2
-
-
-
5
-
5
5
3
1 Number of meetings held during the time that the Director held office or was a member of the Committee during the year.
2 Number of meetings attended.
3 From the date of appointment on 19 February 2021.
4 Prior to the date of retirement on 20 October 2020.
5 From the date of appointment on 17 December 2020.
6 From the date of appointment on 21 October 2020.
The Board held nine scheduled meetings, including an annual strategic review and ten additional meetings to deal with urgent matters. There
was also one scheduled workshop and four ad hoc committees held to consider matters of particular relevance or urgency. In addition,
the Board conducted in-person and virtual visits of Company operations at various sites and met (in person and virtually) with operational
management during the year.
6 Directors’ interests in shares, Options and Rights
The relevant interests of each Director as at 30 June 2021 in shares, 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
J Akehurst
I Atlas
M Brenner
F Calabria
G Lalicker
B Morgan
M McCormack
S Perkins
S Sargent
J Withers
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
Restricted Share Rights
(RSR) over ordinary shares
71,200
50,000
28,367
406,563
100,000
47,143
100,000
56,000
41,429
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
632,9951
45,5562
1,075,2692 356,4622
183,4142
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Exercise price for options and rights
1. 231,707: $5.67; 401,288: $7.37.
2. N/A.
No Director other than the Managing Director and Chief Executive Officer participates in the Company’s Equity Incentive Plan.
50
Annual Report 2021
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 2021:
J Briskin
G Jarvis
A Lucas
M Schubert2
L Tremaine
Performance
Share Rights
Restricted
Shares
Restricted
Share Rights
Matching Share
Plan Rights1
60,104
61,438
49,018
61,438
67,916
123,900
111,258
66,289
130,616
118,650
60,102
61,440
49,017
61,440
67,917
518
518
-
-
518
1 Matching Share Plan Rights were granted in accordance with the Employee Share Plan rules and disclosed to the ASX at the time of grant. The Employee Share Plan is available
to all eligible Origin employees.
2 The securities granted to Mr Schubert were all forfeited upon cessation of his employment on 30 June 2021.
The awards of Performance Share Rights, Restricted Shares, and Restricted Share Rights were made in accordance with the Company’s Equity
Incentive Plan as part of the relevant Executive’s remuneration. Further details on Rights granted during the financial year, and unissued shares
under Options and Rights, are included in Section 7 of the Remuneration Report. No Rights were granted since the end of the financial year.
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 2021, so no ordinary shares in
Origin were issued as a result.
Rights
870,471 ordinary shares of Origin were allocated from the Origin Energy Limited Employee Share Trust during the year ended 30 June 2021
on the vesting and exercise of DSRs, PSRs and Matching Share Plan Rights granted under the Equity Incentive Plan and Employee Share Plan.
No amounts were payable on the vesting of these DSRs, PSRs and Matching Share Plan Rights and, accordingly, no amounts remain unpaid
in respect of any of those shares.
Since 30 June 2021, 3,719 ordinary shares of Origin were allocated from the Origin Energy Limited Employee Share Trust on the vesting of
Matching Share Plan Rights granted under the Employee Share 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 2021, regulators were notified of a total of 30 environmental reportable incidents. All of these incidents resulted in minor
environmental consequences with the appropriate level of investigation undertaken. All incidents are investigated, and lessons learned
captured and shared across the Company.
In FY2021, the Company received two formal environmental Clean Up Notices from a regulator arising from Origin’s activities. All of the
required actions set out in the Notices have been executed with final reports submitted and accepted by the Regulator. There were no fines
issued in FY2021.
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 2021 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 2021.
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.
Directors’ Report
51
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
2021 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.
10 Non-audit services
13 Remuneration
The Remuneration Report forms part of this
Directors’ Report.
The amounts paid or payable to EY for non-
audit services provided during the year was
$1,873,000 (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).
52
Annual Report 2021
Remuneration
Report
For the year ended 30 June 2021
The Remuneration Report for the year ended 30 June 2021 (FY2021) 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 FY2021.
FY2021 remuneration outcomes
FY2021 was a challenging year for many of Origin’s stakeholders,
particularly Origin’s shareholders.
In deciding the short-term incentive outcomes for the Executive
Leadership Team, the Board balanced the fall in the share price
over the financial year with the achievements of the leadership
team in managing the multiple impacts of COVID-19, regulatory
uncertainty, the accelerated growth of renewables and still
performing well against their objectives for the year. Details of the
performance of the team against their objectives for the year are set
out in Section 4 of this Remuneration Report.
The Board’s remuneration governance followed a rigorous process
to test the Short Term Incentive (STI) scorecard outcomes and
decide whether it should exercise its discretion to adjust outcomes.
The STI scorecard outcomes for the year reflected:
In summary, for FY2021:
•
the CEO’s STI outcome was 46.6 per cent of maximum
(77.8 per cent of target);
• other Executive Key Management Personnel (KMP) outcomes
range between 44.3 and 57.8 per cent of maximum (74.0 to
96.5 per cent of target); and
•
the aggregate outcome was 50.7 per cent of maximum
(84.5 per cent of target), ignoring the zero STI award for
M Schubert, who forfeited his STI on resignation.
A partial vesting (35.3 per cent) of the FY2017 Long Term Incentive
(LTI) grant occurred in FY2021, resulting from return on capital
employed (ROCE) performance exceeding target. Further details
are provided in Section 4.1 of the Remuneration Report.
FY2021 remuneration framework and levels
• below-threshold performance in Energy Markets because of
Fixed Remuneration and Non-executive Director fees
The annual fixed remuneration (FR) review normally conducted at
year end was deferred on an organisation-wide basis. No changes to
FR for Executive KMP were made for FY2021.
There were no changes to the level or structure of Non-executive
Director (NEDs') fees in FY2021.
Short Term Incentive Plan
No changes were made to the Short Term Incentive Plan
(STIP) architecture or opportunity levels during the year. The
plan continues to be refined and developed to simplify the
scorecard structure and to increase aspects of conduct and
behavioural reviews.
margin contractions following weaker commodity market prices
from the pandemic and mild summer weather, exacerbated by an
adverse gas price arbitration outcome;
•
stretch performance in Integrated Gas due to strong field
performance, portfolio optimisation and responsiveness to
recovering oil market conditions;
• on-target performance for underlying earning per share (EPS)
and net cash from/(used in) operating and investing activities
(NCOIA), reflecting strong operational performance across our
combined businesses in challenging external markets;
• above-target performance in customer and climate
change performance;
• above-threshold but below-target achievement for our range of
people measures. Notwithstanding a top-quartile engagement
score of 74 and a 69.9 per cent of maximum result for safety,
overall performance on all of the measures did not meet our
robust target requirement.
The outcome for the CEO’s STI scorecard was 62.2 per cent of
maximum (103.7 per cent of target), driven by strong operational
performance in Integrated Gas, and customer and climate change
metrics. In balancing management’s response and execution in
an extraordinarily challenging and dynamic environment against
financial results impacted by a range of headwinds, the Board
and the CEO agreed this outcome should be reduced. The Board
exercised its discretion and made a 25 per cent reduction to better
align the result with the experience of shareholders. The Board
noted that the CEO and leadership team also have significant
shareholdings in the Company.
Remuneration Report
53
FY2022 remuneration
Following the salary freeze in FY2021, modest adjustments will be
made to FR for Executive KMP from 1 July 2021 in order to maintain
market competitiveness. The CEO’s FR will increase by 2.7 per cent,
and Other Executive KMP by an average of 2.3 per cent for FY2022,
in line with adjustments for our workforce more generally.
There is no change to LTIP arrangements for the grants to be made
in early FY2022.
Finally, there will be no changes to the structure or level of NED fees
for FY2022.
Steven Sargent
Chairman, Remuneration and People Committee
Long Term Incentive Plan
A comprehensive assessment of the remuneration framework was
undertaken during FY2020. The Board concluded from the review
that the LTI Plan (LTIP) was not suited to the industry risks and
opportunities inherent in Origin's business. The commodity price
cycles faced by Integrated Gas coupled with the energy transition
and transformation of the Energy Markets business undermined
the efficacy of ROCE metrics. The LTIP was failing to meet
the objectives of attraction, retention, motivation and building
executive shareholding.
As advised to shareholders last year, the Board concluded that
alternative models using Restricted Shares (RSs) with reduced
opportunity, longer deferral periods, underpinning performance
criteria and increased shareholding requirements are better suited
to the Company’s return and investment profile. The new Restricted
Share Rights (RSRs) are considered a better structure to achieve the
intended objectives.
Following the release of the FY2020 Remuneration Report, the
Board engaged with major investors and proxy advisors before
finalising a revised LTIP structure. Overall, the feedback strongly
supported the RSR structure, but a number of stakeholders
expressed a preference for an external financial performance
condition, such as relative TSR (RTSR), as a part of a modified
LTIP structure. Accordingly, the combined RSR and RTSR model
(modified LTIP) was adopted for LTIP awards made in FY2021.
The implications of this change on executive remuneration included:
• a 33 per cent reduction in the LTIP maximum opportunity levels;
• a reduction in maximum Total Remuneration (TR) of
13.4 per cent;
• an increase in the Minimum Shareholding Requirements (MSR)
for Executives;
• an extension of the deferral period from four to five years; and
•
in relation only to those rights that ultimately vest, a dividend-
equivalent for better alignment with shareholders.
The Board made these changes as they better reflect the investment
cycle of our business. They significantly improve alignment of
executive and shareholder interests in the level of reward, the
increased ownership required, and the longer deferral period.
There is no change to the executive remuneration framework,
including equity grant, in FY2022.
54
Annual Report 2021
Report structure
The Remuneration 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 Remuneration Report discloses the remuneration arrangements and outcomes for people listed below: individuals who have been
determined as KMP as defined by AASB 124 Related Party Disclosures. Members of the RPC are identified in the last column.
d
r
a
o
B
Name
S Perkins1
Role
Chairman, Independent
J Akehurst
Independent
I Atlas
M Brenner
G Lalicker
Independent
Independent
Independent
M McCormack
Independent
B Morgan
S Sargent
J Withers
G Cairns
Independent
Independent
Independent
Former Chairman, Independent
T Engelhard
Former NED, Independent
F Calabria
Chief Executive Officer (CEO)
L Tremaine
Chief Financial Officer (CFO)
J Briskin
Executive General Manager, Retail
G Jarvis
Executive General Manager, Energy Supply
and Operations
e
v
i
t
u
c
e
x
e
-
n
o
N
e
v
i
t
u
c
e
x
E
RPC
✓
✓
✓
✓
Chair
Retired
20-Oct-20
20-Oct-20
Appointed
20-Oct-20
29-Apr-09
19-Feb-21
15-Nov-13
1-Mar-19
18-Dec-20
16-Nov-12
29-May-15
21-Oct-20
23-Oct-13
1-May-17
19-Oct-16
10-Jul-17
5-Dec-16
5-Dec-16
M Schubert2
Executive General Manager, Integrated Gas
1-May-17
30-Jun-21
1 KMP full year (appointed to the Board in September 2015 and appointed Chairman on 20 October 2020).
2 KMP full year, terminated employment at close of business on 30 June 2021.
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).
Remuneration Report
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; 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.
Remuneration framework
Performance measures
Link to principles and strategy
Determined by the scope of the role and
its responsibilities, benchmarked annually
against similar roles.
Set at competitive levels to attract and
retain the right people, and to pay fairly.
Element
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 3.7
— 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 3.4
Performance targets set one year in
advance across a balanced scorecard
(generally 60 per cent financial metrics
and 40 per cent non-financial metrics)
with a conduct/behaviour modifier.
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.
— Long Term Incentive (LTI)
Granted as Share Rights allocated at face
value, vesting over three to five years, all
deferred for five years.
Details in sections 3.5 and 3.6
Half of the award vests according to 3-year
achievement against an external financial
performance condition (Origin’s relative
total shareholder return). The other half
vests over 3-5 years subject to satisfactory
performance relative to a holistic suite of
internal performance criteria. All vesting is
subject to a conduct gate and over-riding
Board discretion.
All equity is deferred for five years
and further subject to strong minimum
shareholding requirements.
Designed to encourage long-term focus,
and to build and retain share ownership.
56
Annual Report 2021
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 across the Company. 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 3.8).
Executive KMP are required to build and maintain a minimum shareholding in the Company. Following the introduction of the modified LTIP,
the MSR will increase from the equivalent 200 per cent to 250 per cent of FR for the CEO, and from 100 per cent to 150 per cent of FR for
Other Executive KMP. The changes will take effect from August 2023, which is the earliest date from which the modified LTIP can impact
vesting patterns. From time to time, the Board determines the MSR as a number of shares with reference to movements in FR and share price.
The MSR for FY2021 was 620,000 shares for the CEO and 130,000 for Other Executive KMP. The numeric share determinations will be
reviewed during FY2022.
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) count towards the MSR, but rights are not 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 organisations
with comparable activity and scale and with whom Origin competes for talent.1 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 to reward sustained high performance, or 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
percentile of the reference market.
3.2 Variable Remuneration
VR comprises the total of STI and LTI:
• The minimum VR is zero, where no STI or LTI is awarded, or where the STI scorecard outcome is zero and LTI is not awarded or all of it fails
to vest, or where discretion is exercised to reduce such awards or vesting outcomes to zero.
• The target VR represents the total of STI awarded at the target level, plus 50 per cent of the face value2 of any LTI subject to an explicit
performance hurdle, plus 100 per cent of the face value of any 'underpinned' LTI tranche (Section 3.5). In terms of the LTI component, the
‘target’ represents a risked or expected (probabilistic) outcome.
• The maximum VR is the total of STI awarded at the maximum level, plus the full face value of all LTI tranches assuming 100 per cent vesting.
3.3 Total Remuneration
TR is the sum of FR and VR.
TR at target (TRT)
TR maximum (TRM)
=
=
FR
FR
+
+
target VR
maximum VR
TRT is benchmarked to the median of equivalent TRT in the reference market, with the intention that when Origin’s outcomes are at their
maximum possible (i.e. TRM) they will be comparable to the top quartile of the reference TRT.
1 The prime references are to (a) ASX-listed organisations ranked between 7 and 70 by average two-year market capitalisation (excluding foreign domiciles, listed investment
companies or similar) and to (b) organisations with revenues between 40% and 250% of Origin’s revenue, always including AGL, APA Group, Oil Search, Santos and Woodside.
2 The face value at the date of grant is represented by the share price on the date of grant. The face value of deferred equity elements (Deferred STI, and LTI) is represented by
the current share price, (present-day value) because it is not possible to predict future share prices.
Remuneration Report
57
3.4 FY2021 Short Term Incentive Plan details
The following is a detailed description of how the STIP operates.
Parameter
Award basis
Details
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 per cent of the
weightings) and non-financial categories (generally 40 per cent). The CEO’s FY2021 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 yields 20 per cent of maximum (33 per cent of target).
Target represents the expectation for achieving robust annual plans, yielding 60 per cent of maximum.
Stretch performance represents the delivery of exceptional outcomes well above expectations, yielding the maximum
payout (corresponding to 167 per cent of target).
Opportunity level
Award calculation
The opportunity level for FY2021 for all Executive KMP was unchanged at 100 per cent FR at target with a capped
maximum of 167 per cent of FR.
Assessment
Achievement and performance against each Executive’s balanced scorecard is assessed annually as part of the
Company’s broader performance review process.
Delivery and timing
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.
Either 40 per cent or 50 per cent of the STI award amount is paid in cash, the lower level applicable while the Executive
is yet to reach the relevant MSR level. The balance is delivered in the form of RSs that are subject to a two year deferral.
Both elements are delivered in August-September following the end of the financial year. Prior to FY2018 the deferred
element was delivered in the form of Deferred Share Rights (DSRs).
RS allocation
Service conditions
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.
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.
Result (% of maximum)Maximum100%167%Result (% of target)Target60%100%Threshold 20%33%Minimum0% Threshold Target StretchIncreasing performance level →STIP award ($)=$ FR(at 30 June)✕STIP opportunity(% of FR)✕Balanced scorecard outcome (% )↑Discretionary modifier incorporating behavioural assessment 58
Parameter
Release
Annual Report 2021
Details
RSs in respect of FY2021 STI awards will be released on the second trading day following the release of full-year financial
results for FY2023, 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 deferred cash.
Governance and MSR
After restrictions on RSs are lifted, trading is subject to the MSR (see Section 2.3), to the Company's Dealing in Securities
policy, and to the malus and clawback provisions in Section 5.3.
3.5 FY2021 Long Term Incentive Plan details
The operation of the LTIP is described below.
Parameter
Award basis
Opportunity and
value range
Vehicle, dividends and
voting rights
Details
LTIP awards are conditional grants of equity that may vest in the future, subject to the meeting of performance
conditions and/or underpinning criteria, and subject also to the Executive meeting service and personal conduct
and performance requirements. Awards are considered annually for approximately 60 senior roles representing those
having significant influence in long-term company performance.
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). Opportunity levels are expressed in terms of the total
face value of awards (i.e. not discounted for risk). In FY2021, the opportunity maximums were reduced by one-third as
shown in the table below.
Executive KMP
Minimum
Maximum FY2020
Maximum FY2021
CEO
Other
0
0
180
120
120
80
Face value LTIP opportunity (percentage of FR)
Awards are granted at face value, between the minimum and maximum opportunity level. Prior to the determination of
LTIP grants the Board considers whether there are any reasons to reduce or not make an award, but in the normal course
of events awards are granted at the maximum opportunity level (given that they are subject to future performance and
underpinning conditions, additional to malus and clawback processes). The value of an award is as follows:
•
•
•
the minimum value is zero (which will be the case if the award fails to vest, is forfeited or is not awarded);
the target value represents the risked or expected value of the maximum grant, taking into account the likelihood of
vesting; and
the maximum value represents the present-day face value of the maximum grant, assuming that 100 per cent of the
grant vests, ignoring the risks of achieving performance conditions and of the service requirements.
The actual or realised 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.
LTIP awards are delivered in the form of Share Rights. The Share Rights do not carry any dividend or voting entitlements.
Each vested Share Right represents a right to a fully paid ordinary share (as a Restricted Share) in the Company and such
additional shares equal to the value of dividends (as determined by the Board) in the period from grant to exercise on
the underlying share on a reinvested basis. The terms and conditions applying to the Share Rights or RSs apply also to
the dividend-equivalent amounts and shares. The Board retains a discretion to make a cash equivalent payment to settle
the dividend-equivalent amount in lieu of an allocation of shares. The Share Rights are granted at no cost because they
are awarded as remuneration.
No dividend or dividend-equivalents are received by participants on share rights during a vesting period, and none on
share rights that do not vest. Shares allocated upon vesting of rights (including Rights to a dividend-equivalent amount)
carry the same dividend and voting rights as other shares (including while they are subject to a holding lock).
Number and type of
Share Rights
The total number of Share Rights to be granted is calculated by taking the face value of the award being made and
dividing it by the 30-day VWAP of Origin shares to 30 June at year end, rounded to the nearest whole number.
The award is divided into two halves, each with its own vesting conditions.
One half of the Share Rights is awarded as Performance Share Rights (PSRs) where vesting is subject to a Relative TSR
(RTSR) performance condition with a conventional vesting scale. This is the 'RTSR Tranche'.
The other half of the Share Rights is awarded as Restricted Share Rights (RSRs) where vesting is subject to Board
discretion with reference to a suite of underpinning conditions as described below. The number of RSRs will be divisible
by three because this tranche is further divided into three equal parts, which vest progressively as described below.
Remuneration Report
59
Parameter
Details
Vesting and release
All of the Share Rights are deferred for five years.
RTSR Tranche
RSR Tranche
The RTSR Tranche vests (subject to achievement against the RTSR vesting scale) at the end of the three-year
performance period, into Restricted Shares that remain under a holding lock for a further two years.
The RSR Tranche vests (subject to Board discretion) progressively after three, four and five years. The part which vests
after three years is into Restricted Shares that remain under a two-year holding lock; the part vesting after four years is
locked for a further one year; and the final part vesting after five years vests into unrestricted shares.
The vesting dates corresponding to the three, four and five year periods are determined as the second trading day after
the release of the respective full year results. For FY2021 awards granted in November 2020 (following completion of
the FY2020 year) these are expected to be 21 August 2023, 26 August 2024, and 25 August 2025 (Release Date).
At all times before and after vesting, and after release from holding lock, the Share Rights, Restricted Shares and the
unrestricted shares remain subject to malus and clawback provisions (Section 5.3), and may also be subject to trading
restrictions arising from the Minimum Shareholding Requirement (Section 2.3) and from the Company's Dealing in
Securities policy.
