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Focused on delivering
Beach Energy Limited
ABN 20 007 617 969
Beach Energy
Annual Report 2021
About this report
About Beach Energy
FY21 Performance Highlights
Operations portfolio
Our journey over 60 years
Chairman’s letter
Managing Director’s letter
Executive team
Our markets
Our strategy
Operating review
Reserves statement
Sustainability
Board of directors
Full Financial Report
Directors’ report
Auditor’s independence
declaration
2021 Remuneration in brief
(unaudited)
Remuneration report
Directors’ declaration
Financial statements
Notes to the financial statements
Independent auditor’s report
Additional Information
Glossary
Schedule of tenements
Shareholder information
Corporate information & directory
IFC
02
03
04
06
08
10
12
14
16
17
32
38
40
43
44
59
60
62
79
80
84
125
130
132
137
BC
Cover: Bass Basin, VIC
About this Report
This 2021 Annual Report is a summary of Beach Energy’s
operations and activities for the 12 month period ended
30 June 2021 and financial position as at 30 June 2021. In this
report, unless otherwise stated, references to ‘Beach’ and the
‘Group’, the ‘company’, ‘we’, ‘us’ and ‘our’ refer to Beach Energy
Limited and its subsidiaries. See Glossary for further defined
terms used in this report.
This report contains forward-looking statements. Please refer to
page 51, which contains a notice in respect of these statements.
All references to dollars, cents or $ in this document are to
Australian currency, unless otherwise stated. Due to rounding,
figures and ratios in tables and charts throughout this report
may not reconcile to totals.
An electronic version of this report is available on Beach’s
website, www.beachenergy.com.au
The 2021 Corporate Governance Statement can be viewed
on our website on the Corporate Governance page.
Annual General Meeting
Venue: Adelaide Convention Centre
Address: North Terrace, Adelaide SA 5000
Date: Wednesday, 10 November 2021
Please note, the Annual General Meeting format will
be subject to COVID safety requirements. For more
information, visit: www.beachenergy.com.au/agm
Our Vision
We aim to be Australia’s
premier multi-basin upstream
oil and gas company.
Our Purpose
Sustainably deliver energy for communities.
Our Values
Our values define us, guide our actions, our decisions and our words.
Safety
Safety takes precedence in
everything we do
Creativity
We continuously explore
innovative ways to create value
Respect
We respect each other,
our communities and
the environment
Integrity
We are honest with
ourselves and others
Performance
We strive for excellence and
deliver on our promises
Teamwork
We help and challenge each
other to achieve our goals
Otway Basin, VIC
01
Beach Energy Limited Annual Report 2021 About
Beach Energy
Focused on sustainably delivering
energy for communities.
Beach Energy is an ASX listed, oil and gas exploration and
production company headquartered in Adelaide, South Australia.
Beach’s purpose to ‘sustainably deliver energy for communities’
means it operates while maintaining the highest health, safety
and environmental standards.
Founded in 1961 and now in its 60th year, Beach today has
oil and gas production in five basins across Australia and
New Zealand and is a key supplier of gas into the Australian
East Coast gas market.
Beach’s asset portfolio includes ownership interests in
strategic oil and gas infrastructure and assets across Australia
and New Zealand.
Beach operates a world-class onshore oil business on the
Western Flank of the Cooper Basin and has grown to become
Australia’s largest onshore oil producer.
In addition to its producing assets, Beach has a suite of
exploration permits across the onshore Cooper and Perth
basins, onshore and offshore Otway Basin as well as
offshore acreage in the Bonaparte (Australia) and Taranaki
(New Zealand) basins.
Beach is also planning to enter global LNG markets in H2 2023,
when it will commence export of its share of LNG volumes from
the Waitsia Gas Project Stage 2 in the Perth Basin, operated
by JV participant Mitsui E&P Australia (MEPAU), through the
North West Shelf infrastructure in Karratha.
Beach continues to pursue growth opportunities within
Australia and nearby which align with its strategy, satisfy strict
capital allocation criteria, and demonstrate clear potential for
shareholder value creation.
Beach is committed to reducing emissions from its operations,
targeting a 25% reduction by FY25, and is also undertaking
FEED studies for the proposed Moomba Carbon Capture and
Storage Project.
Beach is committed to engaging positively with the local
communities in which it operates, providing local employment,
supply chain opportunities, as well as partnerships with a
range of clubs and organisations.
(1) Pro forma includes production from the acquisition of Senex Energy’s Cooper Basin and
Mitsui’s Bass Basin assets, with an effective date of 1 July 2020.
02
Expanding Natural Gas Portfolio
Page 2 Expanding Natural
Gas Portfolio
In FY21, gas made up 55% of Beach’s total production.
Gas 55.4%
West Coast 3.1%
East Coast 44.5%
NZ 7.8%
Liquids 44.6%
LPG 7.4%
Condensate 6.3%
Oil 30.9%
25.61 MMboe
FY21 Production
25BY
25
Aspiration of net zero by 2050
Beach Energy has announced an aspiration to reach net
zero scope 1 and scope 2 emissions by 2050. Several
technologies, including carbon capture and storage are
needed to achieve this goal.
Through its 25 by 25 initiative, Beach is already targeting
a 25 per cent reduction in operated emissions by FY25,
compared with FY18 levels.
Beach has already made strong progress, with projected
emissions in FY21, approximately 12 per cent lower when
compared to FY18.
In FY21, Beach delivered initiatives to reduce flaring at our
gas plants and our established Sustainability division will
continue to drive and deliver new emissions reductions ideas.
Read more about our emissions
reduction initiatives on page 38.
FY21 Performance Highlights
26.1MMboe
$1,519M
Sales Volumes
Sales Revenue
$760M
Operating Cash Flow
66%
$363M
Underlying EBITDAX Revenue Margin
Underlying NPAT (1)
71
68
66
560
459
363
339MMboe
2P Reserves
352
339
326
FY19
FY20
FY21
FY19
FY20
FY21
FY19
FY20
FY21
FY21 Summary
2021 was our
safest year
on record.
25.6 MMboe
105% Increase
133%
99.3%
Strength
Production of
25.6 MMboe
net to Beach
Perth Basin
production
increased 105% –
new annual record
Three year
2P reserve
replacement ratio
Otway Gas
Plant reliability
Financial strength
maintained
(1) Underlying results in the chart above are categorised as non-IFRS financial information provided to assist readers to better understand the financial performance
of the underlying operating business. They have not been subject to audit or review by Beach’s external auditors. Please refer to the table on page 47 for a
reconciliation of this information to the financial report
03
Beach Energy Limited Annual Report 2021 A Diverse
Operations Portfolio
Beach Energy operates a diverse portfolio of assets,
spanning onshore and offshore operations across five
operating basins.
These include production facilities in the Cooper, Bass,
Otway (SA & Victoria), Perth and Taranaki Basins.
Darwin
Cooper Basin
Western Flank & Cooper Basin JV
(Various operated and non-operated interests)
Western Flank Oil & Gas
Low-cost operations with unit field operating
costs <$6 per boe.
Beach now the sole operator across the
Western Flank acreage following the $83 million
acquisition of Senex Energy’s Cooper Basin
portfolio.
Middleton gas plant operated at 98.5% reliability.
Cooper Basin JV
Participated in 43 wells at 84% overall
success rate.
Commenced FEED activities for the
Moomba CCS project.
De-bottlenecked the Karmona triplex pipeline
supporting additional gas volumes from
south west Queensland.
Perth Basin
Waitsia (Beach 50% non-operated)
Beharra Springs (Beach 50% operated)
Production increased 105% following successful
completion of Waitsia Stage 1A and tie-in of the
Beharra Springs Deep 1 exploration well.
Reached FID for the Waitsia Gas Project Stage 2
development.
Successfully executed key agreements
underpinning the Waitsia LNG project.
Clough awarded the lump sum engineering,
procurement and construction contract for
Waitsia gas plant and associated infrastructure.
04
Perth
Adelaide
SA Otway Basin
Katnook (Beach 100% operated)
Production increased 77% from FY20.
Awarded exploration licence PEL 680
with Cooper Energy.
Gas processing facilities
Gas production
Oil production
Exploration
Beach office
Darwin
Brisbane
Adelaide
Sydney
Canberra
Penola
Melbourne
Victorian Otway Basin
Otway Gas Project/HBWS
(Beach 60% operated)
Enterprise 1 nearshore gas discovery yielded
34 MMboe gross 2P gas and associated liquids
reserves (20 MMboe net to Beach).
Favourable outcome from the Otway Lattice
East Coast gas price review.
Commenced offshore Otway drilling campaign,
with two successful wells (Artisan 1 and Geographe
4) drilled to target depth during the financial year.
Artisan 1 offshore gas discovery provides
optionality for future Otway Gas Plant backfill.
Completed major planned Otway Gas Plant
maintenance activity on time and within budget.
99.3% reliability at Otway Gas Plant
Bass Basin
BassGas (Beach 88.75% operated)
Completed the acquisition of all MEPAU’s
Bass Basin interests.
Completed comprehensive Concept Select
and entered FEED phase for the Trefoil
development project.
Hobart
Taranaki Basin
Kupe (Beach 50% operated)
No recordable safety incidents encountered
throughout the Kupe compressor project.
Approximately 98.5% reliability at the
Beach-operated Kupe facility.
New Plymouth
Wellington
Illustration not to scale.
05
Beach Energy Limited Annual Report 2021 Our Journey
over 60 Years
2021 marks 60 years since Dr Reg Sprigg
incorporated Beach Petroleum, drilling the first well
in the beachside suburbs of Adelaide – giving rise
to the company today known as Beach Energy.
Since that time, Beach has grown to become one of Australia’s
leading energy producing companies, and today has operations
in five producing basins across Australia and New Zealand.
A string of successful Cooper/
Eromanga Basin oil discoveries
deliver growth – 1985
In the early 1980s, Beach made
oil discoveries at Jackson,
Bodalla South and Kenmore in
south-western Queensland.
Beach makes a commercial
gas discovery in Victorian
Otway Basin – 1979
Beach Petroleum’s first well,
named Grange 1, is drilled in
the Adelaide beachside suburb
of Grange. The well is now the
location of the Grange Golf
Course – 1962
Beach Petroleum is
incorporated by South Australian
geologist and conservationist,
Dr Reg Sprigg – 1961
1960
06
1970
1980
5 basins
Major acquisition of Lattice Energy
results in significant diversification,
taking Beach from one operating
basin to five – 2018
1 MMboe
Following earlier commercial
discoveries in the Cooper Basin,
Beach’s annual production
reaches 1m boe – 2005
Acquisition of Drillsearch
This acquisition consolidates
Beach’s position as a key Cooper
Basin producer – 2016
Proudly
South
Australian
Beach returns to South Australia,
consolidates its financial position,
and expands its operations with a
focus on the Cooper/Eromanga Basin.
60 Years
Beach celebrates
60th Anniversary – 2021
>$1 billion
Beach embarks on >$1 billion
offshore Otway Project, while first
LNG volumes are marketed for the
Waitsia Gas Project Stage 2 – 2021.
Safest
year on
record
Beach records its safest year on
record including 3 million hours
without a lost time injury – FY21
2000
2010
2020
07
Beach Energy Limited Annual Report 2021 Letter from
the Chairman
Focused on our stated purpose
to “sustainably deliver energy
for communities.”
Dear Shareholder,
This financial year Beach Energy will celebrate its
60th anniversary, having drilled its first well in 1962 at
Grange Beach in Adelaide, South Australia.
People are at the heart of this and every company. As we turn
60 I take this opportunity to thank all those who have been
involved in contributing to Beach, both past and present.
Beach today is the sum of all of your contributions which we
acknowledge and appreciate.
Over the past 60 years, Beach has undergone a significant
evolution to become an oil and gas exploration and production
company with a broad and diverse portfolio of assets producing
energy in five basins across Australia and New Zealand.
Today that diverse portfolio and a strong balance sheet gives
Beach the right foundation to further develop its assets to
deliver sustainable long term growth. We look forward to the
development of the portfolio over the next three years and the
cash flows that will generate.
Throughout FY22 and FY23 we will be investing in our existing
assets across all five basins with the aim of sustainably
delivering energy for the benefit of our communities and stable
long term cash flows for the benefit of our shareholders with
delivery of Kupe compression and Geographe gas this financial
year, Thylacine gas in FY23 and Waitsia gas in FY24.
Achieving this aim sustainably requires us to develop our
assets safely. To that end, 2021 saw Beach achieve its safest
year-on-record. Three million hours were worked without a
lost time injury. That is a great achievement and I thank and
congratulate our employees and contractors whilst at the
same time asking them to continue their focus on safety.
08
Achieving our aim sustainably also requires us to operate in an
environmentally conscious way. In this regard we have achieved
our first-year targets for emissions reduction as part of our
“25 by 25” initiative as well as deliver the first suite of projects
under this program. You will see in our Sustainability Report the
company is also taking further steps to achieve its aspiration of
decarbonising the business on a net basis by 2050.
Financial year 2021 did, however, present challenges for our
Western Flank asset. As a result of our drilling program, it was
determined that the 2P reserves for Western Flank, previously
reported in accordance with PRMS guidelines, were less than
anticipated. Reserves changes are not uncommon, but the
reduction in reserves was of course disappointing. We are
sensitive to the corresponding impact felt by shareholders.
A detailed review of the forward plan for the asset has been
undertaken and in FY22 we will recommence exploration
activity across the Western Flank with the obvious goal of
unlocking new reserves. Despite this, the Western Flank
remains a key part of our portfolio generating strong margins
and cash flow.
Your company is in a strong financial position with the assets
and work program to deliver increasing value for shareholders
in the coming years. I thank shareholders for their continued
support as we focus on delivering that program and value.
I also thank all of our staff, contractors and stakeholders
for their continued dedication to safely delivering sound
operational results in FY21.
Glenn Davis | Chairman
16 August 2021
Bass Basin, VIC
Focused
on growth
09
Beach Energy Limited Annual Report 2021 Managing
Director’s Letter
Our Purpose at Beach Energy is to ‘Sustainably
deliver energy for communities’, and in FY21,
our efforts to drive down emissions from our
operations shifted up several gears.
Of all the highlights from FY21, nothing gives me greater
satisfaction than to say that our team made it our safest year on
record. Beach’s Total Recordable Injury Frequency Rate (TRIFR)
of 2.1 was a 40 per cent improvement from FY20. Furthermore,
Beach also passed a significant milestone of three-million hours
without a Lost Time Injury.
This is an extraordinary result for our team in our busiest year
and with an overlay of the challenges of COVID-19.
Our Purpose at Beach Energy is to ‘Sustainably deliver energy
for communities’, and in FY21, our efforts to drive down
emissions from our operations shifted up several gears.
A key element of this is Beach’s newly adopted aspiration to
reach net zero Scope 1 and 2 operated emissions by 2050.
We set this goal with confidence given our progress on our
25 by 25 target and the capabilities within our business to drive
further emissions reduction.
In relation to our 25 by 25 initiative – our stated objective to
reduce company emissions by 25 per cent by FY25 against FY18
levels – we made some tangible steps toward decarbonisation
this year.
A key element of this is Beach’s
newly adopted aspiration to
reach net zero Scope 1 and 2
operated emissions by 2050.
An example of one of these projects is the installation of
Mercury Removal Facilities at the Otway Gas Plant. This
resulted in a reduction in the use of flaring at the plant, and cuts
emissions by about 12,000 tonnes over the next decade.
It is projects like this that have seen our emissions at the end
of FY21 reduce by approximately 12 per cent on the FY18
emissions benchmark. This sees us on track to meet our
“25 by 25” target.
I look forward to updating our shareholders on more 25 by 25
initiatives as these projects and ideas progress.
Separately, we continue to progress the proposed Moomba
Carbon Capture and Storage project with operator Santos,
which aims to safely and permanently store 1.7 million tonnes
of carbon dioxide per year.
In a Financial Year which began with a second-wave of
COVID-19 in Victoria, our team’s capacity to think creatively
in order to deliver on our work program was regularly tested,
and the team delivered with flying colours.
Dear Shareholder,
The 2021 Financial Year was a period in which the team at
Beach Energy remained focused on delivering its key growth
projects, aligned with our purpose to sustainably deliver energy
for communities.
It was a year that was not without its challenges, namely our
production and reserves downgrade in the Western Flank,
which was a disappointing outcome for everyone at Beach.
Despite this downgrade, our balance sheet remained well
supported through our diversified portfolio – highlighting why
our company undertook the Lattice acquisition in 2018.
The last year was highlighted by significant milestones from
our two major growth projects in the Perth and Victorian
Otway basins.
In the Perth Basin, Beach reached Final Investment Decision
on the Waitsia Gas Project Stage 2. This is a transformational
project for Beach that will see our company enter the global
LNG market in 2023. While in Victoria, our team commenced
the offshore Otway Basin drilling campaign, Beach’s largest ever
investment in a single campaign, as we work towards bringing
the Otway Gas Plant back toward peak production by 2023.
Helping that objective were our two exploration successes in
the Otway Basin, with the Enterprise 1 nearshore well delivering
an excellent result and the Artisan 1 offshore exploration well
providing a future backfill opportunity for the Otway Gas Plant.
It was a year which also saw Beach make two strategic bolt-on
acquisitions. One expands our operatorship in the Western
Flank, while the other increases Beach’s interest in the Bass
Basin where we recently commenced FEED activity for the
Trefoil project.
10
I am again pleased to say that, at the end of FY21, there had
been no cases of COVID-19 infection at any Beach Energy
facility or operated drilling site. This is testament to the robust
controls implemented by our teams and contractors.
The impacts of the pandemic have not subsided, but I’d like
to thank the teams for being flexible in adjusting to change
and working collaboratively in response to the challenges
as they arise.
FY21 Review
Despite the downgrades in the Western Flank, Beach
ends the year with a strong balance sheet, a testament
to our strategically diversified portfolio through the 2018
Lattice acquisition.
Beach recorded an Underlying NPAT of $363 million and ended
the year with net debt of $48 million, net gearing of 1.5% and
liquidity of $402 million.
Beach’s annual production for FY21 was 25.6 MMboe, down
4% on FY20, largely the result of the declining performance
in the Western Flank.
There were several key company highlights in FY21,
which included:
• Reaching Final Investment Decision for Waitsia Gas Project
Stage 2 and executed key agreements required to export
LNG through North West Shelf from H2 2023
• Commencing the seven-well offshore Otway drilling
campaign aiming to re-fill the Otway Gas Plant by mid-FY23
• Two exploration successes, Enterprise 1 and Artisan 1,
in nearshore and offshore Otway Basin
• Announcing two bolt-on value accretive acquisitions in the
Cooper and Bass Basins, which will serve as a platform for
future growth
• Concluding Cooper and Otway Basin Lattice GSA price
reviews with Origin at favourable terms to Beach
• Successfully completed expansion of Xyris Production
Facility and tied-in Beharra Springs Deep 1, resulting in the
doubling of the deliverability of the Perth Basin assets
On the operational side of the business, highlights included:
• Delivering Beach’s safest year on record with three million
hours worked without a Lost Time Injury
• Achieving high facility reliability at the Otway Gas plant,
which operated at 99.3% reliability, with Kupe and
Middleton facilities at 98.5%
• Progressing the Kupe compression project to commissioning
on budget
• The safe and successful completion of 28-day statutory
shutdown at the Otway Gas Plant in November 2021, on
time and budget despite border restrictions impacting
personnel and equipment logistics
FY22 Outlook
Delivering on our growth projects remains the focus at Beach
in FY22, with activity happening in all corners of the business.
The Otway Gas Plant will be connected to new supply with the
tie-in of the Geographe development wells, with a further four
Thylacine development wells being drilled during the year.
In the Perth Basin, where along with our JV operator Mitsui,
activities will ramp up on the Waitsia Gas Project Stage 2,
with construction commencing on the new gas facility and the
drilling of our first development wells.
In the Cooper Basin, the drill-bit will be very busy again,
particularly on the exploration front. On the Western Flank,
we are planning a single-rig program, mainly focused on
oil and gas exploration.
In New Zealand, the Kupe Compression project will come online
in the first half of FY22, extending the production life of the
facility, as we investigate future drilling opportunities to keep
the Kupe plant full.
Conclusion
2021 marks 60 years since Reg Sprigg first created Beach
Petroleum, the company you know today as Beach Energy.
We remain faithful to Dr Sprigg’s legacy – a company with a
pioneering spirit. We also continue to grow and evolve into an
industry leading exploration and production company, with an
increased focus on sustainability.
Our company has had some setbacks in FY21, and we don’t hide
from that. But if you look across the company today, you will see
investment in projects that deliver growth – and that is what we
remain focused on in FY22.
Matt Kay | Managing Director & Chief Executive Officer
16 August 2021
12,000t
Anticipated emission reduction over the next decade
due to the installation of Mercury Removal Facilities
11
Beach Energy Limited Annual Report 2021 Executive
Team
Matthew (Matt) Kay
Managing Director &
Chief Executive Officer
BEc, MBA, FCPA, GAICD
Morné Engelbrecht
Chief Financial Officer
BCom (Hons),
CA (ANZ & South Africa), MAICD
Ian Grant
Chief Operating Officer
MSc, CMgr FCMI
Mr Engelbrecht joined Beach in 2016 as
Chief Financial Officer and is responsible
for the finance, tax, treasury, IT, contracts
& procurement, insurance, internal audit
and investor relations functions.
Mr Grant has over 25 years’ experience
in the energy industry, having held
senior leadership and executive roles
in operations, projects, drilling and
supply chain functions.
He is a Chartered Accountant with
more than 20 years’ experience in the
oil & gas and resource sectors across
various jurisdictions including Australia,
South Africa, the United Kingdom,
Papua New Guinea and China. He
has held various executive, financial,
commercial and advisory senior
management positions at InterOil,
Lihir Gold (Merged with Newcrest),
Harmony Gold and PwC.
Mr Engelbrecht also has extensive
experience in strategy and planning,
capital management, debt and
equity markets, M&A and joint
venture management and operations.
Born in Scotland, Mr Grant has extensive
North Sea experience and has worked
in Europe and Australia with companies
such as Mobil, ARCO/BP, Apache,
Quadrant Energy and Santos.
Most recently Mr Grant was Chief
Operating Officer for Quadrant Energy
and Vice President of Production
Operations for Santos based in Perth.
He is passionate about delivering
safety, operational and commercial
performance in both onshore and
offshore environments.
Mr Kay joined Beach in May 2016
as Chief Executive Officer and was
appointed to the Board as Managing
Director in February 2019. In November
2018, he was elected to the Australian
Petroleum Production & Exploration
Association (APPEA) Board.
Mr Kay brings 28 years of experience
in the Oil and Gas industry to Beach.
Before joining Beach, he served as
Executive General Manager, Strategy
and Commercial at Oil Search, a position
he held for two years. In that role he
was a member of the Executive team
and led the strategy, commercial,
supply chain, economics, marketing,
M&A and legal functions.
Prior to Oil Search, Mr Kay spent 12 years
with Woodside Energy in various
leadership roles, including Vice President
of Corporate Development, General
Manager of Production Planning and
General Manager of Commercial for
Middle East and Africa. In these roles
Mr Kay developed extensive leadership
skills across LNG, pipeline gas and
oil joint ventures, and developments
in Australia and internationally.
12
Sam Algar
Group Executive Exploration
and Subsurface
BA (Hons), PhD
Thomas Nador
Group Executive Development
Dr Algar joined Beach in February 2021
and brings over 25 years’ experience
in the energy industry, having held
senior leadership and executive roles in
Australia and internationally, including
the UK, Indonesia, Malaysia, Canada and
the USA, looking after global exploration,
new venture and subsurface portfolios.
Most recently Dr Algar was Senior Vice
President, Subsurface and Exploration
with ASX listed Oil Search Limited.
Dr Algar holds a Bachelor of Arts (Hons)
Geology from Oxford University and a
PhD Geology from Dartmouth College
in the USA.
Previous employers include Ophir
Energy, Murphy Oil, ENI, LASMO and
Enterprise Oil.
Mr Nador joined Beach in July 2019 as
General Manager, WA Development,
representing Beach in the Waitsia
Joint Venture. He has over 25 years’
experience in the energy sector at senior
management and executive levels.
He has held previous roles as Executive
Vice President and Country Manager for
InterOil in Papua New Guinea, as well as
Development Manager, Project Interface
Manager and Project Integration Manager
for LNG projects at Woodside Energy.
Mr Nador holds a Bachelor of Science
from the University of WA, a Post
Graduate Diploma in Science from
Curtin University of Technology and is
a Member of the Australian Institute of
Company Directors.
Lee Marshall
Group Executive Corporate
Strategy and Commercial
BE Commerce (Economics and Finance)
Mr Marshall joined Beach in
January 2018 as Group Executive
Corporate Strategy and Commercial.
Prior to joining Beach, Mr Marshall was
most recently General Manager UK for
Woodside Energy. Based in London,
Mr Marshall managed exploration assets
and business development opportunities
in the Atlantic Basin and Africa. He has
over 20 years of Australian and global
commercial, business development and
financial management experience across
upstream oil and gas and LNG.
Mr Marshall is responsible for upstream
commercial, strategy, economics, M&A,
business development and marketing.
Sheree Ford
General Counsel
BA, LLB, MBA
Brett Doherty
Group Executive Health, Safety,
Environment and Risk
BEng (Electrical), LLB (Hons)
Lesley Adams
Group Executive,
Human Resources
Ms Ford joined Beach in March 2018
bringing over 25 years’ experience as
a corporate lawyer primarily in the
upstream oil and gas industry. Prior
to joining Beach, Ms Ford worked for
over 10 years as in house counsel at
BHP Limited, primarily in the oil and
gas business and was General Counsel
and Company Secretary at listed and
privately owned oil and gas companies
including InterOil Corporation, Oil Search
Limited and Roc Company Limited.
As well as extensive experience in
upstream oil and gas business across
Australia, Asia, Africa and the United
Kingdom, Ms Ford has been involved in
numerous large company transactions
including M&A.
Mr Doherty joined Beach in February
2018 as Group Executive Health,
Safety, Environment and Risk, bringing
over 30 years of upstream oil and gas
experience to Beach. His career includes
extensive exposure to both offshore and
onshore development and operations.
Prior to Beach, Mr Doherty was
General Manager of Health, Safety and
Environment at INPEX Australia. He
has held several senior international
positions during his career, including
ten years as the Chief HSEQ Officer
at RasGas Company Limited, in the
State of Qatar.
Ms Adams commenced with Beach in
October 2019. She is an experienced
executive with more than 25 years’
experience within the international
and Australian oil and gas industry,
with business experience in Human
Resources, Continuous Improvement,
Strategic Planning, Joint Venture
Management, Emergency Management,
Sustainability, Indigenous and
Government Affairs and M&A.
Prior to Beach, Ms Adams was Group
Executive Corporate Services for
Quadrant Energy and assisted the
integration post-acquisition by Santos Ltd.
Lesley has previously worked for Santos,
Woodside, AMEC and Schlumberger.
Ms Adams is passionate about
employee engagement and
empowerment to drive results.
13
Beach Energy Limited Annual Report 2021 Our Markets
Focused on four key gas markets.
LNG market
New Zealand gas market
•
In FY21, Beach took FID on the Waitsia Stage 2 Gas
Project, which will see Beach become Australia’s newest
LNG participant.
• Beach is actively marketing its 50% share of 7.5 million
tonnes of LNG over a five-year period from H2 2023.
• Global LNG trade increased 0.4% in 2020, despite the
impact of COVID-19 on global economic activity.
• LNG market is emerging from recent oversupply, with
JKM spot pricing reaching an all-time high of US$32.50
per MMBtu during northern summer period and
LNG forward curves rising over the last 3 – 6 months.
• Beach operated Kupe gas facility supports approximately
15% of New Zealand’s domestic market.
• New Zealand domestic market tightened during FY21 due
to declining production from other local fields and lower
than average hydroelectric storage levels driving gas
demand for thermal power generation.
• Kupe compressor project is expected be completed in
H1 FY22 to support plateau production rates at the plant’s
capacity until mid-FY24.
• Beach’s share of Kupe gas production remains fully
contracted until September 2024.
Taranaki Basin
Actively marketing
net share of Waitsia
LNG from H2 2023.
14
West Coast gas market
East Coast gas market
Perth Basin
• Beach and our joint venture participant MEPAU are
currently supplying ~40 TJ per day (~15 PJ per annum)
(gross) through the Xyris gas facility and Beharra Springs
gas facility into the West Coast domestic market, which
will continue throughout the LNG export period.
• 50% of Waitsia 2P gas reserves available to supply up to
250 TJ per day to the domestic gas market from 2029.
• Tightening West Coast gas market supported by reduced
NWS domestic gas supply and increasing customer demand.
• Waitsia JV supporting transition to low emission fuel
in WA’s Mid-West region with signing of gas supply
agreement with Clean Energy Fuels Australia.
West Coast gas market
(PJ)
1,600
1,400
1,200
1,000
800
600
400
200
0
SA Otway Basin
Victorian Otway Basin
Bass Basin
•
Increased exposure to the East Coast gas market was an
important strategic element for the 2018 Lattice acquisition.
• Beach supplied ~12% of domestic East Coast gas volumes
during 2020.
• Beach and JV participants spending more than $1 billion in
exploration and development capital to re-fill the Otway
Gas Plant.
• ACCC and AEMO forecast market shortfall during mid-2020s.
AEMO forecast winter shortfalls by as early as 2023, with
signs of tight winter supply already emerging this year.
• Majority of Beach’s East Coast gas volumes contracted, with
next major re-pricing event from 1 July 2023, similar time to
the gas shortfall anticipated by AEMO.
• Additional exposure to East Coast gas dynamics with
uncontracted gas reserves at Enterprise, Artisan and Trefoil.
Page 14 East Coast gas
Forecast gas supply – 2020 to 2039
volumes contracted
(PJ per annum)
2,500
2,000
1,500
1,000
500
0
2021
2022 2023 2024 2025 2026 2027 2028 2029
2030
Source: AEMO WA Gas Statement of Opportunities (December 2020)
0
2
0
2
1
2
0
2
2
2
0
2
3
2
0
2
4
2
0
2
5
2
0
2
6
2
0
2
7
2
0
2
8
2
0
2
9
2
0
2
0
3
0
2
1
3
0
2
2
3
0
2
3
3
0
2
4
3
0
2
5
3
0
2
6
3
0
2
7
3
0
2
8
3
0
2
9
3
0
2
Potential Gas supply (existing)
Waitsia
Gorgon (tranche 2)
Source: AEMO Gas Statement of Opportunities (March 2021)
West Erregulla
Demand (High)
Scarborough
Developed
Committed
Anticipated
Demand (Base)
Demand (Low)
Forecast demand
15
Beach Energy Limited Annual Report 2021 Our
Strategy
We continue to execute
and deliver against our
well defined strategy.