RTSR measures the Company’s TSR performance relative to a reference group of companies assuming reinvestment of
dividends, measured over three financial years with vesting deferred for a further two years. It has been chosen because
it aligns Executive reward with shareholder returns. It rewards only when Origin outperforms the reference group; it does
not reward overall market uplifts. The market reference group is the S&P/ASX 501 which, while not a perfect substitute
for an investment in Origin, represents a transparent and widely understood listed group with which Origin competes
for shareholders, skills and talent.
In calculating RTSR, share prices are determined using three-month VWAPs to 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 of the 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.
Straight-line pro-rata vesting applies between these two points.
The RSR tranche complements the RTSR tranche. Unlike the RTSR tranche, which is subject to an external financial
metric, the RSR Tranche is expected to vest unless there are material adverse deviations in the underlying health and
performance of the Company. While the reduction in LTI opportunity level offsets the increased probability of vesting,
the Board is committed to a robust assessment of a holistic suite of performance indicators to ensure that unwarranted
vesting does not occur.
The core objective of the RSR Tranche is to increase alignment between management and shareholders by more
predictably building Executive share ownership which, in turn, has been locked in through increased MSR requirements.
Executives are therefore exposed to the share price and market performance in a steadier manner than has been
associated with boom-or-bust vesting cycles.
The Board will determine the vesting outcome shortly before the vesting date by reference to a broad range of
performance indicators that are expected to position the business for success, growth and sustainability. While the
long-term share price performance will typically reflect the underlying health of the Company, the Board also considers,
through these measures, whether there are any material reasons why vesting should not occur as expected (on an
individual or collective basis). This process incorporates a formal People and Performance Review conducted by the full
Board reviewing the CEO and each member of the Executive Leadership Team. The process includes taking feedback
from: Chairs of the Health, Safety and Environment Committee, the Audit Committee and the Risk Committee; the
internal auditor; the General Counsel and Executive General Manager Company Secretariat, Risk and Governance;
and the Executive General Manager, People & Culture. The review considers any risk and reputation matters covering
whistle-blowing, discrimination, bullying or harassment complaints; employee relations matters, and contribution to
business strategy and overall performance with reference to the underpinning indicators.
The vesting process will consider a range of performance indicators summarised below and predominantly reflect
those that will be presented (with outcomes and performance trend data) in the Performance Overview tables in the
annual Sustainability Report (commencing with the 2021 publication). In addition, other indicators may be considered
over time.
Area
Customers
Communities
Planet
Measures
Customer base, Green Energy customers
Ombudsman complaint rate
Net promoter scores (strategic, interaction and episodic)
Reputation (RepTrak score)
Customers successfully completed Power On Hardship program
Regional procurement spend, Indigenous supplier spend
Foundation funds distributed
Employee volunteering to support local communities
Landholder/community complaints
Emissions (Scope 1 and Scope 2), emissions intensity, total air and fugitive emissions
Solar photovoltaic installations
Proportion of CSG water treated, proportion of Eraring ash recycled
Level of renewables and storage (percentage of owned and contracted capacity)
Environmental consequence incidents
60
Annual Report 2021
Parameter
Details
People & Culture
Health and safety
Total Recordable Injury Frequency Rate
Serious incidents, learning incidents
Process safety incidents (Tier 1 and Tier 2)
Diversity and inclusion
Female representation in Executive and senior leadership positions
Indigenous representation and Stretch Reconciliation Action Plan progress
Employee engagement
Vesting decisions will be disclosed in the relevant remuneration reports, together with commentary on the rationale for
those decisions in the context of performance across the totality of measures.
Service conditions and
cessation of employment
Unless the Board determines otherwise, Share Rights are forfeited if the Executive resigns or is dismissed for cause prior
to the end of the relevant vesting period.
In 'good leaver' circumstances (typically death, disability, redundancy or genuine retirement), Share Rights remain on
foot subject to their original terms and conditions (other than the continuing service condition) or may be dealt with in
an appropriate manner as determined by the Board, and/or the holding lock may be lifted in whole or part.
Sourcing
The Board’s preferred approach is to satisfy the vesting of Rights through the purchase of shares on market, but it may
issue shares or make the award in alternative forms, including cash or deferred cash.
1 The TSR reference group is set at the commencement of the performance period. For FY2021, it comprised A2 Milk, AGL Energy, Amcor, Ampol, APA Group, Aristocrat
Leisure, ASX Limited, Aurizon, ANZ Group, BHP, Brambles, Cochlear, Coles, CBA, Computershare, CSL, Dexus, Fortescue, Goodman Group, GPT Group, Insurance
Australia Group, James Hardie Industries, Lendlease, Macquarie Group, Medibank Private, Mirvac, NAB, Newcrest Mining, Oil Search, Orica, Qantas, QBE, Ramsay Health
Care, Rio Tinto, Santos, Scentre Group, Sonic Healthcare, South32, Stockland, Suncorp, Sydney Airport, Telstra, Transurban, Treasury Wine Estates, Vicinity Centres,
Wesfarmers, Westpac, Woodside Petroleum and Woolworths. Companies are not replaced (for example as a consequence of merger, acquisition or delisting) unless the Board
determines otherwise.
3.6 Remuneration cycle timelines
The following chart summarises the remuneration cycle and timelines, noting that the equity timelines shown are for grants to be made after
the end of FY2021.
MSRFY2021Aug 2021Oct 2021Aug 2022Aug 2023Aug 2024Aug 2025Aug 2026→Fixed remunerationpaid through year1 July 2020–30 June 2021STIPperformance against annual targets1 July 2020–30 June 2021Cash 40–50%Deferred STI 50–60% Restricted Shares allocated2-year holding lockLTIPRTSR tranche (50%)Allocation confirmed; performance period startsPerformance Share Rights grantedvest after 3 yearsRSR tranche (50%)Allocation confirmed; review period startsRestricted Share Rights grantedMSRMSRMSRMSR1/3 vest after 3 years1/3 vest after 4 years1/3 vest after 5 years2-year holding lock2-year holding lock holding lock Remuneration Report
61
3.7 Remuneration range and mix
The potential range for the CEO’s remuneration in FY2021 was between a minimum of $1.831 million (his FR) to a target of $5.310 million
and, following the reduction in LTIP opportunity, a maximum of $7.086 million (FY2020: $8.185 million). The remuneration mix at target
and at maximum is shown in the chart below which shows the significant proportion of variable or performance-based pay and delivery in
equity. Variable or performance-based pay represents 65.5 per cent of the CEO’s package at target outcomes, and 74.2 per cent at maximum
outcomes. Forfeitable equity represents 48.3 per cent at target outcomes and 52.6 per cent at maximum outcomes.
CEO remuneration mix
Corresponding figures for the average remuneration mix for other Executive KMP range from $939,000 (FR and minimum), to $2.442 million
at target and $3.259 million at maximum. The proportion of performance-based pay is 61.5 per cent at target and 71.2 per cent at maximum,
and the level of equity is 42.3 per cent at target and 47.1 per cent at maximum.
3.8 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 in shares annually.
Under the $1,000 scheme (the General Employee Share Plan (GESP)) shares are restricted for three years or until cessation of employment,
whichever occurs first.
Under the Matching Share Plan (MSP), 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.
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 FY2021.
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. No retention arrangements were put in place for Executive KMP in FY2021.
FR Cash STI Deferred STI LTI TargetMaximum1,8311,5291,5292,1977,0861,0002,0003,0004,0005,0006,0007,00065.5% performance-based74.2% performance-based52.2% equity-based48.3% equity-based1,8319169161,6485,310 62
Annual Report 2021
4 Company performance and remuneration outcomes
This section summarises remuneration outcomes for FY2021 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 FY2017 to FY2021, grouped and compared
with short-term and long-term remuneration outcomes.
Five-year key performance metrics FY2017–211
FY17
FY18
FY19
FY20
FY21
Operational measures
Underlying EPS (cents)2
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 ($m)3
Distribution break-even (USD/barrel)4
sNPS5
TRIFR6
Female representation in senior roles (%F)7
CEO-1
CEO-2
Senior leadership roles
Origin Engagement Score8
STI award outcomes
Percentage of maximum (%)9
Return measures
Closing share price at end of June ($)10
Dividends (cents per share)11
Annual TSR (%)
Three-year rolling TSR (CAGR % p.a.)12
Group Statutory EBIT ($m)5
Underlying ROCE13 (%)
LTI outcomes
LTI vesting percentage (%)14
22.8
1,378
1,492
1,104
8,111
-
(16)
3.2
11.1
26.2
34.0
58
47.7
2,645
1,811
1,521
6,496
39
(13)
2.2
20.0
33.8
34.2
61
58.4
1,914
1,574
1,892
5,417
36
(6)
4.5
25.0
40.6
34.4
61
58.1
1,813
1,459
1,741
5,158
29
2
2.6
33.3
43.9
33.9
75
18.1
1,183
991
1,135
4,639
22
6
2.7
33.3
42.9
34.6
74
63.3
88.7
73.7
84.1
50.7
6.86
0
19.3
(14.2)
(1,746)
4.9
10.03
0
46.2
(2.6)
473
7.7
7.31
25
(26.1)
12
1,432
9.1
5.84
25
(17.7)
(8)
305
8.8
4.51
20
(19.7)
(20.6)
(1,713)
4.5
0
0
0
0
35.3
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 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 On a continuing activities basis (excludes Lattice Energy for FY2017 and FY2018).
3 Adjusted Net Debt for FY2020 includes first recognition of lease liability ($514 million) under AASB16.
4 Distribution break-even reported since FY2018 following commissioning of APLNG Train 2.
5 sNPS is measured at the business level and is an industry-recognised measure of customer advocacy.
6 TRIFR is the total number of injuries resulting in lost time, restricted work duties or medical treatment per million hours worked.
7 CEO-1 represents Executives reporting directly to the CEO. It has been restated to include the CEO, in line with market practice and consistent with Chief Executive Women
guidance and 40:40 Vision definitions, and to align with reporting lines as at 30 June in each year. CEO-2 includes roles directly reporting to CEO-1. Senior leadership roles
captures the three reporting levels below CEO and includes roles with base salaries exceeding approximately $200,000 per annum.
8 Employee engagement is measured as a score through an annual Company-wide survey conducted independently.
9 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. The FY2021 figure excludes M Schubert, whose STI award was forfeited. If M Schubert's forfeited STI is included, the figure would reduce to 42.4%.
10 The opening share price on 1 July 2017 was $5.75.
11 Dividends represent the interim plus final dividends determined for each financial year. For FY2021, this includes the final dividend determined on 19 August 2021 to be paid
on 1 October 2021. The amounts paid within each financial year are 0c, 0c, 10c, 30c and 22.5c, respectively.
12 TSR calculations use the three-month VWAP share price to 30 June, reflecting the testing methodology for relative TSR ranking.
13 Underlying ROCE is defined in the Glossary and Interpretation.
14 LTI awards granted in FY2017 were allocated 50% to a ROCE target, which vested at a level of 70.6% on 24 August 2020, and the other 50% to a RTSR target, which failed
to reach its vesting threshold at test on 30 June 2021 and was subsequently wholly forfeited.
Remuneration Report
63
4.2 Process for assessment of variable remuneration outcomes
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.
Specific examples in relation to the implementation of these principles in FY2021 were a reduction in the target for NCOIA to adjust for the
additional investment in Octopus Energy announced in December 2020, offset by an increase to the target to account for deferred capex in
Growth Assets and APLNG. The additional investment in Octopus arose after targets were set. The Board’s approach was that the investment
was a beneficial decision for shareholders and not one for which management be penalised, accordingly the target was reduced. In the case
of the capex underspend compared to plans in place when the target was set, the approach taken was that management should not benefit
from such reduced scope or deferral, accordingly the amount of the underspend was added to the target. The Board analysed outcomes with
and without any adjustments, finding that net movements were minor and that no unwarranted benefit or significant disadvantage arose from
the process.
The EPS and Energy Markets EBITDA scorecard measures are presented in the financial accounts in terms of underlying, which is also the
starting point for consideration in setting of targets for STI purposes. Further adjustment may be made according to the governing principles.
In FY2021 there was no material difference from the underlying view.
4.2.1 STI outcomes
For FY2021, the Board considered the effect and implications on the STI scorecard (Section 4.3) of the following positive and negative
factors including:
•
•
•
•
targets being set at the start of the year based on commodity price outlooks at that time;
the impact of increased network and metering costs that cannot be recovered in regulated tariffs;
the cumulative impact of regulatory actions by federal and state governments that limit the capacity for EBITDA growth in the Energy
Markets business;
the COVID-19 pandemic’s impact on domestic and global demand; and
• management’s business execution and responses to challenges.
Having regard for all these factors, advice from each of the Board committees and in consideration of shareholder experience and
expectations, the Board determined that management has responded well to changing priorities and market conditions in an extraordinarily
challenging and dynamic environment. Against this background, and with particular regard for the financial results, the CEO and the Board
agreed to make a 25 per cent reduction to the formulaic outcome of the CEO scorecard which is provided in Section 4.3. Outcomes for all
Executive KMP are provided in Section 4.3.1.
4.2.2 LTI outcomes
A partial vesting (35.3 per cent) of LTI awards granted in FY2017 occurred during the year. This was the first vesting of any LTI in nine years
and resulted from above-target performance on a ROCE performance measure, which comprised half of the award.
The target for this ROCE measure was set at grant in the form of two gates, both of which need to be achieved for vesting to occur. The starting
point for ROCE calculations for these gates is statutory EBIT divided by average capital employed (underlying ROCE data is presented in the
Operating and Financial Review).
The first gate required that the average ROCE across the four financial years (FY2017-FY2020) equalled or exceeded the average of the four
annual plan targets (which was 7.7 per cent p.a.) for any vesting to occur. The second gate required that the ROCE equalled or exceeded
9.5 per cent p.a.1 (for 50 per cent vesting) or 11.5 per cent p.a. (for full vesting) in either the third or fourth financial year, with pro-rata
vesting between those levels. An average ROCE of 8.4 per cent p.a was achieved with 10.32 per cent recorded in FY2019, resulting in a
calculated 70.6 per cent vesting for this half of the award. The Board found no reason to vary the calculation outcome. Accordingly, the
vest was confirmed at the calculated level. The other half of the award was subject to a 4-year RTSR hurdle against a 'ten-up/ten-down' peer
group.2At the test date of 30 June 2021, this tranche failed to achieve a ranking above that of the 50th percentile in the peer group (the vesting
threshold), and it was subsequently lapsed.
1 9.5% was referable to pre-tax WACC and set at the time of grant. Exceeding this by 2 percentage points set the stretch or full vesting point.
2 The TSR peer group constituents were disclosed in the 2017 Remuneration Report.
64
Annual Report 2021
4.3 STI awards and scorecard details for FY2021
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 FY2021 scorecard was weighted 60 per cent to financial measures and 40 per cent to non-financial metrics
(customer, strategic, climate change, safety and people). The details and results are set out below.
CEO FY2021 STI scorecard
Measure, rationale and performance
Origin EPS (underlying) (cps)1
Measure of Origin’s earnings and profitability
Origin NCOIA ($m)
Measure of effective cash flow generation
Energy Markets EBITDA ($m)
Measure of operating performance of the Energy Markets business
Integrated Gas free cash flow ($m)
Effective cash flow generation, measured as Integrated Gas EBITDA less
capex, including share of APLNG capex (excluding impact of oil price, foreign
exchange or royalty changes)
Integrated Gas value ($m)
Uplift in net present value of APLNG (100% basis) over the life of the field
relative to prior internal forecast (at constant oil price, foreign exchange and
discount rates)
Financial measures
Voice of the customer
Strategic, interaction and episodic net promoter scores measuring customer
advocacy, recent and critical experiences
Customer innovation
Composite measure of the readiness of new customer solutions
Climate change (emissions reduction, %)
Scope 1 equity emissions reduction (CO2-e) – short term target to reduce
emissions, compared to FY2017 baseline
People measures
Employee engagement score (74%) measuring connection of the workforce
to the business; female representation in senior roles and pipeline cohorts
to senior roles (33.2%) measuring gender diversity; and Health, Safety and
Environment measures (69.9% of maximum) measuring preventative actions,
and improvements in composite measures
Non-financial measures
Total unadjusted
Total (adjusted)
(discretionary adjustment 25% down)
Targets and outcomes
Result
Weight
Threshold
Target
Stretch
(% max)
15%
10%
15%
10%
10%
60%
10%
5%
10%
15%
40%
100%
100%
11.8
19.3
26.8
18.1
975
1,230
1,485
1,183
1,050
1,230
1,410
991
735
790
845
882
200
500
1,000
1,294
20
60
100
55.6
20
60
100
76.0
20
60
100
4
6
86.6
10
11.2
20
60
100
45.9
20
60
100
20
72.1
60
62.2
100
20
60
100
46.6
53.6
52.6
0.0
100.0
100.0
55.6
76.0
86.6
100.0
45.9
72.1
62.2
46.6
1 The FY2021 underlying EPS target of 19.3 cents per share was lower than the prior year actual (58.1), consistent with August 2020 market guidance.
Remuneration Report
65
4.3.1 Executive KMP STI outcomes
The application of the discretionary downward adjustment identified in Section 4.2.1 to the CEO’s scorecard balanced the high operational
and customer achievements with the financial results impacted by the range of headwinds. It resulted in an STI outcome for CEO of
46.6 per cent of maximum (77.8 per cent of target).
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. Other Executive KMP scorecard outcomes were all below target and ranged between 44.3 to 57.8 per cent
of maximum (74.0 to 96.5 per cent of target). M Schubert’s outcome was zero as his STI award was forfeited on resignation. In the context
of the team’s operational execution and response to the challenging headwinds the Board concluded that the below-target outcomes were
appropriate and made no further discretionary adjustments. The aggregate outcome for all Executive KMP was 50.7 per cent of maximum
(84.5 per cent of target), ignoring the zero STI award for M Schubert.
Executive KMP
% of target
% of maximum
% forfeited
STI award
F Calabria
L Tremaine
J Briskin
G Jarvis
M Schubert
77.8
96.0
96.5
74.0
0.0
46.6
57.5
57.8
44.3
0
53.4
42.5
42.2
55.7
100
$’000
1,425
976
868
681
0
4.4 Total pay received in FY2021
In line with general market practice, a non-AASB presentation of actual pay received in FY2021 is provided below, as a summary of real or ‘take
home’ pay. AASB statutory remuneration is presented in Table 7-1.
($'000)
Executive KMP
F Calabria
L Tremaine
J Briskin
G Jarvis
M Schubert
FR1
1,831
1,017
900
920
920
STI cash2
Short term
equity3
Long term
equity4
Actual total
pay received
712
488
434
341
0
961
407
188
322
190
264
522
52
82
80
3,768
2,434
1,574
1,665
1,190
1 FR is cash and superannuation received during FY2021.
2 STI cash represents 50 per cent of the FY2021 STI award, with the balance deferred into equity.
3 Short-term equity represents the value of previously awarded equity from short-term arrangements (including STIP and grants under the Employee Share Plan) that are vested
or released (as relevant) during FY2021. The value is determined as the number of shares vested or released multiplied by the five-day VWAP immediately prior to the date of
vest/release. This value is usually the same as the equity’s taxable value to the executive. The amounts shown above relate to DSR vests and Restricted Share releases all on
24 August 2020 arising from Deferred STI arrangements, plus GESP shares released on 28 August 2020 and Matching Share Plan allocations released on 30 October 2020.
4 Long-term equity represents the value of previously awarded equity from long-term arrangements (LTIP and other arrangements with deferral periods of three or more years)
that are vested or released (as relevant) during FY2021. The value is determined in the same way as described in note 3. The amounts shown all relate to vesting and releases
on 24 October 2020 (being four-year ROCE LTI awards, and, for L Tremaine, 2017 sign-on awards).
66
Annual Report 2021
5 Governance
5.1 The 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 four times during the reporting period.
Including its Chairman, the RPC has five 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.
BoardThe Board approves:• Executive remuneration policy• remuneration for the CEO and ELT• STI and LTI targets and hurdles• NED fees• CEO and ELT succession and appointmentsRemuneration and People CommitteeThe 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 implementationInformation 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 shareholdersRegular dialogue with shareholders and proxy advisors.Independent remuneration advisorsThe RPC appoints an external independent advisor to assist it with market and governance issues, benchmarking, best practice observations and general advice.ManagementManagement 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. Remuneration Report
67
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 FY2021. Guerdon Associates was appointed for this period; however, it 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
Each year the full Board formally reviews the conduct, behaviour and risk management of the CEO and each member of the Executive
Leadership Team, taking feedback from the Chairs of the Health, Safety & Environment Committee, Audit Committee, and the Risk
Committee; from the internal auditor; and from the General Counsel and Executive General Manager Company Secretariat, Risk and
Governance; and the Executive General Manager, People & Culture. The review considers conduct, behaviour, risk and reputation matters as
well as operational performance and contribution.
This process is in addition to the behavioural assessment process which forms part of the company-wide performance management
framework (see Section 2.2). The Board is guided by a set of overarching principles to apply in assessing items or events that impact
risk (including non-financial risk) or performance. This ensures a consistent approach to determining whether discretionary adjustments to
incentive outcomes are warranted (positive or negative modification) to achieve fairness for Executives and shareholders.
In addition to this process for moderation of award outcomes 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.
Malus has been applied over time, both to STI formulaic outcomes and to LTI allocations, to provide better alignment of variable pay outcomes
with the broader context and overall circumstances of the Company.
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 would 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.
68
Annual Report 2021
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 $3.2 million p.a., as approved by shareholders in 2017.
The Origin Chairman receives a single fee that includes committee activities, while other NEDs receive a NED Base Fee and separate fees
for their role on specific committees (other than the Nomination Committee, which is considered within the NED Base Fee). All fees include
superannuation contributions.
The table below summarises the structure and level of NED fees. No change to the fee structure or quantum is proposed for FY2022.
Office
Board – Chairman (inclusive of committee fees)
NED Base Fee (exclusive of committee fees)
Audit – Chairman
Audit – Member
RPC – Chairman
RPC – Member
HSE – Chairman
HSE – Member
Risk – Chairman
Risk – Member
Nomination – Chairman
Nomination – Member
FY2021 and FY2022
($'000)
677
196
57
29
47
23.5
47
23.5
47
23.5
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 of shares determined by reference to the level and any movements in the NED
Base Fee and/or the share price.1 The numeric shareholding levels are currently set at 28,000 shares (56,000 for the Chairman) and will be
redetermined during FY2022.
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 in 2018. 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.
1 Generally considering the weighted average share price over the prior year
Remuneration Report
69
7 Statutory tables and disclosures
Table 7-1 (a) Executive KMP statutory remuneration ($’000)
Short term
Long term
FR1
PEB1
Base
salary7
Super-
annuation
Other2
Cash
STI3
Leave
accrual4
Share based
STI and Other5
RS
DSR
Matching
share
rights
Totals
LTI6
Total
accounting
remuneration
At
risk
(%)
Share-
based
(%)
Executive Director
F Calabria
2021
2020
1,786
1,768
Other Executive KMP
J Briskin
G Jarvis
2021
2020
2021
2020
M Schubert8
2021
2020
2021
2020
L Tremaine
Executive total
873
806
877
820
898
843
990
991
22
21
22
21
22
21
22
21
22
21
46
41
19
15
37
34
84
178
34
26
712
1,277
434
495
341
666
0
522
488
711
2021
5,424
2020
5,228
110
105
220
294
1,975
3,671
122
(65)
15
25
65
72
40
44
(16)
61
226
137
— 1,015
76
1,385
— 1,053
180
812
2
0.6
2
1.7
484
438
712
481
— (471)
—
2
1.7
465
625
649
0
9
0
10
0
7
5
209
296
171
332
199
(369)
193
440
242
5,164
5,087
2,145
1,980
2,388
2,305
204
2,273
2,590
2,912
6 2,365
81 2,084
4 3,086
415
1,617
12,491
14,557
62
65
57
56
58
59
0
52
60
62
52
60
48
40
36
31
44
30
0
29
41
38
36
35
1 FR comprises base remuneration and superannuation (post-employment benefit, PEB).
2 Represents non-monetary benefits including insurance premiums and fringe benefits (such as car parking and expenses associated with travel).
3 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.
4 Movement in leave provision over the reporting period. Negative movement indicates that leave taken during the year exceeded leave accrued during the current year.
5 Includes Deferred STI and other equity arrangements subject to continuous employment. 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 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.
6 LTI includes all long-term equity awards (those not pursuant to 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.
7 The increase in base salary for J Briskin, G Jarvis and M Schubert reflects a mid-year change during FY2020. No increase applied for FY2021.
8 ‘Other’ includes accommodation benefits associated with travel from home base to the Brisbane office.
70
Annual Report 2021
Table 7-1 (b) NEDs statutory remuneration ($’000)
NEDs - current
J Akehurst
I Atlas2
M Brenner
G Lalicker
M McCormack2
B Morgan
S Perkins
S Sargent
J Withers2
NEDs - former
G Cairns2
T Engelhard2
NED total
Short term
Board and
Committee
Fees
Other1
Post-
employment
Super-
annuation
contributions
Total
remuneration
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
244
245
59
—
267
251
191
175
112
—
278
279
529
274
268
244
151
—
217
666
84
239
2,400
2,373
1
0.2
0
—
0
0.2
0
0.2
0
—
1
0.2
2
18
1
0.2
0
—
0
18
1
16
6
53
22
21
6
—
20
21
20
21
11
—
22
21
22
21
22
21
16
—
10
11
7
21
178
158
267
266
65
—
287
272
211
196
123
—
301
300
553
313
291
265
167
—
227
695
92
276
2,584
2,583
1 Represents non-monetary benefits including insurance premiums and fringe benefits (such as car parking and expenses associated with travel).
2 G Cairns and T Engelhard retired on 20 October 2020; J Withers, M McCormack, I Atlas appointed 21 October 2020, 18 December 2020 and 21 February 2021 respectively.
Remuneration Report
71
Abbreviations in tables 7-2 through 7-4
Rights
• DSR – Deferred Share Rights
• PSR – Performance Share Rights
• RSR – Restricted Share Rights
• MR – Matching Rights (under share purchase and matching rights provisions of the Matching Share Plan, see Section 3.8)
Shares
• Shares (R) – Restricted Shares (those with a specific time holding lock, in addition to any MSR requirements)
• Shares (UR) – Unrestricted Shares (but may be subject to restriction by the operation of MSR requirements)
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. None of the instruments have an
exercise price, and there is nil cost to recipients.
The expiry date, if applicable, is the vest date. To the extent that rights fail to meet the relevant performance conditions, they will lapse effective
on the test date, which may be on or before the vest date.
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
Type
PSR
RSR
183,416
183,414
Shares(R)
213,220
PSR
RSR
MR
60,104
60,102
518
Shares(R)
123,900
PSR
RSR
MR
Shares(R)
PSR
RSR
61,438
61,440
518
111,258
61,438
61,440
Shares(R)
130,616
PSR
RSR
MR
67,916
67,917
518
Shares(R)
118,650
1.37
4.28
5.58
1.37
4.28
0.47
5.58
1.37
4.28
0.47
5.58
1.37
4.28
5.58
1.37
4.28
0.47
5.58
—
—
—
—
—
3-Nov-20
21-Aug-23
21-Aug-23
3-Nov-20 2023-2025
2023-2025
2-Sep-20
22-Aug-22
—
3-Nov-20
21-Aug-23
21-Aug-23
3-Nov-20 2023-2025
2023-2025
— 25-Sep-20
31-Oct-22
2-Sep-20
22-Aug-22
—
—
—
—
3-Nov-20
21-Aug-23
21-Aug-23
3-Nov-20 2023-2025
2023-2025
— 25-Sep-20
31-Oct-22
2-Sep-20
22-Aug-22
—
—
3-Nov-20
21-Aug-23
21-Aug-23
3-Nov-20 2023-2025
2023-2025
2-Sep-20
22-Aug-22
—
3-Nov-20
21-Aug-23
21-Aug-23
3-Nov-20 2023-2025
2023-2025
— 25-Sep-20
31-Oct-22
—
2-Sep-20
22-Aug-22
—
—
—
—
—
—
—
—
1 For MRs, the fair value is per $1 contributed by the Executive.
2 For PSRs, the expiry date is the same as the vesting date. For RSs, the vest date refers to the date when the trading restriction is lifted.
3 Rights may expire earlier than the nominal expiry date. To the extent that they fail to meet the relevant performance conditions, they will lapse effective on the test date.
72
Annual Report 2021
Table 7-3 (a) Details of, and movements in, equity rights and ordinary shares of the Company - Executive KMP
The following table summarises holdings and movements of rights and ordinary shares held (directly, indirectly or beneficially, including by
related parties) over the reporting period (or KMP portion of the period), including grants, transactions and forfeits, by value and by number.
See Table 7-4 for further details of the terms and conditions of those rights.
Type
Held at start1
Number,
Value ($)
No. vested
Number
Value ($)8
disposed4,5 Held at end,6,7
Granted/Acquired2,3
Exercised/Released
Forfeited/
Executive Director
F Calabria
Options
PSR
RSR
DSR
Shares (R)
Shares(UR)
Other Executive KMP
J Briskin
Options
PSR
RSR
MR
Shares (R)
Shares(UR)
G Jarvis
Options
PSR
RSR
MR
Shares (R)
Shares(UR)
M Schubert
Options
PSR
RSR
Shares (R)
Shares(UR)
L Tremaine
Options
PSR
RSR
DSR
MR
632,995
958,872
0
110,779
0
183,416
183,414
0
249,926
213,220
1,189,768
187,340
219,223
0
251,280
785,012
0
0
82,342
257,237
2,256
0
0
620,820
0
0
262,963
0
0
93,045
290,685
2256
86,910
250,886
0
190
80,124
64,574
164,927
250,848
0
509
199,745
65,684
154,160
247,480
0
0
60,104
60,102
518
43,838
0
61,438
61,440
111,258
78,933
0
61,438
61,440
123,900
691,362
262,963
518
2,256
85,992
130,616
728,837
51,414
81,441
314,546
0
76,202
509
48,274
0
67,916
67,917
0
518
0
0
0
0
632,995
47,316
47,316
264,496
19,703
1,075,269
0
0
0
0
65,223
65,223
364,597
0
0
0
106,684
596,364
0
0
0
0
0
0
0
0
0
183,414
45,556
356,462
406,563
86,910
9,368
9,368
52,367
26,289
275,333
0
0
0
0
0
0
0
0
0
33,435
186,902
0
0
0
0
0
0
0
0
0
0
319
0
0
0
0
319
0
1,434
57,249
320,022
0
0
0
0
0
0
0
121,000
154,160
0
0
0
0
0
0
33,717
188,478
0
0
0
0
61,440
182,891
60,000
0
60,102
708
170,589
108,412
164,927
291,545
61,440
708
253,754
23,617
0
0
0
0
39,688
81,441
17,237
17,237
96,355
7,178
358,047
0
0
0
—
76,202
76,202
425,969
319
0
0
319
1,434
72,500
405,275
0
0
0
0
0
0
0
67,917
0
708
213,740
378,107
84,170
14,375
14,375
80,356
294,543
84,170
14,644
14,644
81,860
6,097
Shares (R)
Shares(UR)
167,590
118,650
662,067
210,814
167,293
0
1 The number of instruments that held at the start/end of the reporting period.
2 Rights to equity and RSs 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 Shares(UR) include purchases and transfers in, and shares received upon the vesting and exercise of PSRs and DSRs. For Other Executive KMP includes allotments of fully
paid ordinary shares granted or acquired under the Employee Share Plan (number of shares acquired: G Jarvis 1.035; J Briskin 1,035; L Tremaine: 1,035). Executive Directors
do not participate in the GESP or the MSP.
4 Forfeited Options and PSRs were granted in October 2015.
5 Sales and transfers out.
6 Options granted in 2016 and 2017, and PSRs granted in 2017 and 2018 failed to meet their test on 30 June 2021 and were subsequently lapsed, following wich the remainig
number of instruments held is as follows: Options (F Calabria:401,288; G Jarvis: 93,219), PSRs (F Calabria:792,280; J Briskin: 216,861; G Jarvis:228,829; L Tremain: 296,822).
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 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).
Remuneration Report
73
Table 7-3 (b) Details of, and movements in, equity rights and ordinary shares of the Company - NEDs
Type
Held at start1
Acquired2
Disposed3
Held at end1,4
NEDs - current5
J Akehurst
I Atlas
M Brenner
G Lalicker
M McCormack
B Morgan
S Perkins
S Sargent
J Withers
NEDs - former
G Cairns
T Engelhard6
Shares(UR)
Shares(UR)
Shares(UR)
Shares(UR)
Shares(UR)
Shares(UR)
Shares(UR)
Shares(UR)
Shares(UR)
Shares(UR)
Shares(UR)
71,200
0
28,367
100,000
0
50,000
0
0
0
100,000
47,143
30,000
31,429
0
163,660
34,421
0
26,000
10,000
0
0
0
0
0
0
0
0
0
0
0
0
0
34,421
71,200
50,000
28,367
100,000
100,000
47,143
56,000
41,429
0
163,660
0
1 The number of instruments that held at the start/end of the reporting period.
2 Purchases and transfers in.
3 Sales and transfers out.
4 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.
5 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.
6 The disposal of shares occurred post retirement.
74
Annual Report 2021
Table 7-4 Summary of share rights outstanding
The table below lists all the share rights outstanding at 30 June 2021 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 test dates on or before 30 June 2021 lapsed effective on that test date.
Granted
Legacy Options
30-Aug-16
19-Oct-16
30-Aug-17
30-Aug-17
18-Oct-17
PSRs
30-Aug-17
18-Oct-17
10-Sep-18
17-Oct-18
30-Aug-19
16-Oct-19
3-Nov-20
RSRs
3-Nov-20
3-Nov-20
3-Nov-20
DSRs
18-Oct-17
MRs
27-Sep-19
25-Sep-20
Number
Outstanding1
Number
outstanding
held by KMP
Exercise
price, $
Earliest
vest date2
Last possible
expiry date3,4
23-Aug-21
23-Aug-21
23-Aug-21
23-Aug-27
23-Aug-27
1,350,898
450,000
81,441
821,594
401,288
801,123
126,866
1,279,914
312,245
1,714,271
452,742
983,143
331,723
331,723
331,723
303,415
0
81,441
180,129
401,288
56,948
126,866
250,929
312,245
427,590
452,742
372,874
124,291
124,291
124,291
45,556
45,556
206,685
169,210
1,293
831
5.67
5.21
7.37
7.37
7.37
—
—
—
—
—
—
—
—
—
—
—
—
—
23-Aug-21
23-Aug-21
23-Aug-21
22-Aug-22
22-Aug-22
23-Aug-21
23-Aug-21
23-Aug-21
23-Aug-21
22-Aug-22
22-Aug-22
21-Aug-23
21-Aug-23
26-Aug-24
25-Aug-25
23-Aug-21
31-Oct-21
31-Oct-22
1 Options and PSRs with the Earliest Vest Date of 23 Aug 2021 were tested on 30 June 2021. As they did not satisfy the vesting conditions they will lapse on 23 August 2021
in accordance with the Plan Rules: Options granted in 2016 and 2017, PSRs granted in 2017 and 2018 (TSR hurdle only, the remaining total balance of 2018 PSRs: 804,942;
held by KMP:281,586).
2 The vest date for PSRs and RSRs granted since 2018 does not include the trading restriction of approximately one to two years that applies to the shares allocated on vesting.
3 Where no expiry is given, automatic exercise applies at vesting. To the extent that rights fail to meet the relevant performance conditions, they will lapse effective on the test
date, which may be on or before the vest date.
4 Options with the Expiry Date of 23 Aug 2021 failed their test on 30 June 2021 and as such will lapse on 23 August 2021, in accordance with the Plan Rules.
Remuneration Report
75
Table 7-5 Executive service agreements
The main terms of executive service agreements at 30 June 2021 are set out in the table below.
Item
Basis of contract
Notice period
Termination
benefits for cause
Termination benefits
for resignation
Termination benefits for
other than resignation
or cause
CEO
Ongoing
Other Executive KMP
Ongoing
• Twelve months by either party
• Six months by either party
• Shorter notice may apply by agreement
• Shorter notice may apply by agreement
• No notice in defined circumstances1
• No notice in defined circumstances
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; statutory entitlements
Notice as above or payment in lieu of notice that is not
worked; current-year STI forfeited; unvested equity lapses;
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; 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; 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.
Scott Perkins
Chairman
Sydney, 19 August 2021
76
Annual Report 2021
Lead Auditor’s
Independence Declaration
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 2021, I declare to the best of my knowledge and belief, there have been: a) no contraventions of the auditor independence requirements of the Corporations Act 2001 in relation to the audit; 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 19 August 2021 78
Financial
Statements
30 June 2021
Annual Report 2021
G Other information
G1 Contingent liabilities
G2 Commitments
G3 Share-based payments
G4 Related party disclosures
G5 Key management personnel
G6 Notes to the statement of cash flows
G7 Auditors' remuneration
G8 Master netting or similar agreements
G9 Deed of Cross Guarantee
G10 Parent entity disclosures
G11 Subsequent events
Directors’ Declaration
Independent
Auditor’s Report
Primary statements
Income statement
C Operating assets
and liabilities
Statement of comprehensive income
C1
Trade and other receivables
Statement of financial position
Statement of changes in equity
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
C2 Exploration and evaluation assets
C3 Property, plant and equipment
C4 Intangible assets
C5 Trade and other payables
C6 Provisions
C7 Other financial assets and liabilities
C8 Impairment of non-current assets
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
B Investment in
E Taxation
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
E1
Income tax expense
E2 Deferred tax
F Group structure
F1 Controlled entities
F2 Business combinations
F3
Joint arrangements and investments
in associates
Financial Statements
for the year ended 30 June
Revenue
Other income
Expenses1
Results of equity accounted investees1
Interest income
Interest expense
(Loss)/profit before income tax
Income tax expense
(Loss)/profit for the year
(Loss)/profit for the year attributable to:
Members of the parent entity
Non-controlling interests
(Loss)/profit for the year
Earnings per share
Basic earnings per share
Diluted earnings per share
79
2020
$m
13,157
54
(13,418)
512
190
(316)
179
(93)
86
83
3
86
Note
A2
A3
A4
A5
A3
A4
E1
2021
$m
12,097
43
(14,048)
195
109
(242)
(1,846)
(443)
(2,289)
(2,291)
2
(2,289)
A6
A6
(130.2) cents
(130.2) cents
4.7 cents
4.7 cents
1 Refer to the Overview for details of prior year reclassification.
The income statement should be read in conjunction with the notes to the financial statements.
80
Annual Report 2021
Statement of comprehensive income
for the year ended 30 June
(Loss)/profit for the year
Other comprehensive income
Items that will not be reclassified to profit or loss, net of tax
Actuarial gain on defined benefit superannuation plan
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
Note
E1
E1
2021
$m
(2,289)
3
(6)
(639)
91
356
(195)
(2,484)
(2,485)
1
(2,484)
2020
$m
86
-
3
125
4
(493)
(361)
(275)
(279)
4
(275)
The statement of comprehensive income should be read in conjunction with the notes to the financial statements.
Financial Statements
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
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
Employee benefits
Provisions
Total current liabilities
Non-current liabilities
Trade and other payables
Interest-bearing liabilities
Derivatives
Other financial liabilities
Deferred tax 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
81
2020
$m
1,240
1,959
164
630
479
89
105
2021
$m
472
2,298
113
769
503
7
121
4,283
4,666
14
366
1,465
6,952
3,291
245
4,374
-
47
16,754
21,037
2,407
169
2,004
741
344
231
43
5,939
-
3,224
506
15
283
36
1,219
5,283
11,222
9,815
7,138
525
2,132
9,795
20
9,815
18
528
2,225
7,360
4,331
190
5,420
315
40
20,427
25,093
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
Note
C1
D4
C7
C1
D4
C7
A5
C3
C2
C4
E2
C5
D2
D4
C7
C6
C5
D2
D4
C7
E2
C6
D3
The statement of financial position should be read in conjunction with the notes to the financial statements.
82
Statement of changes in equity
for the year ended 30 June
Annual Report 2021
$m
Contributed
equity
Share-based
payments
reserve
Foreign
currency
translation
reserve
Fair
value
reserve
Retained
earnings
Non-
controlling
interests
(638)
447
(1)
(195)
(638)
447
(3)
(2,291)
1
(2,484)
Balance as at 1 July 2020
7,145
223
(Loss)/profit for the year
Translation of
foreign operations
Cash flow hedges
Investment
valuation changes
Actuarial gain on defined
benefit superannuation plan
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
-
-
-
-
-
-
-
-
(7)
-
(7)
Balance as at 30 June 2021
7,138
Balance as at 30 June 2019
Adoption of AASB 16 Leases
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
7,125
-
7,125
-
-
-
-
-
-
-
20
-
20
-
-
-
-
-
-
-
-
-
3
3
226
234
-
234
-
-
-
-
-
-
-
-
(11)
(11)
Hedge
reserve
(375)
-
-
447
-
-
860
-
(638)
-
-
-
-
-
-
-
222
736
-
736
-
124
-
-
-
-
-
-
72
114
-
114
-
-
(489)
-
124
(489)
124
(489)
-
-
-
-
-
-
-
-
Total
equity
12,701
(2,289)
(639)
447
(6)
3
21
2
(1)
-
-
-
8
-
-
-
(6)
3
(3)
4,819
(2,291)
-
-
-
-
-
-
-
-
-
5
5
-
5
-
-
-
3
3
3
-
-
-
-
8
(396)
(2)
(398)
-
-
-
-
(7)
3
(396)
(2)
(402)
2,132
4,915
349
5,264
83
-
-
-
-
83
(528)
-
-
(528)
4,819
20
20
-
20
3
1
-
-
1
4
(3)
-
-
(3)
21
9,815
13,149
349
13,498
86
125
(489)
3
(361)
(275)
(531)
20
(11)
(522)
12,701
Balance as at 30 June 2020
7,145
223
860
(375)
The statement of changes in equity should be read in conjunction with the notes to the financial statements.