Optimise core producing assets
• Delivered Beach’s safest year on record achieving
three million hours worked since the last lost time injury
• Otway Gas Plant operated at 99.3% facility reliability
• Kupe facility and Middleton gas facility operated at
98.5% reliability
• Successful delivery of statutory shutdown of the
Otway Gas Plant during Q2 FY21
• Reached commissioning of Kupe compressor project,
with first gas on track for H1 FY22
Strengthen our complimentary gas business
• Took FID at Waitsia Stage 2, securing access to international
LNG markets through North West Shelf facility from H2 2023
• Made two offshore gas discoveries in the Otway Basin,
extending production plateau through the Otway Gas Plant
• Commenced offshore Otway development drilling campaign
to deliver Otway Gas Plant to capacity by mid-FY23
• Completed Xyris facility expansion and Beharra Springs
facility upgrade, expanding Perth Basin capacity to
40 TJ per day and increasing production by ~50% on FY20
Maintain financial strength
• Prudent balance sheet management and diversification strategy
supported Beach through unexpected production decline
• Net debt position of $48 million at 30 June 2021, with
$402 million liquidity
• Net gearing of 1.5%
• Earnings stability from our mostly fixed-price, CPI-linked
gas business contributed ~40% of FY21 revenue
Our people and culture
• Supported staff wellbeing throughout pandemic by
an increased focus on resilience training and support
for leadership
Instituted a new Flexible Work Arrangements procedure,
supporting diversity and inclusion at work
•
• Launched a Team Volunteering program to support
staff committing up to two days paid time to support
recognised charities
• Delivered $1.2 million in support through community
partnerships including Royal Flying Doctor Service
(SA/NT), South Australia Museum, as well as a range of
local community clubs and organisations
Pursue other compatible growth opportunities
• Completed acquisition of Senex Energy’s Cooper Basin
assets for $83 million, delivering Beach sole operatorship
of the Western Flank infrastructure
• Announced the acquisition of MEPAU’s Bass Basin
interests, including the producing BassGas assets and
Trefoil development
• Completed comprehensive ‘Concept Select’ phase and
entered Define phase for Trefoil development
16
Operating
Review
Performance overview
Name
Production
2P reserves
2C contingent resource
Sales revenue
Net profit after tax
Underlying net profit after tax
Earnings per share
Underlying earnings per share
Cash flow from operating activities
Net assets
Net debt/(cash)
Net gearing ratio
Fully franked dividends declared per share
Shares on issue
Share price at year end
Market capitalisation at year end
Production
Western Flank
Cooper Basin JV
Other Cooper Basin
SA Otway
Perth Basin
SAWA
Vic Otway
Bass Basin
Victoria
New Zealand
Total Production
MMboe
MMboe
MMboe
$ million
$ million
$ million
cps
cps
$ million
FY17
10.6
75
153
653
388
162
20.4
8.5
319
FY18
19.0
313
207
FY19
29.4
326
185
FY20
26.7
352
180
1,251
1,925
1,650
199
302
9.2
13.9
663
577
560
25.4
24.6
1,038
2,374
499
459
21.9
20.2
874
FY21
25.6
339
191
1,519
317
363
13.9
15.9
760
$ million
1,402
1,838
$ million
(198)
%
cents
million
$
$ million
n/a
2.0
1,874
0.575
1,077
639
25.9
2.0
2,277
1.755
3,995
FY20
Oil
equivalent
(MMboe)
FY21
Oil
(MMbbl)
Gas liquids
(MMboe)
9.6
8.7
0.1
0.2
0.4
18.9
3.6
1.4
5.0
2.8
6.7
1.1
0.0
–
–
7.9
–
–
–
–
26.7
7.9
0.7
1.3
0.0
0.0
0.0
2.0
0.4
0.5
0.8
0.8
3.6
2,818
3,088
(172)
(50)
n/a
2.0
2,278
1.985
4,522
n/a
2.0
2,281
1.520
3,467
48
1.5
2.0
2,281
1.240
2,829
Gas
(PJ)
8.9
33.3
0.3
1.7
4.7
48.8
14.1
8.1
22.2
11.5
82.5
Oil
Equivalent
(MMboe)
Year-on-year
change
(%)
8.9
8.1
0.1
0.3
0.8
18.2
2.8
1.9
4.7
2.7
25.6
(7%)
(7%)
36%
77%
105%
(4%)
(22%)
34%
(7%)
(3%)
(4%)
17
Beach Energy Limited Annual Report 2021 Bass Basin, VIC
Operating
Review
Beach remains well
positioned to fund our future
growth endeavours.
Finance
FY21 demonstrated the importance of the Lattice acquisition
strategy in diversifying the business from Cooper Basin single
asset exposure into multiple production hubs across Australia
and New Zealand.
The downgrade in the Western Flank experienced during the
year highlighted Beach’s prudent capital management and focus
on maintaining a strong balance sheet, which has allowed us to
withstand this adverse event.
We have continued to maintain an impressive balance sheet,
despite these challenges, ending the financial year with
$48 million net debt and net gearing of 1.5%, while boasting
liquidity of $402 million. This was despite the $83 million
acquisition of the value accretive Cooper Basin assets from
Senex, which completed in March 2021.
The stable earnings from our mostly fixed-price, CPI-linked gas
business, which contributed ~40% of our FY21 revenue, resulted
in Beach delivering within our original FY21 underlying EBITDA
forecast of $900 – 1,000 million. These stable gas earnings are
expected to be further supported in coming years following two
favourable re-pricing events on our Lattice Cooper Basin and
Otway Basin gas contracts and growth in gas production.
Our business remains well positioned to fund our future
growth endeavours, including the committed capital towards
the offshore Otway drilling program in Victoria and Waitsia
Stage 2 project in Western Australia. These two projects are
expected to deliver significant uplift in gas production to Beach,
supporting stable, long-life revenue generation.
Beach remains a growth orientated business with free cash
flow prioritised towards our existing portfolio of organic growth
projects. Several of these projects are currently in execution
phase, which plans to deliver production and revenue growth
upon completion from mid-FY23.
We continue to take a measured and prudent assessment
of inorganic growth opportunities throughout Australia and
New Zealand. In FY21, we announced two strategic bolt-on
acquisitions, which lay the foundations for future growth,
specifically within the Bass Basin with the Trefoil development,
which plans to return the Lang Lang Gas Plant to capacity
from mid-FY25.
18
Focused on
future growth
19
Beach Energy Limited Annual Report 2021 Operating
Review
Victorian Otway Basin
FY21 Highlights
• Enterprise 1 nearshore gas discovery yielded
34 MMboe gross 2P gas and associated liquids
reserves (20 MMboe net to Beach).
• Positive outcome from the Otway gas price
review arbitration.
• Commenced offshore Otway drilling campaign,
with two successful wells drilled to target depth
during the financial year.
• Artisan 1 offshore gas discovery provides future
Otway Gas Plant backfill opportunity.
• Completed major planned Otway Gas Plant
maintenance activity on time and within budget.
• 99.3% reliability at the Otway Gas Plant
FY22 Focus
• Complete drilling of Geographe 5 and tie-in of the
two Geographe development gas wells to the Otway
Gas Plant. First production expected in mid-FY22.
• Drill four Thylacine development gas wells.
• Progress tie-back of Enterprise gas field to the
Otway Gas Plant to FID.
Operations
Victorian Otway Basin
FY21 Production
FY21 Production
Victorian Otway Basin
2P Reserves
2P Reserves
2.8MMboe
70MMboe
11% of Beach total
21% of Beach total
20
Operations
Victorian Otway Basin operations contributed 11% of
Beach’s FY21 production. Net production was 2.8 MMboe,
down 22% from FY20 due to major planned maintenance
activities at the Otway Gas Plant in November 2020 and
reduced customer nominations. The fields produced 14.1 PJ
of net sales gas to Beach sold under contract, representing
21% of Beach’s East Coast gas market exposure.
Development
Beach and its joint venture participant O.G. Energy are investing
more than $1 billion in the Otway Basin to support extended
operations at the Otway Gas Plant and supply much needed
gas volumes into Australia’s East Coast gas market.
During FY21, Beach commenced the offshore Otway
drilling campaign, one of the key pillars driving the delivery
of the Company’s growth strategy. The project aims to
commercialise gas and associated liquids reserves within
the currently producing Thylacine and Geographe gas fields.
The development is targeting to re-fill the Otway Gas Plant
by mid-FY23.
The development encompasses two additional phases to the
Otway Gas Project. This includes the drilling, completion and
tie-in of two infield development wells at the Geographe gas
field, with production expected to commence in mid-FY22 and
the drilling, completion and tie-in of four (two lateral) infield
development wells at the Thylacine gas field, with production
expected to commence in FY23.
At the end of the financial year, Beach had completed extended
reach drilling activities at Geographe 4, placed subsea xmas
trees at both Geographe 4 and Geographe 5 top-hole locations,
and commenced drilling operations at Geographe 5.
Beach plans to complete the Geographe 5 deviated section in
early FY22 before moving the rig to the Thylacine field to carry
out further development drilling.
Beach also plans to continue progressing the Front-End
Engineering Design (FEED) works associated with the
connection of the newly discovered Enterprise gas field, located
in the nearshore Otway Basin, to the Otway Gas Plant during
FY22. Production from Enterprise is expected to commence
during H2 FY23.
Beach drilled two successful
exploration wells within
the Victorian Otway Basin
during FY21.
Exploration and Appraisal
Beach drilled two successful exploration wells within
the Victorian Otway Basin during FY21. The discovery
of the nearshore Enterprise gas field was announced in
November 2020 and resulted in the booking of 34 MMboe
gross 2P gas and associated liquids reserves (20 MMboe net
to Beach), including 161 PJ gross sales gas (97 PJ net to Beach),
within the Upper Waarre formation. Importantly, the field
yielded materially higher liquids than pre-drill expectation and
de-risks additional nearshore opportunities in close proximity
to the Otway Gas Plant.
In March 2021, Beach announced the discovery of the
Artisan offshore gas discovery. The well was suspended for
future completion and production through the Otway Gas
Plant beyond FY25.
In July 2020, Beach was awarded VIC/P007192(v) in
the nearshore Victorian Otway, adjacent to VIC/P42(v)
which hosts the Enterprise gas discovery. The permit was
subsequently sold down to joint venture participant O.G. Energy,
aligning interest in the Otway Basin. The selldown remains
subject to government approval.
Commercial
In April 2021, Beach announced a positive outcome in respect
to the arbitration relating to the re-pricing of Victorian Otway
gas sales under the existing Lattice GSA (i.e. excluding the
GSA for the sale of gas from the 5% interest previously held
by Toyota Tsusho).
The redetermined price applies from 1 July 2020, with the
required true-up payment received during the fourth quarter.
The next re-pricing event will occur on 1 July 2023.
Description
Victorian Otway Basin (Beach 60% and operator, O.G. Energy
40%) includes producing licences VIC/L1(v) which contains
Halladale, Black Watch and Speculant nearshore gas field and
licences VIC/L23, T/L2 and T/L3, which contain the Geographe
and Thylacine offshore gas fields. Gas from all producing fields
is processed at the Otway Gas Plant.
The Victorian Otway Basin also includes non-producing
nearshore VIC/P42(v), including the Enterprise gas discovery
and offshore licences VIC/P43, including the Artisan gas
discovery, VIC/P73, including the La Bella gas field (Beach 60%
and operator, O.G. Energy 40%), T/30P (Beach 100%). It also
includes the nearshore exploration permit VIC/P007192(v)
(Beach 60% and operator, O.G. Energy 40%).
Diamond Ocean Onyx rig,
Courtesy of Diamond Offshore
Focused on
East Coast gas
21
Beach Energy Limited Annual Report 2021 Operating
Review
Perth Basin
FY21 Highlights
• Production increased 105% following successful
completion of Waitsia Stage 1A expansion and tie-in
of the Beharra Springs Deep 1 exploration well.
• Reached FID for the Waitsia Gas Project Stage 2
development.
• Successfully executed agreements with NWS,
AGIG and WA State Government underpinning the
Waitsia LNG project.
• Clough awarded the lump sum engineering,
procurement and construction contract for
Waitsia gas plant and associated infrastructure.
FY22 Focus
• Commence on-site construction activities for the
Waitsia Gas Project Stage 2 gas processing facility.
• Commence drilling of up to six conventional
Waitsia Stage 2 development wells from H2 FY22.
• Target completion of marketing Waitsia LNG
volumes, Beach’s first LNG sale.
• Progress plans for exploration drilling within EP 320
during FY23.
Operations
Perth Basin
FY21 Production
FY21 Production
Perth Basin
2P Reserves
2P Reserves
0.8MMboe
100MMboe
3% of Beach total
30% of Beach total
22
Operations
Perth Basin operations contributed 3% of Beach’s FY21
production. Net production was 0.8 MMboe, a 105% increase
following the completion of the Waitsia Stage 1A expansion
project in August 2020 and the tie-in of Beharra Springs Deep
in early April 2021.
Development
The Waitsia Stage 1A expansion of the MEPAU operated
Xyris Production Facility was completed during August 2020.
The project successfully doubled the capacity of the plant to
20 TJ per day and connected the Waitsia field to the Dampier to
Bunbury Natural Gas Pipeline (DBNGP) with the interconnector
sized to 280 TJ per day. The additional capacity allows for the
future handling of Waitsia Gas Project Stage 2 production.
Performance testing at the Xyris Production Facility has resulted
in sustained production rates in excess of 20 TJ per day during
the second half of the financial year.
Activities were also completed at the Beach-operated Beharra
Springs Gas Processing Facility with the installation and
commissioning of a new cyclonic separator in October 2020.
These activities were completed ahead of the April 2021
commencement of production from the recently discovered
Beharra Springs Deep field in April 2021.
During FY21, the Waitsia Joint Venture reached FID for the
Waitsia Gas Project Stage 2 development. The development
is a key pillar in Beach’s growth strategy, with production
expected to commence in the second half of calendar year
2023. Gas from the Waitsia field will be transported via the
DBNGP and processed into liquefied natural gas through the
existing North West Shelf infrastructure in Karratha before
being exported into international markets.
The Waitsia Joint Venture awarded Clough the lump sum
engineering, procurement and construction contract for the
new 250 TJ per day Gas Processing Facility and associated
infrastructure in January 2021. Construction activities are
scheduled to commence the first quarter of FY22. The
initial phase of the project involves the drilling of up to six
development wells, construction of the new 250 TJ per day gas
processing facility and associated gas gathering infrastructure.
Exploration and Appraisal
Interpretation of the Trieste 3D seismic, which covers the Beach
operated EP 320, was completed during FY21. The encouraging
results have helped define the prospectivity towards the
southeast of the Waitsia gas field. During FY22, Beach and its
joint venture participant MEPAU will commence planning to
drill the exploration commitment well within EP 320.
Waitsia, Perth Basin
Beach Energy Limited Annual Report 2021
Focused on
West Coast growth
Commercial
During FY21, the Waitsia Joint Venture entered into several
key commercial and State Government agreements required to
enable FID of Waitsia Stage 2, including:
• A Domestic Gas Commitment Agreement and Project
Development Deed with the State of Western Australia.
• A Gas Processing Agreement, Tie-in Agreement, Production
Allocation Agreement and Lifting and Offtake Agreements
with the North West Shelf Project participants; and
• A Gas Transportation Agreement with AGIG, owner and
operator of the DBNGP.
Beach commenced marketing activities of the Company’s equity
share of up to 7.5 million tonnes of LNG (3.75 million tonnes
net to Beach). Volumes will be processed into LNG through the
existing North West Shelf infrastructure in Karratha between the
second half of 2023 and the end of 2028. At the end of FY21,
Beach was conducting discussions with potential buyers and
progressing toward contracting LNG volumes during FY22.
The Waitsia and Beharra Springs joint venture participants
continue to support the Western Australian domestic gas
market, entering several Gas Sales Agreements throughout the
year for supply during calendar years 2021 and 2022. This is
in addition to the announced five-year deal with Clean Energy
Fuels Australia (CEFA), which will see Waitsia volumes supply
CEFA’s Mid-West LNG Hub project, delivering trucked LNG to
customers throughout Western Australia’s Mid-West region.
These volumes will support new industry and enable the supply
of low GHG emission fuels to energy uses in the region.
Description
Producing licences areas are Waitsia (Beach 50%, MEPAU
50% and operator) in licence L1/L2 and Beharra Springs
(Beach 50% and operator, MEPAU 50%) licences L11 and L22.
The exploration permit is EP 320 (Beach 50% and operator,
MEPAU 50%).
23
Operating
Review
Western Flank Oil & Gas
FY21 Highlights
• Low-cost operation with unit field operating costs
<$6 per boe.
• Beach now the sole operator across the Western
Flank acreage following the $83 million acquisition
of Senex Energy’s Cooper Basin portfolio.
• Middleton gas plant operated at 98.5% reliability.
FY22 Focus
• Recommence of drilling activities with single-rig
program aimed at reducing decline of Western
Flank oil fields and extending plateau gas
production through the Middleton gas plant.
• Re-focus efforts on development of Birkhead
acreage within the ex-Senex Western Flank
acreage north of PEL 91.
Operations
Western Flank Oil and Gas
Western Flank Oil and Gas
2P Reserves
FY21 Production
2P Reserves
FY21 Production
8.9MMboe
35% of Beach total
34MMboe
10% of Beach total1
1. Includes other Cooper Basin/Gemba Reserves
24
Operations
Western Flank oil operations accounted for 26% of Beach’s
FY21 production. Beach’s share of Western Flank oil production
was 6.7 MMboe, down 10% on FY20. This was offset by the
acquisition of Senex Energy’s Western Flank interests from
1 March 2021. The average gross daily production rate across
the Western Flank oil assets was 17.4 kbopd.
Western Flank gas operations accounted for 9% of Beach’s
FY21 production. Western Flank gas and associated liquids
production was 2.2 MMboe, a 3% increase on FY20. The
performance benefited from improved reliability of the
Middleton gas plant, which delivered 98.5% during the year.
Development
Activities during FY21 focused on development drilling across
the Western Flank oil fields, predominantly within the Bauer
field. Beach drilled and operated a total of 21 Western Flank
oil wells during the financial year. This included 11 wells within
the Bauer field, three in Kalladeina, two in each of the Hanson,
Chiton and Balgowan fields, and a single well in Callawonga.
During the FY21, several development oil wells came in below
expectation, with higher than expected decline rates. In the
Bauer field this was due to higher than forecast interference
between wells and water saturations above expectation within
several wells. FY21 drilling in non-Bauer fields indicated a
lower structural relief and greater complexity than previously
modelled. Beach undertook a review of its geological modelling
across eight fields outside of Bauer, updating the mapping
workflow. This resulted in a 17.6 MMbbl downgrade to Beach’s
Western Flank 2P oil reserves which was announced to the
market on 30 April 2021.
Beach expects to undertake additional development drilling
during FY22 across the greater Western Flank acreage. This
includes fields acquired from the acquisition of Senex Energy’s
Cooper Basin assets, where Beach plans to target development
opportunities within the Birkhead reservoir.
The review also led to a downgrade of 2P gas and associated
liquids reserves within the Western Flank gas acreage
by 7.2 MMboe. This was primarily a result of new Lowry
production data indicating a lower-than-expected connected
gas volume and incorporation of new production and pressure
data across seven other fields within ex-PEL 106.
Exploration and Appraisal
No exploration or appraisal drilling was undertaken during FY21,
with focus on high grading oil and gas prospects for the FY22
exploration campaign. Beach has more than 100 prospects
and leads across the Western Flank oil and gas acreage and is
planning to recommence drilling activities during early FY22.
2.2 MMbbl
Western Flank gas and associated
liquids production
4%
2021 2.2 | 2020 2.1
Commercial
In November 2020, Beach executed an Asset Sale Agreement
with Senex Energy to acquire Senex’s Cooper Basin assets
for $83 million, with an effective date of 1 July 2020. The
acquisition was completed on 1 March 2021 and solidified
Beach’s position as the sole operator of all Western Flank oil
and gas infrastructure.
During the year, Beach executed GSAs with customers for the
supply of Western Flank gas in calendar years 2021 and 2022.
Description
Western Flank oil producing assets include ex PEL 91 (Beach
100%), ex PEL 104/111 (Beach 100%) and ex PEL 92 (Beach
75% and operator, Cooper Energy 25%).
Western Flank gas producing assets include ex PEL 106 (Beach
100%), ex PEL 91 (Beach 100%) and the Udacha Block – PRL 26
(Beach 100%). Other non-production licences include ex
PEL 107 (Beach 100%) and PEL 630 (Beach 50% and operator,
Bridgeport 50%).
Cooper Basin, SA
Focused on
exploration
25
Beach Energy Limited Annual Report 2021 Operating
Review
Cooper Basin JV
FY21 Highlights
• Participated in 43 wells at 84% overall success rate.
• Commenced FEED activities for the Moomba
CCS project.
• De-bottlenecked the Karmona triplex pipeline
supporting additional gas volumes from south
west Queensland.
FY22 Focus
• Four-rig drilling campaign targeting up to 90 wells
in FY22.
• Plans to commence major central electrification
across Cooper Basin JV assets.
Operations
Cooper Basin JV
FY21 Production
FY21 Production
Cooper Basin JV
2P Reserves
2P Reserves
8.1MMboe
77MMboe
32% of Beach total
23% of Beach total
26
Operations
The Cooper Basin joint venture operations contributed 32% of
Beach’s FY21 production. Net gas and gas liquids production
of 7.0 MMboe was down 6% due to planned and unplanned
outages, including compressor downtime at satellite fields,
and natural field decline. The operator Santos undertook a
comprehensive in-line inspection of the Big Lake to Moomba
trunkline to reduce the chance of further unplanned shutdowns.
Net oil production of 1.1 MMbbls was down 12% due to natural
field decline and weather-related outages.
Exploration, appraisal and development
Beach participated in 43 Cooper Basin JV wells during
FY21, including 40 gas wells (11 exploration, 9 appraisal and
20 development) and 3 oil wells (2 appraisal and 1 development,
with an overall success rate of 84%).
During the financial year, the joint venture completed
de-bottlenecking of Karmona triplex pipeline. The
de-bottlenecking activities increased throughput from south
west Queensland by approximately 6 mmscf/d (gross) and
frees up additional capacity within the Cooper Basin JV system.
Commercial
Beach and Origin concluded the price review of the Cooper
Basin Lattice GSA, which relates to a portion of the gas sold from
Beach’s interest in the Cooper Basin JV acquired from Origin
Energy in 2017. The agreed new price was completed with
favourable terms to Beach and will be applied to gas sold under
the Cooper Basin Lattice GSA from 1 July 2021 for a period of
three years.
During the year, Beach executed GSAs with customers for the supply
of uncontracted CBJV gas through calendar years 2021 and 2022.
In H2 FY21, Beach executed an agreement with Santos for
Beach to undertake FEED activities for the Moomba Capture
and Storage (CCS) project. The project aims to use existing
infrastructure and depleted fields within the Cooper Basin to
initially sequester 1.7 million tonnes of CO2 per annum (gross).
In June, the Australian Federal Government awarded the
Moomba CCS project funding of $15 million from the Carbon
Capture Use and Storage Development Fund and released
the public consultation paper regarding CCS methodology.
This highlights the Federal Government’s support for the
project, which is expected to support approximately 230 new
South Australian jobs through construction.
Description
Beach owns non-operated interest in the South Australian
Cooper Basin joint ventures (collectively 33.40% in SA Unit
and 27.68% in Patchawarra East), the South West Queensland
joint ventures (various interests of 30% to 52.2%) and ATP 299
(Tintaburra) (Beach 40%), which are collectively referred to as
the Cooper Basin JV. Santos is the operator.
Taranaki Basin
FY21 Highlights
• No recordable safety incidents encountered
throughout the Kupe compressor project.
• Approximately 98.5% reliability at the Beach-operated
Kupe facility.
FY22 Focus
• Completion of the Kupe compressor project during
H1 FY21.
• Evaluation of a potential development well into the
Kupe field to extend production plateau beyond FY24.
Operations
Taranaki Basin
FY21 Production
FY21 Production
2P Reserves
2.7MMboe
27MMboe
11% of Beach total
8% of Beach total
Operations
New Zealand operations accounted for 11% of Beach’s FY21
production. Net production was 2.7 MMboe, down 3% over
FY20 due to natural field decline. This was offset by improved
reliability of the Kupe Production Station, which has delivered
98.5% during FY21.
Development, Exploration and Appraisal
During FY21, Beach continued to progress the Kupe inlet
compression project and despite the global supply chain
challenges resulting from COVID-19, the project remains
on budget. At the end of the financial year, the project was
nearing mechanical completion, with the commencement of
commissioning activities in support of project completion in
H1 FY22.
Beach continues to assess opportunities to extend the 77 TJ
per day production plateau beyond FY24. Preparation work
for a potential Kupe East development well within the Kupe
field is expected to commence during FY22. This could lead to
the drilling of a potential development well in FY23, subject to
joint venture and regulatory approvals.
Beach also continues to assess the value of exploration
opportunities that could be drilled from and tied back to
the Kupe infrastructure. Further evaluation of a proposed
exploration well will be assessed during FY22.
Description
New Zealand operations comprises Kupe (Beach 50% and
operator, Genesis 46%, NZOG 4%) in the Taranaki Basin.
Kupe produces gas from the offshore Kupe field, situated
approximately 30-kilometres off the New Zealand North Island
in licence PML38146. Gas from the Kupe field is then piped to
the onshore Kupe production station.
98.5%
Kupe Production Station reliability
27
Beach Energy Limited Annual Report 2021 Operations
The BassGas Project accounted for 7% of Beach’s FY21
production. Net production from the project was 1.9 MMboe,
up 34% on the prior year, following the recognition of the
acquisition of MEPAU’s interest in the project from 1 January
2021. This was offset by planned compressor maintenance,
unplanned downtime and natural field decline.
Development
During FY21, Beach continued to assess opportunities to increase
the life of the existing BassGas Project infrastructure. The
Company completed a comprehensive Concept Select phase
for the Trefoil development and proceeded to the Front-End
Engineering Design phase in late FY21.
The Trefoil development concept comprises two offshore
development wells and an approximate 37-kilometre tie-back
to Beach’s existing offshore Yolla platform. The concept would
allow for the life extension of the Yolla field. Beach is targeting
FID in H1 FY23, with potential for first gas in H2 FY25, subject
to necessary internal and external approvals.
Beach continued to assess upside opportunities from the
producing Yolla field, including a three well wireline intervention
campaign planned for FY22 and potential infield drilling.
Exploration and Appraisal
Seismic reprocessing over the Yolla field in FY21 has shown
favourable uplift in imaging. During FY22 Beach plans to assess
the potential value of additional in-field drilling and in-well
optimisation activities to extend production.
Planning of the Prion 3D seismic survey covering the White
Ibis and Bass discoveries and the Trefoil field continued during
FY21. Data is expected to be acquired during FY22, subject
to regulatory approvals. The high-resolution 3D seismic data
is expected to improve imaging of the Trefoil field and provide
a more informed FID for the Trefoil development. Imaging
of the White Ibis and Bass discoveries with 3D seismic is
aimed at quantifying their potential value as tiebacks into a
Trefoil development.
Operating
Review
Bass Basin
FY21 Highlights
• Announced the acquisition of all MEPAU’s Bass
Basin interests.
• Completed comprehensive Concept Select and
entered FEED phase for the potential Trefoil
development project.
• Completed emissions reduction project through
decreased flaring of off-spec gas during Lang Lang
Gas Plant start-up.
FY22 Focus
• Safely undertake planned major integrity shutdown
of the Lang Lang gas facility and Yolla compressor.
• Progress FEED studies for the Trefoil development,
targeting FID in H1 FY23.
• Complete three well wireline intervention campaign
within Yolla field.
• Undertake 3D seismic acquisition over the White Ibis
and Bass discoveries and Trefoil field.
• Continue to assess opportunities to extend Yolla field
life through wireline intervention and infield drilling.
Operations
Bass Basin
FY21 Production
FY21 Production
Taranaki Basin
2P Reserves
2P Reserves
1.9MMboe
7% of Beach total
31MMboe
9% of Beach total
28
Bass Basin, VIC
Focused
on safety
Commercial
During FY20, Beach entered into an Asset Sale and Purchase
Agreement with MEPAU subsidiaries to acquire all its interests
in the Bass Basin. These assets include MEPAU’s 35.0% interest
in the BassGas Project (comprising the onshore BassGas Plant
and offshore Yolla gas field), as well as its 40.0% interest in the
Trefoil development project and surrounding retention leases.
The terms of the acquisition are confidential and subject to
regulatory approvals and third-party consents. The transaction
has an effective date of 1 July 2020, and was subsequently
completed in July 2021.
Description
The BassGas Project (Beach 88.75% and operator, Prize
Petroleum 11.25%) produces gas from the Yolla field, situated
approximately 140 kilometres off the Gippsland coast in licence
T/L1. Gas from Yolla is piped to a gas processing facility located
near the township of Lang Lang, approximately 70 kilometres
southeast of Melbourne. Beach also holds a 90.25% operated
interest in licences T/RL2, T/RL3, T/RL4 and T/RL5, which host
the Trefoil, White Ibis and Bass gas discoveries.
29
Beach Energy Limited Annual Report 2021 Operations
South Australian Otway operations contributed 1% of Beach’s
FY21 production. Net production was 0.3 MMboe, up 77% over
FY20. Operations at the Katnook Gas Plant are planned to be
suspended during H2 FY22 as gas volumes decline below the
minimum turndown rate.
Development, Exploration and Appraisal
Beach plans to conduct a 3D seismic survey over the Dombey
gas discovery during FY22 to assess potential of development
of this discovery through the Katnook Gas Plant.
Beach and Cooper Energy were awarded exploration licence
PEL 680 in March 2021. The work commitments under the
licence predominantly focus on geological and geophysical
studies, with the possibility of 2D seismic acquisition over the
initial five-year period.
Description
SA Otway gas producing area is PPL 62 (Beach 100%).
Other licences include PEL 494, which contains the Dombey
gas field, PEL 680 and PRL 32 (Beach 70% and operator,
Cooper Energy 30%).
Beach plans to conduct a
3D seismic survey over the
Dombey gas discovery during
FY22 to assess potential of
development of this discovery
through the Katnook Gas Plant.
Operating
Review
South Australian Otway
FY21 Highlights
• Production increased 77% from FY20.
• Awarded exploration licence PEL 680 with
Cooper Energy.
FY22 Focus
• 3D seismic acquisition over the Dombey field
to take place during H1 FY22.
Operations
SA
FY21 Production
FY21 Production
0.3MMboe
1% of Beach total
30
Frontier Exploration
Bonaparte Basin
Beach and its joint venture participants (Neptune 54%
and operator, Santos 40.25% and Beach 5.75%) continued
interpretation of the Petrelex 3D seismic survey over the Petrel
gas field. Neptune is progressing the final resource estimate
and the development concept, which are expected during
FY22. The joint venture was awarded a new exploration permit,
WA-545-P, which lies south of the Petrel field.
The joint venture was granted two new exploration permits
(NT/P88 and WA-548-P) that surround the Petrel gas field and
capture the potential extension of the field.
Carnarvon Basin
The Ironbark gas exploration prospect in exploration permit
WA-359-P (BP 42.5% and operator, Cue 21.5%, Beach 21%
and NZOG 15%), offshore Carnarvon Basin was drilled to a
total depth of 5,618 metres (MD) in Q2 FY21. Logging while
drilling data indicated no significant hydrocarbons were
present within the primary reservoir. The well was plugged and
abandoned and the rig mobilised from site on 11 January 2021.
In March, Beach withdrew from the WA-359-P and the joint
venture subsequently did not renew the permit. The WA-359-P
permit is now expired.
Canterbury Basin
During FY21, Beach and its joint venture participants applied
to surrender exploration permit PEP 52717 (Clipper), which
contains the Barque prospect, and PEP 38264, which contains
the Wherry prospect, in offshore New Zealand Canterbury
Basin. Both submissions to surrender have been approved by
the regulator. The decision was made as it was determined that
the projects did not meet the risk profile required for frontier
exploration expenditure.
Great South Basin
During FY21, Beach and its joint venture participants submitted
an application to surrender PEP 50119 (Tawhaki). This surrender
application was granted in FY21. Planning is underway for a
regulatory compliance post-drill marine benthic marine survey
which is planned for H2 FY22.
Kupe, New Zealand
Focused on
creating value
31
Beach Energy Limited Annual Report 2021 Reserves
Statement
Net to Beach at 30 June 2021.
Beach ended the year with 339 MMboe
in 2P oil and gas reserves
Beach’s 2P reserves declined by 13 MMboe (-4%) to
339 MMboe at 30 June 2021 due to production of 26 MMboe,
a 26 MMboe downgrade within the Western Flank oil and
gas assets and re-classification of 5 MMboe at La Bella to
2C contingent resources following exploration success at
Enterprise and Artisan.
The reductions to 2P reserves were offset by discovery of the
Enterprise gas field in the offshore Otway Basin, which added
20 MMboe, and acquisitions of Senex Energy’s Cooper Basin
assets and Mitsui’s interests in the Bass Basin, adding 7 MMboe
and 14 MMoe respectively.
2C contingent resources increased by 11 MMboe to 191 MMboe
(+6%) following acquisition of Mitsui’s interests in the Bass
Basin, exploration success at Artisan, re-classification of La Bella
reserves and removal of some contingent resources from the
Cooper Basin joint venture.
Key metrics
1P Reserves
2P Reserves
3P Reserves
2C Contingent Resources
Organic 2P reserve replacement ratio
Inorganic 2P reserve replacement ratio
2P reserves life (years)
1
2
3
Note
FY19
(MMboe)
FY20
(MMboe)
FY21
(MMboe)
201
326
514
185
204%
141%
12.4
202
352
576
180
214%
200%
13.2
183
339
531
191
(33%)
49%
13.2
1P Reserves (MMboe)
2P Reserves (MMboe)
2P Reserve Life (Years)
190
201
202
183
313
326
352
339
12
11
13
13
38
FY17
FY18
FY19
FY20
FY21
75
FY17
FY18
FY19
FY20
FY21
FY17
FY18
FY19
FY20
FY21
7
32
1P Reserves
Note
FY20 Production
Western Flank Oil
Western Flank Gas
Cooper Basin JV
Perth Basin
Otway Basin
Bass Basin
Taranaki Basin
Total
4, 5
5, 6
7
8
9
10, 11
12
24
8
45
55
35
13
22
7
2
8
1
3
2
3
202
26
All products (MMboe)
Acquisition/
Divestment
Exploration/
Appraisal
Contingent
Resources
to Reserves
Other
Total
Revisions
FY21
3
2
–
–
–
10
–
14
–
–
0
–
7
–
–
7
(0)
(1)
0
–
(4)
–
–
(9)
(2)
(0)
(1)
2
(0)
0
(5)
(10)
(7)
(1)
1
(1)
6
9
0
7
10
5
37
54
38
20
19
183
1P Reserves
Western Flank Oil
Western Flank Gas
Cooper Basin JV
Perth Basin
Otway Basin
Bass Basin
Taranaki Basin
Total
Note
4, 5
5, 6
7
8
9
10, 11
12
Gas
(PJ)
LPG
(kt)
Condensate
(MMbbl)
Oil
(MMbbl)
Total
(MMboe)
Developed
Undeveloped
All Products
–
18
163
313
185
93
80
–
89
310
–
355
230
350
852
1,334
–
1
3
0
3
3
2
12
10
–
4
–
–
–
–
10
5
37
54
38
20
19
14
183
7
4
33
16
10
2
16
89
3
1
4
37
28
18
3
94
33
Beach Energy Limited Annual Report 2021
Reserves Statement
2P Reserves
Note
FY20 Production
Western Flank Oil
Western Flank Gas
Cooper Basin JV
Perth Basin
Otway Basin
Bass Basin
Taranaki Basin
Total
4, 5
5, 6
7
8
9
10, 11
12
46
16
85
101
56
19
29
7
2
8
1
3
2
3
352
26
All products (MMboe)
Acquisition/
Divestment
Exploration/
Appraisal
Contingent
Resources
to Reserves
Other
Total
Revisions
5
2
–
–
–
14
–
21
–
–
0
–
20
–
–
20
(1)
(2)
1
–
(5)
–
–
(17)
(6)
(1)
(0)
2
0
0
(7)
(22)
(13)
(5)
0
(0)
17
14
0
13
FY21
26
8
77
100
70
31
27
339
Note
4, 5
5, 6
7
8
9
10, 11
12
Gas
(PJ)
–
31
341
583
346
141
113
LPG
(kt)
Condensate
(MMbbl)
Oil
(MMbbl)
Total
(MMboe) Developed
Undeveloped
All Products
–
151
631
–
652
358
494
–
2
6
0
5
4
3
26
–
8
–
–
–
–
26
8
77
100
70
31
27
339
20
7
60
23
10
4
22
6
1
17
77
59
27
5
146
193
1,555
2,285
20
34
2P Reserves
Western Flank Oil
Western Flank Gas
Cooper Basin JV
Perth Basin
Otway Basin
Bass Basin
Taranaki Basin
Total
34
Beach Energy Limited Annual Report 2021
2C Contingent
Resources
FY20
(MMboe)
Note
Reserves
to
Contingent
Resources
(MMboe)
Acquisition/
Divestment
(MMboe)
Revisions
(MMboe)
FY21
(MMboe)
Gas
(PJ)
LPG
(kt)
Condensate
(MMbbl)
Oil
(MMbbl)
Total
(MMboe)
5
1
60
39
19
5
6
23
157
14
23
180
Western Flank
Oil
Western Flank
Gas
Cooper Basin JV
Perth Basin
Otway Basin
4, 5
5, 6
7
8
9
Bass Basin
10, 11
Taranaki Basin
Bonaparte Basin
12
13
Total
Conventional
2C Contingent
Resources
Cooper Basin JV
(unconventional)
Total 2C
Contingent
Resources
Notes
3
0
–
–
–
4
–
–
7
–
7
(1)
(2)
1
–
(5)
–
–
–
3
(1)
0
(0)
7
1
(1)
–
12
2
59
38
31
10
5
23
–
6
246
222
168
34
18
128
–
27
230
–
147
146
78
–
(7)
8
179
823
628
–
(11)
12
42
205
–
0
2
0
0
3
1
1
8
3
12
–
13
–
–
–
–
–
12
2
59
38
31
10
5
23
25
179
–
12
(7)
(3)
191
866
832
11
25
191
FY21 organic 2P reserves replacement ratio calculated as 2P reserves reduction of 8.5 MMboe divided by FY21 reported production of 25.6 MMboe.
(1)
(2) FY21 inorganic 2P reserves replacement ratio calculated as 2P reserves additions of 12.6 MMboe divided by FY21 reported production of 25.6 MMboe.
(3) FY21 2P reserves life calculated as 339.3 MMboe divided by FY21 production of 25.6 MMboe.
(4) Western Flank Oil comprises ex PEL 91 (Beach 100%), ex PEL 92 (Beach 75%), ex PEL 104/111 (Beach 100%), PPL 207 (Beach 70%) and PEL 113/115/516/90/93 and PRL 83 (Beach 100%).
1P reserves at 30 June 2021 are split ex PEL 91 (56%), ex PEL 92 (21%), ex PEL104/111 (22%) and other (1%). 2P reserves at 30 June 2021 are split ex PEL 91 (60%), ex PEL 92 (18%),
ex PEL 104/111 (22%) and other (1%).
(5) Acquisition of Senex Cooper Basin assets increased equity from 40% to 100% in ex PEL 104/111 and from 43% to 100% in PRL 135 (Vanessa). New permits include 70% in PPL 207 (Worrior),
100% in PEL 113/115/516/90/93, PRL 83 and PPL 270 (Gemba). The effective date of the acquisition is 1 July 2020. Refer ASX announcement #037/20, 3 November 2020.
(6) Western Flank Gas comprises ex PEL 106/91 (Beach 100%), PRL 135 and PPL 270 (Beach 100%). 1P reserves at 30 June 2021 are split ex PEL 106/91 (79%), PPL 270 (21%). 2P reserves at
30 June 2021 are split ex PEL 106/91 (82%), PPL 270 (18%).
(7) Cooper Basin JV comprises the South Australian Cooper Basin joint ventures (Beach 27.68% and 33.4%), the South West Queensland joint ventures (Beach 20.76% to 45%), SWJV and
Tintaburra JV (Beach 40%).
(8) Perth Basin comprises Waitsia (Beach 50%) and Beharra Springs (Beach 50%).
(9) Otway Basin comprises Thylacine, Geographe, Artisan, La Bella, Halladale, Black Watch, Speculant and Enterprise (Beach 60%) and Haselgrove (Beach 100%). 1P reserves at 30 June 2021
are split Thylacine and Geographe (74%) and Halladale, Black Watch, Speculant, Enterprise (26%). 2P reserves at 30 June 2021 are split Thylacine and Geographe (66%) and Halladale,
Black Watch, Speculant, Enterprise (34%).
(10) Bass Basin comprises Yolla (Beach 88.75%) and Trefoil, White Ibis (Beach 90.25%).
(11) Acquisition of Mitsui’s equity in Bass Basin assets increased equity from 53.75% to 88.75% in T/L1 (Yolla) and from 50.25% to 90.25% in T/RL2 and T/RL4 (Trefoil and White Ibis).
The effective date of the acquisition is 1 July 2020. Refer ASX announcement #002, 27 January 2021.
(12) Taranaki Basin comprises Kupe (Beach 50%).
(13) Bonaparte Basin comprises Petrel (Beach 5.75%).
(14) Cooper Basin JV (unconventional) includes the South Australian Cooper Basin joint ventures (Beach 27.68% and 33.4%) classified as unconventional.
35
Material Reserves Changes
Beach has previously disclosed material reserves changes
throughout the year in accordance with continuous disclosure
obligations. These included:
• Acquisition of Senex Energy’s Cooper Basin assets
(refer to ASX Announcement #037/21 (3 November 2020):
“Beach expands Cooper Basin portfolio”).
• Acquisition of Mitsui’s Bass Basin interest
•
(refer to ASX Announcement #002/21 (27 January 2021):
“FY21 Second Quarter Activities Report”).
Initial Report of Enterprise 2P Reserves
(refer to ASX Announcement #004/21 (15 February
2021): “Enterprise Exploration Success Delivers Material
2P Reserves Booking”).
• Western Flank 2P oil and gas reserves downgrade
(refer to ASX Announcement #013/21 (30 April 2021):
“Business Update”).
Material Contingent Resources Changes
There are no material contingent resources changes.
Reserves Statement
Notes to the Reserves Statement
The reserves and resources estimates are prepared in
accordance with the 2018 update to the Petroleum Resources
Management System sponsored by the Society of Petroleum
Engineers, World Petroleum Council, American Association
of Petroleum Geologists and Society of Petroleum Evaluation
Engineers (SPE-PRMS).
The statement presents Beach’s net economic interest
estimated at 30 June 2021 using a combination of probabilistic
and deterministic methods. Each category is aggregated by
arithmetic summation. Note that the aggregated 1P category
may be a very conservative estimate due to the portfolio
effects of arithmetic summation.
Reserves are stated net of fuel, flare and vent at reference points
defined by the custody transfer point of each product, with
the exception of Waitsia reserves, which include 3.4 MMboe
of fuel used for LNG processing through the NWS facilities in
Karratha between the second half of 2023 and the end of 2028.
Conversion factors used to evaluate oil equivalent quantities
are sales gas and ethane: 171,940 boe per PJ, LPG: 8.458 boe
per tonne, condensate: 0.935 boe per bbl and oil: 1 boe per bbl.
The estimates are based on, and fairly represent, information
and supporting documentation prepared by, or under the
supervision of, Qualified Petroleum Reserves and Resources
Evaluators (QPRRE) employed by Beach. The QPRRE are
Ian Cockerill, Scott Delaney, Mark Sales and Jason Storey,
who are all members of the SPE.
The reserves statement as a whole is approved by
Ms Paula Pedler (Head of Reservoir Engineering). Ms Pedler
is an employee of Beach and a member of the SPE; she has
a Bachelor of Engineering (Honours) from the University of
Adelaide and in excess of 25 years of relevant experience.
The reserves statement has been issued with the prior written
consent of Ms Pedler as to the form and context in which the
estimates and information are presented.
Beach prepares its reserves and resources estimates annually
as specified in the Beach reserves policy. This policy also details
the external audit and internal governance requirements of
the reserves and resources estimation process.
An independent audit of Beach’s reserves at 30 June 2021
was conducted by RISC Advisory Pty Ltd (RISC). In RISC’s
opinion the YEJ21 reserves estimates are reasonable and
have been prepared in accordance with the definitions and
guidelines contained within the SPE-PRMS and generally
accepted petroleum engineering and evaluation principles.
The audit encompassed 52% of 2P reserves and included
69% of developed reserves and 38% of undeveloped reserves.
Contingent resources have not been audited.
36
Beach Energy Limited Annual Report 2021
Kupe, Taranaki Basin, New Zealand
37
Sustainability
Focused on
Sustainability.
The role of Gas
As a significant producer of natural gas, Beach has an important
role to play in a low carbon future, as natural gas is widely
recognised for its part in reducing global emissions.
Natural gas produces half the greenhouse gas emissions of
coal when used to generate electricity.1
The International Energy Agency’s (IEA) Sustainable Development
Scenario, under which global temperature growth is limited to well
below 2 degrees, highlights the role of coal-to-gas switching.
It states coal-to-gas switching is essential to the US’
decarbonisation providing almost a quarter of all emission
reductions required.3
In the United Kingdom, coal-to-gas switching has contributed
to a drop of 50 per cent in the emissions intensity of power
generation since 2010.4 This has supported a drop in the UK’s
total emissions of 32 per cent since 2008 and more than
50 per cent since 1990, overachieving on targets already at
the leading edge of developed nations.
In an Australian context, the development of more natural gas
supplies is also seen as critical in reducing Australia’s emissions
footprint. The Integrated System Plan (ISP), which models
electricity generation over the next 20 years in the National
Electricity Market (NEM), was updated in August 2020 by AEMO.
The ISP predicts higher levels of gas fired power generation in
2041–42 relative to 2021–22 levels in all modelled scenarios,
including the most ambitious ‘step change’ scenario, which
would see most coal fired generation closed over this timeframe
to achieve a 90% reduction in carbon emissions from power
generation by 2041–42.
Under this step change scenario, gas-fired generation increases
33% through to 2041–42, enabling renewables generation to
increase by 285%.
AEMO 2020 Integrated System Plan – Step Change Scenario
2021–22
% Share
2041–42
% Share
%
Change
61.2
1.5
7.8
0.4
29.1
2.2
1.5
5.1
9.7
81.4
–95
33
–9
3,442
285
Coal
Gas
Hydro
Storage
Renewables
FY21 Sustainability Report
The Beach Energy FY21 Sustainability Report
will be released on 18 August 2021.
To read this year’s report visit
beachenergy.com.au/sustainability
(1, 2, 3, 4). International Energy Agency, The Role of Gas in Today’s Energy Transitions, 2019
38
Sustainably delivering energy
for Communities
Regardless of the critical role natural gas has to play in the future
energy mix, Beach recognises that climate change is one of the
global challenges of this century and, as a member of the energy
industry, it has a role to play in managing carbon emissions.
As such, Beach is committed to integrating low emissions
technologies in our operations and identifying opportunities for
carbon emission reduction, where economically practicable.
In addition, Beach is committed to playing a role in helping
Australia and New Zealand meet their commitments under the
Paris Agreement by:
• Pursuing growth of natural gas – the transition fuel
• Helping to meet the demand increase globally
• Aligning with Australia’s energy ambitions
• Modelling against various climate and pricing scenarios
• Being part of an industry driven effort to lower absolute
emissions – including emissions intensity
Beach is focused on taking practical steps to reduce emissions
from its operations, and in FY20, we announced our 25 by 25
initiative which aims to reduce emissions by 25 per cent by
FY25 against FY18 levels.
In FY21, we established a new Sustainability division of the
business, to identify and ensure delivery of key emissions
reductions initiatives.
Beach also made significant
progress on 25 by 25 in FY21,
delivering the first projects
which result in the reduction
of flaring at both our key gas
processing facilities in Victoria.
Beach is also a participant, along with operator Santos, in
the proposed Moomba Carbon Capture and Storage Project,
which aims to safely and permanently store 1.7 million tonnes
of carbon dioxide (CO2) per year.
800
600
400
200
e
2
O
C
t
K
~12%
On
Track
FY18
FY21
FY25
Subject to final National Greenhouse Emissions Reporting Scheme
(NGERs) numbers. Does not include emissions from the acquired
Senex Cooper Basin assets and fuel data for Katnook.
25BY
25
Progressing 25 by 25
Mercury Removal Facility
Installation of mercury removal facilities into the Mol
Sieve Regen Gas Circuit at Otway Gas Plant has resulted
in Beach reducing its anticipated CO2 emissions by around
12,000 tonnes over the next 12 years.
12,000t
Anticipated CO2 emission reduction
over the next 12 years
BassGas Start Up Procedure
Change to plant operating parameters for restart using
existing infrastructure resulting in reduced need for flaring
and estimated reduction of 2,500 tonnes of CO2 per year.
2,500t
Estimated reduction of CO2 per year
Our Safest Year
on Record
At Beach, safety takes priority in everything we do.
In FY21, Beach recorded its safest year on record, with a Total
Recordable Injury Frequency Rate (TRIFR) of 2.1. This was a
40 per cent improvement from FY20.
Beach also passed the significant milestone of three-million
hours without a Lost Time Injury.
Safety initiatives in FY21 that contributed to this result include:
• Rollout of a new Operations Excellence Management
System (OEMS) which sets out a framework for all of
Beach’s policies and procedures
• Delivery of a new Safety Strategy for the Cooper Basin. This
initiative was a finalist in the 2021 Australian Petroleum
Production and Exploration Association (APPEA) Awards.
39
Beach Energy Limited Annual Report 2021 Board of
Directors
Glenn Davis
Independent Non-Executive Chairman
LLB, BEc, FAICD
Matthew (Matt) Kay
Managing Director &
Chief Executive Officer
BEc, MBA, FCPA, GAICD
Colin Beckett AO
Independent Non-Executive
Deputy Chairman
Mr Davis has practiced as a solicitor in
corporate and risk throughout Australia
for over 30 years initially in a national
firm and then a firm he founded. He
has expertise and experience in the
execution of large transactions, risk
management and in corporate activity
regulated by the Corporations Act and
ASX Limited. Mr Davis has worked in
the oil and gas industry as an advisor
and director for over 25 years.
Mr Davis’s special responsibilities
include membership of the
Remuneration and Nomination
Committee. Mr Davis joined Beach on
6 July 2007 as a non-executive director.
He was appointed non-executive Deputy
Chairman in June 2009 and Chairman in
November 2012. He was last re-elected
to the board on 25 November 2020.
Mr Kay joined Beach in May 2016
as Chief Executive Officer and was
appointed to the Board as Managing
Director in February 2019. In
November 2018, he was elected to the
Australian Petroleum Production &
Exploration Association (APPEA) Board.
Mr Kay brings 28 years of experience
in the Oil and Gas industry to Beach.
Before joining Beach, he served as
Executive General Manager, Strategy
and Commercial at Oil Search, a position
he held for two years. In that role he
was a member of the Executive team
and led the strategy, commercial,
supply chain, economics, marketing,
M&A and legal functions.
Prior to Oil Search, Mr Kay spent
12 years with Woodside Energy in
various leadership roles, including Vice
President of Corporate Development,
General Manager of Production Planning
and General Manager of Commercial for
Middle East and Africa. In these roles
Mr Kay developed extensive leadership
skills across LNG, pipeline gas and oil
joint ventures, and developments in
Australia and internationally.
Mr Beckett is an experienced
non-executive director and previously
held senior executive positions in
Australia with Chevron, Mobil, and BP. His
experience in engineering design, project
management, commercial negotiations
and gas marketing provides him with a
diverse and complementary set of skills
relevant to the oil and gas industry.
Mr Beckett read engineering at
Cambridge University and has a Master
of Arts. He was awarded an honorary
doctorate from Curtin University in
2019. He was previously a fellow of the
Australian Institute of Engineers. He is
a graduate member of the Institute of
Company Directors.
He is currently Chair of Western
Power. He was the Chancellor of Curtin
University until end 2018. He is a past
Chairman of Perth Airport Pty Ltd
and past Chairman of the Australian
Petroleum Producers and Explorers
Association (APPEA).
Mr Beckett’s special responsibilities
include chairmanship of the Remuneration
and Nomination Committee and
membership of the Risk, Corporate
Governance and Sustainability Committee.
He was appointed to the Board on
2 April 2015, last having been re-elected to
the Board on 26 November 2019.
40
Philip Bainbridge
Independent Non-Executive Director
BSc (Hons) Mechanical Engineering,
MAICD
Mr Bainbridge has extensive industry
experience having worked for the
BP Group for 23 years in a range of
petroleum engineering, development,
commercial and senior management
roles in the UK, Australia and USA.
From 2006, he has worked at Oil Search,
initially as Chief Operating Officer,
then Executive General Manager LNG,
responsible for all aspects of Oil Search’s
interests in the $19 billion PNG LNG
project, then EGM Growth responsible
for gas growth and exploration.
He is currently a member of PNG
Sustainable Development Program, a
company limited by guarantee and the
non-executive chairman of the Global
Institute of Carbon Capture and Storage.
He was formerly the non-executive
chairman of Sino Gas and Energy
Holdings until 2018 and a non-executive
director of Drillsearch Energy Limited
from 2013 to 2016.
Mr Bainbridge’s special responsibilities
include membership of the Risk,
Corporate Governance and Sustainability
Committee and the Audit Committee.
He was appointed by the Board on
1 March 2016, last having been elected
to the Board on 26 November 2019.
Joycelyn Morton
Independent Non-Executive Director
BEc, FCA, FCPA, FIPA, FCIS, FAICD
Ryan Stokes AO
Non-Executive Director
BComm FAIM
Ms Morton has extensive experience in
finance and taxation having begun her
career with Coopers & Lybrand (now
PwC), followed by senior management
roles with Woolworths Limited and
global leadership roles in Australia and
internationally within the Shell Group
of companies.
Ms Morton was National President of
both CPA Australia and Professions
Australia, has served on many
committees and councils in the private,
government and not-for-profit sectors
and held international advisory positions.
She holds a Bachelor of Economics
degree from the University of Sydney.
Her other current ASX listed board
positions are Argo Investments Limited,
Argo Global Listed Infrastructure Limited
and Felix Group Holdings Limited. She is
also a non-executive director of ASC Pty
Ltd and, as of 30 June 2021, concluded
nine years with Snowy Hydro Limited –
both government owned corporations.
She has valuable board experience
across a range of industries, including
previous roles as a non-executive director
and Chair of both Thorn Group Limited
and Noni B Limited and a non-executive
director of Crane Group Limited, Count
Financial Limited and InvoCare Limited.
Ms Morton’s special responsibilities
include membership of the Audit
Committee. She was appointed a
non-executive director of Beach Energy
Limited on 23 February 2018.
Mr Stokes is the Managing Director and
Chief Executive Officer of Seven Group
Holdings Limited (SGH). SGH is a listed
diverse investment company involved in
Industrial Services, Media, and Energy.
SGH interests include 30.02% of Beach
Energy, WesTrac, Coates Hire and 41%
of Seven West Media Limited. Mr Stokes
is Chairman of Boral Limited, Chairman
of Coates Hire and a director of WesTrac
and Seven West Media.
Mr Stokes is Chief Executive Officer of
Australian Capital Equity Pty Limited
(ACE). ACE is a private company with
its primary investment being an interest
in SGH. Mr Stokes is Chairman of the
National Gallery of Australia and is an
Officer of the Order of Australia. He is also
a member of the International Olympic
Committee Education Commission.
His previous roles include Chairman
of the National Library of Australia,
member of the Prime Ministerial
Advisory Council on Veterans’ Mental
Health, Founding Chair Headspace,
Youth Mental Health Foundation.
Mr Stokes is a member of the
Remuneration and Nomination
Committee. He was appointed by the
Board on 20 July 2016, last having
been re-elected to the Board on
23 November 2018.
Margaret Helen Hall
Alternate director for Ryan Stokes
Non-Executive Director
B.Eng (Met) Hons, MIEAust, GAICD, SPE
Ms Hall was appointed alternate director
for Mr Stokes on 3 May 2021. Biographical
details regarding Ms Hall are set out
within the Directors Report on page 57.
41
Beach Energy Limited Annual Report 2021 Board of
Directors
Richard Richards
Non-Executive Director
BComs/Law (Hons), LLM, MAppFin, CA,
Admitted Solicitor
Mr Richards is currently Chief Financial
Officer of Seven Group Holdings
Limited (SGH) (since October 2013).
He is responsible for Finance across the
diversified conglomerate (equipment
manufacture, sales and service,
equipment hire, investments, property,
media and oil and gas). Mr Richards
is a member of the Board of Directors
of Boral Limited, WesTrac Pty Limited
and SGH Energy Pty Limited, is a
Director and Chair of the Audit and Risk
Committee of Coates Hire Pty Limited,
a Director and member of KU Children
Services (NFP) and a member of the
Marcia Burgess Foundation Committee
(DGR). He has held senior finance roles
with Downer EDI, the Lowy Family Group
and Qantas.
Mr Richards is both a Chartered
Accountant and admitted solicitor with
over 30 years of experience in business
and complex financial structures,
corporate governance, risk management
and audit.
Mr Richards’ special responsibilities
include membership of the Audit
Committee, and as a member of the Risk,
Corporate Governance & Sustainability
Committee. He was appointed to
the Board on 4 February 2017 and
was last re-elected to the Board on
25 November 2020.
42
Dr Peter Moore
Independent Non-Executive Director
PhD, BSc (Hons), MBA, GAICD
Sally-Anne Layman
Independent Non-Executive Director
B Eng (Mining) Hon, B Com, CPA, MAICD
Sally-Anne Layman is a company
director with diverse international
experience in the resources sector and
financial markets. Previously, Ms Layman
held a range of senior positions with
Macquarie Group Limited, including as
Division Director and Joint Head of the
Perth office of the Metals, Mining &
Agriculture Division.
Prior to moving into finance, Ms Layman
undertook various roles with resource
companies including Mount Isa Mines,
Great Central Mines and Normandy
Yandal. Ms Layman holds a WA First
Class Mine Manager’s Certificate of
Competency.
Ms Layman is also a Non-Executive
Director of Imdex Ltd, Pilbara Minerals
Ltd and Newcrest Mining Ltd.
Ms Layman holds a Bachelor of
Engineering (Mining) Hon from Curtin
University and a Bachelor of Commerce
from the University of Southern
Queensland. Ms Layman is a Certified
Practicing Accountant, and is a member
of CPA Australia Ltd and the Australian
Institute of Company Directors.
Ms Layman is Chair of the Audit
Committee, was appointed to the Board
in February 2019 and formally elected to
the Board on 26 November 2019.
Dr Moore has over 40 years of oil and
gas industry experience. His career
commenced at the Geological Survey
of Western Australia, with subsequent
appointments at Delhi Petroleum Pty
Ltd, Esso Australia, ExxonMobil and
Woodside. Dr Moore joined Woodside
as Geological Manager in 1998 and
progressed through the roles of Head
of Evaluation, Exploration Manager
Gulf of Mexico, Manager Geoscience
Technology Organisation and Vice
President Exploration Australia.
From 2009 to 2013, Dr Moore led
Woodside’s global exploration efforts
as Executive Vice President Exploration.
In this capacity, he was a member of
Woodside’s Executive Committee and
Opportunities Management Committee,
a leader of its Crisis Management Team,
Head of the Geoscience function and
a director of ten subsidiary companies.
From 2014 to 2018, Dr Moore was
a Professor and Executive Director
of Strategic Engagement at Curtin
University’s Business School. He has
his own consulting company, Norris
Strategic Investments Pty Ltd. Dr Moore
is currently a non-executive director of
Carnarvon Petroleum Ltd (since 2015).
Dr Moore’s special responsibilities
include chairmanship of the Risk,
Corporate Governance and Sustainability
Committee and membership of
the Remuneration and Nomination
Committee. Dr Moore was appointed
by the Board on 1 July 2017 and
last re-elected to the Board on
26 November 2019.
Full Financial Report
Directors’ Report
Auditor’s Independence Declaration
2021 Remuneration in Brief (Unaudited)
Remuneration Report (Audited)
Directors’ Declaration
Financial Statements
Consolidated Statement of Profit or Loss and
Other Comprehensive Income
Consolidated Statement of Financial Position
Consolidated Statement of Changes in Equity
Consolidated Statement of Cash Flows
Notes to the Financial Statements
Basis of preparation
Results for the year
1. Operating segments
2.