Financial Statements
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 received/(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
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 paid1
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 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
1
Includes $17 million (2020: $16 million) of interest payments on leases.
The statement of cash flows should be read in conjunction with the notes to the financial statements.
83
Note
2021
$m
2020
$m
G6
12,954
(12,021)
933
31
964
(124)
(47)
(168)
-
(161)
3
7
110
599
219
-
(1,042)
(90)
(65)
(234)
(76)
(341)
(2)
(3)
(96)
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)
(1,949)
(2,118)
(766)
1,240
(2)
472
(305)
1,546
(1)
1,240
84
Annual Report 2021
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 19 August 2021, the Directors resolved
to authorise the issue of these consolidated
general purpose financial statements for the
year ended 30 June 2021.
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 (IFRS) as
issued by the International Accounting
Standards Board;
• on a historical cost basis, except for
derivatives and other financial assets
and liabilities that are measured at fair
value; and
• on a going concern basis. As at 30 June
2021, the consolidated statement of
financial position shows a net current
liability position of $1,656 million. The
deficit is primarily caused by the
classification of capital markets debt
maturing in the next 12 months as
current liabilities. Notwithstanding the
net current liability position, the Group
has reasonable grounds to believe it
will be able to pay its debts as and
when they become due, based on the
continued strong cash flows of the
Group’s existing operations, the Group's
overall net asset position, and the
Group’s strong financial profile, which
includes significant committed undrawn
bank debt facilities and cash totalling
$3,279 million.
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.
Change to accounting policy not
yet adopted - IFRIC agenda
decision - Configuration or
Customisation Costs in a Cloud
Computing Arrangement
In April 2021, the IFRS Interpretations
Committee (IFRIC) published a decision
relating to configuration and customisation
costs incurred in implementing Software
as a Service arrangements. The Group/
Company is assessing the impact of the
IFRIC decision on its accounting policy,
which may result in previously capitalised
costs being recognised as an expense.
The process to quantify the impact of
the decision is ongoing, due to the
effort required in obtaining the underlying
information from historical records covering
multiple projects, and assessing the nature
of each of the costs. At the date of this
report, the impact of the IFRIC agenda
decision on the Group/Company is not
reasonably estimable.
items in the financial statements, including
revenue and receivables, equity accounted
investments, 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, 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
• B2.2 – Summary APLNG statement of
financial position
• C1 – Trade and other receivables
• C3 – Property, plant and equipment
• C4 – Intangible assets
Use of judgements and estimates
• C6 – Provisions
• C8 – Impairment of non-current assets
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.
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 have had wider
impacts on consumers, businesses and
the overall economy. The Group entered
the 2021 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.
The economic impacts of the changes
in the Group's operating environment
due to commodity price and COVID-19
impacts have implications for various line
Financial Statements
85
Overview (continued)
Key judgements and estimates – Renewable Power Purchase Agreements (PPAs)
Management judgement has been applied on the adoption of AASB 16 Leases to a number of the Group's renewable PPAs. In June 2021,
IFRIC published a tentative agenda decision addressing whether an agreement for the use of a windfarm provides the right to obtain
substantially all the economic benefits to qualify as a lease. At the date of this report, this guidance is still a tentative decision and is open
for comment. Once IFRIC has published a final decision, the Group will ensure the updated guidance is reflected in its accounting policy
and financial statements.
If the PPAs had not been considered to meet the definition of a lease, net electricity derivative liabilities of $898 million would have been
recognised in the statement of financial position at 30 June 2021. A $449 million loss would have been treated as an item excluded from
underlying profit, consistent with other fair value movements.
During the year, the Group recognised an impairment of goodwill allocated to the Energy Markets Retail CGU amounting to $830 million
and the cash flows associated with the renewable PPAs are included in the calculation of the recoverable amount for the Retail CGU. Should
IFRIC conclude that the PPAs are required to be classified as derivatives, this change in the Group’s accounting policy will result in an
income statement reclassification between impairment expense and the fair value loss related to the PPAs, representing the mark to market
loss on the PPAs currently included in the $830m impairment. This reclassification forms part of the $449 million fair value loss noted above
but will vary in quantum due to the different discount rates used in the derivative fair value and recoverable amount calculations.
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. Accordingly, such leases have nil lease liability balances and thus nil right-of-use asset balances. All payments made under
these leases are recognised within operating expenses as incurred.
Reclassifications
At the date of signing the 30 June 2020 Group consolidated financial statements, the APLNG financial statements had not yet been finalised.
The Group recorded an impairment of $746 million in relation to its equity accounted investment in APLNG, based on the Group’s carrying
value of its investment and its assessment of the recoverable amount. This was recorded as an impairment charge in the Group’s income
statement. Subsequently, the APLNG 30 June 2020 financial statements were finalised, including a US$251 million (A$366 million) (100 per
cent APLNG) impairment charge within the joint venture. Accordingly, the Group’s 30 June 2020 comparatives have been updated for this
timing difference to reclassify $96 million (37.5 per cent of $366 million net of tax) of the impairment charge to loss from equity accounted
investments. The total net impairment charge recorded by the Group has not changed.
The following disclosures have been amended to reflect the reclassification described above.
- Income Statement
Revenue
Other income
Expenses
Results of equity accounted investees
Interest income
Interest expense
Profit before income tax
Income tax expense
Profit for the year
Reclass–
ification
96
(96)
2020
$m
13,157
54
(13,514)
608
190
(316)
179
(93)
86
Restated
2020
$m
13,157
54
(13,418)
512
190
(316)
179
(93)
86
86
Annual Report 2021
Overview (continued)
- Note A1 Segments
External revenue
EBITDA
Depreciation and amortisation
Share of ITDA of equity
accounted investees
EBIT
Interest income
Interest expense
Income tax expense
Non-controlling interests (NCI)
Statutory profit/(loss)
attributable to members of
the parent entity
Reconciliation of statutory
profit/(loss) to segment
underlying profit/(loss)
Fair value and foreign
exchange movements
Disposals, impairments,
business restructuring
and other
Tax and NCI on items excluded
from underlying profit
Total significant items
Segment underlying
profit/(loss)
Underlying EBITDA
- Note A4 Expenses
Share of APLNG
Reclass-
ification
-
(137)
-
41
(96)
-
-
-
-
2020
$m
-
1,915
-
(1,301)
614
-
-
-
-
Integrated Gas
Restated
2020
$m
-
1,778
-
(1,260)
518
-
-
-
-
2020
$m
269
(1,185)
(29)
5
(1,209)
174
-
-
-
614
(96)
518
(1,035)
-
-
-
-
614
1,915
-
-
384
(96)
-
(96)
-
-
(96)
-
(96)
614
1,915
(1,396)
-
(1,012)
(23)
(174)
Other
Reclass-
ification
-
96
-
-
96
-
-
-
-
96
-
96
-
96
-
-
Restated
2020
$m
269
(1,089)
(29)
5
(1,113)
174
-
-
-
(939)
384
(1,300)
-
(916)
(23)
(174)
- Note A5 Results of equity accounted investees - APLNG
- Note B2.1 Summary APLNG income statement - Origin's share
- Note B2.2 Summary APLNG statement of financial position
- Note E1 Income tax expense
- Note G6 Notes to the statement of cash flows
- Note G9 Deed of Cross Guarantee
Financial Statements
87
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;
• Significant onerous contracts; and
• Other significant non-recurring items.
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 opportunities
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 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.
88
Annual Report 2021
A1 Segments (continued)
Segment result for the year ended 30 June
$m
Ref.
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
Energy Markets Share of APLNG1
Other1
Corporate
Consolidated
Integrated Gas
External revenue
11,931
12,888
-
-
166
269
-
-
12,097
13,157
EBITDA
(1,074)
1,521
1,145
1,778
(389)
(1,089)
Depreciation and amortisation
(518)
(477)
-
-
(30)
(29)
Share of ITDA of equity
accounted investees
EBIT
Interest income2
Interest expense3
Income tax expense4
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, business
restructuring and other
Tax and NCI items excluded from
underlying profit
Total significant items
Segment underlying profit/(loss)
Underlying EBITDA5,6
(41)
(7)
(921)
(1,260)
4
5
(1,633)
1,037
224
518
(415)
(1,113)
106
174
113
(2)
-
111
3
(242)
(443)
(2)
(134)
(205)
2,076
(3)
(550)
(509)
-
(958)
(1,262)
(137)
(1,713)
16
(316)
(93)
(3)
109
(242)
(443)
(2)
305
190
(316)
(93)
(3)
(1,633)
1,037
224
518
(309)
(939)
(573)
(533)
(2,291)
83
(a)
(1)
83
(b)
(2,064)
(20)
(2,065)
432
991
63
974
-
-
-
-
(556)
384
187
(73)
(370)
394
(96)
176
(1,300)
4
(2)
(1,884)
(1,418)
(96)
(380)
(916)
(355)
(164)
84
(355)
84
9 (2,609)
(940)
224
614
71
(23)
(409)
(542)
318
1,023
1,459
1,145
1,915
(10)
(174)
(78)
(59) 2,048
3,141
1 Refer to the Overview for details of prior year restatements in the IG - Share of APLNG and IG - Other segment.
2 Interest income earned on MRCPS has been allocated to the Integrated Gas - Other segment.
3 Interest expense related to general financing is allocated to the Corporate segment.
4 Income tax expense for entities in the Origin tax consolidated group is allocated to the Corporate segment.
5 Underlying profit and underlying EBITDA are non-statutory (non-IFRS) measures.
6 Underlying EBITDA equals segment result and underlying profit/(loss) adjusted for: depreciation and amortisation; share of ITDA of equity accounted investees; interest
income/(expense); income tax expense; and NCI.
Financial Statements
89
A1 Segments (continued)
Segment result for the year ended 30 June
$m
(a) Fair value and foreign exchange movements
(Decrease)/increase in fair value of derivatives
Net (loss)/gain from financial instruments measured at fair value
Exchange gain/(loss) on foreign-denominated debt
Fair value and foreign exchange movements
(b) Disposals, impairments, business restructuring and other
Loss on sale - Horan & Bird Energy Pty Ltd
Disposals
Impairment - APLNG equity accounted investment
Impairment - share of APLNG
Impairment - Energy Markets
Impairments
Restructuring costs
Transaction costs
Transformation costs
Business restructuring
Deferred tax liability recognition - APLNG
LGC net shortfall charge
Onerous contract provision1
Other provision
2021
2020
Gross
Tax and NCI
Gross
Tax and NCI
(366)
(163)
159
(370)
(13)
(13)
-
-
(1,828)
(1,828)
(3)
(2)
(20)
(25)
-
(198)
176
4
109
49
(47)
111
-
-
-
-
250
250
1
-
6
7
(669)
-
(53)
(1)
(466)
275
123
(4)
394
-
-
(650)
(96)
-
(746)
(9)
(13)
-
(22)
-
-
(650)
-
(1,418)
(83)
(37)
1
(119)
-
-
-
-
-
-
3
5
-
8
-
-
195
-
203
Total disposals, impairments, business restructuring and other
(1,884)
1 This amount represents the non-cash movement during the year relating to the Group's onerous contracts. Future realised gains or losses will be recognised within underlying
profit. Refer to note C6.
90
Annual Report 2021
A1 Segments (continued)
Segment assets and liabilities as at 30 June
$m
Assets
Integrated Gas
Energy Markets Share of APLNG
Other
Corporate
Consolidated
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
Segment assets
11,182
12,567
-
-
743
687
221
214
12,146
13,468
Investments accounted for using the equity
method (refer to note A5)1
Cash, funding-related derivatives and tax assets
420
381
7,315
7,766
(783)
(788)
1,296
2,109
Total assets
11,602 12,948
7,315
7,766
1,256
2,008
-
643
864
1
6,952
7,360
2,156
1,939
4,265
2,371 21,037 25,093
Liabilities
Segment liabilities
Financial liabilities, interest-bearing liabilities,
funding-related derivatives and tax liabilities
Total liabilities
Net assets
(3,645)
(3,414)
(3,645)
(3,414)
-
-
-
(1,210)
(1,155)
(673)
(726)
(5,528)
(5,295)
-
(1,210)
(1,155)
(6,367)
(7,823) (11,222) (12,392)
(5,694)
(7,097)
(5,694)
(7,097)
Additions of non-current assets
415
519
-
-
7,957
9,534
7,315
7,766
46
61
853 (5,503)
(5,452)
9,815
12,701
95
15
12
491
626
1 Refer to the Overview for details of prior year restatements in the IG - Share of APLNG and IG - Other segments.
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
2021
$m
12,022
75
12,097
2021
$m
14,884
39
14,923
2020
$m
13,067
90
13,157
2020
$m
17,317
42
17,359
Financial Statements
A2 Revenue
2021
$m
Sale of electricity
Sale of gas
Pool revenue
Other revenue
Total revenue
2020
$m
Sale of electricity
Sale of gas
Pool revenue
Other revenue
Total revenue
91
Total
7,229
3,314
1,337
217
12,097
7,591
3,810
1,527
229
13,157
Retail
4,381
1,148
-
35
5,564
4,569
1,163
-
45
5,777
Business and
Wholesale
2,754
1,307
1,337
34
5,432
2,941
1,673
1,527
64
6,205
Solar and
Energy
Services
Integrated
Gas
94
108
-
144
346
81
99
-
118
298
-
166
-
-
166
-
269
-
-
269
LPG
-
585
-
4
589
-
606
-
2
608
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
sectors. 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 2021. The Group uses a backcasting model
and volume-matching process to provide a reliable estimate of unbilled revenue as at 30 June 2021. 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.
92
Annual Report 2021
A2 Revenue (continued)
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.
A3 Other income
Net gain on sale of assets
Fees and services, and other income1
Other income
Interest earned from other parties2
Interest earned on APLNG MRCPS (refer to note B4)
Interest income
2021
$m
-
43
43
3
106
109
1 This amount includes $7 million (2020: $39 million) relating to insurance proceeds received 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
Cost of sales
Employee expenses1
Depreciation and amortisation
Impairment of non-current assets2,3
Impairment of trade receivables (net of bad debts recovered)
Decrease/(increase) in fair value of derivatives
Net loss/(gain) from financial instruments measured at fair value
Net loss on sale of assets4
Net foreign exchange gain
Onerous contracts provision5
Other6
Expenses
Interest on borrowings
Interest on lease liabilities
Unwind of discounting on long-term provisions
Interest expense
1
Includes contributions to defined contribution superannuation funds of $62 million (2020: $62 million).
2 In the prior year, a $650 million impairment (restated from $746 million - refer to Overview) was recognised relating to the Group's equity accounted investment in APLNG,
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 Developments Limited joint venture.
3 Refer to note C8 for further details of the impairment during the current year.
4 The current period includes a $13 million loss relating to the sale of Horan & Bird Energy Pty Ltd.
5 Refer to note C6.
6 Includes variable lease payments of $103 million (2020: $22 million), of which $82 million (2020: $21 million) relates to renewable power plants (refer to note D2) and
$21 million (2020: $nil) relates to other variable leases. Also included are payments of $5 million (2020: $1 million) for low-value assets and short-term leases.
2020
$m
1
53
54
16
174
190
2020
$m
10,732
662
509
668
124
(275)
(123)
-
(15)
650
486
2021
$m
10,261
643
550
1,828
88
366
163
11
(163)
(176)
477
14,048
13,418
218
17
7
242
296
18
2
316
Financial Statements
93
A5 Results of equity accounted investees
for the year ended 30 June
2021
$m
APLNG1,2
Total joint ventures
Octopus Energy3
Gasbot Pty Limited4
Total associates
Total
2020
$m
APLNG1,2,5
Total joint ventures
Octopus Energy3
Total associates
Total
Share of EBITDA
Share of ITDA
Share of net
(loss)/profit
1,145
1,145
9
(1)
8
1,153
1,778
1,778
(4)
(4)
(917)
(917)
(41)
-
(41)
(958)
(1,255)
(1,255)
(7)
(7)
1,774
(1,262)
228
228
(32)
(1)
(33)
195
523
523
(11)
(11)
512
1 APLNG's summary financial information is separately disclosed in note B2.
2 Included in the Group’s share of net profit is $4 million (2020: $5 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.
3 The Group acquired a 20 per cent interest in Octopus Energy effective 1 May 2020. Included in the Group's share of net profit is $18 million (2020: $5 million) of depreciation,
relating to the fair value attributed to assets at the acquisition date. Refer to note B3.
4 The Group holds a 35 per cent interest in Gasbot Pty Limited and has significant influence over the entity.
5 Refer to the Overview for details of prior year reclassification.
as at 30 June
$m
APLNG1
Octopus Energy2
PNG Energy Developments Limited
Gasbot Pty Limited3
Gaschem Sydney4
Total
1 APLNG's summary financial information is separately disclosed in note B2.
2 Octopus Energy's summary financial information is separately disclosed in note B3.
3 The Group holds a 35 per cent interest in Gasbot Pty Limited and has significant influence over the entity.
4 During the year the Group acquired a 25 per cent interest in Gaschem Sydney and has significant influence over the entity.
Equity accounted investment
carrying amount
2021
6,532
408
-
1
11
2020
6,978
380
1
1
-
6,952
7,360
94
Annual Report 2021
A6 Earnings per share
Weighted average number of shares on issue-basic1
Weighted average number of shares on issue-diluted2
Statutory profit
Earnings per share based on statutory consolidated profit
Statutory (loss)/profit $m
Basic earnings per share
Diluted earnings per share
Underlying profit
Earnings per share based on underlying consolidated profit
Underlying profit $m3
Underlying basic earnings per share
Underlying diluted earnings per share
2021
2020
1,759,555,663
1,759,801,186
1,764,549,534
1,764,776,000
(2,291)
(130.2) cents
(130.2) cents
83
4.7 cents
4.7 cents
318
18.1 cents
18.0 cents
1,023
58.1 cents
58.0 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 that would be issued if outstanding Options, Performance Share Rights, Deferred Share Rights, Restricted Shares and Matching Share Rights were to
be exercised (2021: 4,993,871; 2020: 4,974,814).
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 7.5 cents per share, payable on 1 October 2021. Dividends paid during
the year ended 30 June are detailed below.
Final unfranked dividend of 10 cents per share, in respect of FY2020, paid 2 October 2020
(2020: 15 cents per share, in respect of FY2019, fully franked at 30 per cent, paid 27 September 2019)
Interim unfranked dividend of 12.5 cents per share, in respect of FY2021, paid 26 March 2021
(2020: 15 cents per share, in respect of FY2020, fully franked at 30 per cent, paid 27 March 2020)
Total dividends provided for or paid
Dividend franking account
2021
$m
176
220
396
2020
$m
264
264
528
Franking credits available to shareholders of Origin Energy Limited for subsequent financial years are shown below.
Australian franking credits available at 30 per cent
New Zealand franking credits available at 28 per cent (in NZD)
(7)
304
(57)
304
Financial Statements
95
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
APLNG1
Octopus Energy2
PNG Energy Developments Limited
Gasbot Pty Limited
Gaschem Sydney
KUBU Energy Resources (Pty) Limited
Reporting date
30 June
30 April
Country
of incorporation
Australia
United Kingdom
31 December
PNG
30 June
Australia
31 December
Germany
30 June
Botswana
Ownership interest (per cent)
2021
37.5
20.0
50.0
35.0
25.0
50.0
2020
37.5
20.0
50.0
35.0
-
50.0
1 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.
2 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.
Of the above interests in joint ventures and associates, only APLNG and Octopus Energy have a material impact on the Group at 30 June 2021.