Revenue from contracts with customers
and other income
Expenses
Employee benefits
Taxation
Earnings per share (EPS)
Inventories
Property, plant and equipment (PPE)
Petroleum Assets
Exploration and evaluation assets
Intangible assets
Interests in joint operations
Provisions
Leases
Commitments for expenditure
3.
4.
5.
6.
Capital employed
7.
8.
9.
10.
11.
12.
13.
14.
15.
Financial and risk management
16.
17.
18.
Equity and group structure
Contributed equity
19.
20. Reserves
Dividends
21.
Subsidiaries
22.
Deed of cross guarantee
23.
Parent entity financial information
24.
Related party disclosures
25.
26.
Acquisitions and disposals
Other information
27.
Contingent liabilities
28. Remuneration of auditors
Subsequent events
29.
Finances and borrowings
Cash flow reconciliation
Financial risk management
Independent Auditor’s Report
Glossary
Schedule of Tenements
Shareholder information
Corporate directory
125
130
132
137
BC
44
59
60
62
79
80
80
81
82
83
84
84
87
87
89
90
91
93
96
97
97
97
98
101
102
102
104
106
108
109
109
110
111
115
115
116
116
117
118
120
121
121
123
123
124
124
43
Beach Energy Limited Annual Report 2021 Directors’ Report
Your directors present their report for Beach Energy Limited (Beach or Company) on the consolidated accounts for the financial
year ended 30 June 2021. Beach is a company limited by shares that is incorporated and domiciled in Australia.
The directors of the Company during the year ended 30 June 2021 and up to the date of this report are:
Surname
Davis
Beckett
Bainbridge
Hall
Kay
Layman
Moore
Morton
Richards
Stokes
Other Names
Glenn Stuart
Colin David
Philip James
Margaret Helen
Matthew Vincent
Sally-Anne Georgina
Peter Stanley
Joycelyn Cheryl
Richard Joseph
Ryan Kerry
Position
Independent non-executive Chairman
Independent non-executive Deputy Chairman
Independent non-executive director
Alternate non-executive director (1)
Managing director
Independent non-executive director
Independent non-executive director
Independent non-executive director
Non-executive director
Non-executive director
(1) Appointed as an alternate director for Mr Stokes on 3 May 2021.
Directors Interests in shares, options and rights
The relevant interest of each director in the ordinary share capital of Beach at the date of this report is:
Shares held in Beach Energy Limited
Name
G S Davis
C D Beckett
P J Bainbridge
M V Kay
S G Layman
P S Moore
J C Morton
R J Richards (3)
R K Stokes (3)
M H Hall (3)(4)
Shares
320,101 (2)
91,678 (1)
137,320 (2)
3,918,255 (1)
45,000 (2)
44,200 (2)
74,000 (1)(2)
388,053 (2)
–
17,068 (2)
Rights
–
–
–
3,105,102 (1)
–
–
–
–
–
–
(1) Held directly.
(2) Held by entities in which a relevant interest is held.
(3) Mr Stokes does not hold a relevant interest in Beach shares but he was nominated as a director by Beach’s largest shareholder Seven Group Holdings Limited (SGH) and related corporations
who collectively have a relevant interest in 30.02% of Beach shares. He is Managing Director and Chief Executive Officer of SGH. Mr Richards was also nominated as a director by SGH. He is the
Chief Financial Officer of SGH. Ms Hall is the chief executive officer of Seven Group Holdings Energy.
(4) Ms Hall is an alternate director for Mr Stokes, appointed till no later than 3 May 2022 or until terminated in accordance with the Beach constitution.
Details of the qualifications, experience, special responsibilities and meeting attendance of each of the directors are set out later in
the Directors’ Report.
44
Principal activities
Beach Energy is an ASX listed, oil and gas, exploration and production company headquartered in Adelaide, South Australia.
It has operated and non-operated, onshore and offshore, oil and gas production from five producing basins across Australia and
New Zealand and is a key supplier to the Australian east coast gas market. Beach’s asset portfolio includes ownership interests
in strategic oil and gas infrastructure and assets across Australia and New Zealand and continues to pursue growth opportunities
which align with its strategy, satisfy strict capital allocation criteria, and demonstrate clear potential for shareholder value creation.
Beach is focused on maintaining the highest health, safety and environmental standards.
Operating and Financial Review
A review of operations of Beach Energy during the financial year are set out on pages 17 to 31.
Financial results from FY21 are summarised below:
– Group profit attributable to equity holders of Beach was $316.5 million (FY20 $499.1 million).
– Sales revenue was down 8% from FY20 to $1,519.4 million due to lower volumes and unfavourable A$/US$ exchange rates,
partly offset by favourable US dollar oil and liquids prices.
– Cost of sales were down 8% from FY20 to $967.1 million, mainly as a result of lower tariff and toll charges, royalties, third party
purchases and depreciation partly offset by inventory movements.
– A net profit after tax of $316.5 million was reported reflecting lower sales and other revenue, higher impairment and exploration
expense partly offset by lower cost of sales and related tax impacts.
Key Results
Operations
Production
Production (pro-forma) (1)
Sales
Capital expenditure
Income
Sales revenue
Total revenue
Cost of sales
Gross profit
Other income
Net profit after tax (NPAT)
Underlying NPAT (2)
Dividends paid
Dividends announced
Basic EPS
Underlying EPS (2)
Cash flows
Operating cash flow
Investing cash flow
Financial position
Net assets
Cash balance
2021
2020
Change
MMboe
MMboe
MMboe
$m
$m
$m
$m
$m
$m
$m
$m
cps
cps
cps
cps
$m
$m
$m
$m
24.8
25.6
26.1
(671.3)
1,519.4
1,562.0
(967.1)
594.9
51.1
316.5
363.0
2.00
1.00
13.88
15.92
26.7
26.7
27.7
(863.0)
1,650.3
1,728.2
(1,056.7)
671.5
76.6
499.1
459.3
2.00
1.00
21.89
20.15
759.8
(757.8)
873.9
(899.2)
3,087.8
126.7
2,817.8
109.9
(7%)
(4%)
(6%)
22%
(8%)
(10%)
8%
(11%)
(33%)
(37%)
(21%)
0%
0%
(37%)
(21%)
(13%)
16%
10%
15%
Includes the impact of the acquisition of Senex Energy’s Cooper Basin assets and Mitsui’s Bass Basin assets, with an effective date 1 July 2020.
(1)
(2) Underlying results in the table above are categorised as non-IFRS financial information provided to assist readers to better understand the financial performance of the underlying operating
business. They have not been subject to audit or review by Beach’s external auditors. Please refer to the table on page 47 for a reconciliation of this information to the financial report.
45
Beach Energy Limited Annual Report 2021 Directors’ Report
Revenue
Sales revenue of $1,519.4 million in FY21 was $130.9 million or 8% lower than FY20, driven by lower production volumes, higher FX
rates and lower third-party sales, partly offset by higher realised prices.
Lower production volumes, largely from the Western Flank, decreased sales revenue by $106.8 million, unfavourable A$/US$
exchange rates in FY21 resulted in a reduction in revenue of $69.3 million and lower sales from third party product decreased revenue
by $24.7 million. US dollar oil and liquids prices increased in FY21 resulting in an additional $65.5 million in revenue with the average
realised liquid price increasing to US$57.56/boe, up from US$52.36/boe in FY20.
Sales Revenue Comparison ($m)
1,800
1,600
1,400
1,200
1,000
800
600
400
200
0
1,650.3
65.5
Oil and
liquids
prices
US$/boe
FY20 $52.36
FY21 $57.56
4.4
(24.7)
Third party
sales
Gas/ethane
prices
A$/GJ
FY20 $7.29
FY21 $7.35
(69.3)
FX rates
A$/US$
FY20 $0.671
FY21 $0.747
(106.8)
Volume/
mix
1,519.4
8%
$130.9 million
total decrease
FY20
Average price
A$59.66/boe
FY21
Average price
A$58.28/boe
Gross Profit
Gross profit for FY21 of $594.9 million (FY20 $671.5 million) was down 11%, driven by lower sales and other revenue and inventory
movements, partly offset by lower total operating costs, depreciation and third party purchases.
The decrease in cost of sales, down 8% from FY20 to $967.1 million, is due principally to lower total operating costs, primarily lower
tariff and toll charges of $84.9 million including the favourable arbitral outcome regarding the allocation of carbon emissions under
one of Beach’s long term gas sales agreements and royalties of $7.4 million as a result of lower sales revenue and lower Cooper Basin
volumes. Third party purchases were lower reflecting less crude shipments with depreciation also lower due to reduced production
volumes. These are partly offset by inventory movements of $42.6 million driven by lower Cooper Basin volumes and costs.
Gross Profit Comparison ($m)
80.9
26.7
24.6
(42.6)
671.5
Depreciation
Third party
purchases
Inventory
Total
Operating
Costs
(166.2)
Sales and
other
revenue
Cost of Sales $89.6 million
11%
$76.6 million
total decrease
FY20
594.9
FY21
900
800
700
600
500
400
300
200
100
0
46
Net Profit Result
Other income of $51.1 million, is $25.5 million lower than FY20, due to lower joint venture lease recoveries of $5.7 million and the
prior period including gains on sale of joint operations of $8.9 million and cessation of overseas operations of $8.7 million.
Other expenses of $203.7 million were $160.2 million higher from FY20 with the impairment of the SA Otway $117.0 million,
exploration and evaluation expenditure expensed during FY21 of $56.7 million, relating to the IronBark exploration well drilled in FY21
and relinquishment of exploration areas of interest in FY21, and foreign exchange losses realised of $8.9 million.
The reported net profit after income tax of $316.5 million is $182.6 million lower than FY20, due to the lower gross profits driven by
lower volumes, higher other expenses resulting from impairment of assets during the period, partially offset by lower income tax
corresponding with lower profits.
By adjusting the FY21 profit to exclude asset impairment and an acquisition related liability reversal, Beach’s underlying net profit
after tax is $363.0 million.
Comparison of underlying profit
Net profit after tax
Adjusted for:
Gain on asset disposals
Gain on reversal of acquired liabilities
Impairment of assets
Tax impact of above changes
Underlying net profit after tax(1)
FY21
$ million
FY20
$ million
Movement
from PCP
$ million
316.5
499.1
(182.6)
-37%
–
(35.4)
117.0
(35.1)
(17.6)
(37.8)
1.6
14.0
363.0
459.3
17.6
2.4
115.4
(49.2)
(96.3)
-21%
(1) Underlying results in this report are categorised as non-IFRS financial information provided to assist readers to better understand the financial performance of the underlying operating business.
They have not been subject to audit or review by Beach’s external auditors. All of the items being adjusted pre-tax are separately identified within Notes 2(b) and 3(b) to the financial statements.
Underlying Net Profit After Tax Comparison ($m)
550
500
450
400
350
300
250
200
150
100
50
0
459.3
22.1
Tax
8.5
Net
financing
costs
(50.3)
Other expenses
and income
(76.6)
Gross profit
21%
$96.3 million
total decrease
FY20
363.0
FY21
47
Beach Energy Limited Annual Report 2021 Directors’ Report
Financial Position
Assets
Total assets increased by $466.9 million to $4,679.2 million
during the period with cash balances increased by $16.8 million
to $126.7 million, primarily due to:
– Cash inflow from operations of $759.8 million,
– Cash inflow from financing activities of $21.0 million,
offset by,
– Cash outflow from investing activities of $757.8 million, and
– Unfavourable foreign exchange impact of $6.2 million.
Receivables increased by $139.2 million due to higher sales
accruals driven by higher prices at the end of the period
and receivables recognised following the favourable arbitral
outcome regarding the allocation of carbon emissions
under one of Beach’s long term gas sales agreements and
the acquisition of Mitsui’s interest in the BassGas assets.
Inventories decreased by $7.5 million. Other current assets
increased by $14.6 million, primarily driven by the recognition
of Victoria Otway sublease receivable.
Fixed assets, petroleum and exploration assets increased
by $316.5 million. Capital expenditure of $643.4 million,
acquisitions of $166.7 million, increases for restoration of
$57.5 million and the capitalisation of depreciation of lease
assets under AASB 16 Leases of $27.3 million. This is partly
offset by depreciation and amortisation of $407.3 million,
impairment of assets of $117.0 million and exploration
and evaluation expenditure expensed during the period of
$56.7 million. Deferred tax assets decreased by $33.6 million.
Other non-current assets increased $19.4 million due to higher
prepayments. Lease assets recognised under AASB 16 Leases
increased by $13.5 million with new contracts offsetting the
depreciation during the period.
Liabilities
Total liabilities increased by $196.9 million to $1,591.4 million,
due to an increase in provisions of $152.6 million mainly relating
to restoration on the acquisitions of Senex owned assets and
Mitsui’s share of BassGas, as well as for wells drilled in FY21,
increase in debt drawn of $115 million and lease liabilities
of $40.9 million partially offset by a decrease in current tax
liability of $82.5 million and contract liabilities of $32.3 million.
Equity
Total equity increased by $270.0 million, primarily due to net
profit after tax of $316.5 million, partly offset by dividends paid
during the period of $45.6 million.
Dividends
During the financial year, the Company paid a FY20 fully
franked final dividend of 1.0 cent per share as well as an interim
FY21 fully franked dividend of 1.0 cent per share. The Company
will also pay a FY21 fully franked final dividend of [1.0] cent per
share from the profit distribution reserve.
48
State of affairs
A review of operations of Beach Energy during the financial year
on pages 17 to 31 sets out a number of matters that have had a
significant effect on the state of affairs of the group. Other than
those matters, there were no significant changes in the state of
affairs of the group during the financial year.
Funding and capital management
As at 30 June 2021, Beach held cash and cash equivalents
of $127 million.
Beach currently has a Senior Secured Debt Facility in place for
$525 million, comprised of a $450 million revolving debt facility
(Facility C) and a $75 million Letter of Credit facility (Facility D),
both of which have a maturity date of November 2022.
As at 30 June 2021 $175 million of Facility C was drawn with
$275 million remaining undrawn, with $73 million of Facility D
being utilised predominantly by way of bank guarantees.
Material Business Risks
Beach recognises that the management of risk is a critical
component in Beach achieving its purpose of delivering
sustainable growth in shareholder value.
The Company has a framework to identify, understand, manage
and report risks. As specified in its Board Charter, the Board
has responsibility for overseeing Beach’s risk management
framework and monitoring its material business risks.
Given the nature of Beach’s operations, there are many factors
that could impact Beach’s operations and results. The material
business risks that could have an adverse impact on Beach’s
financial prospects or performance include economic risks,
health, safety and environmental risks, community and social
licence risks and legal risks. These may be further categorised
as strategic risks, operational risks, commercial risks, regulatory
risks, reputational risks and financial risks. A description of the
nature of the risk and how such risks are managed is set out
below. This list is neither exhaustive nor in order of importance.
Economic risks
Exposure to oil and gas prices
A decline in the price of oil and gas may have a material
adverse effect on Beach’s financial performance. Historically,
international crude oil prices have been very volatile.
A sustained period of low or declining crude oil prices could
adversely affect Beach’s operations, financial position and
ability to finance developments. Beach uses a structured
framework for capital allocation decisions. The process
provides rigorous value and risk assessment against a broad
range of business metrics and stringent hurdles to maximise
return on capital. This process is a significant development in
Beach’s continuing focus on reducing capital and operating
expenditure and improving business efficiency.
Declines in the price of oil and continuing price volatility
may also lead to revisions of the medium and longer term
price assumptions for oil from future production, which, in
turn, may lead to a revision of the carrying value of some of
Beach’s assets.
The valuation of oil and gas assets is affected by a number of
assumptions, including the quantity of reserves and resources
booked in relation to these oil and gas assets and their expected
cash flows. An extended or substantial decline in oil and/or
gas prices or demand, or an expectation of such a decline, may
reduce the expected cash flows and/or quantity of reserves
and resources booked in relation to the associated oil and
gas assets, which may lead to a reduction in the valuation of
these assets. If the valuation of an oil and gas asset is below its
carrying value, a non-cash impairment adjustment to reduce
the historical book value of these assets will be made with a
subsequent reduction in the reported net profit in the same
reporting period.
Foreign exchange and hedging risk
Beach’s financial report is presented in Australian dollars. Beach
converts funds to foreign currencies as its payment obligations
in those jurisdictions where the Australian dollar is not an
accepted currency become due. Certain of Beach’s costs will be
incurred in currencies other than Australian dollars, including
the US dollar and the New Zealand dollar. Accordingly, Beach
is subject to fluctuations in the rates of currency exchange
between these currencies.
The Company may use derivative financial instruments such
as foreign exchange contracts, commodity contracts and
interest rate swaps to hedge certain risk exposures, including
commodity price fluctuations through the sale of petroleum
productions and other oil-linked contracts.
Ability to access funding
The oil and gas business involves significant capital expenditure
in relation to exploration and development, production,
processing and transportation. Beach relies on cash flows from
operating activities and bank borrowings and offerings of debt
or equity securities to finance capital expenditure.
If cash flows decrease or Beach is unable to access necessary
financing, this may result in postponement of or reduction in
planned capital expenditure, relinquishment of rights in relation
to assets, or an inability to take advantage of opportunities or
otherwise respond to market conditions. Any of these outcomes
could have a material adverse effect on Beach’s ability to
expand its business and/or maintain operations at current
levels, which in turn could have a material adverse effect on
Beach’s business, financial condition and operations.
Beach has a Board approved financial risk management policy
covering areas such as liquidity, debt management, interest rate
risk, foreign exchange risk, commodity risk and counterparty
credit risk. The policy sets out the organisational structure to
support this policy. Beach has a treasury function and clear
delegations and reporting obligations. The annual capital and
operating budgeting processes approved by the Board ensure
appropriate allocation of resources.
A dispute, or a breakdown in the relationship, between Beach
and its JVPs, suppliers or customers, a failure to reach a suitable
arrangement with a particular JVP, supplier or customer, or
the failure of a JVP, supplier or customer to pay or otherwise
satisfy its contractual obligations (including as a result of
insolvency, financial stress or the impacts of COVID-19), could
have an adverse effect on the reputation and/or the financial
performance of Beach.
Operational risks
Joint Venture Operations
Beach participates in a number of joint ventures for its business
activities. This is a common form of business arrangement
designed to share risk and other costs. Under certain joint
venture operating agreements, Beach may not control the
approval of work programs and budgets and a JVP may vote to
participate in certain activities without the approval of Beach.
As a result, Beach may experience a dilution of its interest or
may not gain the benefit of the activity, except at a significant
cost penalty later in time.
Failure to reach agreement on exploration, development and
production activities may have a material impact on Beach’s
business. Failure of Beach’s JVPs to meet financial and other
obligations may have an adverse impact on Beach’s business.
Beach works closely with its JVPs to minimise joint venture
misalignment.
Material change to reserves and resources
The estimated quantities of reserves and resources are based
upon interpretations of geological, geophysical and engineering
models and assessment of the technical feasibility and
commercial viability of producing the reserves. Estimates that
are valid at a certain point in time may alter significantly or
become uncertain when new reservoir information becomes
available through additional drilling or subsurface technical
analysis over the life of the field. As reserves and resources
estimates change, development and production plans may be
altered in a way that may adversely affect Beach’s operations
and financial results.
Beach prepares its reserves and resources estimates in
accordance with the 2018 update to the Petroleum Resources
Management System sponsored by the Society of Petroleum
Engineers, World Petroleum Council, American Association
of Petroleum Geologists and Society of Petroleum Evaluation
Engineers (SPE-PRMS). These estimates are subject to periodic
independent external review or audit.
49
Beach Energy Limited Annual Report 2021 Directors’ Report
Exploration and development
Success in oil and gas production is key and in the normal
course of business Beach depends on the following factors:
successful exploration, establishment of commercial oil and
gas reserves, finding commercial solutions for exploitation of
reserves, ability to design and construct efficient production,
gathering and processing facilities, efficient transportation
and marketing of hydrocarbons and sound management of
operations. Oil and gas exploration is a speculative endeavour
and the nature of the business carries a degree of risk
associated with failure to find hydrocarbons in commercial
quantities or at all. Individual projects being undertaken by
Beach may also be affected by any restrictions relating to the
COVID-19 pandemic.
Beach utilises well-established prospect evaluation and ranking
methodology to manage exploration and development risks.
Production risks
Any oil or gas project, including off-shore activity, may be
exposed to production decrease or stoppage, which may be the
result of facility shut-downs, mechanical or technical failure,
climatic events and other unforeseeable events. A significant
failure to maintain production could result in Beach lowering
production forecasts, loss of revenue and additional operational
costs to bring production back online.
There may be occasions where loss of production may incur
significant capital expenditure, resulting in the requirement
for Beach to seek additional funding, through equity or debt.
Beach’s approach to facility design, process safety and integrity
management is critical to mitigating production risks.
Beach and its JVPs may face such disruptions as a result of
the restrictions on the movement and supply of personnel and
products in response to the COVID-19 pandemic. A significant
failure to meet production targets could compromise the
Beach’s production and sales deliverability obligations, impact
operating cash flows through loss of revenue and/or from
incurring additional costs needed to reinstate production to
required levels.
Cyber Risk
The integrity, availability and confidentiality of data within
Beach’s information and operational technology systems
may be subject to intentional or unintentional disruption
(for example, from a cyber security attack). Beach continues
to invest in robust processes and technology, supported by
specialist cyber security skills to prevent, detect, respond and
recover from such attacks should one occur.
This risk has escalated as a result of the increased global
cyber threat across the economy, particularly with regard
to ransomware. Beach has invested in further measures
that align with the Australian Signals Directorate (ASD)
Essential 8 Maturity Framework that include application allow
listing, system hardening and retiring of legacy systems. In
addition, we have expanded validation of existing controls
through regular penetration testing, phishing simulations and
cyber exercises.
50
Social licence to operate risks
Regulatory risk
Changes in government policy (such as in relation to taxation,
environmental protection, competition and pricing regulation
and the methodologies permitted to be used in oil and gas
exploration and production activity such as produced water
disposal) or statutory changes may affect Beach’s business
operations and its financial position. A change in government
regime may significantly result in changes to fiscal, monetary,
property rights and other issues which may result in a material
adverse impact on Beach’s business and its operations.
Companies in the oil and gas industry may also be required
to pay direct and indirect taxes, royalties and other imposts
in addition to normal company taxes. Beach currently
has operations or interests in Australia and New Zealand.
Accordingly its profitability may be affected by changes in
government taxation and royalty policies or in the interpretation
or application of such policies in each of these jurisdictions.
Beach monitors changes in relevant regulations and engages
with regulators and governments to ensure policy and law
changes are appropriately influenced and understood.
Permitting risk
All petroleum licences held by Beach are subject to the granting
and approval of relevant government bodies and ongoing
compliance with licence terms and conditions.
Tenure management processes and standard operating
procedures are utilised to minimise the risk of losing tenure.
Land access, cultural heritage and Native Title
Beach is required to obtain the consent of owners and occupiers
of land within its licence areas. Compensation may be required
to be paid to the owners and occupiers of land in order to carry
out exploration and development activities.
Beach operates in a number of areas within Australia that are
or may become subject to claims or applications for native
title determinations or other third party access. Native title
claims have the potential to introduce delays in the granting of
petroleum and other licences and, consequently, may have an
effect on the timing and cost of exploration, development and
production.
Native or indigenous title and land rights may also apply or be
implemented in other jurisdictions in which Beach operates
outside of Australia, including New Zealand.
Beach’s standard operating procedures and stakeholder
engagement processes are used to manage land access, cultural
heritage and native title risks.
Health, safety and environmental risks
Climate change
The business of exploration, development, production and
transportation of hydrocarbons involves a variety of risks which
may impact the health and safety of personnel, the community
and the environment.
Oil and gas production and transportation can be impacted by
natural disasters, operational error or other occurrences which
can result in hydrocarbon leaks or spills, equipment failure
and loss of well control. Potential failure to manage these risks
could result in injury or loss of life, damage or destruction
of wells, production facilities, pipelines and other property,
damage to the environment, legal liability and damage to
Beach’s reputation.
Losses and liabilities arising from such events could significantly
reduce revenues or increase costs and have a material adverse
effect on the operations and/or financial conditions of Beach.
Beach employs a health, safety and environment management
system to identify and manage risks in this area. Insurance
policies, standard operating procedures, contractor
management processes and facility design and integrity
management systems, amongst other things, are important
elements of the system that supports mitigation of these risks.
Beach seeks to maintain appropriate policies of insurance
consistent with those customarily carried by organisations
in the energy sector. Any future increase in the cost of such
insurance policies, or an inability to fully renew or claim
against insurance policies as a result of the current economic
environment and the impact of COVID-19 (for example, due
to a deterioration in an insurers ability to honour claims),
could adversely affect Beach’s business, financial position and
operational results.
Beach’s ability to mitigate these risks and effectively respond to
health and safety incidents may be also impaired by restrictions
on the movement of products and personnel relating to the
COVID-19 pandemic.
Pandemic risk
Large scale pandemic outbreak of a communicable disease such
as COVID-19 has the potential to affect personnel, production
and delivery of projects. The Company employs its crisis and
emergency management plans, health emergency plans and
business continuity plans to manage this risk including ongoing
monitoring and response to government directions and advice.
This enables the Company to take active steps to manage risks
to the Company’s staff and stakeholders and to mitigate risks to
production and progress of growth projects.
Beach is likely to be subject to increasing regulations and costs
associated with climate change and management of carbon
emissions. Strategic, regulatory and operational risks and
opportunities associated with climate change are incorporated
into Company policy, strategy and risk management processes
and practices. The Company actively monitors current and
potential areas of climate change risk and takes actions
to prevent and/or mitigate any impacts on its objectives
and activities including setting of targets to reduce carbon
emissions. Reduction of waste and emissions is an integral part
of delivery of cost efficiencies and forms part of the Company’s
routine operations.
Forward Looking Statements
This report contains forward-looking statements, including
statements of current intention, opinion and predictions
regarding the Company’s present and future operations,
possible future events and future financial prospects. While
these statements reflect expectations at the date of this report,
they are, by their nature, not certain and are susceptible to
change. Beach makes no representation, assurance or guarantee
as to the accuracy or likelihood of fulfilling of such forward
looking statements (whether expressed or implied), and
except as required by applicable law or the ASX Listing Rules,
disclaims any obligation or undertaking to publicly update such
forward-looking statements.
Material Prejudice
As permitted by sections 299(3) and 299A(3) of the
Corporations Act 2001, Beach has omitted some information
from the above Operating and Financial Review in relation
to the Company’s business strategy, future prospects and
likely developments in operations and the expected results
of those operations in future financial years on the basis that
such information, if disclosed, would be likely to result in
unreasonable prejudice (for example, because the information
is premature, commercially sensitive, confidential or could give
a third party a commercial advantage). The omitted information
typically relates to internal budgets, forecasts and estimates,
details of the business strategy, and contractual pricing.
51
Beach Energy Limited Annual Report 2021 Directors’ Report
Environmental regulations and performance statement
Beach participates in projects and production activities that are subject to the relevant exploration and development licences
prescribed by government. These licences specify the environmental regulations applicable to the exploration, construction and
operations of petroleum activities as appropriate. For licences operated by other companies, this is achieved by monitoring the
performance of these companies against these regulations.
There have been no known significant breaches of the environmental obligations of Beach’s operated contracts or licences during
the financial year.
Beach reports under the National Greenhouse and Energy Reporting Act for its Australian operations and the Climate Change
Response Act 2002 for its New Zealand operations.
Dividends paid or recommended
Since the end of the financial year the directors have resolved to pay a fully franked dividend of 1.0 cent per share on
30 September 2021. The record date for entitlement to this dividend is 31 August 2021. The financial impact of this dividend,
amounting to $22.8 million has not been recognised in the Financial Statements for the year ended 30 June 2021 and will be
recognised in subsequent Financial Statements.
The details in relation to dividends paid during the reporting period are set out below:
Dividend
FY20 Final
FY21 Interim
Record Date
31 August 2020
26 February 2021
Date of payment
30 September 2020
31 March 2021
Cents per share
Total Dividends
1.0
1.0
$22.8 million
$22.8 million
For Australian income tax purposes, all dividends were fully franked and were not sourced from foreign income.
Share options and rights
Beach does not have any options on issue at the end of financial year and has not issued any during FY21.
Share rights holders do not have any right to participate in any issue of shares or other interests in the Company or any other entity.
There have been no unissued shares or interests under option of any controlled entity within the Group during or since the reporting
date. For details of performance rights issued to executives as remuneration, refer to the Remuneration Report. During the financial
year, the following movement in share rights to acquire fully paid shares occurred:
Executive Performance Rights
On 25 November 2020, Beach issued 263,199 Short Term Incentive (STI) unlisted performance rights under the Executive Incentive
Plan (EIP). These performance rights are exercisable for nil consideration and are not exercisable before 1 July 2021 and 1 July 2022.
On 14 December 2020, Beach issued 2,360,550 Long Term Incentive (LTI) unlisted performance rights under the EIP.
On 31 May 2021, Beach issued a further 311,722 LTI unlisted performance rights under the EIP. 28,619 performance rights,
which expire on 30 November 2024, are exercisable for nil consideration and are not exercisable before 1 December 2022.
2,643,653 performance rights, which expire on 30 November 2025, are exercisable for nil consideration and are not
exercisable before 1 December 2023.
52
Rights
2017 LTI unlisted rights
Balance at
beginning of
financial
year
Issued
during the
financial
year
Vested/
exercised
during the
financial
year
Expired/
lapsed
during the
financial
year
Issued 1 December 2017 and 9 April 2018
2,283,944
2017 STI unlisted rights
Issued 6 December 2018
2018 LTI unlisted rights
206,847
Issued 14 December 2018 and 19 December 2019
2,192,835
2018 STI unlisted rights
Issued 19 December 2019
2019 LTI unlisted rights
637,259
–
–
–
–
Issued 19 December 2019 and 14 December 2020
1,602,015
28,619
2019 STI unlisted rights
Issued 25 November 2020
2020 LTI unlisted rights
Issued 14 December 2020 and 31 May 2021
–
–
263,199
2,643,653
(1,069,650)
(206,847)
–
–
–
(550,388)
1,642,447
(318,632)
(43,518)
275,109
–
–
–
(406,522)
1,224,112
(49,534)
213,665
(331,421)
2,312,232
Balance at
end of
financial
year
1,214,294
–
Total
6,922,900
2,935,471
(1,595,129)
(1,381,383)
6,881,859
Employee share plan
An employee share plan (Plan) was approved by shareholders in November 2019. Under the terms of the Plan, Employees who
buy shares under the Plan will have those shares matched by Beach, provided any relevant conditions determined by the Board are
satisfied. Eligible Employees are employees of the Group, other than a non-executive director and any other person determined
by the Board as ineligible to participate in the Plan. The Board has the discretion to set an annual limit on the value of shares that
participants may purchase under the Plan, not exceeding $5,000. Purchased Shares have been acquired periodically at the prevailing
market price. Participants pay for their Purchased Shares using their own funds which may include salary sacrifice. To receive
Matched Shares, a participant must satisfy the conditions determined by the Board at the time of the invitation. Full terms can be
found in the Notice of 2018 Annual General Meeting released on 19 October 2018.
Rights
FY20 employee share plan (1)
Issued up to 30 June 2020
FY21 employee share plan (2)
Issued up to 30 June 2021
Total
(1) 3-year restriction period end on the first practicable date after 30 June 2022.
(2) 3-year restriction period end on the first practicable date after 30 June 2023.
Balance at
beginning
of financial
year
Issued
during the
financial
year
Vested
during the
financial
year
Expired/
lapsed
during the
financial
year
Balance
at end of
financial
year
514,235
–
–
514,235
821,546
821,546
–
–
–
(11,732)
502,503
(21,569)
799,977
(33,301)
1,302,480
53
Beach Energy Limited Annual Report 2021
Directors’ Report
Information on Directors
The names of the directors of Beach who held office during the financial year and at the date of this report are:
Current and former listed company directorships
in the last 3 years
Nil.
Responsibilities
His special responsibilities include chairmanship of the
Remuneration and Nomination Committee and membership of
the Risk, Corporate Governance and Sustainability Committee.
Date of appointment
Mr Beckett was appointed to the Board on 2 April 2015 and last
re-elected to the Board on 26 November 2019.
Philip James Bainbridge
Independent non-executive director –
BSc (Hons) Mechanical Engineering, MAICD
Experience and expertise
Mr Bainbridge has extensive industry experience having
worked for the BP Group for 23 years in a range of petroleum
engineering, development, commercial and senior management
roles in the UK, Australia and USA. From 2006, he has worked
at Oil Search, initially as Chief Operating Officer, then Executive
General Manager LNG, responsible for all aspects of Oil
Search’s interests in the $19 billion PNG LNG project, then
EGM Growth responsible for gas growth and exploration.
He is currently a member of the PNG Sustainable
Development Program, a company limited by guarantee
and the non-executive chairman of the Global Institute
of Carbon Capture and Storage.
Current and former listed company directorships
in the last 3 years
Mr Bainbridge was formerly the non-executive chairman of
Sino Gas and Energy Holdings (from 2014 until 2018).
Responsibilities
His special responsibilities include membership of the Risk,
Corporate Governance and Sustainability Committee.
Date of appointment
Mr Bainbridge was appointed to the Board on 1 March 2016 and
was last re-elected to the Board on 26 November 2019.
Glenn Stuart Davis
Independent non-executive Chairman – LLB, BEc, FAICD
Experience and expertise
Mr Davis has practiced as a solicitor in corporate and risk
throughout Australia for over 30 years initially in a national firm
and then a firm he founded. He has expertise and experience
in the execution of large transactions, risk management and
in corporate activity regulated by the Corporations Act and
ASX Limited. Mr Davis has worked in the oil and gas industry
as an advisor and director for over 25 years.
Current and former listed company directorships
in the last 3 years
Mr Davis is a former director of ASX listed company
Auteco Minerals (previously called Monax Mining Limited)
(from 2004 to November 2018).
Responsibilities
His special responsibilities include Chairmanship of the
Board and membership of the Remuneration and Nomination
Committee.
Date of appointment
Mr Davis joined Beach on 6 July 2007 as a non-executive
director. He was appointed non-executive Deputy Chairman
in June 2009 and Chairman in November 2012. He was last
re-elected to the Board on 25 November 2020.
Colin David Beckett, AO
Independent non-executive Deputy Chairman – FIEA,
MICE, GAICD
Experience and expertise
Mr Beckett is an experienced non-executive director and
previously held senior executive positions in Australia with
Chevron, Mobil, and BP. His experience in engineering design,
project management, commercial negotiations and gas
marketing provides him with a diverse and complementary
set of skills relevant to the oil and gas industry. Mr Beckett
read engineering at Cambridge University and has a Master
of Arts. He was awarded an honorary doctorate from Curtin
University in 2019. He was previously a fellow of the Australian
Institute of Engineers. He is a graduate member of the Institute
of Company Directors. He is currently Chair of Western
Power. He was the Chancellor of Curtin University until end
2018. He is a past Chairman of Perth Airport Pty Ltd and
past Chairman of the Australian Petroleum Producers and
Explorers Association (APPEA).
54
Matthew Vincent Kay
Managing director & Chief executive officer – BEc, MBA,
FCPA, GAICD
Experience and expertise
Mr Kay joined Beach in May 2016 as Chief Executive Officer.
Mr Kay has circa 30 years’ experience in energy and resources
and prior to joining Beach, served as Executive General
Manager, Strategy and Commercial at Oil Search, a position
he held for two years. In that role he was a member of the
executive team and led the strategy, commercial, supply chain,
economics, marketing, M&A and legal functions.
Prior to Oil Search, Mr Kay spent 12 years with Woodside
Energy in various leadership roles, including Vice President
of Corporate Development, General Manager of Production
Planning leading over 80 operations professionals, and General
Manager of Commercial for Middle East and Africa. In these
roles Mr Kay developed extensive leadership skills across
LNG, pipeline gas and oil joint ventures, and developments in
Australia and internationally.
Current and former listed company directorships
in the last 3 years
Nil.
Responsibilities
Managing Director & Chief Executive Officer.
Date of appointment
Mr Kay was appointed managing director of Beach Energy
Limited on 25 February 2019 and elected to the Board on
26 November 2019.
Sally-Anne Layman
Independent non-executive director – B Eng (Mining) Hon,
B Com, CPA, MAICD
Experience and expertise
Ms Layman is a company director with diverse international
experience in the resources sector and financial markets.
Previously, Ms Layman held a range of senior positions with
Macquarie Group Limited, including as Division Director
and Joint Head of the Perth office of the Metals, Mining &
Agriculture Division. Prior to moving into finance, Ms Layman
undertook various roles with resource companies including
Mount Isa Mines, Great Central Mines and Normandy Yandal.
Ms Layman holds a WA First Class Mine Manager’s Certificate
of Competency, a Bachelor of Engineering (Mining) Hon
from Curtin University and a Bachelor of Commerce from the
University of Southern Queensland. Ms Layman is a Certified
Practicing Accountant and is a member of CPA Australia Ltd
and the Australian Institute of Company Directors.
Current and former listed company directorships
in the last 3 years
Ms Layman is on the board of Newcrest Mining Ltd
(since September 2020), Imdex Ltd (since February 2017) and
Pilbara Minerals Ltd (since April 2018) and was previously
on the board of Perseus Mining Ltd (from September 2017
until October 2020) and Gascoyne Resources Ltd
(from June 2017 until May 2019).
Responsibilities
Her special responsibilities include Chair of the Audit
Committee.
Date of appointment
Ms Layman was appointed to the Board on 25 February 2019
and elected to the Board on 26 November 2019.
Peter Stanley Moore
Independent non-executive director – PhD, BSc (Hons),
MBA, GAICD
Experience and expertise
Dr Moore has over forty years of oil and gas industry
experience. His career commenced at the Geological Survey
of Western Australia, with subsequent appointments at Delhi
Petroleum Pty Ltd, Esso Australia, ExxonMobil and Woodside.
Dr Moore joined Woodside as Geological Manager in 1998 and
progressed through the roles of Head of Evaluation, Exploration
Manager Gulf of Mexico, Manager Geoscience Technology
Organisation and Vice President Exploration Australia. From
2009 to 2013, Dr Moore led Woodside’s global exploration
efforts as Executive Vice President Exploration. In this capacity,
he was a member of Woodside’s Executive Committee and
Opportunities Management Committee, a leader of its Crisis
Management Team, Head of the Geoscience function and
a director of ten subsidiary companies. From 2014 to 2018,
Dr Moore was a Professor and Executive Director of Strategic
Engagement at Curtin University’s Business School. He has his
own consulting company, Norris Strategic Investments Pty Ltd.
Current and former listed company directorships
in the last 3 years
Dr Moore is currently a non-executive director of
Carnarvon Petroleum Ltd (since 2015) and was previously
a non-executive director of Central Petroleum Ltd (from 2014
to November 2018).
Responsibilities
His special responsibilities include Chairmanship of the Risk,
Corporate Governance and Sustainability Committee and
membership of the Remuneration and Nomination Committee.
Date of appointment
Dr Moore was appointed by the Board on 1 July 2017 and then
elected to the Board on 26 November 2019.
55
Beach Energy Limited Annual Report 2021 Directors’ Report
Joycelyn Cheryl Morton
Independent non-executive director – BEc, FCA, FCPA,
FIPA, FCIS, FAICD
Experience and expertise
Ms Morton has extensive experience in finance and taxation
having begun her career with Coopers & Lybrand (now PwC),
followed by senior management roles with Woolworths Limited
and global leadership roles in Australia and internationally
within the Shell Group of companies.
Ms Morton was National President of both CPA Australia and
Professions Australia, has served on many committees and
councils in the private, government and not-for-profit sectors
and held international advisory positions. She holds a Bachelor
of Economics degree from the University of Sydney. She is
also a non-executive director of ASC Pty Ltd (since 2017) –
a government owned corporation.
In addition, Ms Morton has valuable board experience across a
range of industries, including previous roles as a non-executive
director and Chair of both Thorn Group Limited (from 2011
to 2018) and Noni B Limited (from May 2009 to February
2015) and a non-executive director of Crane Group Limited
(from October 2010 to April 2011), Count Financial Limited
(from 2006 to 2011) and InvoCare Limited (from August 2015
to May 2018).
Current and former listed company directorships
in the last 3 years
Ms Morton is currently a non-executive director of Argo
Investments Limited (since 2012), Argo Global Listed
Infrastructure Limited (since March 2015) and Felix Group
Holdings Limited (since July 2021). She previously was
non-executive director of Snowy Hydro (until June 2021)
and non-executive director and Chair of Thorn Group Limited
(from 2011 to 2018) and non-executive director of InvoCare
Limited (from 2015 to 2018).
Responsibilities
Her special responsibilities include membership of the
Audit Committee.
Date of appointment
Ms Morton was appointed a non-executive director of Beach
Energy Limited on 21 February 2018 and then elected to the
Board on 23 November 2018.
Richard Joseph Richards
Non-executive director – BComs/Law (Hons), LLM, MAppFin, CA,
Admitted Solicitor
Experience and expertise
Mr Richards is currently Chief Financial Officer of Seven
Group Holdings Limited (SGH) (since October 2013). He is
responsible for Finance across the diversified conglomerate
(equipment manufacture, sales and service, equipment hire,
investments, property, media and oil and gas). Mr Richards is
a member of the Board of Directors of WesTrac Pty Limited,
SGH Energy Pty Limited, Boral Limited (from August 2021), is a
56
Director and Chair of the Audit and Risk Committee of Coates
Hire Pty Limited, a former Director and Chair of the Audit and
Risk Committee of KU Children Services (NFP) and a member of
the Marcia Burgess Foundation Committee (DGR). He has held
senior finance roles with Downer EDI, the Lowy Family Group
and Qantas. Mr Richards is both a Chartered Accountant and
admitted solicitor with over 30 years of experience in business
and complex financial structures, corporate governance, risk
management and audit.
Current and former listed company directorships
in the last 3 years
Boral Limited during October 2020 and was reappointed in
August 2021.
Responsibilities
His special responsibilities include membership of the Audit
Committee and a member of the Risk, Corporate Governance &
Sustainability Committee.
Date of appointment
Mr Richards was appointed to the Board on 4 February 2017
and was last re-elected to the board on 25 November 2020.
Ryan Kerry Stokes, AO
Non-executive director – BComm, FAIM
Experience and expertise
Mr Stokes is the Managing Director and Chief Executive Officer
of Seven Group Holdings Limited (SGH). SGH is a listed diverse
investment company involved in Industrial Services, Media
and Energy. SGH interests include 30.02% of Beach Energy,
WesTrac Pty Limited, Coates Hire, 69.9% of Boral Limited and
41% of Seven West Media Limited. Mr Stokes is Chairman
of Boral Limited, Chairman of Coates Hire and a director of
WesTrac Pty Limited and Seven West Media.
Mr Stokes is Chief Executive Officer of Australian Capital Equity
Pty Limited (ACE). ACE is a private company with its primary
investment being an interest in SGH. Mr Stokes is Chairman of
the National Gallery of Australia and is an Officer of the Order
of Australia. He is also a member of the International Olympic
Committee Education Commission. His previous roles include
Chairman of the National Library of Australia, member of the
Prime Ministerial Advisory Council on Veterans’ Mental Health,
Founding Chair Headspace, Youth Mental Health Foundation.
Current and former listed company directorships
in the last 3 years
Mr Stokes is an executive director of Seven Group Holdings
(since 2010) and a non-executive director of Seven West Media
(since 2012) and Boral Limited (since Sep 2020).
Responsibilities
His special responsibilities include membership of the
Remuneration and Nomination Committee.
Date of appointment
Mr Stokes was appointed to the Board on 20 July 2016 and then
elected to the Board on 23 November 2018.
Margaret Helen Hall – alternate director
Non-executive director – B.Eng (Met) Hons, MIEAust, GAICD, SPE
Alternate for Mr Ryan Stokes
Experience and expertise
Ms Hall is the chief executive officer of Seven Group Holdings Energy, a subsidiary of Seven Group Holdings Limited. Ms Hall has
over 28 years of experience in the oil and gas industry having worked at both super-major and independent companies. From 2011
to 2014 Ms Hall held senior management roles in Nexus Energy with responsibilities covering Development, Production Operations,
Engineering, Exploration, Health, Safety and Environment. This was preceded by 19 years with ExxonMobil in Australia, across
production and development in the Victorian Gippsland Basin and joint ventures across Australia.
Current and former listed company directorships in the last 3 years
Ms Hall has had no listed company directorships in the last 3 years.
Date of appointment
Ms Hall was appointed alternate director for Mr Stokes on 3 May 2021, pursuant to the terms of the Beach constitution. Ms Hall’s
appointment will continue for a period of one year or until terminated in accordance with Beach’s constitution.
There are no directors of Beach who held office during the financial year and are no longer on the Board.
Directors’ meetings
The number of Directors’ meetings and meetings of Committees of Directors held during the financial year and the number of
meetings attended by each of the directors is set out below:
Directors’ Meetings
Audit
Committee
Meetings
Remuneration and
Nomination Committee
Meetings
Risk, Corporate
Governance and
Sustainability
Committee Meetings
Held (1) Attended
Held (1) Attended
Held (1) Attended
Held (1) Attended
15
15
15
15
15
15
15
15
15
1
15
15
15
15
14
15
14 (3)
15
14 (2)
1 (2)
–
–
–
–
6
–
6
6
–
–
–
–
–
–
6
–
6
6
–
–
6
6
–
–
–
6
–
–
6
–
6
6
–
–
–
5
–
–
6
–
–
5
5
–
–
5
–
2
–
–
Name
G S Davis
C D Beckett
P J Bainbridge
M V Kay
S G Layman
P S Moore
J C Morton
R J Richards
R K Stokes
M H Hall
(1) Number of Meetings held during the time that the director was appointed to the Board or committee.
(2) Ms Hall was only required to attend one meeting during the year as an alternate director for Mr Stokes.
(3) Ms Morton was an apology due to Beach information technology issues.
Board Committees
Chairmanship and current membership of each of the board committees at the date of this report are as follows:
Committee
Audit
Risk, Corporate Governance & Sustainability
Remuneration and Nomination
Chairman
S G Layman
P S Moore (1)
C D Beckett
Members
J C Morton, R J Richards
P J Bainbridge, C D Beckett, R J Richards (2)
G S Davis, R K Stokes, P S Moore
(1) Mr Bainbridge ceased as committee chair on 25 June 2021 and Dr Moore commenced as committee chair.
(2) Mr Richards commenced as a committee member on 25 March 2021.
–
5
5
–
–
5
–
2
–
–
57
Beach Energy Limited Annual Report 2021 Directors’ Report
Indemnity of Directors and Officers
Beach has arranged directors’ and officers’ liability insurance
policies that cover all the directors and officers of Beach and its
controlled entities. The terms of the policies prohibit disclosure
of details of the amount of the insurance cover, the nature
thereof and the premium paid.
Company Secretary
Daniel Murnane
Company Secretary – BA/LLB
Mr Murnane joined Beach in May 2018 as Senior Legal Counsel
and was appointed to Company Secretary on 2 March 2020.
He has more than 16 years’ experience, including over 12 years
advising resources companies. Mr Murnane has worked as
a senior associate in private legal practice predominately
for energy companies on mergers and acquisitions, major
projects, capital raisings and commercial disputes. In addition,
Mr Murnane has held various in-house roles spanning legal and
corporate governance environments, including with a NYSE
listed oil and gas company.
Mr Murnane is qualified as a solicitor in New South Wales
and Papua New Guinea and holds a Bachelor of Arts and a
Bachelor of Laws.
Non-audit services
Beach may decide to employ the external auditor on
assignments additional to their statutory audit duties where the
auditor’s expertise and experience with Beach are important.
The Board has considered the position and is satisfied that
the provision of the non-audit services is compatible with the
general standard of independence for auditors imposed by
the Corporations Act 2001. The directors are satisfied that the
provision of non-audit services by the auditor as set out below,
did not compromise the audit independence requirement of the
Corporations Act 2001 for the following reasons:
– All non-audit services have been reviewed by the Audit
Committee to ensure they do not impact the impartiality and
objectivity of the auditor.
– None of the services undermine the general principle relating
to auditor independence as set out in APES 110 Code – Code
of Ethics for Professional Accountants, including reviewing or
auditing the auditor’s own work, acting in a management or
a decision making capacity for Beach, acting as advocate for
Beach or jointly sharing economic risk and reward.
Details of the amounts paid or payable to the external auditors,
Ernst & Young, for audit and non-audit services provided during
the year are set out at Note 28 to the financial statements.
Rounding off of amounts
Beach is an entity to which ASIC Corporations (Rounding in
Financial/Directors’ Reports) Instrument 2016/191 issued by
the Australian Securities and Investments Commission applies
relating to the rounding off of amounts.
58
Accordingly, amounts in the directors’ report and the financial
statements have been rounded to the nearest hundred
thousand dollars, unless shown otherwise.
Proceedings on behalf of Beach
No person has applied to the Court under Section 237 of the
Corporations Act 2001 for leave to bring proceedings on behalf
of Beach, or to intervene in any proceedings to which Beach is a
party, for the purpose of taking responsibility on behalf of Beach
for all or part of those proceedings.
No proceedings have been brought or intervened in on behalf
of Beach with leave of the Court under Section 237 of the
Corporations Act 2001.
Matters arising subsequent to the end
of the financial year
The acquisition by Beach of Mitsui’s 35.0% interest in the
BassGas Project (comprising the onshore Lang Gas Plant
and Yolla gas field), as well as its 40.0% interest in the
Trefoil development project and surrounding retention lease
completed on 31 July 2021 with an adjustment made to the
acquisition price based on cash flows from the effective date
of 1 July 2020 to the completion date.
The Group has received a favourable arbitral outcome in
relation to a contractual dispute under one of its long term gas
sales agreements in New Zealand regarding the allocation of
carbon emission obligations between the parties. A one-off
cash payment of circa NZ$42m (plus interest) will be received
in reimbursement of costs incurred to satisfy the emission
obligations under the gas sales agreement during the period of
the dispute. The details of the dispute are confidential.
Other than the matters described above, there has not arisen
in the interval between 30 June 2021 and up to the date of
this report, any item, transaction or event of a material and
unusual nature likely, in the opinion of the directors, to affect
substantially the operations of the Group, the results of those
operations or the state of affairs of the Group in subsequent
financial years, unless otherwise noted in the financial report.
Audit independence declaration
Section 307C of the Corporations Act 2001 requires our auditors,
Ernst & Young, to provide the directors of Beach with an
Independence Declaration in relation to the audit of the full year
financial statements. This Independence Declaration is made on
the following page and forms part of this Directors’ Report.
This Directors’ Report is signed in accordance with a
resolution of directors made pursuant to section 298(2)
of the Corporations Act 2001.
On behalf of the directors
G S Davis
Chairman
Adelaide, 16 August 2021
Auditor’s Independence Declaration
Ernst & Young
121 King William Street
Adelaide SA 5000 Australia
GPO Box 1271 Adelaide SA 5001
Tel: +61 8 8417 1600
Fax: +61 8 8417 1775
ey.com/au
Auditor’s independence declaration to the directors of Beach Energy
Limited
As lead auditor for the audit of the financial report of Beach 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 Beach Energy Limited and the entities it controlled during the financial
year.
Ernst & Young
Anthony Jones
Partner
16 August 2021
A member firm of Ernst & Young Global Limited
Liability limited by a scheme approved under Professional Standards Legislation
59
Beach Energy Limited Annual Report 2021
2021 Remuneration in Brief (Unaudited)
Remuneration to executive key management personnel in FY21
Consistent with FY20 remuneration outcomes, Board and management have sought to ensure FY21 remuneration takes into account
broader economic conditions which have impacted Beach whilst acknowledging key outcomes achieved throughout the year.
A summary of the audited cost to the Company of executive key management personnel (KMP) remuneration is provided in Table 8.
FY21 remuneration outcomes at a glance
Fixed Remuneration
NO INCREASES
IN FY21
BENCHMARK
INCREASE FOR ONE
SENIOR EXECUTIVE
Short Term Incentive (STI)
NO STI AWARDED
Long Term Incentive (LTI)
LTI VESTED
Non-executive directors
BASE FEES
UNCHANGED
Total fixed remuneration (TFR) increased for one senior executive according
to industry benchmarks. No other TFR increases were applied in FY21
(including KMP).
Senior executives (excluding new starters) were subject to a 10% reduction in
base remuneration for the period from 1 July 2020 for a period of 6 months in
recognition of the COVID-19 impact on the global economy.
Although one of the two hurdle measures have been met (return on capital),
the Board has exercised its discretion and determined that no FY21 STI will
be awarded.
The 2017 and 2018 STI performance rights converted automatically to shares on
the retention condition being met on 1 July 2020.
The 2017 LTI performance rights fully vested following achievement of the
performance conditions on 30 November 2020.
Fees payable to non-executive directors was unchanged during the financial
year, save that non-executive directors were subject to a 10% reduction in
base remuneration for the period from 1 July 2020 for a period of 6 months
in recognition of the COVID-19 impact on the global economy.
2020 AGM
Remuneration Report
98.9% ‘YES VOTE’
Beach received more than 98% of ‘yes’ votes on a poll to adopt its Remuneration
Report for the 2020 financial year. No specific feedback on Beach’s remuneration
practices was received at the 2020 annual general meeting.
Disclosures required in the remuneration report by the Corporations Act, particularly the inclusion of accounting values for LTI
performance rights awarded but not vested, can vary significantly from the remuneration actually paid to senior executives. This is
because the Accounting Standards require a value to be placed on a right at the time it is granted to a senior executive and then
reported as remuneration even if ultimately the senior executive does not receive any actual value, for example because performance
conditions are not met and the rights do not vest.
60
The following table is a summary of remuneration actually paid or payable to executive KMP for FY21. It is not audited.
Table 1: Remuneration to executive key management personnel (unaudited)
Name
M V Kay
Managing Director and Chief Executive Officer
I Grant
Chief Operating Officer
M Engelbrecht
Chief Financial Officer
S Algar (2)
Group Executive Exploration & Subsurface
T Nador (2)
Group Executive Development
L Marshall
Group Executive Corporate Strategy & Commercial
Former KMP
G J Barker (3)
Group Executive Development
J L Schrull (3)
Group Executive Exploration & Appraisal
Total
TFR
Salary
$
Super
$
STI cash
bonus
$
1,177,864
25,000
601,054
25,000
545,954
25,000
220,500
12,187
165,864
8,750
439,703
25,000
277,307
16,250
303,684
3,731,930
16,250
153,437
–
–
–
–
–
–
–
–
–
Other (1)
$
–
Total Cash
$
1,202,864
54,750
680,804
–
570,954
54,750
287,437
–
174,614
60,000
524,703
–
–
293,557
319,934
169,500
4,054,867
(1) Other remuneration includes the payment of accrued employee entitlements and allowances paid under the terms and conditions of employment such as relocation and retention allowances.
(2) Mr Algar and Mr Nador both became KMP with effect from 23 February 2021 with their remuneration only shown for the period from that date until 30 June 2021.
(3) Mr Barker and Mr Schrull both ceased to be KMP on 22 February 2021 although continued to be employed with no decision making rights until 18 July 2021 and 18 May 2021 respectively.
61
Beach Energy Limited Annual Report 2021 Remuneration Report (Audited)
This report has been prepared in accordance with section 300A of the Corporations Act 2001 (Cth) (Corporations Act) for
the consolidated entity for the financial year ended 30 June 2021. It has been audited as required by section 308(3C) of the
Corporations Act and forms part of the Directors’ Report.
Key management personnel
The Company’s KMP are listed in Table 2. They are the Company’s non-executive directors (NED) and executive KMP who have
authority and responsibility for planning, directing and controlling the activities of the Company, directly or indirectly.
Table 2: Key management personnel during FY21
Name
Executive KMP
M V Kay
M Engelbrecht
I Grant
T Nador
L Marshall
S Algar
Non-executive Directors
G S Davis
P J Bainbridge
C D Beckett
P S Moore
J C Morton
R J Richards
R K Stokes
S G Layman
M H Hall
Former KMP
G J Barker
J Schrull
Position
Period as KMP during the year
Managing Director & Chief Executive Officer (MD & CEO)
Chief Financial Officer
Chief Operating Officer
Group Executive Development
Group Executive Corporate Strategy and Commercial
Group Executive Exploration and Subsurface
All of FY21
All of FY21
20 July 2020 – 30 June 2021
23 February 2021 – 30 June 2021
All of FY21
23 February 2021 – 30 June 2021
Independent Chairman
Non-executive Director
Non-executive Director
Non-executive Director
Non-executive Director
Non-executive Director
Non-executive Director
Non-executive Director
Alternate Director
All of FY21
All of FY21
All of FY21
All of FY21
All of FY21
All of FY21
All of FY21
All of FY21
3 May 2021 – 30 June 2021
Group Executive Development
Group Executive Exploration and Appraisal
1 July 2020 – 22 February 2021
1 July 2020 – 22 February 2021
Beach’s remuneration policy framework
Beach’s vision is to be Australia’s premier multi-basin upstream oil and gas company.
Beach’s remuneration framework seeks to focus executives on delivering that purpose:
– Fixed remuneration aligns to market practice and prevailing economic conditions. It seeks to attract, motivate and retain
executives focused on delivering Beach’s purpose.
– ‘At risk’ performance-based incentives link to shorter- and longer-term Company goals. The goals contribute to the achievement
of Beach’s purpose.
– Longer term ‘at risk’ incentives align with shareholder objectives and interests. Beach benchmarks shareholder returns against
peers considered to be alternative investments to Beach. Beach offers share based rather than all cash rewards to executives.
– Beach may recover remuneration benefits paid if there has been fraud or dishonesty.
– The Corporations Act and Beach’s Share Trading Policy prohibit hedging. Hedging is where a person enters a transaction to reduce
the risk of an ‘at risk’ incentive. Beach has a process to track compliance with its no hedging policy. Beach’s Share Trading Policy is
available at Beach’s website: www.beachenergy.com.au.
62
How Beach makes decisions about remuneration
The Board decides Beach’s KMP remuneration. It decides that remuneration based on recommendations by its Remuneration and
Nomination Committee. The Committee’s members are all non-executive directors. Its charter is available at Beach’s website:
www.beachenergy.com.au. Beach’s MD & CEO may attend Committee meetings by invitation in an advisory capacity. Other
executives may also attend by invitation. The Committee excludes executives from any discussion about their own remuneration.
External advisers and remuneration advice
Beach follows a protocol to engage an adviser to make a remuneration recommendation. The protocol ensures the recommendation
is free from undue influence by management. The Board or Committee chair engages the adviser. The Board or Committee chair
deals with the adviser on all material matters. Management involvement is only to the extent necessary to coordinate the work.
The Board and Committee seek recommendations from the MD & CEO about executive remuneration. The MD & CEO does not
make any recommendation about his own remuneration.
The Board and Committee have regard to industry benchmarking information.
How Beach links performance to incentives
Beach’s remuneration policy includes short term and long-term incentive plans. The plans seek to align management performance
with shareholder interests.
The LTI links to an increase in total shareholder return over an extended period.
The STI has equal proportions of cash and performance rights. Performance rights may convert to Beach shares.
The following table shows some key shareholder wealth indicators.
KPI and STI awards for FY20 and FY21 are detailed in Table 8.
Table 3: Shareholder wealth indicators FY17 – FY21
Total revenue
Net profit/(loss) after tax
Underlying net profit after tax
Share price at year-end
Dividends declared
Reserves
Production
FY17
FY18
FY19
FY20
FY21
$665.7m
$387.5m
$161.7m
57.5 cents
2.00 cents
75 MMboe
10.6 MMboe
$1,267.4m
$198.8m
$301.5m
175.5 cents
2.00 cents
313 MMboe
19.0 MMboe
$2,077.7m
$577.3m
$560.2m
198.5 cents
2.00 cents
326 MMboe
29.4 MMboe
$1,728.2m
$499.1m
$459.3m
152.0 cents
2.00 cents
352 MMboe
26.7 MMboe
$1,562.0m
$316.5m
$363.0m
124.0 cents
2.00 cents
339 MMboe
25.6 MMboe
Senior executive remuneration structure
This section details the remuneration structure for senior executives.
Remuneration mix
Remuneration for senior executives is a mix of a fixed cash salary component and an ‘at risk’ component. The ‘at risk’ component
means that specific targets or conditions must be met before a senior executive becomes entitled to it.
63
Beach Energy Limited Annual Report 2021
Remuneration Report (Audited)
What is the balance between fixed and ‘at risk’ remuneration?
The remuneration structure and packages offered to senior executives for the period were:
– Fixed remuneration.