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
2021
2020
for the year ended 30 June
$m
Operating revenue
Operating expenses
Impairment expense1
EBITDA
Depreciation and amortisation expense
Interest income
Interest expense – MRCPS
Other interest expense
Income tax expense1
ITDA
Statutory result for the year
Other comprehensive income
Statutory total comprehensive income2
Items excluded from segment result
Impairment1
Items excluded from segment result (net of tax)
Underlying profit for the year3
Underlying EBITDA for the year3
1 Refer to the Overview for details of prior year reclassification.
Total
APLNG
4,595
(1,544)
-
3,051
(1,568)
6
(282)
(357)
(255)
(2,456)
-
595
-
-
595
3,051
Origin
interest
Total
APLNG
Origin
interest
7,100
(1,992)
(366)
4,742
(1,863)
40
(463)
(474)
(598)
1,778
(699)
15
(174)
(177)
(225)
(3,358)
(1,260)
-
1,384
256
256
1,640
5,108
-
518
96
96
614
1,915
1,145
(588)
2
(106)
(134)
(95)
(921)
-
224
-
-
224
1,145
2 Excluded from the above is $4 million (2020: $5 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.
3 Underlying profit and underlying EBITDA are non-statutory (non-IFRS) measures.
Income and expense amounts are converted from USD to AUD using the average exchange rate prevailing for the relevant period.
96
Annual Report 2021
B2.2 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&E1
Exploration, evaluation and development assets1
Other assets1
Non-current assets
Total assets
Bank loans – secured
Payable to shareholders (MRCPS)
Liabilities classified as held for sale
Other liabilities
Current liabilities
Bank loans – secured
Payable to shareholders (MRCPS)
Other liabilities
Non-current liabilities
Total liabilities
Net assets
Group's interest of 37.5 per cent of APLNG net assets1
Group's impairment expense1
Group's own costs
MRCPS elimination2
Investment in APLNG Pty Ltd3
2021
905
24
647
1,576
335
31,352
486
730
32,903
34,479
681
-
1
588
1,270
7,179
3,417
3,107
13,703
14,973
19,506
7,315
(650)
25
(158)
6,532
2020
1,072
5
775
1,852
370
35,350
518
1,108
37,346
39,198
720
117
-
689
1,526
8,587
5,398
2,981
16,966
18,492
20,706
7,766
(650)
25
(163)
6,978
1 Refer to the Overview for details of prior year reclassification.
2 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.
3 Includes a movement of $(674) 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 0.7516 (2020: 0.6862).
Key judgements and estimates
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.
Financial Statements
97
B2.3 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
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
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 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
2021
2020
4,808
(1,494)
3,314
3
-
-
(431)
(28)
8
(448)
(48)
(45)
(19)
(672)
(263)
(1,598)
(293)
(2,938)
(72)
1,072
(95)
905
7,321
(2,079)
5,242
8
6
(245)
(1,001)
(37)
40
(1,229)
(45)
(80)
(19)
(731)
(382)
(2,918)
(480)
(4,655)
(642)
1,610
104
1,072
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.
98
Annual Report 2021
B3 Investment in Octopus Energy Holdings Limited
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. During the year, the Group committed an additional investment of
£36 million to maintain its 20 per cent interest. Refer to note B4 for further details.
The following table summarises the financial information of Octopus Energy, as included in its financial statements, adjusted for 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 year ended 30 June
$m
Operating revenue
Statutory and underlying result for the year
Other comprehensive income
Statutory total comprehensive income1
2021
Total
Octopus
Energy
3,907
(72)
-
(72)
Origin
interest
-
(14)
-
(14)
2020
Total
Octopus
Energy
349
(32)
-
(32)
1 Excluded from the above is $18 million (2020: $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 assets1
Non-current assets
Current liabilities2
Non-current liabilities2
Net assets
Group's interest of 20 per cent of Octopus Energy net assets
Goodwill and fair value adjustments3
Group's own costs
Group's carrying amount of the investment in Octopus Energy4
2021
1,317
331
(1,323)
-
325
65
337
6
408
Origin
interest
-
(6)
-
(6)
2020
1,040
163
(852)
(197)
154
31
344
5
380
1 Current assets includes cash and cash equivalents of $233 million (2020: $113 million).
2 Includes current financial liabilities and non-current financial liabilities of $306 million (2020: $237 million) and $Nil million (2020: $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 $48 million related to an additional investment during the year and $12 million related to foreign exchange that has been recognised in the foreign
currency translation reserve (2020: $21 million).
Reporting date balances are converted from GBP to AUD using an end-of-period exchange rate of 0.5428 (2020: 0.5584).
The associate has no contingent liabilities or capital commitments as at 30 June 2021.
Financial Statements
99
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 (2021: $354 million; 2020: $339 million) and sell gas to APLNG
(2021: $7 million; 2020: $32 million). At 30 June 2021, the Group's outstanding payable balance for purchases from APLNG was $55 million
(2020: $33 million) and outstanding receivable balance for sales to APLNG was $7 million (2020: $1 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$963 million following APLNG share buy-backs of US$456 million. 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 $1,296 million as at 30 June 2021 (2020: $2,109 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
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 prior to 30 June 2020 and £150 million was deferred over two financial years.
The Group has also entered into a licensing agreement for a total cash consideration of £25 million, of which £5 million was paid prior to
30 June 2020 and £20 million was deferred over two financial years. During the year, the Group paid £50 million ($95 million) to Octopus
Energy in respect of the deferred consideration payable under the equity purchase agreement. A further £20 million ($36 million) was also
paid to Octopus Energy during the year, representing £10 million of the deferred consideration payable under the licensing agreement and
an additional £10 million which became payable on achievement of certain milestones. The remaining £110 million ($202 million) of deferred
consideration is payable within the next 12 months.
On 7 January 2021, the Group committed an additional investment of £36 million (~A$65 million) to maintain its 20 per cent equity interest,
following the announcement of an agreed partnership between Octopus Energy and Tokyo Gas. Subsequently, the Group has paid £27 million
($48 million) in March 2021 as a result of relevant completions being satisfied. The remaining £8.7 million ($16 million) is contingent in nature
and will only become payable upon achievement of agreed milestones and is therefore not included in the deferred consideration balance as
of 30 June 2021.
During the year, Octopus Energy utilised the remaining available tranche of a working capital facility, for which the Group has provided a
financial guarantee to Octopus Energy’s financiers, in accordance with the agreement entered into with Octopus Energy in the prior year.
During the year, $8 million (2020: $1 million) has been recognised within other income in respect of the financial guarantee income.
100
Annual Report 2021
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
Total current
Non-current
Trade receivables
Other receivables
Total non-current
2021
$m
602
1,444
252
2,298
9
5
14
2020
$m
618
1,072
269
1,959
8
10
18
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 had a wide-ranging impact on businesses and individuals, with 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. 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, coupled with continued
uncertainty around the impacts of any additional lock-downs required;
• 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
101
C1 Trade and other receivables (continued)
The Group has assessed 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. The Group models the expected credit loss 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.
As at 30 June 2021, the allowance for impairment in respect of trade receivables and unbilled revenue is $186 million (2020: $162 million),
with $34 million (2020: $40 million) of this amount reflecting the increased potential impact of COVID-19.
The average age of trade receivables is 19 days (2020: 20 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
Total
2021
2020
Gross
1,465
380
105
45
30
207
2,232
Impairment
allowance
(21)
(8)
(7)
(9)
(9)
(132)
(186)
Gross
1,092
387
102
46
40
185
1,852
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
Impairment losses recognised
Amounts written off
Balance as at 30 June
162
88
(64)
186
Impairment
allowance
(20)
(14)
(6)
(8)
(10)
(104)
(162)
135
124
(97)
162
102
Annual Report 2021
C2 Exploration and evaluation assets
Balance as at 1 July
Additions
Balance as at 30 June1
2021
$m
190
55
245
2020
$m
98
92
190
1 The 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); a 75 percent interest in five
exploration permits with Bridgeport; and a 100 percent interest in one exploration permit in the Cooper–Eromanga Basin; a 50 per cent interest in five exploration permits
with Buru Energy; and a 40 per cent interest in two permits with Buru Energy and Rey Resources in the Canning Basin.
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
103
C3 Property, plant and equipment
Owned
Right-of-use
Total
Plant
and equipment
Land
and buildings
Capital work
in progress
Plant
and equipment
Land
and buildings
$m
2021
Cost
Less: Accumulated
depreciation and
impairment losses
Total
Balance as at 1 July 2020
Additions
Disposals
Modifications to lease terms
Depreciation/amortisation
Impairment1
Transfers within PP&E
Transfers from intangibles
Effect of movements in foreign
exchange rates
5,863
(3,405)
2,458
3,443
36
-
-
(294)
(801)
71
5
(2)
Balance as at 30 June 2021
2,458
2020
Cost
Less: Accumulated
depreciation and
impairment losses
Total
Balance as at 30 June 2019
Adoption of AASB 16 Leases
Balance as at 1 July 2019
Additions
Disposals
Modifications to lease terms
Depreciation/amortisation
Impairment2
Transfers within PP&E
Effect of movements in foreign
exchange rates
Balance as at 30 June 2020
1 Refer to Note C8.
5,774
(2,331)
3,443
3,268
(44)
3,224
267
(1)
-
(295)
(19)
267
-
3,443
194
(82)
112
143
1
-
-
(4)
(28)
-
-
-
112
194
(51)
143
141
-
141
1
-
-
(4)
-
5
-
143
317
-
317
278
110
-
-
-
-
(71)
-
-
317
162
408
6,944
(78)
84
108
29
(13)
12
(48)
(4)
-
-
-
84
(88)
320
359
1
(1)
1
(40)
-
-
-
-
320
(3,653)
3,291
4,331
177
(14)
13
(386)
(833)
-
5
(2)
3,291
278
155
407
6,808
-
278
188
(31)
157
393
-
-
-
-
(272)
-
278
(47)
108
-
127
127
20
(1)
8
(46)
-
-
-
(48)
359
-
318
318
1
-
78
(40)
-
-
2
(2,477)
4,331
3,597
370
3,967
682
(2)
86
(385)
(19)
-
2
108
359
4,331
2 Impairment relating to the Mortlake generator asset write-off following an electrical fault.
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.
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
104
Annual Report 2021
C3 Property, plant and equipment (continued)
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 the 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 expenses within note A4.
Refer to note D2 for discussion of the recognition and measurement of associated lease liability balances.
Key judgements and estimates
Recoverability of carrying values: 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 sensitive to changes in key assumptions. Refer to note C8 for further details.
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
C4 Intangible assets
Goodwill
Software and other intangible assets
Accumulated amortisation and impairment losses
Total
Reconciliations of the carrying amounts of each class of intangible asset are set out below.
$m
Balance as at 1 July 2020
Additions1
Transfers to PP&E
Impairment2
Amortisation expense
Balance as at 30 June 2021
Balance as at 1 July 2019
Additions1
Disposals
Amortisation expense
Balance as at 30 June 2020
105
2020
$m
4,818
1,494
(892)
5,420
Total
5,420
135
(5)
(1,006)
(170)
4,374
5,381
171
(2)
(130)
5,420
2021
$m
4,818
1,568
(2,012)
4,374
Goodwill
Software
and other
intangibles
4,818
-
-
(1,006)
-
3,812
4,818
-
-
-
4,818
602
135
(5)
-
(170)
562
563
171
(2)
(130)
602
1 Additions include amounts relating to the build of the Kraken technology platform, along with amounts relating to the implementation of a new Enterprise Resource Planning
system for the Group.
2 Includes $995 million related to the impairment of Energy Markets segment goodwill (refer to note C8) and $11 million related to goodwill written off when Horan & Bird Energy
Pty Ltd was sold.
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 13 per cent (2020: 10 per cent).
Key judgements and estimates
Recoverability of carrying values: Refer to note C8 for further details.
C5 Trade and other payables
Current
Trade payables and accrued expenses
Deferred consideration1
Total
Non-current
Deferred consideration1
Total
2021
$m
2,205
202
2,407
-
-
2020
$m
1,827
107
1,934
193
193
1 Relates to the £100 million (2020: £150 million) deferred cash consideration for the shares acquired in Octopus Energy on 1 May 2020 and £10 million (2020: £20 million)
deferred cash consideration for the Kraken licence agreement with Octopus Energy (refer to note B4).
106
Annual Report 2021
C6 Provisions
$m
Balance as at 1 July 2020
Provisions recognised
Provisions released
Payments/utilisation
Unwinding of discounting
Effect of movements in foreign exchange rates
Balance as at 30 June 2021
Current
Non-current
Total provisions
Restoration1
Onerous
contracts2
Other3
661
23
(3)
(7)
1
-
675
641
13
(152)
(40)
3
(54)
411
174
16
(4)
(10)
-
-
176
Total
1,476
52
(159)
(57)
4
(54)
1,262
43
1,219
1,262
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 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.
The closing balance includes an onerous contract provision of $398 million (US$299 million) for the Cameron LNG purchase contract and $13 million was recognised during
the year in respect of a short-term LNG sales contract with ENN.
3 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; and
• 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
107
C7 Other financial assets and liabilities
$m
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 and other securities1
Equity securities
Measured at fair value through other comprehensive income
Equity securities1
Measured at amortised cost
Futures collateral
Total other financial assets
Other financial liabilities
Measured at fair value through profit or loss
Environmental scheme surrender obligations
Measured at amortised cost
Futures collateral
Financial guarantees2
Total other financial liabilities
2021
2020
Current
Non-current
Current
Non-current
-
42
255
-
12
-
-
194
503
321
23
-
344
1,296
31
-
64
22
6
46
-
1,465
-
-
15
15
44
34
103
-
-
-
-
298
479
234
3
-
237
2,065
26
-
55
25
-
54
-
2,225
-
-
16
16
1 The prior year comparative has been restated to reclassify $8 million from fair value through other comprehensive income to fair value through profit and loss.
2 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.
C8 Impairment of non-current assets
The carrying amounts of the Group's cash generating units (CGUs) are reviewed at each reporting date to determine whether there is any
indication of impairment. Where an indicator of impairment exists, or where goodwill is present, a formal estimate of the recoverable amount
is made.
Cash-generating units
Assets are grouped together into the smallest group of individual assets that generate largely independent cash inflows (cash generating unit
or (CGU)). As a result of the impairment indications identified and the goodwill associated with each CGU in the Energy Market segment, an
impairment assessment was performed at June 2021 in line with the requirements under the accounting standards.
The Energy Markets segment consists of the following materially distinct CGUs:
• Retail CGU: incorporates Mass Market customers, Commercial & Industrial customers and the Wholesale & Trading businesses for
electricity and natural gas commodities. The Wholesale & Trading business includes various electricity PPAs and major wholesale gas
supply contracts.
• Generation CGU: incorporates cash flows from Origin's power stations.
• LPG CGU: supplies and distributes LPG to residential and business locations across Australia and the Pacific.
Impairment testing for the year ended 30 June 2021
Origin’s assessment of the carrying value of its non-current assets in Energy Markets considers a range of macroeconomic factors, including
market prices for wholesale electricity, large-scale generation certificate (LGCs) and gas, retail market dynamics, discount rates and costs. The
principal changes since the last assessment at 30 June 2020 are a significant reduction in wholesale electricity prices and a contraction in
near-term gas earnings as a result of higher procurement costs and subdued business customer demand.
As a result, Origin has recognised an impairment of $998 million in respect of the Generation CGU, consisting of $833 million of Generation
PP&E and $165 million of allocated goodwill, with the lower outlook for wholesale electricity prices driven by new supply expected to
come online, including both renewable and dispatchable capacity, impacting the valuation of the Generation fleet, particularly Eraring
Power Station.
108
Annual Report 2021
C8 Impairment of non-current assets (continued)
The impairment of goodwill allocated to the Retail CGU of $830 million primarily relates to lower electricity prices impacting margins on
long-term renewable PPAs, as well as lower near-term gas earnings.
It was determined that the LPG CGU is not impaired.
The impairment expense recognised by class of asset is outlined in the following table.
Impairment expense
Non-current assets
PP&E
Intangible assets
Total impairment expense on non-current assets
Recoverable amount
Note
C3
C4
A4
2021
$m
833
995
1,828
The recoverable amount of the CGUs within the Energy Markets segment have been determined using value-in-use models that include an
appropriate terminal value. The value-in-use calculations are 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. The key assumptions
used by the Group in its impairment assessment are shown in the table below.
Key assumptions
Energy Markets
Commodity prices
Future commodity price assumptions impact the recoverability of carrying values and are reviewed at least twice annually.
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.
Long-term
growth rates
Cash flows are projected for the life of each Generation asset and for the term of electricity PPAs and major wholesale supply
contracts in the Retail CGU. Other Retail CGU cash flows are projected for five years. The growth rate used to extrapolate Retail
cash flows beyond the initial period projected averages 2.3 per cent, analogous to long term Consumer Price Index.
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 cost
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 rates for Generation and Retail are 9.4 per cent (2020: 9.3 per cent) and 9.7 per cent (2020: 9.6 per
cent) respectively.
As a result of the factors outlined above, the carrying amount of the Retail and Generation CGUs exceed their recoverable amounts at 30 June
2021. The resulting impairment write-downs recognised in the year ended 30 June 2021 are shown in the following table.
PP&E
Intangible assets
Total impairment expense
Goodwill allocation
Retail
Generation
-
830
830
833
165
998
Total
833
995
1,828
Goodwill has been allocated for impairment testing purposes to the individual CGUs in the Energy Markets segment. The carrying amount of
goodwill allocated to the Retail CGU is $4,620 million. The carrying amount of goodwill allocated to each of the other CGUs is not significant
in comparison with the total carrying amount of goodwill.
Sensitivity analysis
To the extent the CGUs that include a significant portion of goodwill have been written down to their respective recoverable amounts in the
current year, any change in key assumptions on which the valuations are based would further impact asset carrying values. When modelled
in isolation, it is estimated that changes in the key assumptions would result in the following additional impairments in FY2021.
Sensitivity
Retail
Discount rates
increase by 1%
Long-term
growth rates
decrease by 1%
(606)
(428)
Changes in any of the aforementioned assumptions may be accompanied by changes in other assumptions, which may have an
offsetting impact.
Financial Statements
109
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 (Baa2) through the cycle and an appropriate level of net debt are required to meet these
objectives. The Group's current credit rating is 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 cash1
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
1 This balance excludes $30 million (2020: $76 million) of cash held by Origin, as upstream operator, to fund APLNG-related operations.
2021
$m
4,765
463
5,228
(442)
4,786
(147)
4,639
9,815
14,454
32%
2.9x
2020
$m
6,338
514
6,852
(1,164)
5,688
(530)
5,158
12,701
17,859
29%
2.1x
The Group undertook a bank debt extension during the year ended 30 June 2021. This activity was aimed at strengthening the capital profile
by extending the weighted average tenor of the Group’s debt portfolio.
A summary of key transactions is shown below.
Bank debt facility extension
2 July 2020 - 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.
31 August 2020 – extended US$200 million of a bank guarantee facility from a FY2023 maturity date to a new maturity date in FY2025.
Debt maturity
23 October 2020 - repaid the €750 million seven-year note under the Euro Medium Term Note (EMTN) program. The notes had been
swapped to A$950 million.
19 December 2020 – repaid the US$65 million seven-year US Private Placement note.
110
Annual Report 2021
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
Total non-current borrowings
Lease liabilities – secured
Total non-current interest-bearing liabilities
2021
$m
2020
$m
1,938
1,938
66
2,004
537
2,290
2,827
397
3,224
1,328
1,328
73
1,401
535
4,475
5,010
441
5,451
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.
The Group's leases of renewable power plants are entirely variable as they depend on the amount of energy generation in the period and, as
such, there are no lease liability amounts associated with these leases. The variable lease payments associated with these leases are disclosed
in note A4.
The contractual maturity of lease liabilities is 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
2021
$m
237
534
2,056
2,827
2020
$m
2,069
356
2,585
5,010
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 2021, these terms had not been triggered.
Financial Statements
111
D3 Contributed equity
Ordinary share capital
Opening balance1
Less treasury shares:
Opening balance1
Shares purchased on market
Utilisation of treasury shares on vesting of employee share schemes
and DRP
Total treasury shares
Closing balance
2021
2020
2021
2020
Number of shares
$m
1,761,211,071
1,761,211,071
7,163
7,163
(3,212,930)
(4,809,617)
(20,903,960)
(12,291,634)
18,070,562
13,888,321
(6,046,328)
(3,212,930)
(18)
(96)
89
(25)
(38)
(75)
95
(18)
1,755,164,743
1,757,998,141
7,138
7,145
1 The sum of the opening balances of share capital and treasury shares is $7,145 million (2020: $7,125 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
Market
Liquidity
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).
Purchase and sale
of commodities and
funding risks
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 cash flow 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.
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.
112
Annual Report 2021
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
Foreign exchange
Foreign-denominated borrowings and investments (e.g.,
APLNG MRCPS) and future foreign currency denominated
commercial transactions
Interest rate
Variable-rate borrowings (cash flow risk) and fixed-rate
borrowings (fair value risk)
Due to vertical integration, a significant portion of the
Group's spot electricity purchases from the NEM are
naturally hedged by generation sales into the NEM at
spot prices. 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 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 with values that are 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
Futures
Swaps
Options
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.