– ‘At risk’ remuneration comprising:
Short term incentive (STI) – an annual cash and equity-based incentive, which may be offered at the discretion of the Board,
linked to Company and individual performance over a year.
Long term incentive (LTI) – equity grants, which may be granted annually at the discretion of the Board, linked to performance
conditions measured over three years.
The balance between fixed and ‘at risk’ remuneration depends on the senior executive’s role. The MD & CEO has the highest level of
‘at risk’ remuneration reflecting the greater level of responsibility of this role.
Table 4 sets out the relative proportions of the three elements of the executives KMP’s total remuneration packages for FY20 and FY21.
Table 4: Remuneration mix (1)
Position
MD & CEO
2021
2020
Other Executive KMP
2021
2020
Performance based remuneration
Fixed
Remuneration
%
STI %
LTI %
34
34
51
51
33
33
23
23
33
33
26
26
Total
‘at risk’
%
66
66
49
49
(1) The remuneration mix assumes maximum ‘at risk’ awards. Percentages shown later in this report reflect the actual incentives paid as a percentage of total fixed remuneration, movements in
leave balances and other benefits and share based payments calculated using the relevant accounting standards.
Fixed remuneration
What is fixed remuneration?
Senior executives are entitled to a fixed cash remuneration amount inclusive of the guaranteed
superannuation contribution. The amount is not based upon performance. Senior executives may
decide to salary sacrifice part of their fixed remuneration for additional superannuation contributions
and other benefits.
How is fixed remuneration
reviewed?
Fixed remuneration is determined by the Board based on independent external review or advice that takes
account of the role and responsibility of each senior executive. It is reviewed annually against industry
benchmarking information including the National Rewards Group Incorporated remuneration survey.
Fixed remuneration
for the year
Total fixed remuneration (TFR) of KMP are provided in Table 1 and Table 8. Table 8 reports on the
remuneration for KMP as required under the Corporations Act. Table 1 shows the actual realised cash
remuneration that KMP received.
64
Short Term Incentive (STI)
What is the STI?
How does the STI link to
Beach’s objectives?
The STI is part of ‘at risk’ remuneration offered to senior executives. It measures individual and Company
performance over a 12-month period. The period coincides with Beach’s financial year. It provides equal parts
of cash and equity that may vest subject to extra retention conditions. It is offered to senior executives at the
discretion of the Board.
The STI is an at risk opportunity for senior executives. It rewards senior executives for meeting or exceeding
key performance indicators. The key performance indicators link to Beach’s key purpose. The STI aims to
motivate senior executives to meet Company expectations for success. Beach can only achieve its purpose
if it attracts and retains high performing senior executives. An award made under the STI has a retention
component. Half is paid in cash and half is issued as performance rights with service conditions attached.
What are the performance
conditions or KPIs?
Beach’s key performance indicators (KPIs) are set by the Board for each 12-month period beginning at the
start of a financial year. They reflect Beach’s financial and operational goals that are essential to it achieving
its purpose. Senior executives also have individual KPIs to reflect their particular responsibilities.
For the reporting period, the performance measures comprised:
STI Measures
Company KPIs
Production
Statutory NPAT
Reserves replacement
All in cost/boe
Personal safety
Process safety
Environment
Individual KPIs
Weighting
75%
15%
15%
15%
15%
5%
5%
5%
25%
Refer to Table 6 for more information.
Individual KPIs link to Beach’s strategy and strategic plan. Individual KPIs relate to areas where senior
executives are able to influence or control outcomes. KPIs may include: gender diversity targets; delivery of
cost savings; development of project specific plans to align with Beach’s strategic pillars; specific initiatives
for developing employee capability; funding capacity; improvements in systems to achieve efficiencies;
specific commercial or corporate milestones; or specific safety and environmental and sustainability targets.
Are there different
performance levels?
The Board sets KPI measures at threshold, target and stretch levels. A participant must achieve the threshold
level to entitle them to any payment for an individual KPI. The stretch level is the greatest performance
outcome for an individual KPI.
65
Beach Energy Limited Annual Report 2021 Remuneration Report (Audited)
What is the value of the STI
award that can be earned?
Incentive payments are based on a percentage of a senior executive’s fixed remuneration.
The MD & CEO can earn up to a maximum of 100% of his fixed remuneration.
How are the performance
conditions assessed?
Is there a threshold level of
performance or hurdle before
an STI is paid?
The value of the award that can be earned by other senior executives is up to a maximum of 45% of their
fixed remuneration.
The KPIs are reviewed against an agreed target.
The Board assesses the extent to which KPIs were met for the period after the close of the relevant financial
year and once results are finalised. The Board assesses senior executive performance on the MD & CEO’ s
recommendation. The Board assesses the achievement of the KPIs for the MD & CEO.
Yes. At the end of Beach’s financial year there is a calculation of return on capital. There is also a calculation
of a one year relative total shareholder return against the ASX 200 Energy Index. Refer to Table 5 below.
Table 5: Two-tiered test
Measures
One year Relative Total Shareholder Return against the ASX 200
Energy Index (Index Return) for the Performance Period
Return on capital (1)
Green
Red
> = Index return
< Index return
> = 10%
< 10%
(1) Return on capital (ROC) is based on statutory NPAT/average total equity (being the average total equity at the beginning and end of the financial year).
What happens if an STI
is awarded?
On achievement of the relevant KPIs, Beach pays half of the STI award in cash. Beach includes cash awards
in its financial statements for the relevant financial year. Beach pays cash awards after the end of its financial
year, usually in October.
Beach issues the remaining half of the STI award value in performance rights. Performance rights vest
over one and two years if the senior executive remains employed by Beach at each vesting date. If a senior
executive leaves Beach before the vesting date the performance rights lapse. The Board may exercise its
discretion for early vesting if the senior executive leaves Beach due to death or disability. The Board may
exercise its discretion for early vesting in the event of a change of control of Beach. The Board also has a
general discretion to allow early vesting of performance rights. The Board needs exceptional circumstances
to consider exercising that general discretion.
STI Performance for the year
At the completion of the financial year the Board tested each senior executive’s performance against the STI performance conditions
set for the year. The results of the two hurdle measures were:
FY21 measures
One year Relative Total Shareholder Return against ASX 200 Energy Total Return Index at the end of the
Performance Period
Return on capital at the end of the Performance Period
Outcome
Hurdle
(16.9%)
10.7%
6.9%
10.0%
Although one of the two hurdle measures have been met, the Board exercised its discretion and determined that no FY21 STI will
be awarded.
Whilst no STI will be payable, outcomes of the Company related performance conditions that make up a fixed percentage of the
STI KPIs are provided in Table 6.
66
Table 6: Outcome of FY21 STI Company KPIs
STI Measure
Production
Statutory NPAT
Reserves replacement
All in cost/boe
Personal safety
Process safety
Link to Beach’s strategy
Performance and score
Production is fundamental to Beach’s earnings
and profit.
Beach’s full year production was 25.6 MMboe.
Score – threshold not met.
Statutory NPAT reflects Beach’s earning
performance. Stretch performance is achieved
through strong sales revenue and cost reduction.
Replacing reserves is fundamental to Beach’s
longer term financial sustainability.
Maintaining a cost and efficiency focus in order to
optimise our core production hubs and maintain
financial strength are key strategic pillars.
Beach’s key value is that ‘Safety takes precedence
in everything we do’. Beach is focused on
ensuring it and its contractors operate in a safe
manner. Beach has included other safety and
reliability measures in the annual Sustainability
Report. The Sustainability Report is available on
Beach’s website.
In FY21 Beach delivered Statutory NPAT of $316.5 million.
Score – threshold not met.
Beach’s 2P reserves increased by 12.6 MMboe
(excluding production and divestments) to 339 MMboe.
Score – threshold not met.
Beach’s all in cost/boe for FY21 was $9.97.
Score – threshold not met.
Beach achieved a total recordable injury frequency rate
(TRIFR) of 2.2.
Score – stretch met.
Beach recorded one Loss of Primary Containment events
during the year.
Score – target met.
Environment
Beach strives to reduce the environmental impact
of its activities.
Beach recorded two loss of hydrocarbon events in FY21.
Score – threshold met.
STI performance rights issued in 2019 and 2020 to senior executives converted automatically to shares because they remained
employed by the Company on 1 July 2021. A total of 386,613 shares were transferred.
STI performance rights issued or in operation in FY21
The fair value of services received in return for STI rights (see Table 13) granted is measured by reference to the fair value of STI
rights granted calculated using the Binomial or Black-Scholes Option Pricing Models. The contractual life of the STI rights is used as
an input into the valuation model. The expected volatility is based on the historic volatility (calculated based on the weighted average
remaining life of the rights), adjusted for any expected changes to future volatility due to publicly available information. The risk free
rate is based on Commonwealth Government bond yields relevant to the term of the performance rights.
67
Beach Energy Limited Annual Report 2021 Remuneration Report (Audited)
Long Term Incentive (LTI)
What is the LTI?
The LTI is an equity based ‘at risk’ incentive plan. The LTI aims to reward results that promote long term
growth in shareholder value or total shareholder return (TSR).
Beach offers LTIs to senior executives at the discretion of the Board.
How does the LTI link to
Beach’s key purpose?
The LTI links to Beach’s key purpose by aligning the longer term ‘at risk’ incentive rewards with outcomes that
match shareholder objectives and interests by:
– benchmarking shareholder returns against a group of companies considered alternative investments
to Beach;
– giving share based rather than cash-based rewards to executives. This links their own rewards to
shareholder expectations of dividends and share price growth.
How are the number of rights
issued to senior executives
calculated
The number of performance rights granted to the executives under the LTI is calculated as fixed remuneration
at 1 November of the Financial year times the relevant percentage divided by the market value. The Market
Value is the market value of a fully paid ordinary share in the Company, calculated using a five day VWAP,
up to and including the date the performance rights are granted. This method of calculating the number of
performance rights does not discount for the value of anticipated dividends during the performance period.
What equity based grants
are given and are there plan
limits?
Beach grants performance rights using the formula set out above. If the performance conditions are met,
senior executives have the opportunity to acquire one Beach share for every vested performance right.
There are no plan limits as a whole for the LTI. This is due to the style of the plan and advice by external
remuneration consultants about individual plan limits. Individual limits for the plans that are currently
operational are set out in Table 8.
What is the performance
condition?
The performance condition is based on Beach’s Total Shareholder Return (TSR) relative to the ASX 200
Energy Total Return Index. The initial out-performance level is set at the Index return plus 5.5% compound
annual growth rate (CAGR) over the three year performance period, such that:
– < the Index return – 0% vesting;
– = the Index return – 50% vesting;
– Between the Index return and Index + 5.5% – a prorated number will vest;
– = or > Index return + 5.5% – 100% vesting.
TSR is a measure of the return to shareholders over a period of time through the change in share price and
any dividends paid over that time. The dividends are notionally reinvested to perform the calculation. Beach
chose this performance condition to align senior executive remuneration with increased shareholder value.
The Board has reinforced that alignment by imposing two more conditions. First, the Board sets a threshold
level for the executive to meet before making an award. Secondly, the Board will not make an award if Beach’s
TSR is negative.
All entitlements to shares on the vesting of LTI performance rights are currently satisfied by the purchasing
of shares on market which does not result in any dilution to shareholders equity.
Why choose this performance
condition?
Is shareholders equity diluted
when shares are issued on
vesting of performance rights
or exercise of options?
What happens to LTI
performance rights on a
change of control?
The Board reserves the discretion for early vesting in the event of a change of control of the Company.
Adjustments to a participant’s entitlements may also occur in the event of a company reconstruction and
certain share issues.
68
Table 7: Details of LTI equity awards issued, in operation or tested during the year
Details
Type of grant
2017, 2018, 2019 and 2020 Performance Rights
Performance rights
Calculation of grant limits for senior
executives
Max LTI is 100% of Total Fixed Remuneration (TFR) for MD & CEO
Max LTI is 50% of TFR for other senior executives
Grant date
2020 Performance Rights
14 Dec 2020/31 May 2021
2019 Performance Rights
19 Dec 2019/14 Dec 2020
2018 Performance Rights
14 Dec 2018/19 Dec 2019
2017 Performance Rights
1 Dec 2017/9 April 2018
Issue price of performance rights
Granted at no cost to the participant
Performance period
Note: the date immediately after the end
of the performance period is the first
date that the performance rights vest and
become exercisable
2020 Performance Rights
1 Dec 2020 – 30 Nov 2023
2019 Performance Rights
1 Dec 2019 – 30 Nov 2022
2018 Performance Rights
1 Dec 2018 – 30 Nov 2021
2017 Performance Rights
1 Dec 2017 – 30 Nov 2020
Expiry/lapse
Expiry date
Performance rights lapse if vesting does not occur on testing of performance condition
2020 Performance Rights
30 Nov 2025
2019 Performance Rights
30 Nov 2024
2018 Performance Rights
30 Nov 2023
2017 Performance Rights
30 Nov 2022
Exercise price on vesting
Not applicable – provided at no cost
What is received upon vesting and exercise? One ordinary share in Beach for every performance right
Status
2020 Performance Rights
In progress
2019 Performance Rights
In progress
2018 Performance Rights
In progress
2017 Performance Rights
Testing completed. Resulted in full vesting of performance rights
69
Beach Energy Limited Annual Report 2021 Other senior executives
Other senior executives have employment agreements that
are ongoing until terminated by either Beach upon six months’
notice or the senior executive upon giving between three and
six months’ notice. Beach may terminate a senior executive’s
appointment for cause (for example, for serious breach)
without notice. Beach must pay any amount owing but unpaid
to the employee whose services have been terminated at the
date of termination, such as accrued leave entitlements. In
certain circumstances Beach may terminate employment on
notice of not less than between one and three months for issues
concerning the senior executive’s performance that have not
been satisfactorily addressed. If Beach terminates the senior
executive’s appointment other than for cause or he or she
resigns due to a permanent relocation of his or her workplace to
a location other than their location of hire, then they are entitled
to an amount up to one time their final annual salary.
Details of total remuneration for
KMP calculated as required under the
Corporations Act for FY20 and FY21
Legislative and IFRS reported remuneration
for KMP
Details of the remuneration package by value and by
component for senior executives in the reporting period and the
previous period are set out in Table 8. These details differ from
the actual payments made to senior executives for the reporting
period that are set out in Table 1.
Remuneration Report (Audited)
Details of LTI performance rights
issued or in operation in FY21
The fair value of services received in return for LTI performance
rights (see Table 13) granted is measured by reference to the
fair value of LTI performance rights granted calculated using the
Binomial or Black-Scholes Option Pricing Models. The estimate
of the fair value of the services received for the LTI performance
rights and options issued are measured with reference to the
expected outcome, which may include the use of a Monte Carlo
simulation. The contractual life of the LTI performance rights is
used as an input into this model. Expectations of early exercise
are incorporated into a Monte Carlo simulation method where
applicable. The expected volatility is based on the historic
volatility (calculated based on the weighted average remaining
life of the rights or options), adjusted for any expected changes
to future volatility due to publicly available information. The risk
free rate is based on Commonwealth Government bond yields
relevant to the term of the performance rights.
Employment agreements –
senior executives
The senior executives have employment agreements
with Beach.
The provisions relating to duration of employment,
notice periods and termination entitlements of the senior
executives are as follows:
Managing Director and
Chief Executive Officer
The MD & CEO’s employment agreement commenced
with effect 2 May 2016 and is ongoing until terminated
by either Beach or Mr Kay on six months’ notice. Beach
may terminate the MD & CEO’s employment at any
time for cause (for example, for serious breach) without
notice. In certain circumstances Beach may terminate the
employment on notice of not less than three months for issues
concerning the MD & CEO’s performance that have not been
satisfactorily addressed.
70
Other
long term
benefits
Long
Service
Leave (3)
$
Total
at risk
%
Total
issued in
equity
%
Total
$
52,729
2,223,018
(5,227) 2,600,951
Table 8: Senior executives’ remuneration for FY20 and FY21 as required under the Corporations Act
Short Term Employee Benefits
Share based
payments (1)
Name
M V Kay
Fixed
Remuner-
ation (2)
$
Year
2021
1,202,864
2020 1,266,000
M Engelbrecht 2021
2020
L Marshall
I Grant (6)
T Nador (7)
S Algar (7)
2021
2020
2021
2020
2021
2020
2021
2020
570,954
597,886
524,703
546,591
680,804
–
174,614
–
287,437
–
Former Senior Executives
G J Barker (8)
2021
2020
J L Schrull (8)
D Summers
2021
2020
2021
2020
293,557
486,591
319,934
532,950
–
586,132
Total
2021 4,054,867
2020
4,016,150
Annual
Leave (3)
$
22,092
35,358
29,387
(3,439)
7,441
393
29,192
–
2,018
–
18,829
–
(16,810)
10,577
(10,297)
28,252
–
(12,726)
81,852
58,415
LTI
Rights
$
736,372
658,367
174,929
165,574
154,969
142,172
36,349
–
6,553
–
2,292
–
(88,815)
140,167
(97,347)
139,631
–
(180,191)
STI (4)
–
143,808
–
44,388
–
33,498
–
–
–
–
–
–
–
28,243
–
36,690
–
–
–
STI
Rights (5)
$
208,961
502,645
50,465
109,380
41,018
86,050
126,165
–
–
–
72,421
–
13,669
(2,231)
4,834
(2,277)
–
–
–
–
–
–
16,201
82,760
(58,817)
95,198
–
(72,547)
4,210
(2,277)
10,005
(1,924)
–
(22,983)
839,404
911,558
732,965
806,427
872,510
–
183,185
–
380,979
–
208,343
746,061
163,478
830,797
–
297,685
925,302
456,414
85,447 5,603,882
286,627
1,065,720
803,486
(36,919) 6,193,479
45
50
28
35
27
32
19
–
4
–
20
–
–
33
–
32
–
–
26
34
43
45
27
30
27
28
19
–
4
–
20
–
–
30
–
28
–
–
25
30
(1)
In accordance with the requirements of the Australian Accounting Standards, remuneration includes a proportion of the notional value of equity compensation granted or outstanding during the
year. The fair value of equity instruments are determined as at the grant date and then progressively expensed over the vesting period. The amount included as remuneration is not related to
or indicative of the benefit (if any) that individuals may ultimately realise should the rights vest. The fair value of the rights as at the date of their grant has been determined in accordance with
principles set out in Note 4 to the Financial Statements.
(2) Fixed remuneration comprises base salary and superannuation and other contractual payments treated as remuneration including retention and relocation payments where applicable.
(3) This amount represents the movement in the relevant leave entitlement provision during the year. In respect of long service leave, the probability weighting for employees with less than 7 years
service was reduced during FY20 to better align with Beach’s current average workplace tenure which resulted in a reduction in the provision for all KMP.
(4) No STI was payable for FY21. Cash portion of the STI for FY20 was paid in October 2020.
(5) Mr Grant and Mr Algar are entitled to retention payments on the first and third anniversary of their commencement dates. The retention payments are payable in shares, equal to $100,000 for
Mr Grant and $125,000 for Mr Algar respectively, divided by a 5 day VWAP as calculated on the relevant anniversary date.
(6) Mr Grant became KMP with effect from 20 July 2020.
(7) Mr Algar and Mr Nador both became KMP with effect from 23 February 2021.
(8) Mr Barker and Mr Schrull both ceased to be KMP on 22 February 2021 although continued to be employed with no decision making rights until 18 July 2021 and 18 May 2021 respectively.
71
Beach Energy Limited Annual Report 2021 Remuneration Report (Audited)
Remuneration policy for non-executive directors
The fees paid to non-executive directors are determined using the following guidelines. Fees are:
– not incentive or performance based but are fixed amounts;
– determined by reference to the nature of the role, responsibility and time commitment required for the performance of the role
including membership of board committees;
– are based on independent advice and industry benchmarking data; and
– driven by a need to attract a diverse and well-balanced group of individuals with relevant experience and knowledge.
Following a review by the Remuneration & Nomination Committee a recommendation was made to, and approved by the Board, to
leave all non-executive director’s fees unchanged in FY21. However, all non-executive directors reduced their fees by 10% for the
period 1 July 2020 – 31 December 2020 in recognition of the COVID-19 impact on the global economy.
The remuneration of Beach non-executive directors remains within the aggregate annual limit of $1,500,000 approved by
shareholders at the 2016 annual general meeting.
The remuneration for non-executive directors comprises directors’ fees, board committee fees and superannuation contributions
to meet Beach’s statutory superannuation obligations.
Directors who perform extra services for Beach or make any special exertions on behalf of Beach may be remunerated for those
services in addition to the usual directors’ fees. Non-executive directors are also entitled to be reimbursed for their reasonable
expenses incurred in the performance of their directors’ duties.
Details of the fees payable to non-executive directors for Board and committee membership for FY21 are set out in Table 9.
Table 9: FY21 non-executive directors’ fees and board committee fees per annum
Board (1)
Board Committee
Chairman/
Deputy
Chairman
$
Member
$
Chairman
Audit
$
305,000/122,500
122,500
25,000
Chairman
Remuneration
and
Nomination
$
Member
Remuneration
and
Nomination
$
Chairman Risk,
Corporate
Governance
and
Sustainability
$
Member Risk,
Corporate
Governance
and
Sustainability
$
25,000
15,000
25,000
15,000
Member
Audit
$
15,000
(1) The Chairman does not receive additional fees for committee work. The fees shown are inclusive of the statutory superannuation contribution.
72
Table 10: Non-executive directors’ remuneration for FY20 and FY21
Name
G S Davis (1)
P J Bainbridge (2)
C D Beckett (3)
S G Layman (4)
P S Moore (5)
J C Morton (6)
R J Richards (7)
R K Stokes (8)
M H Hall (9)
Total
Directors Fees
(inc committee fees)
$
Superannuation
$
289,750
305,000
127,968
134,703
144,154
155,451
131,167
134,703
132,306
139,269
124,660
131,535
122,965
125,571
130,625
131,535
–
–
1,203,595
1,257,767
–
–
12,157
12,797
10,221
7,049
8,958
12,797
12,569
13,231
5,965
5,965
11,682
11,929
–
5,965
–
–
61,552
69,733
Year
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
Total
$
289,750
305,000
140,125
147,500
154,375
162,500
140,125
147,500
144,875
152,500
130,625
137,500
134,647
137,500
130,625
137,500
–
–
1,265,147
1,327,500
(1) No superannuation contributions were made on behalf of Mr Davis. Director’s fees for Mr Davis are paid to a related entity. Mr Davis does not receive additional fees for committee work.
(2) Mr Bainbridge is a member of the Risk, Corporate Governance and Sustainability Committee. Mr Bainbridge ceased as chair of the Risk, Corporate Governance and Sustainability Committee on
25 June 2021.
(3) Mr Beckett is Deputy Chairman and chair of the Remuneration and Nomination Committee. He is a member of the Risk, Corporate Governance and Sustainability Committee.
(4) Ms Layman is chair of the Audit Committee.
(5) Dr Moore is the chair of the Risk, Corporate Governance and Sustainability Committee and a member of the Remuneration and Nomination Committee. Dr Moore became chair of the Risk,
Corporate Governance and Sustainability Committee on 25 June 2021, prior to that point he was a member of the committee.
(6) Ms Morton is a member of the Audit Committee.
(7) Mr Richards is a member of both the Audit Committee and the Risk, Corporate Governance and Sustainability Committee. Mr Richards became a member of the Risk, Corporate Governance and
Sustainability Committee on 25 March 2021.
(8) Mr Stokes is a member of the Remuneration and Nomination Committee.
(9) Ms Hall is an alternate Director for Mr Stokes and does not receive any separate remuneration for this role.
73
Beach Energy Limited Annual Report 2021 Remuneration Report (Audited)
Other KMP disclosures
The following three tables show the movements during the reporting period in shares and performance rights over ordinary shares in
the Company held directly, indirectly or beneficially by each KMP and their related entities.
Performance rights held by KMP
The following table details the movements during the reporting period in performance rights over ordinary shares in the Company
held directly, indirectly or beneficially by each KMP and their related entities.
Table 11: Movements in performance rights held by key management personnel
Opening
balance
Granted
Vested/
exercised
Lapsed
Other (1)
Closing
balance
Rights
MD & CEO
M V Kay
Senior executives
M Engelbrecht
I Grant
S Algar
L Marshall
T Nador
Former senior executives
J L Schrull
G J Barker
Total
2,565,582
794,559
(255,039)
195,334
181,492
167,736
157,235
64,729
(57,589)
–
–
(261,363)
–
634,943
–
–
545,641
–
569,697
535,930
–
–
–
–
–
–
–
3,105,102
–
–
–
–
46,691
772,688
181,492
167,736
441,513
111,420
171,491
153,760
(274,269)
(251,652)
(466,919)
(403,091)
–
(34,947)
–
–
4,851,793
1,886,336
(1,099,912)
(870,010)
11,744
4,779,951
(1) Relates to changes resulting from individuals becoming or ceasing to be KMPs during the period.
74
The following table details the movements during the reporting period in ordinary shares in the Company held directly, indirectly or
beneficially by each KMP and their related entities.
Table 12: Shareholdings of key management personnel
Issued on
exercise of
performance
rights
Sold
Other (1)
Ordinary Shares
Directors
G S Davis
P J Bainbridge
C D Beckett
M H Hall (2)
S G Layman
P S Moore
J C Morton
R J Richards
R K Stokes
MD & CEO
M V Kay
Senior executives
M Engelbrecht
I Grant
S Algar
T Nador
L Marshall
Former senior executives
J L Schrull
G J Barker
Total
Opening
balance
243,226
118,090
81,694
–
–
44,200
50,000
188,053
–
Purchased
76,875
19,230
9,984
–
45,000
–
24,000
200,000
–
–
–
–
–
–
–
–
–
–
3,663,216
–
255,039
405,634
–
–
–
10,389
371,010
38,199
5,213,711
–
–
76,826
–
–
–
–
57,589
–
–
–
261,363
274,269
251,652
451,915
1,099,912
(1) Relates to changes resulting from individuals becoming or ceasing to be KMPs during the period.
(2) M Hall is an alternate director for Mr Stokes.
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
Closing
balance
320,101
137,320
91,678
17,068
45,000
44,200
74,000
388,053
–
3,918,255
463,223
–
76,826
–
271,752
–
–
–
17,068
–
–
–
–
–
–
–
–
–
–
–
(645,279)
(289,851)
(918,062)
–
–
5,847,476
75
Beach Energy Limited Annual Report 2021 Remuneration Report (Audited)
Specific details of the number of LTI and STI performance rights granted, vested/exercised and lapsed in FY21 for KMP are set out
in Table 13.
Table 13: Details of LTI and STI Performance Rights
Fair Value
$
Granted
Vested/
Exercised
Lapsed
Other (1)
Performance
rights on
issue at
30 June
2020
849,057
106,130
781,759
148,909
148,909
530,818
–
–
–
0.6161
1.5314
1.0181
2.5500
2.5300
1.4600
1.8100
1.7900
1.0300
–
–
–
–
–
–
47,556
47,555
699,448
–
(106,130)
–
(148,909)
–
–
–
–
–
2,565,582
794,559
(255,039)
247,642
28,268
174,430
29,321
29,321
125,961
–
–
–
634,943
225,365
10,390
156,157
25,608
25,607
102,514
–
–
–
545,641
0.6161
1.5314
1.0181
2.5500
2.5300
1.4600
1.8100
1.7900
1.0300
0.7997
1.5314
1.0181
2.5500
2.5300
1.4600
1.8100
1.7900
1.0300
891,631
542,245
–
–
–
–
–
–
14,679
14,679
165,976
–
(28,268)
–
(29,321)
–
–
–
–
–
195,334
(57,589)
223,780
118,058
–
–
–
–
–
–
11,078
11,077
135,080
(225,365)
(10,390)
–
(25,608)
–
–
–
–
–
157,235
(261,363)
179,011
261,436
Performance
rights on
issue at
30 June
2021
Date
performance
rights vest
and become
exercisable
849,057
–
781,759
–
148,909
530,818
47,556
47,555
699,448
3,105,102
247,642
–
174,430
–
29,321
125,961
14,679
14,679
165,976
772,688
–
–
156,157
–
25,607
102,514
11,078
11,077
135,080
441,513
1 Dec 2020
1 Jul 2020
1 Dec 2021
1 Jul 2020
1 Jul 2021
1 Dec 2022
1 Jul 2021
1 Jul 2022
1 Dec 2023
1 Dec 2020
1 Jul 2020
1 Dec 2021
1 Jul 2020
1 Jul 2021
1 Dec 2022
1 Jul 2021
1 Jul 2022
1 Dec 2023
1 Dec 2020
1 Jul 2020
1 Dec 2021
1 Jul 2020
1 Jul 2021
1 Dec 2022
1 Jul 2021
1 Jul 2022
1 Dec 2023
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
Date of grant
1 Dec 2017
6 Dec 2018
14 Dec 2018
19 Dec 2019
19 Dec 2019
19 Dec 2019
25 Nov 2020
25 Nov 2020
14 Dec 2020
1 Dec 2017
6 Dec 2018
14 Dec 2018
19 Dec 2019
19 Dec 2019
19 Dec 2019
25 Nov 2020
25 Nov 2020
14 Dec 2020
9 Apr 2018
6 Dec 2018
14 Dec 2018
19 Dec 2019
19 Dec 2019
19 Dec 2019
25 Nov 2020
25 Nov 2020
14 Dec 2020
Name
M V Kay
Total
Total ($)
M Engelbrecht
Total
Total ($)
L Marshall
Total
Total ($)
76
Performance
rights on
issue at
30 June
2020
Name
Date of grant
Fair Value
$
Granted
Vested/
Exercised
Lapsed
Other (1)
Performance
rights on
issue at
30 June
2021
Date
performance
rights vest
and become
exercisable
9 Apr 2018
6 Dec 2018
14 Dec 2018
19 Dec 2019
19 Dec 2019
19 Dec 2019
25 Nov 2020
25 Nov 2020
14 Dec 2020
1 Dec 2017
6 Dec 2018
14 Dec 2018
19 Dec 2019
19 Dec 2019
19 Dec 2019
25 Nov 2020
25 Nov 2020
14 Dec 2020
14 Dec 2020
14 Dec 2020
3 May 2021
3 May 2021
G J Barker
Total
Total ($)
J L Schrull
Total
Total ($)
I Grant
Total
Total ($)
T Nador
Total
Total ($)
S Algar
Total
Total ($)
217,845
8,199
156,157
25,608
25,607
102,514
–
–
–
535,930
224,057
24,332
157,818
25,880
25,880
111,730
–
–
–
569,697
–
–
–
–
–
–
–
0.7997
1.5314
1.0181
2.5500
2.5300
1.4600
1.8100
1.7900
1.0300
0.6161
1.5314
1.0181
2.5500
2.5300
1.4600
1.8100
1.7900
1.0300
1.0300
1.0300
0.4100
0.4100
–
–
–
–
–
–
9,340
9,340
135,080
(217,845)
(8,199)
–
(25,608)
–
–
–
–
–
–
–
(156,157)
–
–
(102,514)
–
(9,340)
(135,080)
–
–
–
–
(25,607)
–
(9,340)
–
–
153,760
(251,652)
(403,091)
(34,947)
172,756
252,067
–
–
–
–
–
–
12,134
12,133
147,224
(224,057)
(24,332)
–
(25,880)
–
–
–
–
–
–
–
(157,818)
–
(25,880)
(111,730)
(12,134)
(12,133)
(147,224)
171,491
(274,269)
(466,919)
195,321
181,492
181,492
186,937
–
64,729
64,729
26,539
167,736
167,736
68,772
241,298
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
46,691
–
46,691
–
–
(1) Relates to changes resulting from individuals becoming or ceasing to be KMPs during the period.
1 Dec 2020
1 Jul 2020
1 Dec 2021
1 Jul 2020
1 Jul 2021
1 Dec 2022
1 Jul 2021
1 Jul 2022
1 Dec 2023
1 Dec 2020
1 Jul 2020
1 Dec 2021
1 Jul 2020
1 Jul 2021
1 Dec 2022
1 Jul 2021
1 Jul 2022
1 Dec 2023
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
181,492
1 Dec 2023
181,492
46,691
64,729
111,420
1 Dec 2023
1 Dec 2023
167,736
1 Dec 2023
167,736
77
Beach Energy Limited Annual Report 2021 Flexible Work Arrangements
New Flexible Work Arrangements (FWA) procedures and
leader guides were implemented across Beach in FY21. FWA
arrangements are an important way to offer an environment
which supports diversity and inclusion at work, whilst also
ensuring the business meets legislative requirements in
Australia and New Zealand operations. In addition, the FWA
arrangements have supported the Beach response to COVID-19
orders across multiple jurisdictions, ensuring employees are
aware of the multiple work arrangements at their disposal.
Remuneration Report (Audited)
Looking ahead – Remuneration and
related issues for 2022
Superannuation guarantee
Effective from 1 July 2021, the Superannuation Guarantee
(SG) minimum compulsory rate for all Australian employees
is legislated to increase from 9.5% to 10%. In respect
of all Australian employees, Beach has increased total
fixed remuneration so that no employee suffers any real
remuneration decrease as a consequence of the legislative
change. The total fixed remuneration of non-executive
directors was not increased as part of the SG increase, the rate
change to superannuation instead deducted from base salary.
Employee Retention
The ability to attract and retain the workforce will remain of
critical importance as Beach seeks to ensure our planning and
engagement practices are optimised to deliver operational
and project priorities.
Activities in areas including engagement, remuneration,
wellbeing and resourcing practices will continue to be optimised
with any improvement opportunities identified in these areas
being applied.
Leadership Development
Several leadership programs have been developed and deployed
throughout FY21 and will continue in FY22. Examples being
the Front Line Leadership Program which was deployed in
a self-paced manner to our operational sites and includes a
module on situational (safety) leadership with the participants
being highly engaged.
Beach has also implemented an Unconscious Bias online
module for all employees, which focusses on effective
decision making and ensuring all ideas and approaches are
included for consideration to optimise business decisions.
This will progress into face to face training, with practical tool
application in FY22.
78
Directors’ Declaration
1.
In the directors’ opinion:
(a) t he financial statements and notes set out on pages 80 to 124 are in accordance with the Corporations Act 2001, including:
(i) complying with accounting standards, the Corporations Regulations 2001 and other mandatory professional reporting
requirements; and
(ii) giving a true and fair view of the consolidated entity’s financial position as at 30 June 2021 and of its performance for the
financial year ended on that date; and
(b) there are reasonable grounds to believe that Beach will be able to pay its debts as and when they become due and payable.
2. The attached financial statements are in compliance with International Financial Reporting Standards, as noted in the Basis of
Preparation which forms part of the financial statements.
3.
At the time of this declaration, there are reasonable grounds to believe that the members of the Extended Closed Group
identified in note 23 will be able to meet any obligations or liabilities to which they are, or may become, subject by virtue of the
deed of cross guarantee described in note 23.
4.
This declaration has been made after receiving the declarations required to be made to the Directors in accordance with section
295A of the Corporations Act 2001 for the financial year ended 30 June 2021.
Signed in accordance with a resolution of the directors made pursuant to section 295(5) of the Corporations Act 2001 on behalf of
the directors.
G S Davis
Chairman
Adelaide
16 August 2021
79
Beach Energy Limited Annual Report 2021
Consolidated Statement of Profit or Loss and
Other Comprehensive Income
For the financial year ended 30 June 2021
Revenue
Cost of sales
Gross profit
Other income
Other expenses
Operating profit before financing costs
Interest income
Finance expenses
Profit before income tax expense
Income tax expense
Net profit after tax
Other comprehensive income/(loss)
Items that may be reclassified to profit or loss
FCTR release on cessation of overseas operations
Net gain/(loss) on translation of foreign operations
Other comprehensive income/(loss), net of tax
Total comprehensive income after tax
Basic earnings per share (cents per share)
Diluted earnings per share (cents per share)
The accompanying notes form part of these financial statements.
Consolidated
2021
$million
1,562.0
(967.1)
594.9
51.1
(203.7)
442.3
0.9
(6.4)
436.8
(120.3)
316.5
–
0.3
0.3
316.8
13.88¢
13.87¢
2020
$million
1,728.2
(1,056.7)
671.5
76.6
(43.5)
704.6
2.0
(16.0)
690.6
(191.5)
499.1
(8.7)
(4.9)
(13.6)
485.5
21.89¢
21.84¢
Note
2(a)
3(a)
2(b)
3(b)
16
16
5
26
6
6
80
Consolidated Statement of Financial Position
As at 30 June 2021
Current assets
Cash and cash equivalents
Receivables
Inventories
Contract assets
Other
Total current assets
Non-current assets
Property, plant and equipment
Petroleum assets
Exploration and evaluation assets
Intangible assets
Deferred tax assets
Lease assets
Contract assets
Other
Total non-current assets
Total assets
Current liabilities
Payables
Provisions
Current tax liabilities
Lease liabilities
Contract liabilities
Total current liabilities
Non-current liabilities
Payables
Provisions
Interest bearing liabilities
Deferred tax liabilities
Lease liabilities
Contract liabilities
Total non-current liabilities
Total liabilities
Net assets
Equity
Contributed equity
Reserves
Retained earnings
Total equity
The accompanying notes form part of these financial statements.
Consolidated
Note
2021
$million
2020
$million
17
18
7
8
9
10
11
5
14
18
13
14
18
13
16
5
14
19
20
126.7
355.0
99.4
16.2
73.6
670.9
8.6
3,431.6
334.8
77.1
–
72.2
38.8
45.2
4,008.3
4,679.2
263.2
42.9
3.9
77.0
12.0
399.0
4.5
939.5
174.1
44.4
26.0
3.9
1,192.4
1,591.4
3,087.8
1,859.5
867.1
361.2
3,087.8
109.9
215.8
106.9
16.0
59.0
507.6
9.6
2,986.5
462.4
78.8
33.6
58.7
49.3
25.8
3,704.7
4,212.3
276.4
30.9
86.4
26.8
35.7
456.2
5.6
798.9
56.7
29.3
35.3
12.5
938.3
1,394.5
2,817.8
1,861.2
911.9
44.7
2,817.8
81
Beach Energy Limited Annual Report 2021 Consolidated Statement of Changes in Equity
For the financial year ended 30 June 2021
Share
based
payment
reserve
$million
32.8
–
–
–
–
–
–
–
–
3.2
3.2
Foreign
currency
translation
reserve
$million
8.3
–
(13.6)
(13.6)
–
–
–
–
–
–
–
36.0
(5.3)
Profit
distribution
reserve
$million
126.8
–
–
–
–
–
(22.8)
(22.8)
800.0
–
754.4
881.2
–
–
–
–
–
–
(22.8)
(22.8)
–
(45.6)
Total
$million
2,374.1
499.1
(13.6)
485.5
1.3
(0.7)
(22.8)
(22.8)
–
3.2
(41.8)
2,817.8
316.5
0.3
316.8
0.2
(4.0)
–
(22.8)
(22.8)
2.6
(46.8)
–
0.3
0.3
–
–
–
–
–
–
–
(5.0)
835.6
3,087.8
–
–
–
–
–
(2.1)
–
–
2.6
0.5
36.5
Contributed
equity
$million
Retained
earnings
$million
Note
Balance as at 30 June 2019
Profit for the year
Other comprehensive income/(loss)
Total comprehensive income/(loss) for the year
Transactions with owners in their capacity
as owners:
Shares issued during the year
Shares purchased on market, net of tax
(Treasury shares)
Final dividend paid
Interim dividend paid
Transfer to profit distribution reserve
Increase in share based payments reserve
Transactions with owners
Balance as at 30 June 2020
Profit for the year
Other comprehensive income/(loss)
Total comprehensive income/(loss) for the year
Transactions with owners in their capacity
as owners:
Shares issued during the year
Shares purchased on market, net of tax
(Treasury shares)
Utilisation of Treasury shares on vesting of
shares and rights under employee and executive
incentive plans
Final dividend paid
Interim dividend paid
Increase in share based payments reserve
Transactions with owners
Balance as at 30 June 2021
19
19
21
21
19
19
19
21
21
1,860.6
–
–
–
1.3
(0.7)
–
–
–
–
0.6
1,861.2
–
–
–
0.2
(4.0)
2.1
–
–
–
(1.7)
345.6
499.1
–
499.1
–
–
–
–
(800.0)
–
(800.0)
44.7
316.5
–
316.5
–
–
–
–
–
–
–
1,859.5
361.2
The accompanying notes form part of these financial statements.
82
Consolidated Statement of Cash Flows
For the financial year ended 30 June 2021
Cash flows from operating activities
Receipts from customers and other
Payments to suppliers and employees
Payments for restoration
Interest received
Financing costs
Income tax paid
Net cash provided by operating activities
Cash flows from investing activities
Payments for property, plant and equipment
Payments for petroleum assets
Payments for exploration and evaluation assets
Payments for intangible assets
Proceeds from government grants
Proceeds on sale of joint operations interests
Proceeds from sale of non-current assets
Payments for acquisition of joint operations
Net cash used in investing activities
Cash flows from financing activities
Proceeds from borrowings
Repayment of borrowings
Payment of the principal portion of lease liabilities
Proceeds from employee incentive loans
Payment for shares purchased on market (Treasury shares)
Dividends paid
Net cash provided by/(used in) financing activities
Net increase/(decrease) in cash held
Cash at beginning of financial year
Effects of exchange rate changes on the balances of cash held in foreign currencies
Cash at end of financial year
The accompanying notes form part of these financial statements.
Consolidated
Note
2021
$million
2020
$million
1,624.3
(692.6)
(12.7)
0.2
(6.5)
(152.9)
17
759.8
26
26
17
17
21
(1.1)
(529.2)
(139.4)
(3.9)
–
–
–
(84.2)
(757.8)
260.0
(145.0)
(42.9)
0.2
(5.7)
(45.6)
21.0
23.0
109.9
(6.2)
126.7
1,913.2
(761.7)
(7.9)
2.2
(7.2)
(264.7)
873.9
(5.1)
(643.1)
(266.1)
(5.8)
11.3
8.9
0.7
–
(899.2)
225.0
(165.0)
(54.2)
1.4
(1.0)
(45.6)
(39.4)
(64.7)
171.9
2.7
109.9
83
Beach Energy Limited Annual Report 2021 Notes to the Financial Statements
Notes to and forming part of the Financial Statements for the financial year ended 30 June 2021
Basis of preparation
This section sets out the basis upon which the Group’s
(comprising Beach Energy Limited and its subsidiaries) financial
statements are prepared as a whole. Significant accounting
policies and key judgements and estimates of the Group
that summarise the measurement basis used and assist in
understanding the financial statements are described in the
relevant note to the financial statements or are otherwise
provided in this section.
Beach Energy Limited (Beach) is a for profit company limited
by shares, incorporated in Australia and whose shares are
publicly listed on the Australian Securities Exchange (ASX).
The nature of the Group’s operations are described in the
segment note. The consolidated general purpose financial
report of the Group for the financial year ended 30 June 2021
was authorised for issue in accordance with a resolution of the
directors on 16 August 2021.
This general purpose financial report:
– Has been prepared in accordance with Australian
Accounting Standards and other authoritative
pronouncements of the Australian Accounting Standards
Board and the Corporations Act 2001. The financial
statements comply with International Financial Reporting
Standards (IFRS) as issued by the International Accounting
Standards Board.
– Has been prepared on a going concern and accruals basis
and is based on the historical cost convention, except for
derivative financial instruments, debt and equity financial
assets, and contingent consideration that have been
measured at fair value.
– Is presented in Australian dollars with all amounts rounded
to the nearest hundred thousand dollars unless otherwise
stated, in accordance with ASIC (Rounding in Financial/
Directors’ Reports) Instrument 2016/191 issued by the
Australian Securities and Investment Commission.
– Has been prepared by consistently applying all
accounting policies to all the financial years presented,
unless otherwise stated.
– The consolidated financial statements provide comparative
information in respect of the previous period. Where there
has been a change in the classification of items in the
financial statements for the current period, the comparative
for the previous period has been reclassified to be consistent
with the classification of that item in the current period.
Notes to the financial statements
The notes include information which is required to understand
the financial statements that is material and relevant to the
operations, financial position or performance of the Group.
Information is considered material and relevant where the
amount is significant in size or nature, it is important in
understanding changes to the operations or results of the Group
or it may significantly impact on future performance.
Key judgements and estimates
In the process of applying the Group’s accounting policies,
management has had to make judgements, estimates and
assumptions about future events that affect the reported
amounts of assets and liabilities, revenue and expenses. These
estimates and judgements incorporate the impact of the
ongoing uncertainties associated with the COVID-19 pandemic
and other material business risks. The reasonableness of these
estimates and underlying assumptions are reviewed on an
ongoing basis. Actual results may differ from these estimates.
The areas involving a higher degree of judgement or complexity,
or areas where assumptions and estimates are significant to
the financial statements are found in the following notes:
Note 2 – Revenue from contracts with customers
Note 3 – Expenses
Note 5 – Taxation
Note 9 – Petroleum assets
Note 10 – Exploration and evaluation assets
Note 11 – Intangible assets
Note 13 – Provisions
Note 14 – Leases
Going concern
The Group ended FY21 with $127 million in cash, drawn
debt of $175 million and net working capital of $272 million
(current assets less current liabilities). Available liquidity was
$402 million, comprising $127 million in cash and $275 million
in undrawn debt facilities. Management has prepared cash flow
forecast scenarios that represent reasonably possible downside
scenarios relating to the business from potential economic
scenarios that could arise over the next 12 months, which have
been reviewed by the directors. These forecasts demonstrate
that the Group has sufficient cash, other liquid resources
and undrawn credit facilities to enable the Group to meet its
obligations as they fall due. As such the directors considered it
appropriate to adopt the going concern basis of accounting in
preparing the full year financial statements.
84
Basis of consolidation
The consolidated financial statements are those of Beach and
its subsidiaries (detailed in Note 22). Subsidiaries are those
entities that Beach controls as it is exposed, or has rights, to
variable returns from its involvement with the subsidiary and
has the ability to affect those returns through its power over the
subsidiary. In preparing the consolidated financial statements,
all transactions and balances between Group companies are
eliminated on consolidation, including unrealised gains and
losses on transactions between Group companies. Where
unrealised losses on intra-group asset sales are reversed
on consolidation, the underlying asset is also tested for
impairment from a Group perspective. Profit or loss and other
comprehensive income of subsidiaries acquired or disposed
of during the year are recognised from the date Beach obtains
control for acquisitions and the date Beach loses control for
disposals, as applicable. The acquisition of businesses is
accounted for using the acquisition method of accounting.
Foreign currency
Both the functional and presentation currency of Beach is
Australian dollars. Some subsidiaries have different functional
currencies which are translated to the presentation currency.
Transactions in foreign currencies are initially recorded in the
functional currency by applying the exchange rate ruling at
the date of the transaction. Monetary assets and liabilities
denominated in foreign currencies are retranslated at the
foreign exchange rate ruling at the reporting date. Foreign
exchange differences arising on translation are recognised in
the profit or loss. Non-monetary assets and liabilities that are
measured in terms of historical cost in a foreign currency are
translated using the exchange rate at the date of the initial
transaction. Non-monetary assets and liabilities denominated
in foreign currencies that are stated at fair value are translated
to the functional currency at foreign exchange rates ruling at
the dates the fair value was determined. Foreign exchange
differences that arise on the translation of monetary items
that form part of the net investment in a foreign operation are
recognised in equity in the consolidated financial statements.
Revenues, expenses and equity items of foreign operations are
translated to Australian dollars using the exchange rate at the
date of transaction while assets and liabilities are translated
using the rate at balance date with differences recognised
directly in the Foreign Currency Translation Reserve.
Adoption of new and revised accounting
standards
In the current year, the Group has adopted all of the new
and revised Standards and Interpretations issued by the
Australian Accounting Standards Board that are relevant to its
operations and effective for the current annual reporting period.
Information on relevant new standards is provided below, with
no immediate material impact on the Group’s consolidated
financial statements except for the acquisitions noted in
Note 26 that have applied the optional concentration test under
AASB 3 Business Combinations.
AASB 2018-6 Amendments to Australian
Accounting Standards – Definition of a Business
The amendments update the definition of a business in AASB 3
Business Combinations to help determine whether an acquired
set of activities and assets is a business or not. They clarify the
minimum requirements for a business, remove the assessment
of whether market participants are capable of replacing any
missing elements, add guidance to help entities assess whether
an acquired process is substantive, narrow the definitions of a
business and of outputs, and introduce an optional fair value
concentration test.
AASB 2019-3 Amendments to Australian
Accounting Standards – Interest Rate
Benchmark Reform
The amendments to AASB 9 Financial Instruments were issued
in response to the effects of Interbank Offered Rates reform on
financial reporting and provide mandatory temporary reliefs
which enable hedge accounting to continue during the period of
uncertainty before the replacement of an existing interest rate
benchmark with an alternative nearly risk-free interest rate.
AASB 2018-7 Amendments to Australian
Accounting Standards – Definition of Material
This Standard amends AASB 101 Presentation of Financial
Statements and AASB 108 Accounting Policies, Changes in
Accounting Estimates and Errors to align the definition of
‘material’ across the standards and to clarify certain aspects
of the definition. The new definition states that, ’Information is
material if omitting, misstating or obscuring it could reasonably
be expected to influence decisions that the primary users of
general purpose financial statements make on the basis of
those financial statements, which provide financial information
about a specific reporting entity.’
The Conceptual Framework for
Financial Reporting
The revised Conceptual Framework for Financial Reporting
(the Conceptual Framework) is not a standard, and none of the
concepts override those in any standard or any requirements
in a standard. The purpose of the Conceptual Framework is to
assist the Accounting Standards Board in developing standards,
to help preparers develop consistent accounting policies if
there is no applicable standard in place and to assist all parties
to understand and interpret the standards. The Conceptual
Framework includes some new concepts, provides updated
definitions and recognition criteria for assets and liabilities, and
clarifies some important concepts.
85
Beach Energy Limited Annual Report 2021 Standards, amendments, and interpretations to
existing standards that are not yet effective and
have not been adopted early by the Group
At the date of authorisation of these financial statements,
certain new standards, amendments and interpretations to
existing standards have been published but are not yet effective,
and have not been adopted early by the Group. Management
anticipates that all of the relevant pronouncements will be
adopted in the Group’s accounting policies for the first period
beginning after the effective date of the pronouncement.
These amendments are not expected to have immediate
material impact on the Group’s annual consolidated financial
statements.
Standard Amendments
Interest Rate Benchmark Reform – Phase 2 –
Amendments to IFRS 9, IAS 39, IFRS 7, IFRS 4
and IFRS 16
Reference to the Conceptual Framework –
Amendments to IFRS 3
Property, Plant and Equipment: Proceeds before
intended use – Amendments to IAS 16
Onerous Contracts – Costs of Fulfilling a Contract –
Amendments to IAS 37
Classification of Liabilities as Current or
Non-Current – Amendments to IAS 1
Application of
standard
1 July 2021
1 July 2022
1 July 2022
1 July 2022
1 July 2023
Deferred Tax related to Assets and Liabilities arising
from a Single Transaction – Amendments to IAS 12
1 July 2023
Impact on previous reporting periods
Change in accounting policy
IFRIC agenda decision – Configuration or Customisation Costs
in a Cloud Computing Arrangement
In April 2021, the IFRS Interpretations Committee (IFRIC)
published an agenda decision for configuration and
customisation costs incurred related to a Software as a Service
(SaaS) arrangement. The Group has changed its accounting
policy in relation to configuration and customisation costs
incurred in implementing SaaS arrangements. The nature
and effect of the changes as a result of changing this policy is
described below.
SaaS arrangements are arrangements in which the Group
does not currently control the underlying software used in the
arrangement. Where costs incurred to configure or customise
SaaS arrangements result in the creation of a resource which is
identifiable, and where the company has the power to obtain
the future economic benefits flowing from the underlying
resource and to restrict the access of others to those benefits,
such costs are recognised as a separate intangible software
asset and amortised over the useful life of the software on a
straight-line basis. The amortisation is reviewed at least at
the end of each reporting period and any changes are treated
as changes in accounting estimates. Where costs incurred to
configure or customise do not result in the recognition of an
intangible software asset, then those costs that provide the
Group with a distinct service (in addition to the SaaS access)
are now recognised as expenses when the supplier provides the
services. When such costs incurred do not provide a distinct
service, the costs are now recognised as expenses over the
duration of the SaaS contract. Previously some costs had been
capitalised and amortised over its useful life.
The change in policy has been retrospectively applied and
comparative financial information has been restated, as follows:
Prior period restatements
30 June 2020
$million
30 June 2019
$million
(2.5)
(2.5)
0.8
0.8
(1.7)
(2.5)
0.8
(1.7)
(0.4)
(0.4)
0.1
0.1
(0.3)
(0.4)
0.1
(0.3)
Impact on equity – increase/(decrease) in equity
Intangible Assets
Total Assets
Deferred Tax Liability
Total Liabilities
Net impact on equity
Impact on statement of profit or loss – increase/(decrease) in profit
Other expenses
Income tax expense
Net profit after tax
86
Notes to the Financial Statements Results for the year
This section explains the results and performance of the Group including additional information about those individual line items in
the financial statements most relevant in the context of the operations of the Group, including accounting policies that are relevant
for understanding the items recognised in the financial statements and an analysis of the Group’s result for the year by reference to
key areas, including operating segments, revenue, expenses, employee costs, taxation and earnings per share.
1. Operating segments
The Group has identified its operating segments to be its South Australian and Western Australian (SAWA), Victorian and New
Zealand interests based on the different geographical regions and the similarity of assets within those regions. This is the basis on
which internal reports are provided to the Managing Director & Chief Executive Officer for assessing performance and determining
the allocation of resources within the Group.
The Group operates primarily in one business, namely the exploration, development and production of hydrocarbons. Revenue is
derived from the sale of gas and liquid hydrocarbons. Gas sales contracts are spread across major Australian and New Zealand
energy retailers and industrial users with liquid hydrocarbon product sales being made to major multi-national energy companies
based on international market pricing.
Details of the performance of each of these operating segments for the financial years ended 30 June 2021 and 30 June 2020
are as follows:
SAWA
Victoria
New Zealand
Total
2021
$million
2020
$million
2021
$million
2020
$million
2021
$million
2020
$million
2021
$million
2020
$million
Segment revenue
Revenue from external
customers (1)
Segment results
Gross segment result before
depreciation, amortisation
and impairment
Depreciation and amortisation
Impairment expense
Other revenue
Other income
Net financing costs
Other expenses
Profit before tax
Income tax expense
Net profit after tax
1,177.8
1,288.1
207.1
222.3
134.5
139.9
1,519.4
1,650.3
709.8
(267.3)
(117.0)
325.5
813.2
(329.1)
–
484.1
134.8
(117.3)
–
17.5
153.8
(90.1)
–
63.7
125.9
(33.6)
–
92.3
71.5
(25.7)
(1.6)
44.2
970.5
(418.2)
(117.0)
435.3
42.6
51.1
(5.5)
(86.7)
436.8
(120.3)
316.5
1,038.5
(444.9)
(1.6)
592.0
77.9
76.6
(14.0)
(41.9)
690.6
(191.5)
499.1
(1) During the year revenue from three customers amounted to $989 million (2020: $1,231 million from three customers) arising from sales from SAWA, Victoria and New Zealand segments.
87
Beach Energy Limited Annual Report 2021 1. Operating segments (continued)
SAWA
Victoria
New Zealand
Total
2021
$million
2020
$million
2021
$million
2020
$million
2021
$million
2020
$million
2021
$million
2020
$million
2,967.7
2,739.7
1,224.9
896.4
287.8
277.6
4,480.4
3,913.7
584.1
502.8
506.4
353.8
106.8
123.3
198.8
4,679.2
1,197.3
394.1
1,591.4
298.6
4,212.3
979.9
414.6
1,394.5
96.7
349.3
446.0
175.7
447.5
623.2
45.2
261.7
306.9
21.6
125.7
147.3
0.7
23.1
23.8
21.2
18.5
39.7
142.6
634.1
776.7
218.5
591.7
810.2
33.4
18.6
810.1
828.8
Australia
New Zealand
Total
2021
$million
3,753.4
2020
$million
3,407.7
2021
$million
209.7
2020
$million
237.6
2021
$million
3,963.1
2020
$million
3,645.3
Segment assets
Total corporate and
unallocated assets
Total consolidated assets
Segment liabilities
Total corporate and
unallocated liabilities
Total consolidated liabilities
Additions and acquisitions
of non-current assets
Exploration and evaluation assets
Petroleum assets
Total corporate and unallocated
assets
Total additions and acquisitions
of non-current assets
Non-current assets*
*excluding financial assets and deferred taxes
88
Notes to the Financial Statements 2. Revenue from contracts with customers
and other income
Revenue from contracts with customers is recognised in the
income statement when the performance obligations are
considered met, which is when control of the hydrocarbon
products or services provided are transferred to the customer.
Revenue is recognised at an amount that reflects the
consideration the Group expects to be entitled to, net of goods
and services tax or similar taxes.
Product sales
Sales revenue is recognised using the “sales method” of
accounting. The sales method results in revenue being
recognised based on volumes sold under contracts with
customers, at the point in time where performance obligations
are considered met. Generally, regarding the sale of
hydrocarbon products, the performance obligation will be met
when the product is delivered to the specified measurement
point (gas) or point of loading/unloading (liquids).
The Group’s sales of crude oil, liquefied natural gas, ethane,
condensate, LPG, and in some contractual arrangements,
natural gas, are based on market prices. In contractual
arrangements with market base pricing, at the time of the
delivery, there is only a minimal risk of a change in transaction
price to be allocated to the product sold. Accordingly, at the
point of sale where there is not a significant risk of revenue
reversal relative to the cumulative revenue recognised, there
is no constraining of variable consideration.
Where the sales price is not final at the point the performance
obligations are met, any subsequent measurement of these
provisionally priced sales is not revenue from customers and
has been recognised as other sales revenue.
Contract liabilities and contract assets
A contract liability for deferred revenue is recorded for
obligations under sales contracts to deliver natural gas in future
periods for which payment has already been received. Where
the period between when payment is received and performance
obligations are considered met, is more than 12 months, an
assessment will be made for whether a significant financing
component is required to be accounted for. Deferred revenue
liabilities unwind as “revenue from contracts with customers”,
with reference to the performance obligation, and if a
significant financing component associated with deferred
revenue exists, an interest expense will also be recognised over
the life of the contract.
On acquisition of the Lattice and Toyota Tsusho interests,
pre-existing revenue contracts were fair valued, resulting
in contract assets and liabilities being recognised. Both the
contract assets and liabilities represent the differential in
contract pricing and market price, and will be realised as
performance obligations are considered met in the underlying
revenue contract. To the extent a contract asset or liability
represents the fair value differential between contract price
and market price, it will be unwound through “other operating
revenue or expense”.
Net contract assets and liabilities have increased by
$22.0 million to $39.1 million, with $20.4 million included in
other revenue and $3.3 million unwind of discount included in
finance expenses offset by $1.7 million included in FCTR.
(a) Revenue
Crude oil
Sales gas and ethane
Liquefied petroleum gas
Condensate
Gas and gas liquids
Revenue from contracts with customers
Crude oil – revaluation of provisionally priced sales
Sales Revenue (1)
Other operating revenue
Total revenue
(1) Provisionally priced oil sales revenue recorded as a receivable at 30 June 2021 totalled $110.9 million (FY20 $89.1 million).
Consolidated
2021
$million
2020
$million
613.6
609.4
130.5
143.6
883.5
1,497.1
22.3
1,519.4
42.6
1,562.0
818.7
604.8
119.1
145.2
869.1
1,687.8
(37.5)
1,650.3
77.9
1,728.2
89
Beach Energy Limited Annual Report 2021 2. Revenue from contracts with customers and other income (continued)
(b) Other income
Gain on sale of joint operations interests (Note 26)
Gain on cessation of overseas operations (Note 26)
Gain on reversal of acquired liabilities
Gain on sale of non-current assets
Other income related to joint venture lease recoveries
Government grants received
Foreign exchange gains
Other
Total other income
3. Expenses
Consolidated
2021
$million
2020
$million
–
–
35.4
–
9.8
5.3
–
0.6
51.1
8.9
8.7
37.8
0.6
15.5
3.7
1.4
–
76.6
The Group’s significant expenses in operating the business are described below split between cost of sales and other expenses
including impairment and corporate and other costs.