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.
A contract in which two parties exchange a series of cash flows for another (such as fixed-for-floating interest rate).
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 $377 million loss (2020:
$292 million gain) for the year. Fair value gains and losses attributable to accounting hedges are discussed in the Hedge Accounting section.
Financial Statements
113
D4 Financial risk management (continued)
$m
2021
Economic hedges
Commodity contracts
Foreign exchange and interest rate contracts
Total economic hedges
Accounting hedges
Commodity contracts
Foreign exchange and interest rate contracts
Total accounting hedges
Total
2020
Economic hedges
Commodity contracts
Foreign exchange and interest rate contracts
Total economic hedges
Accounting hedges
Commodity contracts
Foreign exchange and interest rate contracts
Total accounting hedges
Total
Hedge accounting
Assets
Liabilities
Current
Non-current
Current
Non-current
434
10
444
218
107
325
769
247
2
249
98
283
381
630
201
-
201
121
44
165
366
258
-
258
43
227
270
528
(537)
(54)
(591)
(150)
-
(150)
(741)
(170)
(72)
(242)
(224)
-
(224)
(466)
(342)
(60)
(402)
(44)
(60)
(104)
(506)
(173)
(124)
(297)
(402)
(50)
(452)
(749)
The Group currently uses two types of hedge accounting relationships, as detailed below.
Fair value hedge
Cash flow hedge
Objective of
hedging
arrangement
Effective
hedge portion
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.
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.
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.
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, is
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.
Set out below are the fair values of derivatives designated in hedge accounting relationships at reporting date.
2021
$m
Fair value hedges
Cash flow hedges
Accounting hedges
Assets
Liabilities
Current
Non-current
Current
Non-current
107
218
325
-
165
165
-
(150)
(150)
-
(104)
(104)
114
Annual Report 2021
D4 Financial risk management (continued)
Fair value hedges
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 instrument1
Hedged debt2
Fair value increase/(decrease)
Hedging instrument
Hedged debt
Hedge ineffectiveness3
FX and interest
EUR 800m
AUD/EUR
0.69;
BBSW
Up to Oct 2021
$m
107
(1,259)
$m
(45)
46
1
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 $7 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.
2021
Nominal hedge volumes
Hedge rates
FX and interest
Electricity
13.0 TWh
$29-$132
EUR 750m
AUD/EUR
0.62-0.81;
Fixed
3.2%-6.6%
Crude oil
7,258k barrels
US$43-US$71 (ICE
Brent); US$6.3-
US$9.5 (JKM)
Propane
40k mt
US$265-US$450
Timing of cash flows – up to
Sep 2029
Jun 2025
Dec 2023 (ICE Brent);
Dec 2025 (JKM)
Dec 2022
Carrying amounts - $m
FX and interest
Electricity
Crude oil
Propane
Hedging instrument – assets1
Hedging instrument – liabilities1
Hedge reserve2
Fair value increase/(decrease) - $m
Hedging instrument
Hedged item
Hedge ineffectiveness3
Reconciliation of hedge reserve - $m
Effective portion of hedge gains/(losses)
Transfer of deferred losses/(gains) to:
– Cost of sales
– Finance costs
Tax on above items
Change in hedge reserve (post-tax)
45
(60)
47
(37)
41
4
(7)
-
27
(6)
14
27
(80)
53
61
(61)
-
61
140
-
(61)
140
290
(107)
(189)
404
(398)
6
428
(34)
-
(118)
276
21
(6)
(15)
24
(24)
-
27
(3)
-
(7)
17
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.
Total
383
(253)
(104)
452
(442)
10
509
103
27
(192)
447
Financial Statements
115
D4 Financial risk management (continued)
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
A 10 per cent increase/decrease in the USD exchange rate
would increase/decrease fair value by $21/($18) million
(2020: $19 million).
• 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
• Electricity forward price
Oil forward price
• Commodity derivatives
REC forward price
• REC forwards
• Environmental scheme certificates
• Environmental scheme surrender obligations
Liquidity risk
A 10 per cent increase/decrease in the euro exchange rate
would decrease/increase fair value by $11 million (2020:
$17 million).
A 100 basis point increase/decrease in interest rates
would impact fair value by ($38)/$39 million (2020: ($43)/
$38 million).
A 10 per cent increase/decrease in electricity forward
prices would increase/decrease fair value by $68/
($69) million (2020: $93/($95) million).
A 10 per cent increase/decrease in oil forward prices would
increase/decrease fair value by $44/(40) million (2020:
$54/(52) million).
A 10 per cent increase/decrease in renewable energy
certificate forward prices would increase/decrease fair
value by $23 million (2020: $1 million).
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.
2021
$m
Bank loans and capital markets borrowings
Lease liabilities
Net other financial assets/liabilities
Total
Derivative liabilities
Derivative assets
Total
Net liquidity exposure
Less than
one year
(2,068)
(91)
754
(1,405)
(779)
902
123
(1,282)
(313)
(74)
199
(188)
(289)
211
(78)
(266)
(754)
(147)
7
(894)
(137)
39
(98)
(992)
One to
two years
Two to
five years
Over
five years
The amount of cash and committed undrawn floating rate borrowing facilities expiring beyond one year is $3,279 million.
2020
$m
Bank loans and capital markets borrowings
Lease liabilities
Net other financial assets/liabilities
Total
Derivative liabilities
Derivative assets
Total
Net liquidity exposure
Less than
one year
(1,522)
(99)
82
One to
two years
(2,183)
(84)
395
(1,539)
(1,872)
(782)
918
136
(379)
325
(54)
(1,403)
(1,926)
Two to
five years
(589)
(166)
1,494
739
(200)
143
(57)
682
The amount of cash and committed undrawn floating rate borrowing facilities expiring beyond one year is $4,059 million.
(2,221)
(276)
-
(2,497)
(68)
28
(40)
(2,537)
Over
five years
(2,840)
(313)
-
(3,153)
(71)
30
(41)
(3,194)
116
Annual Report 2021
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.
2021
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
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
Note
D4
C7
D4
C7
D4
C7
D4
C7
Level 1
$m
44
328
372
(86)
(321)
(407)
Level 1
$m
20
163
183
(202)
(234)
(436)
Level 2
$m
1,066
77
1,143
(1,097)
-
(1,097)
Level 2
$m
1,004
72
1,076
(944)
-
(944)
Level 3
$m
25
1,369
1,394
(64)
-
(64)
Level 3
$m
134
2,171
2,305
(69)
-
(69)
The following table shows a reconciliation of movements in the fair value of level 3 instruments during the period.
Balance as at 1 July 2020
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 2021
Total
$m
1,135
1,774
2,909
(1,247)
(321)
(1,568)
Total
$m
1,158
2,406
3,564
(1,215)
(234)
(1,449)
$m
2,236
(12)
(7)
(602)
2
(290)
(103)
106
1,330
Financial Statements
117
D5 Fair value of financial assets and liabilities (continued)
Valuation techniques used to determine fair values
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
Forward foreign
exchange contracts
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.
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.
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.
Instrument1
Unobservable inputs
Relationship to fair value
Electricity
derivatives
MRCPS issued
by APLNG
Forward electricity spot market price curve
Forward electricity cap price curve
Forecast REC prices
Forecast APLNG free cash flows
A 10 per cent increase/decrease in the unobservable inputs would
increase/decrease fair value by $57 million (2020: $68 million).
A 10 per cent improvement/ deterioration in the level of APLNG forecast
cash flows would impact fair value by $1 million (2020: $1 million).
1 Excludes $47 million (June 2020: $55 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 2020
Value recognised in the income statement
New instruments
Balance as at 30 June 2021
Classification of net deferred gain
Derivative assets
Derivative liabilities
Balance as at 30 June 2021
$m
102
(18)
82
166
24
142
166
118
Annual Report 2021
D5 Fair value of financial assets and liabilities (continued)
Financial instruments measured at amortised cost
Except as noted below, the carrying amounts of non-current financial assets and liabilities measured at amortised cost are reasonable
approximations of their fair values due to their short-term nature.
Liabilities
Bank loans – unsecured
Capital markets borrowings – unsecured
Total1
Carrying value
Fair value
Fair value
hierarchy level
2
2
2021
$m
537
2,290
2,827
2020
$m
535
4,475
5,010
2021
$m
575
2,460
3,035
2020
$m
557
4,678
5,235
1 Non-current interest-bearing liabilities in the statement of financial position include $2,827 million (June 2020: $5,010 million) as disclosed above, and lease liabilities of
$397 million (June 2020: $441 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.
Financial Statements
119
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
Adjustments to current tax expense for previous years
Deferred tax expense
Total income tax expense
Reconciliation between tax expense and pre-tax net profit
(Loss)/profit before income tax
Income tax using the domestic corporation tax rate of 30 per cent (2020: 30 per cent)
Prima facie income tax expense on pre-tax accounting profit:
– at Australian tax rate of 30 per cent
– adjustment for tax exempt charity (Origin Foundation Limited)
– adjustment for difference between Australian and overseas tax rates
Income tax (benefit)/expense on pre-tax accounting profit at standard rates
Increase/(decrease) in income tax expense due to:
Share of results of equity accounted investees1
Impairment of carrying value of Energy Market goodwill
Impairment of investment in APLNG1
Recognition of deferred tax liability in respect of investment in APLNG
LGC shortfall charge
Other
Total increase/(decrease)
Under/(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
Provisions
Employee benefits
Other items
Total
1 Refer to the Overview for details of prior year reclassification.
2021
$m
59
(7)
391
443
2020
$m
3
(34)
124
93
(1,846)
179
(554)
(3)
-
(557)
(57)
298
-
669
79
7
996
4
443
190
17
1
(1)
207
54
-
(1)
53
(153)
-
195
-
-
4
46
(6)
93
(211)
-
-
3
(208)
The Company and its wholly owned Australian resident entities that met the membership requirement 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.
120
Annual Report 2021
E1 Income tax expense (continued)
Key judgements and estimates
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 and there will be sufficient future taxable profits against which the benefits can be utilised.
A deferred tax liability is recognised for taxable temporary differences associated with investments in joint ventures unless the Group
is able to control the timing of the reversal of the temporary difference and it is probable that the temporary difference will not reverse
in the foreseeable future. During the year, the Group recognised a deferred tax liability amounting to $669 million in respect of the
investment in APLNG, representing equity accounted earnings that are expected to be distributed to Origin via dividends from APLNG in
the foreseeable of future. In determining the forecast distributions from APLNG, the Group’s assessment of future cash flows considers a
range of macroeconomic and project assumptions, including oil and LNG prices, AUD/USD exchange rates, discount rates and costs over
the asset's life.
At 30 June 2021, none of the remaining unbooked balance is expected to reverse in the foreseeable future through the payment of future
dividends, through sale or through a capital return. The unrecognised portion is disclosed in note E2.
Income tax expense recognised in other comprehensive income
$m
Investment valuation changes
Actuarial gain on defined benefit
superannuation plan
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
2021
2020
Gross
(8)
4
130
509
(623)
12
Tax
2
(1)
(39)
(153)
(16)
(207)
Net
Gross
(6)
3
91
356
(639)
(195)
6
-
5
(705)
125
(569)
Tax
(3)
-
(1)
212
-
208
Net
3
-
4
(493)
125
(361)
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.
Financial Statements
121
E2 Deferred tax (continued)
Movement in temporary differences during the year
Asset/(liability)
$m
Adoption of
AASB 16
Leases
1 July 2019
Recognised
in income
Recognised
in equity
30 June
2020
Recognised
in income
Recognised
in equity
30 June
2021
Employee benefits
Provisions
Tax value of carry-forward
tax losses recognised
PP&E
Exploration and
evaluation assets
Financial instruments at
fair value
Investment in APLNG1
APLNG MRCPS elimination
(refer to note B2.1)
Business-related costs
(deductible under
s.40-880 ITAA97)
ROU assets
Lease liabilities
Other items
65
208
1
(406)
120
285
-
50
43
-
2
12
Net deferred tax liabilities
380
-
(30)
-
23
-
(154)
-
-
-
(134)
144
2
(149)
14
310
45
(120)
(174)
(175)
-
(1)
(16)
(6)
8
(9)
(124)
-
-
-
-
-
211
-
-
-
-
-
(3)
208
79
488
46
(503)
(54)
167
-
49
27
(140)
154
2
315
2
(41)
(45)
277
(13)
103
(669)
(1)
(1)
19
(15)
(7)
(1)
(17)
-
-
-
(190)
-
-
-
-
-
1
80
430
1
(226)
(67)
80
(669)
48
26
(121)
139
(4)
(391)
(207)
(283)
1 The Group has recognised a deferred tax liability in respect of the investment in APLNG amounting to $669 million at 30 June 2021 representing equity accounted earnings
that are expected to be distributed to Origin via dividends from APLNG in the foreseeable future.
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
Total deferred tax assets
Deferred tax liabilities have not been recognised in respect of the following items:
Investment in APLNG1
Total deferred tax liabilities
2021
$m
2020
$m
4
223
118
57
67
8
477
26
216
118
57
67
8
492
(810)
(810)
(1,615)
(1,615)
1 The deferred tax liability in respect of the investment in APLNG has not been recognised in full during the year as not all of the temporary difference is expected to reverse
in the foreseeable future.
122
Annual Report 2021
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).
Incorporated in
Ownership interest per cent
2021
2020
Origin Energy Limited
Origin Energy Finance Limited
Huddart Parker Pty Limited1
FRL Pty Ltd1
B.T.S. Pty Ltd1
Origin Energy Power Limited1
Origin Energy SWC Limited1
BESP Pty Ltd
Origin Energy Eraring Pty Limited1
Origin Energy Eraring Services Pty Limited1
Origin Energy Upstream Holdings Pty Ltd
Origin Energy B2 Pty Ltd
Origin Energy Browse Pty Ltd
Origin Energy West Pty Ltd
Origin Energy C6 Pty Limited
Origin Energy C5 Pty Limited
Origin Energy Future Fuels Pty Ltd
Origin Energy Upstream Operator Pty Ltd
Origin Energy Holdings Pty Limited1
Origin Energy Retail Limited1
Origin Energy (Vic) Pty Limited1
Gasmart (Vic) Pty Ltd1
Origin Energy (TM) Pty Limited1
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 Limited1
Eraring Gentrader Depositor Pty Limited
Sun Retail Pty Ltd1
OE Power Pty Limited1
Origin Energy Uranquinty Power Pty Ltd1
OC Energy Pty Ltd1
Origin Energy Eraring Battery Pty Ltd
Origin Energy International Holdings Pty Limited
Origin Energy Mortlake Terminal Station No. 2 Pty Limited
Origin Energy PNG Ltd2
Origin Energy PNG Holdings Limited2
Origin Energy Tasmania Pty Limited1
The Fiji Gas Co Ltd
Origin Energy Contracting Limited1
NSW
Vic
Vic
WA
WA
SA
WA
Vic
NSW
NSW
Vic
Vic
Vic
NSW
Vic
Vic
Vic
Vic
Vic
SA
Vic
Vic
Vic
Vic
Vic
Vic
Qld
Vic
Vic
Qld
Vic
Vic
Vic
NSW
Vic
Vic
PNG
PNG
Tas
Fiji
Qld
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
66.7
100
100
51
100
1 Entered into ASIC Corporations (Wholly-owned Companies) Instrument 2016/785 and related Deed of Cross Guarantee with Origin Energy Limited.
2 Controlled entity has a financial reporting period ending 31 December.
Financial Statements
123
F1 Controlled entities (continued)
Origin Energy LPG Limited1
Origin (LGC) (Aust) Pty Limited1
Origin Energy SA Pty Limited1
Hylemit Pty Limited
Origin Energy LPG Retail (NSW) Pty Limited
Origin Energy WA Pty Limited1
Origin Energy Services Limited1
OEL US Inc.
Origin Energy NSW Pty Limited1
Origin Energy Asset Management Limited1
Origin Energy Pipelines Pty Limited1
Origin Energy Pipelines (SESA) Pty Limited
Origin Energy Pipelines (Vic) Holdings Pty Limited1
Origin Energy Pipelines (Vic) Pty Limited1
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 Limited1
Oil Investments Pty Limited1
Origin Energy Southern Africa Holdings Pty Limited
Origin Energy Zoca 91-08 Pty Limited1
Sagasco NT Pty Ltd1
Sagasco Amadeus Pty Ltd1
Origin Energy Amadeus Pty Limited1
Amadeus United States Pty Limited1
Origin Energy Vietnam Pty Limited
Origin Energy Singapore Holdings Pte Limited
Origin Energy (Song Hong) Pte Limited
Origin Future Energy Pty Limited
Origin Energy Metering Coordinator Pty Ltd
Origin Energy Resources NZ (Rimu) Limited
Origin Energy VIC Holdings Pty Limited1
Origin Energy Capital Ltd1
Origin Energy Finance Company Pty Limited1
OE JV Co Pty Limited1
Origin Energy LNG Holdings Pte Limited
Origin Energy LNG Portfolio Pty Ltd1
Origin Energy Australia Holding BV2
Origin Energy Mt Stuart BV2
OE Mt Stuart General Partnership2
Parbond Pty Limited
Origin Education Foundation Pty Limited
Origin Energy Foundation Ltd
Incorporated in
Ownership interest per cent
2021
2020
NSW
NSW
SA
Vic
NSW
WA
SA
USA
NSW
SA
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
NSW
NZ
Vic
Vic
Vic
Vic
Singapore
Vic
Netherlands
Netherlands
Netherlands
NSW
Vic
NSW
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
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
1 Entered into ASIC Corporations (Wholly-owned Companies) Instrument 2016/785 and related Deed of Cross Guarantee with Origin Energy Limited.
2 Controlled entity has a financial reporting period ending 31 December.
124
Annual Report 2021
F1 Controlled entities (continued)
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.1
Origin Energy Geothermal Chile Limitada1
Origin Energy Wind Holdings Pty Ltd
Crystal Brook Wind Farm Pty Limited
Wind Power Pty Ltd
Origin Energy Hydro Bermuda Limited
Origin Energy Hydro Chile SpA1
1 Controlled entity has a financial reporting period ending 31 December.
Changes in controlled entities
Incorporated in
Ownership interest per cent
Vic
Vic
Vic
Vic
Vic
Vic
Chile
Chile
Vic
NSW
Vic
Bermuda
Chile
2021
100
-
100
100
100
100
100
-
100
-
100
100
-
2020
100
100
100
100
100
100
100
100
100
100
100
100
100
On 16 July 2020, Origin Energy CSG 2 Pty Limited changed its name to Origin Energy C6 Pty Limited.
The following entities were deregistered on 5 August 2020:
• Amadeus United States Pty Limited;
• Origin Energy Amadeus Pty Limited;
• Sagasco Amadeus Pty Ltd; and
• Sagasco NT Pty Ltd.
The following entities were deregistered on 19 August 2020:
• Origin Renewable Energy Investments No 2 Pty Ltd;
• BESP Pty Ltd;
• Crystal Brook Wind Farm Pty Limited;
• Origin Energy Mortlake Terminal Station No. 2 Pty Limited; and
• Origin Energy Pipelines (SESA) Pty Limited.
On 1 September 2020, Origin Future Energy Pty Ltd transferred its shares in Energy Rewards Pty Ltd to Origin Energy Upstream Holdings
Pty Ltd.
On 3 September 2020, Origin Energy Rewards Pty Ltd changed its name to Origin Energy Future Fuels Pty Ltd.
On 15 December 2020, Origin Energy West Pty Ltd was incorporated.
On 17 December 2020, Horan & Bird Energy Pty Ltd was sold.
The following entities were deregistered on 15 March 2021:
• Origin Energy Capital Ltd;
• Origin Energy Finance Company Pty Limited;
• Origin Energy Pipelines (Vic) Pty Limited;
• Origin Energy Pipelines (Vic) Holdings Pty Ltd;
• Origin Energy NSW Pty Limited;
• Origin Energy Zoca 91-08 Pty Limited; and
• B.T.S. Pty Ltd.
On 21 April 2021, Origin Energy Eraring Battery Pty Ltd was incorporated.
On 12 May 2021, Origin Energy Education Foundation Pty Limited was deregistered.
On 23 June 2021, Origin Energy Geothermal Chile Limitada was wound up.
On 30 June 2021, Origin Energy Hydro Chile SpA was wound up.
Financial Statements
125
F2 Business combinations
There were no significant business combinations during the year.
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 on the Group at
30 June 2021 (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
• Canning Basin
•
Innamincka Deeps Geothermal
• Cooper-Eromanga Basin
On 18 December 2020, the Group reached an agreement with Buru Energy to acquire its 50 per cent interest in five exploration permits
following the execution of a farm-in arrangement, and a 40 per cent interest in two permits with Buru Energy and Rey Resources that was
effective from 15 April 2021. Buru Energy is the operator of these permits and will continue to act in this capacity upon completion.
126
Annual Report 2021
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 Financial
Instruments and has been initially recognised at fair value (refer to note C7) with reference to the guarantee amount in the facility agreement.
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 that are 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.
G2 Commitments
Detailed below are the Group's contractual commitments that are not recognised as liabilities as there is no present obligation.
Capital expenditure commitments
Joint venture commitments1
1
Includes $135 million (2020: $269 million) in relation to the Group's share of APLNG’s capital and joint venture commitments.
2021
$m
107
208
2020
$m
109
340
Financial Statements
127
G3 Share-based payments
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 (ESP).
The table below shows share-based remuneration expenses that were recognised during the year.
Equity Incentive Plan
Employee Share Plan
Total
2021
$m
24
4
28
2020
$m
30
4
34
Equity Incentive Plan
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 FY2018 were offered in the form of Options and/or Share Rights. From FY2019 onwards, equity incentives are granted in the form of
Share Rights and/or Restricted Shares (RSs). Only RSs carry dividend and voting entitlements. To the extent that Share Rights ultimately vest,
a dividend equivalent mechanism operates.
(i) Short Term Incentive
Short Term Incentive (STI) includes the award of RSs, which are subject to trading restrictions for a set period of time (generally up to
two years), after which they become unrestricted, provided that the employee remains employed with satisfactory performance. 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
The Long Term Incentive (LTI) awards include the award of Share Rights, which vest subject to performance conditions. Generally half of each
LTI award is made in the form of Performance Share Rights (PSRs) and is subject to a market hurdle, namely Origin’s Total Shareholder Return
(TSR) relative to a Reference Group of ASX-listed companies, as identified in the 2021 Remuneration Report. The remaining half of each LTI
award is made in the form of Restricted Share Rights (RSRs), where vesting is subject to Board assessment with reference to, 'underpinning
conditions', as set out in the 2021 Remuneration Report.
The number of awards that may vest are considered separately for PSRs and RSRs. For the PSR awards, which are 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. The PSR grants made in FY2021 have a performance period of three years. Vesting is
into RSs with a trading restriction for a further two years (total deferral five years). For the RSR awards, the Board will determine the vesting
outcome shortly before each of three progressive vesting dates at years three, four and five by reference to a broad range of performance
indicators. Vesting is into RSs which all have trading restrictions until the end of the fifth year.
Prior to FY2021, the LTI awards include the award of PSRs, such that half of the award is subject to the TSR hurdle, and 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.
For awards granted in FY2017 and FY2018 that are subject to a ROCE hurdle, which are subject to testing or vesting in FY2021, 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 is allocated to Energy Markets
and the other half 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.
Vested share rights are automatically exercised upon vesting, and there is no exercise price. Upon exercise, 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 up to two years) and carries voting and
dividend entitlements.
In relation to SRs awarded since FY2021, upon vest, a dividend equivalent amount will be delivered in the form of additional shares equal
in value (as determined by the Board) to the amount of dividends that would have been paid and re-invested had the participant held the
underlying shares during the period from the grant date through to the relevant vesting date.
1 The Equity Incentive Plan Rules set out exceptional circumstances, such as death, disability, redundancy or genuine retirement, (‘good leaver’ circumstances) under which
RSs are released 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).
128
Annual Report 2021
G3 Share-based payments (continued)
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 circumstances1 , unvested Share Rights 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 RSRs subject to the underpinning conditions, the initial fair value at grant date is the market value of an Origin share, and the recognised
expense is trued up at each reporting period to the expected outcome as assessed at that time.
Set out below is a summary of RSRs and PSRs issued during the financial year.
Grant date
Grant date share price
Exercise price
Volatility
Risk-free rate1
Grant date fair value (per award)
RSRs
PSRs
03 Nov 2020
03 Nov 2020
$4.28
Nil
-
-
$4.28
$4.28
Nil
35%
0.10%
$1.37
1 Where the risk-free rate is nil, these RSR tranches are subject to a number of underpinning conditions to be assessed by the Board; therefore, the risk-free rate is not relevant
to their valuation.
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 2020
Granted
Exercised/released
Forfeited
Options
3,259,381
-
-
154,160
Weighted
average
exercise
price
$6.33
-
-
-
PSRs
6,243,467
1,044,581
563,432
1,054,312
Outstanding at 30 June 2021
3,105,221
$6.32
5,670,304
Exercisable at 30 June 2021
-
-
-
Outstanding at 1 July 2019
5,565,803
$6.51
Granted
Exercised
Forfeited
Outstanding at 30 June 2020
Exercisable at 30 June 2020
-
-
2,306,422
3,259,381
-
5,126,670
2,346,098
-
1,229,301
-
-
-
$6.33
6,243,467
-
-
RSRs
-
1,056,609
DSRs
213,038
-
-
167,482
RSs
4,523,573
4,216,362
1,758,548
286,232
61,440
995,169
-
-
-
-
-
-
-
-
45,556
6,695,155
-
-
1,920,849
1,867,476
-
3,005,423
1,705,133
2,678
256,173
93,153
213,038
4,523,573
-
-
The weighted average share price during 2021 was $4.75 (2020: $6.80). The options outstanding at 30 June 2021 have an exercise price in
the range of $5.21 to $7.37 (2020: $5.21 to $7.37) and a weighted average contractual life of 5.6 years (2020: 6.6 years).
For more information on these share plans and performance rights issued to key management personnel, refer to the Remuneration Report.
Employee Share Plan
Under the 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.
1 The Equity Incentive Plan Rules provide that Share Rights, and RSs arising from STI arrangements, are forfeited on cessation of employment, except in ‘good leaver’
circumstances or unless the Board determines otherwise. The offer terms provide guidance for the exercise of that discretion, specifically that the Share 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).
Financial Statements
129
G3 Share-based payments (continued)
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 a 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 MRs
which vest at the same time as 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
Details of the shares awarded under the GESP during the year are set out below. The cost per share represents the weighted average market
price of the Company's shares on the grant date.
2021
2020
Grant
date
28 Aug 2020
3 Sep 2019
Shares
granted
703,794
703,794
528,264
528,264
Cost per
share
$5.49
$7.55
Total
Total
Set out below is a summary of MRs outstanding at the beginning and end of the financial year.
Outstanding at 1 July 2020
Granted
Exercised/released
Forfeited
Outstanding at 30 June 2021
Exercisable at 30 June 2021
G4 Related party disclosures
Total cost
$'000
3,864
3,864
3,988
3,988
MRs
228,541
299,315
139,577
12,384
375,895
-
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
Total
2021
$
2020
$
10,344,127
11,619,739
289,963
225,909
262,538
136,474
4,133,424
5,124,047
14,993,423
17,142,798
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 and Equity Incentive 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.
1 The Equity Incentive Plan Rules provide that Share Rights, and RSs arising from STI arrangements, are forfeited on cessation of employment, except in ‘good leaver’
circumstances or unless the Board determines otherwise. The offer terms provide guidance for the exercise of that discretion, specifically that the Share 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).
130
Annual Report 2021
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.
(Loss)/profit for the year
Adjustments for non-cash ITDA
Depreciation and amortisation
Net financing costs
Income tax expense
Non-cash share of ITDA of equity accounted investees1
Adjustments for other non-cash items
Decrease/(increase) in fair value of derivatives
Decrease/(increase) in fair value of financial instruments
Unrealised foreign exchange gain
Impairment of assets1,2
Loss/(gain) on sale of assets
Impairment losses recognised - trade and other receivables
Non-cash share of EBITDA of equity accounted investees1
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
1 Refer to the Overview for details of prior year reclassification.
2 Refer to note C8 for further details.
Reconciliation of movements of liabilities to cash flows arising from financing activities
$m
Balance as at 1 July 2020
Repayment of borrowings/other liabilities
Foreign exchange adjustments
Reclassification
Other non-cash movements
Balance as at 30 June 2021
Liabilities from financing activities
Current
borrowings
Non-current
borrowings
Lease
liabilities
Other financial
(assets)/
liabilities
1,328
(1,348)
(114)
2,068
4
1,938
5,010
-
(120)
(2,068)
5
2,827
514
(76)
(2)
-
27
463
(440)
306
-
-
53
(81)
2021
$m
(2,289)
550
133
443
958
366
163
(153)
1,828
11
88
2020
$m
86
509
126
93
1,262
(275)
(123)
-
668
(1)
124
(1,153)
(1,774)
1
24
(398)
50
450
(178)
(71)
110
31
3,253
964
3
30
217
(26)
(180)
663
104
(340)
(215)
865
951
Total
6,412
(1,118)
(236)
-
89
5,147
Financial Statements
131
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 compliance1
Cyber security
Advisory services2
Sustainability compliance
Other
Total
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
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
2021
$'000
1,998
73
9
823
-
900
141
-
2020
$'000
1,750
173
9
767
155
140
-
4
3,944
2,998
69
69
4,013
169
4,182
69
69
3,067
247
3,314
1 This amount relates to the Group's share of tax compliance work billed. An amount of $800,000 (2020: $701,000) was recharged to APLNG in respect of its share and is
excluded from this amount.
2 The fees for non-audit services paid to the auditor of the Parent Company (EY) have increased in the current year. This is a one-off occurrence due to transactional activities
that took place in the prior year. As part of the acquisition of Octopus Energy and the associated retail transformation process, an external consulting firm was engaged by
the Group to undertake advisory services in respect of this acquisition. In June 2020, midway through the project, the firm engaged by the Group was acquired by EY. As
the Group decided it was in the best interest for the project to continue, the audit committee agreed to a one-off approval allowing for continuation of the work, provided the
time period and fees were limited. This project completed in the current year and therefore these costs will not reoccur going forward.
132
Annual Report 2021
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.
2021
Derivative assets
Derivative liabilities
2020
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
Gross amount
$m
1,488
(1,600)
1,543
(1,600)
(353)
353
(385)
385
1,135
(1,247)
1,158
(1,215)
(867)
867
(650)
650
Net
amount
$m
268
(380)
508
(565)
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 investees1
Impairment1
Interest income
Interest expense
(Loss)/profit before income tax
Income tax expense
(Loss)/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 16 Leases adoption
Dividends paid
Retained earnings at the end of the year
1 Refer to the Overview for details of prior year reclassification.
2021
$m
2020
$m
11,966
15
(12,638)
228
(1,783)
109
(261)
(2,364)
(510)
(2,874)
-
(2,874)
5,604
-
5,604
-
(396)
2,334
13,000
47
(12,314)
523
(669)
189
(356)
420
(72)
348
-
348
5,433
2
5,435
349
(528)
5,604
Financial Statements
133
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
Other financial assets
Income tax receivable
Other assets
Total current assets
Non-current assets
Trade and other receivables
Derivatives
Other financial assets1
Investments accounted for using the equity method
PP&E
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
Total current liabilities
Non-current liabilities
Trade and other payables
Interest-bearing liabilities
Derivatives
Deferred tax liabilities
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.
2021
$m
2020
$m
286
3,304
102
667
491
7
117
1,042
2,916
152
510
479
89
104
4,974
5,292
1,537
302
1,074
6,543
3,077
4,357
-
47
16,937
21,911
2,711
525
1,842
6,979
4,060
5,394
360
40
21,911
27,203
2,443
2,273
169
72
523
311
1
221
38
202
74
448
204
2
153
153
3,778
3,509
5,314
926
402
291
44
1,177
8,154
11,932
9,979
7,138
507
2,334
9,979
7,204
1,001
729
-
21
1,269
10,224
13,733
13,470
7,145
721
5,604
13,470
134
Annual Report 2021
G10 Parent entity disclosures
The following table sets out the results and financial position of the parent entity, Origin Energy Limited.
Origin Energy Limited
(Loss)/profit before income tax
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
Fair value reserve
Retained earnings1
Total equity
2021
$m
(1,428)
(657)
(2,085)
271
16,771
17,042
3,364
3,626
6,990
7,138
226
189
(33)
3
2,529
10,052
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
12,537
1 Refer to note A7 for details of dividends provided for or paid of $396 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 2021 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.
Dividends
On 19 August 2021, the Directors determined an unfranked final dividend of 7.5 cents per share on ordinary shares. The dividend will be paid
on 1 October 2021. The financial effect of this dividend has not been brought to account in the financial statements for the year ended 30 June
2021 and will be recognised in subsequent financial statements.
Financial Statements
135
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 2021 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 2021.
Signed in accordance with a resolution of the Directors:
Scott Perkins
Chairman Director
Sydney, 19 August 2021
136
Annual Report 2021
Independent Auditor’s Report
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 Independent 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 2021, 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 2021 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. Financial Statements
137
Carrying Value of the Energy Markets Group of Cash Generating Unit (CGU) Why significant How our audit addressed the key audit matter In accordance with the requirements of Australian Accounting Standards, the Group is required to test all CGUs annually for impairment where goodwill is present. The Group assesses the recoverable amount of each CGU using a discounted cash flow forecast to determine value in use. As disclosed in Note C8 to the financial statements, as a result of changing market conditions and reduced pricing forecasts, the Group has recognised a $1,828 million impairment charge on its Retail and Generation CGUs, which form part of the Energy Markets group of CGUs. Assumptions used in the forecast cash flows are highly judgmental and inherently subjective. As disclosed in Note C8, small changes in key assumptions can lead to significant changes in the recoverable amount of these assets. As a result, we considered the impairment testing of the Energy Markets group of CGUs and the related disclosures in the financial report to be particularly significant to our audit. Our audit procedures included the following: • Assessed whether the methodology used by the Group met the requirements of Australian Accounting Standards. • Assessed the basis for the determination of the Group’s CGUs based on our understanding of the nature of the Group’s business, the interdependence of cash flows, and the economic environment in which it operates. • Tested the mathematical accuracy of the discounted cash flow models. • Assessed the cash flow forecasts with reference to historical budgeting accuracy and current trading performance, historical growth rates, historical operating results, market data and forecasts, ratio analysis, and discussions with Origin management and senior executives. • Where long term supply or sales contracts are in place, agreed the forecast revenue and costs to the contract terms and rates. • For Generation, compared the useful lives of assets to AEMO closure dates. • Involved our energy market modelling specialists to assess the conclusions reached by the Group’s internal specialists in respect of forecast energy prices, forecast generation volumes, cap revenue and marginal loss factors. • Involved our valuation specialists to: o Assess the discount rates, growth rates and terminal growth rates with reference to publicly available information on comparable companies in the industry and markets in which the Group operates; and o Perform sensitivity analyses and evaluated whether any reasonably possible changes in assumptions could cause the carrying amount of the cash generating unit to exceed its recoverable amount. • Evaluated the adequacy of the related disclosure in the financial report. 138
Annual Report 2021
Carrying Value of the APLNG Equity Accounted Investment Why significant How our audit addressed the key audit matter At 30 June 2021, the Group’s equity accounted investment in APLNG had a carrying value of $6,532 million. The Group estimated the recoverable amount of this investment, using a fair value less cost of disposal (FVLCD) approach and concluded that no impairment or impairment reversal was required. As disclosed in Note B2.2, 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, as the COVID-19 pandemic has brought, 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. Due to the significance of this investment 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: • Considered whether indicators of impairment (or reversal) were present in respect of the equity accounted investment. • 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 headroom implied in the model. • 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: o Comparison of forecast operating costs to APLNG’s recent operating cost history; o Consideration of timing and amount of forecast capital costs with reference to: ▪ APLNG’s gas production profile, its existing inventory of producing wells and forecast development of production wells; and ▪ UDPs from previous financial years; o Understood 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 2021; and o Evaluated the competence, capabilities and objectivity of the internal and external experts used by the Group to measure its gas reserves and resources. • Considered available market information including trading and reserve multiples as a cross check of the carrying value of Origin’s equity accounted investment. Financial Statements
139
APLNG Deferred Tax Liability Why significant How our audit addressed the key audit matter At 30 June 2021 the Group recognised a deferred tax liability (DTL) of $669 million in respect of the temporary taxable difference arising on its equity accounted investment in APLNG. $810 million remains unrecognised. As disclosed in Note E1, the amount recognised represents the equity accounted earnings that are expected to be distributed to Origin via dividends from APLNG in the foreseeable future. The determination of the value of the DTL recognised requires a significant degree of judgment in forecasting future dividends and profits from APLNG over the foreseeable future. The future cash flow modelling performed for the Carrying Value of APLNG Equity Accounted Investment assessment (as outlined above) forms the basis of this assessment. As a result of the level of judgment required and the value of the DTL recognised, we considered this a key audit matter. Our audit procedures included the following: • Evaluated whether the methodology applied in determining the value of the DTL recognised, complied with the requirements of Australian Accounting Standards. • Recalculated the total taxable temporary difference with reference to the carrying value of the investment in APLNG at 30 June 2021 and the tax cost base. • Assessed the forecast future dividends and forecast future profits from APLNG, using the cash flow modelling prepared and referred to above as part of the Carrying Value of APLNG Equity Accounted Investment assessment. • Tested the clerical accuracy of the $669 million DTL recognised based on the forecast dividends from APLNG and timing of when those dividends will be paid out of existing equity accounted earnings. • Assessed the timeframe the Group has applied when forecasting the expected dividends, including assessing the appropriateness of major operating and capex decisions and sales contracts currently in place. • Evaluated the adequacy of the related disclosure in the financial report. Unbilled Revenue Why significant How our audit addressed the key audit matter At 30 June 2021, the Group recognised unbilled revenue net of allowance for impairment of $1,444 million as disclosed in Note C1. 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. Key factors that require consideration impacting the complex estimation process include: Our audit procedures included the following: • Assessed whether the methodology used to recognise unbilled revenue met the requirements of Australian Accounting Standards. • Assessed the effectiveness of the Group’s controls governing energy purchased, energy sold and the customer pricing process. • Tested the unbilled revenue calculation by: o With the assistance of specialists, assessing the calculation methodology and calculation mechanics. o Comparing inputs used in the calculation to supporting data such as historical temperature data and volume data provided by the Australian Energy Market Operator (AEMO). o Compared the prices applied to customer consumption with historical and current data. 140
Annual Report 2021
Unbilled Revenue (continued) Why significant How our audit addressed the key audit matter • 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 due to the ongoing impacts of COVID-19. The Group’s disclosures in respect of the unbilled revenue estimation process are included in Note C1 of the financial report. o Reviewed the Group’s reconciliation of volumes acquired from AEMO against volumes sold and volumes purchased as used by the Group in their analysis. o Compared the accuracy of the unbilled revenue accrual by comparing the historical accrual to final billing data and performing a trend analysis of the accrual year on year. o Tested the accuracy of the unbilled revenue accrual for business customers by comparing the unbilled revenue accrual to subsequent invoices. • 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 2021 annual report, but does not include the financial report and our auditor’s report thereon. Our opinion on the financial report does not cover the other information and accordingly we do not express any form of assurance conclusion thereon. 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, 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. Financial Statements
141
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. 142
Annual Report 2021
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 2021. In our opinion, the Remuneration Report of Origin Energy Limited for the year ended 30 June 2021, 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 19 August 2021 Share and Shareholder Information
143
Share and Shareholder
Information
The information set out below was applicable as at 30 July 2021.
Corporate Governance Statement
The Company’s Corporate Governance Statement can be found on its website at originenergy.com.au/about/investors-media/governance
Substantial shareholders
As at 30 July 2021, 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 30 July 2021 there were:
•
157,585 holders of 1,761,211,071 ordinary shares in the Company;
• 23 holders of 3,105,221 Options, 77 holders of 5,596,599 Performance Share Rights, 1 holder of 45,556 Deferred Share Rights, 58 holders
of 984,324 Restricted Share Rights; and
• 710 holders of 371,801 Matching Share Rights.
Only ordinary shares of the Company are quoted. Only holders of ordinary shares are entitled to attend and vote at a meeting of members.
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 2021 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
Options
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
65,885
64,561
16,211
10,637
28,651,000
158,181,891
116,344,886
222,768,606
291
1,235,264,688
%
1.63
8.98
6.61
12.65
70.14
157,585
1,761,211,071
100.00
Holders
Total Units
0
0
0
12
11
23
0
0
0
786,499
2,318,722
3,105,221
%
0.00
0.00
0.00
25.33
74.67
100.00
144
Annual Report 2021
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
Restricted 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
12,214 shareholders held less than a marketable parcel as at 30 July 2021.
Holders
Total Units
0
0
0
1
0
1
0
0
0
45,556
0
45,556
Holders
Total Units
0
0
7
59
11
77
0
0
47,247
2,584,385
2,964,967
5,596,599
Holders
Total Units
0
0
25
32
1
58
0
0
152,988
647,922
183,414
984,324
%
0.00
0.00
0.00
100.00
0.00
100.00
%
0.00
0.00
0.84
46.18
52.98
100.00
%
0
0
15.54
65.82
18.63
100.00
Holders
Total Units
%
710
371,801
100.00
0
0
0
0
0
0
0
0
0.00
0.00
0.00
0.00
710
371,801
100.00
Share and Shareholder Information
145
Top 20 holdings
Shareholder
J P MORGAN NOMINEES AUSTRALIA PTY LIMITED
HSBC CUSTODY NOMINEES (AUSTRALIA) LIMITED
CITICORP NOMINEES PTY LIMITED
NATIONAL NOMINEES LIMITED
BNP PARIBAS NOMINEES PTY LTD
BNP PARIBAS NOMS PTY LTD
CITICORP NOMINEES PTY LIMITED
ARGO INVESTMENTS LIMITED
BNP PARIBAS NOMINEES PTY LTD SIX SIS LTD
HSBC CUSTODY NOMINEES (AUSTRALIA) LIMITED
CERTANE CT PTY LTD
CERTANE CT PTY LTD
NETWEALTH INVESTMENTS LIMITED
AUSTRALIAN FOUNDATION INVESTMENT COMPANY LIMITED
BNP PARIBAS NOMINEES PTY LTD
THE SENIOR MASTER OF THE SUPREME COURT
AMP LIFE LIMITED
BOND STREET CUSTODIANS LIMITED
BRISPOT NOMINEES PTY LTD
FIRST SAMUEL LTD ACN 086243567
Securities exchange listing
Number of shares
% of issued shares
424,959,024
422,095,849
133,425,054
51,359,297
23,371,868
13,989,026
12,307,849
11,351,603
10,447,814
10,005,432
7,348,901
6,109,232
6,086,166
6,000,000
5,389,715
3,850,660
3,000,820
2,343,971
2,253,019
1,875,737
24.13%
23.97%
7.58%
2.92%
1.33%
0.79%
0.70%
0.65%
0.59%
0.57%
0.42%
0.35%
0.35%
0.34%
0.31%
0.22%
0.17%
0.13%
0.13%
0.11%
Origin shares are traded on the AustralianSecurities 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 perio, 8,886,660 Origin shares were purchased on-market for the purpose of Origin’s employee incentive plans. The
average price per share purchased was $4.61.
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 www.originenergy. com.au/
about/investors-media
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.
146
Annual Report 2021
Exploration and
Production Permits
and Data
NTOrigin permitAPLNG permitProduction facilityPipelinePipelineOrigin Energy InterestsOther (Non Origin)WASANSWQLDNTTASQueenslandWADerbyBroomeBrowse IslandCapeVoltaireAdele IslandCape LevequeCape BaskervilleIndian OceanSAQLD1 Surat/Bowen Basin2 Cooper- Eromanga Basin3 Beetaloo Basin4 Browse Basin Canning Basin1234 Exploration and Production Permits and Data
147
1 Origin's Australian interests
Origin held interests in the following permits at 30 June 2021.
Basin/Project Area
Interest
Basin/Project Area
Interest
Basin/Project Area
Interest
Queensland (continued)
Queensland (continued)
Queensland
Surat/Bowen basins
Angry Jungle
ATP 631; PLs 281 and 282
6.79%
1
Carinya and Ramyard
ATP 972; PL 470; PL(A)s
469 and 471
34.77%
* 1
ATP 973
37.50%
* 1
Gladstone LNG
PFL 20
PPLs 162 and 163
Ironbark
ATP 788; PL(A) 1106
(Deeps)
ATP 788; PL(A) 1106
(Shallows)
37.50%
37.50%
1
* 1
9.38%
* 1
37.50%
* 1
Combabula/Reedy Creek/Peat and
Taroom East
Kenya/Kenya East/Bellevue and Anya
ATP 2047
ATP 606; PLs 297, 403,
404, 405, 407, 408,
412, and 413; PL(A)s 406
and 444
PL 101
PPL 178
Condabri
PLs 265, 266, 267, 1011,
1018 and 1084
PPLs 177, 185, 186, 2000
and 2059
Denison Trough
ATP 1191 Farm-out
(Mahalo block)
PLs 1082 and 1083
(Mahalo block)
18.75%
34.77%
37.50%
37.50%
1
* 1
* 1
* 1
37.50%
* 1
PL 247
PFL 19
PL 1025
PLs 257, 273, 274, 275,
278, 279, 442, 466, 474
and 503 (Shallows)
PLs 179, 180, 228, 229
and 263
PPLs 107, 176, 2014
and 2063
11.02%
11.72%
11.72%
11.72%
15.23%
15.23%
1
1
1
1
1
1
37.50%
* 1
Membrance and Lonesome
ATP 804
PLs 219 and 220
10.99%
37.50%
1
* 1
11.25%
1
Spring Gully
11.25%
* 1
ATP 1191; PLs 450, 451, 457
and 1012; PL(A) 1062
18.75%
PL 1083
PLs 43, 44, 45, 183 and
218 (Deeps)
18.75%
18.75%
Fairview and Arcadia
ATPs 745 and 2033;
PLs 420, 421 and 440;
PL(A) 1059
ATPs 526 and 2012; PLs
90, 91, 92, 99, 100, 232,
233, 234, 235 and 236;
PL(A) 1017
8.94%
8.97%
1
* 1
* 1
1
1
ATP 592; PLs 195, 268,
414, 415, 416, 417 and 418;
PL(A) 419
35.44%
* 1
PL 200
PL 204
35.89%
37.40%
PPLs 143, 180 and 2026
37.50%
* 1
* 1
* 1
Talinga and Orana
ATP 692; PLs 209, 215,
216, 225, 226 and 272;
PL(A) 445
37.50%
* 1
PFL 26
PPLs 171, 181 and 2032
37.50%
37.50%
* 1
* 1
Cooper-Eromanga Basin
ATPs 736, 737, 738, 2025
and 2026
75.00%
PL(A)s 1094, 1095, 1096,
1097, 1098, 1099, 1100,
1101, 1102, 1103 and 1104
99.00%
ATP 784
100%
*
*
*
Northern Territory
Beetaloo Basin
EPs 76, 98 and 117
77.50%
*
Western Australia
Browse Basin
TR/7 and TR/8; WA-90-R,
WA-91-R and WA-92-R
40.00%
Canning Basin
EPs 129, 391, 428, 431
and 436
50.00%
South Australia
Geothermal
GRL 3
30.00%
Notes:
* Operatorship
1 Interest held through 37.5 per cent
ownership of Australian Pacific LNG
Joint Venture
148
Annual Report 2021
Annual
Reserves Report
For the year ended 30 June 2021
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 2021.
1.1 Highlights
APLNG (Origin 37.5 per cent share)
• Strong field performance resulted in 94 per cent 2P (proved plus probable) reserves replacement in both operated and non-operated
areas. During FY2021, APLNG also achieved record daily production rates on two occasions. A detailed breakdown of movements in
Origin’s share of APLNG 2P reserves is as follows:
– 211 PJ (6 per cent) upward revision of operated 2P reserves before production reflecting strong field performance, resulting in improved
estimated recovery from producing fields and maturation of resources to reserves;
– 35 PJ (5 per cent) increase in non-operated 2P reserves before production, primarily due to improved field performance in several
areas; and
– 263 PJ of production that was stable with FY2020 despite a significant reduction in development activity and costs.
• 2P reserve life of 16 years as at 30 June 2021, based on FY2021 annual production of 701 PJ.
• 2P reserves replacement of 90 per cent in operated fields over the last four years, primarily driven by strong performance in producing
fields, along with additional areas shown to be feasible for development through appraisal activities.
• Developed 2P reserves accounted for 60 per cent of total 2P reserves as at 30 June 2021.
• Origin’s share of 1P (proved) reserves has continued to grow, with an increase of 9 per cent or 249 PJ before production as a result of
development drilling. 1P reserves represent 60 per cent of total 3P (proved plus probable plus possible) reserves as at 30 June 2021.
• 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.
1.2 2P reserves (Origin share)
2P reserves decreased by 16 PJ after production to a total of 4,252 PJ, compared to 30 June 2020.
Origin 2P reserves by area
APLNG (PJ)
Operated Assets
Spring Gully & Denison Asset
Condabri, Talinga & Orana Asset
Reedy Creek, Combabula & Peat Asset
Non-Operated Assets
Total 2P
2P
30/06/2020
Acquisition/
divestment
New booking/
discovery
Revisions/
extensions
Production
2P
30/06/2021
3,577
624
1,411
1,542
691
4,268
-
-
-
-
-
-
-
-
-
-
-
-
211
4
151
57
35
247
(201)
(36)
(99)
(66)
(61)
(263)
3,587
591
1,463
1,533
665
4,252
• Summary of 2P reserves movement - key changes include:
– 263 PJ decrease due to production;
– 211 PJ positive revision across all operated areas, reflecting;
– improved understanding of field behaviour, coupled with strong field performance, which resulted in an increase in estimated
recovery from producing fields in Combabula-Reedy Creek, Condabri and Talinga Orana areas; and
– the maturation of new areas from resources to reserves including Ramyard South (within Reedy Creek, Combabula and Peat) and
the Spring Gully East Flank (within Spring Gully and Denison) following successful appraisal activities; and
– 35 PJ increase in non-operated areas, primarily due to improved field performance in several areas.
• As at 30 June 2021, developed 2P reserves represented 60 per cent of total 2P reserves.
• As at 30 June 2021, 100 per cent of Origin’s share of 2P reserves are unconventional gas located in the Surat and Bowen Basins.
Annual Reserves Report
149
Origin 2P reserves by development type
APLNG (PJ)
Operated Assets
Spring Gully & Denison Asset
Condabri, Talinga & Orana Asset
Reedy Creek, Combabula & Peat Asset
Non-Operated Assets
Total 2P
1.3 1P reserves (Origin share)
Developed
Undeveloped
30-6-2020
Developed
Undeveloped
30-6-2021
Total 2P
Total 2P
2,094
1,483
442
976
676
394
2,488
182
435
866
297
1,780
3,577
624
1,411
1,542
691
4,268
2,173
453
1,031
689
393
2,566
1,414
138
432
844
273
1,686
3,587
591
1,463
1,533
665
4,252
1P reserves increased by 249 PJ or 9 per cent before production and decreased by 14 PJ after production to 2,755 PJ, compared to
30 June 2020.
As at 30 June 2021, developed 1P reserves represented 88 per cent of total 1P reserves. The remaining 12 per cent of 1P reserves represents
wells that have been spudded but not connected or planned wells that are immediately adjacent to drilled wells. 100 per cent of 1P reserves
are unconventional gas located in the Surat and Bowen Basins.
Origin 1P reserves by area
APLNG (PJ)
Operated Assets
Spring Gully & Denison Asset
Condabri, Talinga & Orana Asset
Reedy Creek, Combabula & Peat Asset
Non-Operated Assets
Total 1P
Origin 1P reserves by development type
1P
30/06/2020
Acquisition/
divestment
New booking/
discovery
Revisions/
extensions
Production
1P
30/06/2021
2,243
456
1,026
761
526
2,769
-
-
-
-
-
-
-
-
-
-
-
-
161
(8)
196
(27)
88
249
(201)
(36)
(99)
(66)
(61)
(263)
2,203
412
1,124
667
553
2,755
APLNG (PJ)
Operated Assets
Spring Gully & Denison Asset
Condabri, Talinga & Orana Asset
Reedy Creek, Combabula & Peat Asset
Non-Operated Assets
Total 1P
Developed
Undeveloped
30-6-2020
Developed
Undeveloped
30-6-2021
Total 1P
Total 1P
2,091
442
975
674
387
2,478
152
14
51
87
139
291
2,243
456
1,026
761
526
2,769
2,046
402
1,020
624
383
2,428
157
10
104
43
170
327
2,203
412
1,124
667
553
2,755
1.4 2C contingent resources for Origin Energy
Beetaloo Basin
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 the Beetaloo
Basin asset.
150
Annual Report 2021
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 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/resource classification
30/06/2020
Acquisition/
divestment
New booking/
discovery
Revisions/
extensions
Production
30/06/2021
1P (proven)
2P (proven plus probable)
3P (proven plus probable plus possible)
2C (best estimate contingent resource)
7,384
11,381
12,071
3,980
-
-
-
-
-
-
-
-
665
658
834
(378)
(701)
(701)
(701)
-
7,348
11,339
12,204
3,602
Reserves and resources held by Origin (37.5 per cent in APLNG)
Reserves/resource classification
30/06/2020
Acquisition/
divestment
New booking/
discovery
Revisions/
extensions
Production
30/06/2021
1P (proven)
2P (proven plus probable)
3P (proven plus probable plus possible)
2C (best estimate contingent resource)
2,769
4,268
4,526
1,493
-
-
-
-
-
-
-
-
249
247
313
(142)
(263)
(263)
(263)
-
2,755
4,252
4,576
1,351
See details above for movements in 1P and 2P reserves.
The 834 PJ increase in APLNG (100 per cent share) 3P reserves, excluding production is due to improved understanding of field behaviour,
coupled with strong field performance, which has resulted in an increase in estimated recovery from producing areas as well as maturation
of contingent resources to reserves through successful appraisal activities.
The 378 PJ decrease in APLNG (100 per cent share) 2C resources is primarily due to successful appraisal activities that allowed
maturation of resources to reserves, whilst also reflecting the decision by the operator of selected non-operated developments to sole
risk these developments.
Annual Reserves Report
151
Appendix B: Notes
relating to this report
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.
a. Methodology regarding reserves
c. Reversionary rights
and resources
The Reserves Report has been prepared
to be consistent with the Petroleum
Resources Management System (PRMS)
2018 published by the 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) and best estimate
contingent resource (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 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
e. Rounding
Information on reserves is quoted in this
report 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 "-".
f. Abbreviations
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
The CSG interests that APLNG acquired
from Tri-Star in 2002 are subject to
reversionary rights. If triggered, these
rights will require APLNG 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 APLNG claiming that
reversion has occurred. APLNG denies that
reversion has occurred and is defending
the claim.1
d. Information regarding the preparation
of this Reserves Report
h. Reference point
The CSG reserves and resources held
within APLNG’s properties have either
been independently prepared by NSAI or
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 at 30 June
2021 for APLNG’s interests in non-operated
assets are based on information in the NSAI
report dated 4 August 2021. The data has
been compiled by Mr John Hattner, a full-
time employee of NSAI. Mr 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 resource evaluators
who are employees of Origin.
This Reserves Statement as a whole has
been approved by Mr Alistair Jones CPEng
RPEQ, who is a full-time employee of
Origin. Mr Jones is Resource Assessment
Lead, a qualified petroleum reserves and
resources evaluator and a member of
the Society of Petroleum Engineers, has
consented to the form and context in which
these statements appear.
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 Resource Assessment Lead
and Integrated Gas General Managers.
1 Refer to Section 7 of the Operating and Financial Review released to the ASX on 19 August 2021 for further information.
152
Annual Report 2021
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)
Total external revenue
Underlying:
EBITDA2
Depreciation and amortisation expense
Share of interest, tax, depreciation and amortisation
of equity accounted investees3
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/(loss) 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
20211
20201
20191
20181
20171
12,097
13,157
14,727
14,883
14,107
2,048
(550)
(958)
540
(133)
(87)
(2)
318
(2,609)
3,141
(509)
(1,303)
1,329
(126)
(177)
(3)
1,023
(940)
3,232
(419)
(1,504)
1,308
(154)
(123)
(3)
1,028
3,217
(381)
(1,194)
1,642
(278)
(339)
(3)
1,022
2,530
(477)
(925)
1,128
(296)
(279)
(3)
550
183
(804)
(2,776)
(2,291)
83
1,211
218
(2,226)
21,037
4,786
9,795
4,639
9,815
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
1,183
1,813
1,914
2,645
1,378
Statutory basic earnings per share (cents)
(130.2)
Underlying basic earnings per share (cents)
Total dividend per share (cents)5
Net debt to net debt plus equity (adjusted) (%)4
Underlying EBITDA by segment ($m)
Energy Markets2
Integrated Gas
Corporate
General Information
Number of employees
18.1
20
32
991
1,135
(78)
4.7
58.1
25
29
1,459
1,741
(59)
68.8
58.4
25
29
1,574
1,892
(234)
12.4
58.2
-
36
1,811
1,521
(115)
(126.9)
31.3
-
42
1,492
1,104
(66)
Weighted average number of shares
1,759,555,663
1,759,801,186
1,758,935,655
1,757,442,268
1,754,489,221
4,979
5,232
5,360
5,565
5,894
Five-year Financial History
153
Integrated Gas6
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)
Energy Markets
Generation (MW) - owned
Generation dispatched (TWh)
Number of customers ('000)
Electricity
Natural gas
LPG
Broadband
Electricity (TWh)
Natural gas (PJ)
LPG (Kt)
20211
20201
20191
20181
20171
4,252
246
3,370
59
-
-
-
4,268
251
3,258
70
-
-
-
4,599
254
3,257
73
-
-
-
4,799
255
3,213
77
-
-
-
263
265
255
254
6,047
16
4,266
2,625
1,249
359
33
34
193
389
6,029
18
4,236
2,631
1,220
3658
20
34
204
417
6,029
20
4,2007
2,639
1,191
362
8
36
222
426
5,981
21
4,181
2,666
1,145
370
-
38
214
450
5,788
334
2,668
163
1,209
1,615
144
323
6,011
20
4,210
2,716
1,112
382
-
40
188
448
1
Includes discontinued operations and assets held for sale unless stated otherwise.
2 Since FY2019, EBITDA 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;
and FY2017 $(141) 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 Dividends represent the interim and final dividends determined for each FY. This includes the final dividend for FY21 determined on 19 August 2021 to be paid on 1 October
2021. The amounts paid within each FY are 22.5c, 30c ,10c, 0c and 0c respectively.
6 2018 excludes Lattice Energy (continuing operations basis shown).
7 Total number of customers restated to include Broadband customers
8 June 2020 LPG customer accounts restated to include ~2,500 Asia Pacific customer accounts
154
Annual Report 2021
Glossary
and Interpretation
Glossary
Statutory 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
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 4.1. The key Non-
IFRS financial measures included in this report are defined below.
Term
AASB
Adjusted
Net Debt
Adjusted
Underlying
EBITDA
Average
interest rate
Meaning
Australian Accounting Standards Board
Net Debt adjusted to remove fair value adjustments
on hedged borrowings
Origin Underlying EBITDA – Share of APLNG
Underlying EBITDA + net cash from APLNG over the
relevant 12 month period.
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.
FY21
(Current period)
FY20
(Prior period)
Gearing
Twelve months ended 30 June 2021.
Twelve months ended 30 June 2020.
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 4.1
for details.
MRCPS
Mandatorily Redeemable Cumulative
Preference Shares.
Non-cash fair
value uplift
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.
Underlying
EBITDA
Underlying earnings before underlying interest,
underlying tax, underlying depreciation and
amortisation (EBITDA) as disclosed in note A1 of the
Origin Consolidated Financial Statements.
Glossary and Interpretation
155
Term
Meaning
Term
Meaning
SME
TRIFR
TW
TWh
Watt
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
A measure of power when a one ampere of current
flows under one volt of pressure.
Interpretation
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 Group Limited in which Origin holds
a 20% 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.
Underlying
share of ITDA
Underlying
Profit/Loss
Underlying
ROCE (Return
on Capital
Employed)
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.
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.
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.
Non-financial terms
Term
Boe
CES
C&I
DMO
ERP
GJ
JCC
Joule
Kansai
kT
Mtpa
MW
MWh
NEM
NPS
PJ
PJe
PPA
Sinopec
Meaning
Barrel of oil equivalent
Community Energy Services
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
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.
Power Purchase Agreement
When referring to the off-taker under the LNG Sale
and Purchase Agreement (SPA) with APLNG, means
China Petroleum & Chemical Corporation which has
156
Annual Report 2021
This page has been intentionally left blank DirectoryRegistered OfficeLevel 32, Tower 1100 Barangaroo AvenueBarangaroo, NSW 2000GPO Box 5376Sydney NSW 2001T (02) 8345 5000F (02) 9252 9244originenergy.com.auenquiry@originenergy.com.auSecretaryHelen HardyShare RegistryBoardroom Pty LimitedLevel 12, 225 George StreetSydney NSW 2000GPO Box 3993Sydney NSW 2001T Australia 1300 664 446T International (+61 2) 8016 2896F (02) 9279 0664boardroomlimited.com.au origin@boardroomlimited.com.auAuditorEYFurther information about Origin’s performance can be found on our website:originenergy.com.au