(a) Cost of sales
Field operating costs
Tariffs and tolls
Royalties
Total operating costs
Depreciation and amortisation of petroleum assets (Note 9)
Depreciation of leased assets (Note 14)
Third party oil and gas purchases
Decrease/(increase) in product inventory
Total cost of sales
(b) Other expenses
Impairment
Impairment of petroleum assets (Note 9)
Impairment of exploration and evaluation assets (Note 10)
Total impairment expense
Other
Exploration expense
Loss on sale of non-current assets
Depreciation of corporate leased assets (Note 14)
Foreign exchange losses
Corporate expenses (1)
Other expenses
Total other expenses
Consolidated
2021
$million
2020
$million
251.8
76.0
116.9
444.7
405.6
12.6
68.4
35.8
967.1
35.3
81.7
117.0
56.7
1.7
3.5
8.9
15.9
86.7
203.7
240.4
160.9
124.3
525.6
427.1
17.8
93.0
(6.8)
1,056.7
–
1.6
1.6
20.7
–
3.5
–
17.7
41.9
43.5
(1)
Includes depreciation of property, plant and equipment and amortisation of software costs of $7.3 million (FY20 $6.3 million) as shown in Note 8 and 11, and share based payments expense of
$2.6 million (FY20 $3.3 million).
90
Notes to the Financial Statements 4. Employee benefits
Provision is made for the Group’s employee benefits liability
arising from services rendered by employees to the end of
the reporting period. These benefits include wages, salaries,
annual leave and long service leave. Where these benefits are
expected to be settled within 12 months of the reporting date,
they are measured at the amounts expected to be paid when
the liabilities are settled. Expenses for non-vesting personal
leave are recognised when the leave is taken and are measured
at the rates paid or payable. Liabilities for long service leave
and annual leave that is not expected to be taken wholly before
12 months after the end of the reporting period in which the
employee rendered the related service, are recognised and
measured as the present value of the estimated future cash
outflows to be made in respect of employees’ services up to
the reporting date. The obligation is calculated using expected
future increases in wage and salary rates, experience of
employee departures and periods of service. The estimated
future payments have been discounted using Australian
corporate bond rates. The obligations are presented as current
liabilities in the statement of financial position if the Group does
not have the unconditional right to defer settlement for at least
12 months after the reporting date, regardless of when the
actual settlement is expected to occur.
Superannuation commitments – Each employee nominates
their own superannuation fund into which Beach contributes
compulsory superannuation amounts based on a percentage of
their salary.
Termination benefits – Termination benefits may be payable
when employment is terminated before the normal retirement
date, without cause, or when an employee accepts voluntary
redundancy in exchange for these benefits. Beach recognises
termination benefits when it is demonstrably committed to
making these payments.
Equity settled compensation
Employee Incentive Plan – The Group operates an Employee
Incentive Plan, approved by shareholders. Shares are allotted
to employees under this plan at the Board’s discretion. Shares
acquired by employees are funded by interest free non-recourse
loans for a term of 10 years which are repayable on cessation
of employment with the consolidated entity or expiry of the
loan term. The fair value of the equity to which employees
become entitled is measured at grant date and recognised as an
expense over the vesting period with a corresponding increase
in equity. The fair value of shares issued is determined with
reference to the latest ASX share price. Rights are valued using
an appropriate valuation technique such as the Binomial or
Black-Scholes Option Pricing Models which takes into account
the vesting conditions.
The following employee shares are currently on issue
Balance as at 30 June 2019
Loans repaid during 2020 financial year
Balance as at 30 June 2020
Loans repaid during 2021 financial year
Balance as at 30 June 2021
Number
2,541,488
(1,003,200)
1,538,288
(150,850)
1,387,438
No new shares were issued to employees during the financial year, pursuant to this plan.
The closing ASX share price of Beach fully paid ordinary shares at 30 June 2021 was $1.24 as compared to $1.52 as at 30 June 2020.
Employee Share Plan – The group operates an employee share plan, approved by shareholders. Employees who buy shares under
the Plan will have those shares matched by Beach, provided any relevant conditions determined by the Board are satisfied. Eligible
Employees are employees of the Group, other than a non-executive director and any other person determined by the Board as
ineligible to participate in the Plan. The Board has the discretion to set an annual limit on the value of shares that participants may
purchase under the Plan, not exceeding $5,000. Purchased Shares have been acquired periodically at the prevailing market price.
Participants pay for their Purchased Shares using their own funds which may include salary sacrifice. To receive Matched Shares, a
participant must satisfy the conditions determined by the Board at the time of the invitation. Details of shares purchased and utilised
under this plan are detailed in Note 19.
91
Beach Energy Limited Annual Report 2021 4. Employee benefits (continued)
Incentive Rights – The Group operates an Executive Incentive Plan (EIP) providing both Short Term Incentives (STIs) and Long
Term Incentives (LTIs). The STI is part of ‘at risk’ remuneration offered to senior executives. It measures individual and Company
performance over a 12 month period coinciding with Beach’s financial year. It is provided in equal parts of cash and equity that may
or may not vest subject to additional retention conditions. It is offered annually to senior executives at the discretion of the Board.
The LTI is an equity based ‘at risk’ incentive plan. The LTI is intended to reward efforts and results that promote long term growth in
shareholder value or total shareholder return (TSR). LTIs are offered to senior executives at the discretion of the Board. The fair value
of performance rights issued are recognised as an employee benefits expense with a corresponding increase in equity. The fair value
of the performance rights are measured at grant date and recognised over the vesting period during which the senior executives
become entitled to the performance rights. The fair value of the STIs is measured using the Black-Scholes Option Pricing Model and
the fair value of the LTIs is measured using Monte Carlo simulation, taking into account the terms and conditions upon which these
rights were issued.
Details of the key assumptions used in determining the valuation of unlisted performance rights issued during the year are outlined below.
2019
STI Rights
2019
STI Rights
2019
LTI Rights
2020
LTI Rights
2020
LTI Rights
FY21
ESP (1)
Grant date
25 Nov 2020 25 Nov 2020
14 Dec 2020
14 Dec 2020
Vesting date
Expiry date
Share price at grant date (A$)
Exercise price (A$)
Expected volatility (average)
Vesting Period (years)
Risk free rate
Dividend yield
Number of securities issued
Fair value of security at grant date (A$)
Total fair value at grant date
1 Jul 2021
n/a
1.82
Nil
n/a
0.6
n/a
1.10%
131,602
1.81
238,120
1 Jul 2022
n/a
1.82
Nil
n/a
1.6
n/a
1.10%
131,597
1.79
235,559
1 Dec 2022
1 Dec 2023
30 Nov 2024 30 Nov 2025
1.90
Nil
59.5%
3.0
0.10%
1.05%
1.90
Nil
59.5%
2.0
0.04%
1.05%
31 May 2021
Up to
30 Jun 2021
1 Jul 2023
1 Dec 2023
n/a
30 Nov 2025
1.18 – 1.81
1.27
Nil
Nil
n/a
53.2%
2.0 – 2.9
2.5
0.05%
n/a
1.57% 1.11% – 1.69%
28,619
0.88
25,185
2,331,931
1.03
2,401,889
311,722
0.41
127,806
821,546
1.13 – 1.76
1,178,590
(1) Matched Share Rights under the Employee Share Plan are acquired periodically throughout the year. Details show the range of valuation inputs during the year.
Movements in unlisted performance rights are set out below:
Consolidated
2021
number
7,437,135
3,757,017
(1,414,684)
(1,595,129)
2020
number
7,711,875
3,178,907
(873,846)
(2,579,801)
8,184,339
7,437,135
Balance at beginning of period
Issued during the period
Forfeited during the period
Vested/Exercised during the period
Balance at end of period
92
Notes to the Financial Statements 5. Taxation
Australian income tax consolidation
Taxation on the profit or loss for the year comprises current and
deferred tax. Taxation is recognised in profit or loss except to
the extent that it relates to items recognised directly in equity or
other comprehensive income.
Beach and its wholly owned Australian subsidiaries are
consolidated for Australian income tax purposes with Beach
responsible for recognising the current and deferred tax assets
and liabilities for the income tax consolidated group.
Current tax is the expected tax payable on the taxable income
for the year, using tax rates and laws enacted or substantively
enacted at the reporting date, and any adjustments to tax
payable in respect of previous years.
Deferred tax is determined using the statement of financial
position approach on temporary differences arising between the
tax bases of assets and liabilities and their carrying amounts
in the statement of financial position. Deferred tax assets are
recognised to the extent that it is probable that future taxable
profits will be available against which the temporary differences
or unused tax losses and tax offsets can be utilised.
Deferred tax is not recognised for temporary differences arising
from goodwill or from the initial recognition of assets and
liabilities (other than a business combination) in a transaction
that affects neither accounting profit nor taxable income.
Deferred tax assets and liabilities are measured at the tax rates
that are expected to be applied when the asset is realised or the
liability is settled, based on the laws that have been enacted or
substantively enacted at the reporting date.
Current and deferred tax assets and liabilities are offset
when there is a legally enforceable right to offset and when
the tax balances are related to taxes levied by the same tax
authority and the entity intends to settle its tax assets and
liabilities on a net basis.
Petroleum Resource Rent Tax (PRRT)
PRRT is considered, for accounting purposes, to be a tax based
on income. Accordingly, current and deferred PRRT expense is
measured and disclosed on the same basis as income tax.
The impact of future augmentation on expenditure is included
in the determination of future taxable profits when assessing
the extent to which a deferred tax asset for PRRT can be
recognised in the statement of financial position.
Beach is responsible for recognising the current tax liability,
current tax assets and deferred tax assets arising from
unused tax losses and credits for the income tax consolidated
group. The Group has applied the separate taxpayer
approach in determining the appropriate amount of current
taxes and deferred taxes to allocate to members of the tax
consolidated group.
Beach has entered into a tax sharing agreement with its
wholly owned subsidiaries whereby each company in the
Group contributes to the income tax payable in proportion
to their contribution to the net profit before tax of the tax
consolidated group.
Goods and services tax
Revenues, expenses and assets are recognised net of the
amount of goods and services tax (GST), except:
– When the GST incurred on a purchase of goods and services
is not recoverable from the taxation authority, in which case
the GST is recognised as part of the cost of acquisition of the
asset or as part of the expense item as applicable; and
– Receivables and payables, which are stated with the amount
of GST included.
The net amount of GST recoverable from, or payable to, the
taxation authority is included as part of receivables or payables
in the Statement of Financial Position.
Cash flows are included in the Consolidated Statement of
Cash Flows on a gross basis.
Commitments and contingencies are disclosed net of
the amount of GST recoverable from, or payable to, the
taxation authority.
93
Beach Energy Limited Annual Report 2021 5. Taxation (continued)
(a) Income tax expense
Income tax recognised in the statement of profit or loss of the Group is as follows:
Recognised in the statement of profit or loss
Current tax expense
Current year
Adjustments for prior years
Total current tax expense
Deferred tax expense
Origination and reversal of temporary differences
Adjustments for prior years
Total deferred tax expense
Total income tax expense
Consolidated
2021
$million
2020
$million
99.2
(25.6)
73.6
20.7
26.0
46.7
120.3
173.5
(23.6)
149.9
29.2
12.4
41.6
191.5
(b) Numerical reconciliation between tax expense and prima facie tax expense
A reconciliation between income tax expense calculated on profit before tax to income tax expense included in the statement of
profit or loss:
Accounting profit before income tax
Prima facie tax on accounting profit before tax at 30%
Adjustment to income tax expense due to:
Non-deductible expenditure
Impact of tax rates applicable outside Australia
Non assessable income
Over provision in prior years
Income tax expense reported in the Statement of Profit or Loss
Consolidated
2021
$million
436.8
131.0
2020
$million
690.6
207.1
0.9
(2.1)
(9.9)
0.4
120.3
1.5
(0.8)
(5.1)
(11.2)
191.5
94
Notes to the Financial Statements (c) Income tax related to items charged or credited to equity ($million)
Share based equity
(d) Deferred tax assets and liabilities ($million)
Recognised deferred tax assets and liabilities
Oil & Gas Assets
Provisions
Employee benefits
Tax Losses
Leases
Other Items
Tax assets/(liabilities)
Set-off of tax
Net deferred tax assets/(liabilities)
Consolidated
2021
$million
2020
$million
(1.7)
(0.3)
Assets
Liabilities
Net
2021
$million
2020
$million
2021
$million
2020
$million
2021
$million
2020
$million
–
287.0
6.1
2.8
30.9
8.1
334.9
(334.9)
–
7.3
259.4
5.4
3.8
26.4
6.6
308.9
(275.3)
33.6
(301.8)
–
–
–
(10.1)
(67.4)
(379.3)
334.9
(44.4)
(239.6)
(18.3)
–
–
(25.4)
(21.3)
(304.6)
275.3
(29.3)
(301.8)
287.0
6.1
2.8
20.8
(59.3)
(44.4)
–
(44.4)
(232.3)
241.1
5.4
3.8
1.0
(14.7)
4.3
–
4.3
95
Beach Energy Limited Annual Report 2021 6. Earnings per share (EPS)
The Group presents basic and diluted EPS for its ordinary shares. Basic EPS is calculated by dividing the profit or loss attributable
to ordinary shareholders of the Company by the weighted average number of ordinary shares outstanding during the year. Diluted
EPS is determined by adjusting the profit or loss attributable to ordinary shareholders and the weighted average number of ordinary
shares for the dilutive effect, if any, of outstanding share rights which have been issued to employees.
Earnings after tax used in the calculation of EPS is as follows:
Basic EPS and Diluted EPS
2021
$million
316.5
2020
$million
499.1
Weighted average number of ordinary shares and potential ordinary shares used in the calculation of EPS is as follows:
Basic EPS
Share rights
Diluted EPS
Calculation of EPS is as follows:
Basic earnings per share (cents per share)
Diluted earnings per share (cents per share)
2021
Number
2020
Number
2,279,860,248
2,279,909,473
2,118,934
5,277,121
2,281,979,182
2,285,186,594
13.88¢
13.87¢
21.89¢
21.84¢
5,178,791 (FY20 1,602,015 ) potential ordinary shares relating to performance rights that were not considered dilutive during the
period as vesting would not have occurred based on the status of the required vesting conditions at the end of the relevant reporting
period. Accordingly, these have been excluded from the calculation of diluted EPS.
96
Notes to the Financial Statements Capital employed
This section details the investments made by the Group in exploring for and developing its petroleum business including inventories,
property plant and equipment, petroleum assets, joint operations, leases and any related restoration provisions as well as an
assessment of asset impairment and details of future commitments.
7. Inventories
Inventories are stated at the lower of cost and net realisable value. Net realisable value is the estimated selling price in the ordinary
course of business, less the estimated costs of completion and selling expenses. Cost is determined as follows:
(i) Drilling and maintenance stocks, which include plant spares, consumables, maintenance and drilling tools used for ongoing
operations, are valued at weighted average cost; and
(ii) Petroleum products, which comprise extracted crude oil, liquefied petroleum gas, condensate and naphtha stored in tanks and
pipeline systems and process sales gas and ethane stored in sub-surface reservoirs, are valued using the absorption cost method.
Petroleum products
Drilling and maintenance stocks
Less provision for obsolescence
Total current inventories at lower of cost and net realisable value
Petroleum products included above which are stated at net realisable value
8. Property, plant and equipment (PPE)
Consolidated
2021
$million
2020
$million
37.7
65.5
(3.8)
99.4
–
63.4
48.0
(4.5)
106.9
22.9
PPE is measured at cost less depreciation and impairment losses. The carrying amount of PPE is reviewed bi-annually for impairment
triggers. The cost of PPE constructed within the Group includes the cost of materials, direct labour, borrowing costs and an
appropriate proportion of fixed and variable overheads. Subsequent costs are included in the asset’s carrying amount or recognised
as a separate asset, as appropriate, only when it is probable that future economic benefits associated with the item will flow to the
Group and the cost of the item can be measured reliably. All other repairs and maintenance are charged to the profit or loss during
the financial period in which they are incurred. The assets residual values and useful lives are reviewed, and adjusted if appropriate,
at each reporting date. Gains and losses on disposals are determined by comparing proceeds with the carrying amount and are
included in the profit or loss.
The depreciable amount of all PPE is depreciated using a straight line basis over their useful lives commencing from the time the
asset is held ready for use. The depreciation rates used in the current and previous period for each class of depreciable asset are
between 4–33%.
Property, plant and equipment
Plant and equipment
Plant and equipment under construction
Less accumulated depreciation
Total property, plant and equipment
Reconciliation of movement in property, plant and equipment:
Balance at beginning of financial year
Additions
Depreciation expense
Total property, plant and equipment
Consolidated
2021
$million
2020
$million
14.4
2.0
(7.8)
8.6
9.6
0.7
(1.7)
8.6
13.6
2.1
(6.1)
9.6
5.1
5.4
(0.9)
9.6
97
Beach Energy Limited Annual Report 2021 9. Petroleum assets
Petroleum assets are stated at cost less accumulated
depreciation and impairment charges. They include initial
cost, with an appropriate proportion of fixed and variable
overheads, to acquire, construct, install or complete production
and infrastructure facilities such as pipelines and platforms,
capitalised borrowing costs, transferred exploration and
evaluation assets and development wells. Subsequent capital
costs, including major maintenance, are included in the asset’s
carrying amount only when it is probable that future economic
benefits associated with the item will flow to the Group and
the cost of the item can be measured reliably. The depreciable
amount of all onshore production facilities, field and other
equipment excluding freehold land is depreciated using a
straight line basis over the lesser of their useful lives and the life
of proved and probable reserves commencing from the time the
asset is held ready for use. Offshore production facilities and
field equipment are depreciated based on a units of production
method using proved and probable reserves. The depreciation
rates used in the current and previous period for each class of
depreciable asset are 3–67% for onshore production facilities,
field and other equipment.
Subsurface assets are amortised using the units of production
method over the life of the area according to the rate of
depletion of the proved and probable reserves. Retention
of petroleum licences is subject to meeting certain work
obligations/commitments as detailed in Note 15. The assets
residual values and useful lives are reviewed, and adjusted
if appropriate, at each reporting date. Gains and losses on
disposals are determined by comparing proceeds with the
carrying amount and are included in the profit or loss.
Estimates of reserve and resource quantities
The estimated quantities of reserves and resources reported
by the Group are integral to the calculation of amortisation
(depletion) expense and to assessments of possible impairment
or impairment reversal. The estimated quantities of reserves
and resources are based upon interpretations of geological,
geophysical and engineering models and assessment of the
technical feasibility and commercial viability of producing the
reserves. Beach prepares its reserves and resources estimates
in accordance with the 2018 update to the Petroleum Resources
Management System sponsored by the Society of Petroleum
Engineers, World Petroleum Council, American Association
of Petroleum Geologists and Society of Petroleum Evaluation
Engineers (SPE-PRMS).
All estimates of reserves and resources reported by Beach are
prepared by, or under the supervision of, a qualified petroleum
reserves and resources evaluator. Over half of Beach’s 2P
reserves as at 30 June 2021 have been independently audited
by RISC Advisory in accordance with Beach’s reserves policy.
Reserves and resources estimates require assumptions regarding
future development and production costs, commodity prices,
exchange rates and fiscal regimes. Estimates may change
from period to period as the economic assumptions used to
prepare the estimates can change from period to period, and
as additional geological and engineering information becomes
available through additional drilling or subsurface technical
analysis. Estimates are reviewed annually or when there are
significant changes in the circumstances impacting specific
assets or asset groups. These changes may impact depreciation,
asset carrying values, restoration provisions and deferred
tax balances. If reserves estimates are revised downwards,
earnings could be affected by higher depreciation expense or an
immediate write-down of the asset’s carrying value.
Field land and buildings
Land and buildings at cost
Less accumulated depreciation
Total land and buildings
Reconciliation of movement in field land and buildings:
Balance at beginning of financial year
Additions
Depreciation expense
Foreign exchange movement
Total field land and buildings
Production facilities and field equipment
Production facilities and field equipment
Production facilities and field equipment under construction
Less accumulated depreciation
Total production facilities and field equipment
98
Consolidated
2021
$million
2020
$million
78.7
(22.3)
56.4
54.8
4.0
(2.3)
(0.1)
56.4
74.8
(20.0)
54.8
51.2
5.3
(1.4)
(0.3)
54.8
2,090.9
89.9
(996.4)
1,184.4
1,918.7
146.9
(898.8)
1,166.8
Notes to the Financial Statements Reconciliation of movement in production facilities, field and other equipment:
Balance at beginning of financial year
Additions
Acquisition of assets and joint operation interests (Note 26)
Impairment of production facilities and field equipment
Depreciation expense
Disposals
Foreign exchange movement
Total production facilities and field equipment
Subsurface assets
Subsurface assets at cost
Subsurface assets under construction
Less accumulated depreciation
Total subsurface assets
Reconciliation of movement in subsurface assets
Balance at beginning of financial year
Additions
Acquisition of assets and joint operation interests (Note 26)
Increase/(decrease) in restoration
Transfer from exploration and evaluation assets
Impairment of subsurface assets
Borrowing costs capitalised
Foreign exchange movement
Amortisation expense
Disposals
Capitalised depreciation of lease assets
Total subsurface assets
Total petroleum assets
Consolidated
2021
$million
2020
$million
1,166.8
105.4
30.2
(17.7)
(98.1)
(0.2)
(2.0)
1,184.4
1,088.8
150.4
–
–
(67.5)
–
(4.9)
1,166.8
4,031.8
451.0
(2,292.0)
3,229.3
522.5
(1,986.9)
2,190.8
1,764.9
1,764.9
406.8
87.7
53.3
180.8
(17.6)
7.1
(0.1)
(305.2)
(1.5)
14.6
2,190.8
3,431.6
1,586.7
436.1
–
(32.5)
102.6
–
6.1
0.5
(358.2)
(0.4)
24.0
1,764.9
2,986.5
The carrying amounts of petroleum assets are assessed
half yearly to determine whether there is an indication of
impairment or impairment reversal for those assets which
have previously been impaired. Indicators of impairment and
impairment reversals include changes in future selling prices,
future costs and reserves. When assessing potential indicators
of impairment or reversals the Group models scenarios and
a range of possible future commodity prices is considered.
If any such indication exists, the asset’s recoverable amount
is estimated. Petroleum assets are assessed for impairment
indicators on a cash generating unit (CGU) basis. Following
review of interdependencies between the various operations
within the Group, it has been determined that the operational
CGUs are Cooper Basin, Perth Basin, Victoria Otway, South
Australia Otway, Bass Gas and Kupe. Where the carrying value
of a CGU includes goodwill, the recoverable amount of the
CGU is estimated regardless of whether there is an indicator of
impairment or not.
The recoverable amount of an asset or CGU is determined as
the higher of its value in use and fair value less costs of disposal.
Value in use is determined by estimating future cash flows
after taking into account the risks specific to the asset and
discounting it to its present value using an appropriate discount
rate. If the carrying amount of an asset or CGU exceeds its
recoverable amount, the asset or CGU is written down and
an impairment loss is recognised in the statement of profit or
loss. For assets previously impaired, if the recoverable amount
exceeds the carrying amount and the indicators driving
the increase in value are sustained for a period of time, the
impairment loss is reversed, except in relation to goodwill.
The carrying amount of the asset or CGU is increased to the
revised estimate of its recoverable amount, but only to the
extent that the asset’s carrying amount does not exceed the
carrying amount that would have been determined, net of
depreciation or amortisation, if no impairment loss
had been recognised.
99
Beach Energy Limited Annual Report 2021 For the current financial year, the following assumptions were
used in the assessment of the CGU’s recoverable amounts:
– Brent oil price (real) of US$70.50/bbl in FY22, US$67.50/bbl
for FY23, US$67.00/bbl for FY24, US$66.50/bbl for FY25,
US$64/bbl for FY26 and US$60/bbl for FY27 and beyond.
– A$/US$ exchange rate of 0.78 for FY22 and 0.75 for FY23
and beyond.
– Post-tax real discount rate of 7%.
For impairment reversals, the present value of future cash
flows are considered using lower oil price scenarios based on a
Monte-Carlo simulation of Reuters Mean and a 10% reduction
in life of asset production, assuming production loss under
a long-term oil-price constrained environment.
With the planned suspension of operations at the Katnook
Gas Plant due to low gas volumes with lower than originally
expected economic ultimate recovery of gas for the Haselgrove
field, an impairment expense of $35.3 million has been recorded
against the carrying value of petroleum assets for the SA
Otway CGU which is part of the SAWA operating segment. This
impairment charge has been recognised within other expenses
in the statement of profit or loss and other comprehensive
income. The recoverable amount of the SA Otway CGU based
on 2P reserves and a risked outcome on contingent resources is
$62 million which represents the carrying value of exploration
assets before deducting the carrying value of restoration
liabilities and has been calculated using the value in use method
with all petroleum assets impaired to nil.
9. Petroleum assets (continued)
Future cash flow information used for the value in use
calculation is based on the Group’s latest reserves, budget,
five-year plan and project economic plans which includes
information sourced and reviewed from operators of our
non-operated interests. The South Australia Otway was
included as a producing CGU for the first time in FY20 with
the Katnook plant commissioned and commencement of
production in H2 FY20 through the Haselgrove 3 field. As the
Katnook gas plant was constructed to facilitate the processing
of gas across a number of fields, a conservative view of
additional resources for other wells and their development
costs has been included into the NPV calculation and assessed
against a carrying value including additional exploration
transfers to development for these further assumed resource
conversions.
Impairment and impairment reversal indicator modelling
In determining whether there is an indicator of impairment,
in the absence of quoted market prices, estimates are made
regarding the present value of future cash flows for each CGU.
These estimates require significant management judgement
and are subject to risk and uncertainty, and hence changes
in economic conditions can also affect the assumptions used
and the rates used to discount future cash flow estimates.
Current climate change legislation is also factored into the
calculation and future uncertainty around climate change risks
continue to be monitored. These risks may include a proportion
of a CGU’s reserves becoming incapable of extraction in an
economically viable fashion; demand for the Group’s products
decreasing, due to policy, regulatory (including carbon pricing
mechanisms), legal, technological, market or societal responses
to climate change and physical impacts related to acute risks
resulting from increased severity of extreme weather events,
and those related to chronic risks resulting from longer-term
changes in climate patterns. In most cases, the present value of
future cash flows is most sensitive to the assumptions outlined
below. Notwithstanding that there is currently no price on
carbon in Australia, the Group has further assessed the carrying
value of its producing assets in Australia against NPVs including
a carbon pricing slope of $25/tCO2e increasing to A$50/tCO2e
by 2030 then increasing to A$70/tCO2e by 2040 (real) and
incorporating the benefits of carbon capture and storage and
the delivery of projects related to Beach’s ‘25 by 25’ initiative
which would also not result in any impairment being required
as at 30 June 2021 had this been in place. The present value
of future cash flows for each CGU were estimated using the
assumptions below with reference to external market forecasts
at least bi-annually. The assumptions applied have regard to
contracted prices and observable market data including forward
values and external market analyst’s forecasts.
100
Notes to the Financial Statements 10. Exploration and evaluation assets
Expenditure on exploration and evaluation is accounted for in
accordance with the area of interest method. Areas of interest
are based on a geological area. These costs are only carried
forward to the extent that they are expected to be recouped
through the successful development or sale of the area or where
activities in the area have not yet reached a stage that permits
reasonable assessment of the existence of proved and probable
hydrocarbon reserves and where the rights to tenure of the area
of interest are current. The costs of acquiring interests in new
exploration and evaluation licences are capitalised. The costs
of drilling exploration wells are initially capitalised pending the
results of the well. Costs are expensed where the well does not
result in the successful discovery of economically recoverable
hydrocarbons and the recognition of an area of interest.
Subsequent to the recognition of an area of interest, all further
evaluation costs relating to that area of interest are capitalised.
Upon approval for the commercial development of an area of
interest, accumulated expenditure for the area of interest is
transferred to petroleum assets.
Area of interest
An area of interest (AOI) is defined by Beach as an area defined
by major geological structural elements that has a discrete
exploration strategy and has largely independent costs for
exploration and evaluation from other geological areas.
Impairment of exploration and evaluation assets
The recoverability of the carrying amount of the exploration and
evaluation assets is dependent on successful development and
commercial exploitation, or alternatively, sale of the respective
AOI. Each potential or recognised AOI is reviewed half-yearly
to determine whether economic quantities of reserves have
been found or whether further exploration and evaluation work
is underway or planned to support continued carry forward of
capitalised costs. Where a potential impairment is indicated,
assessment is performed using a fair value less costs to dispose
method to determine the recoverable amount for each AOI to
which the exploration and evaluation expenditure is attributed.
This assessment requires management to make certain
estimates and apply judgement in determining assumptions
as to future events and circumstances, in particular, the
assessment of whether economic quantities of reserves
have been found. Any such estimates and assumptions
may change as new information becomes available. If, after
having capitalised expenditure under the policy, the Group
concludes that it is unlikely to recover the expenditure by future
exploitation or sale, then the relevant capitalised amount will
be written off to the statement of profit or loss. Retention
of exploration assets is subject to meeting certain work
obligations/exploration commitments as detailed in Note 15.
Government grants received in relation to the drilling of
exploration wells are recognised as a reduction in the carrying
value of the exploration permit as expenditure is incurred.
With the planned suspension of operations at the Katnook
Gas Plant due to low gas volumes with lower than originally
expected economic ultimate recovery of gas for the Haselgrove
field, an impairment expense of $81.7 million has been recorded
against the carrying value of exploration and evaluation assets
for the SA Otway CGU which is part of the SAWA operating
segment. This impairment charge has been recognised within
other expenses in the statement of profit or loss and other
comprehensive income. The recoverable amount of the SA
Otway CGU based on 2P reserves and a risked outcome on
contingent resources is $62 million which represents the
carrying value of exploration assets before deducting the
carrying value of restoration liabilities and has been calculated
using the value in use method.
Exploration and evaluation assets at beginning of financial year
Additions
Increase/(decrease) in restoration
Acquisition of assets and joint operation interests (Note 26)
Transfer to petroleum assets
Impairment of exploration and evaluation assets
Exploration and evaluation expenditure expensed
Disposal of joint operation interests
Borrowing costs capitalised
Foreign exchange movement
Capitalised depreciation of lease assets
Total exploration and evaluation assets
Consolidated
2021
$million
2020
$million
462.4
126.5
4.2
48.8
(180.8)
(81.7)
(56.7)
(0.4)
–
(0.2)
12.7
334.8
355.3
231.5
(9.5)
0.1
(102.6)
(1.6)
(20.7)
(2.2)
0.4
0.3
11.4
462.4
101
Beach Energy Limited Annual Report 2021 11. Intangible assets
Goodwill
Goodwill represents the excess of the cost of an acquisition over the fair value of the Group’s share of the net identifiable assets of
the acquired business combination accounted at the date of acquisition. Goodwill on acquisitions is included in intangible assets.
Goodwill is not amortised, but instead tested for impairment annually or more frequently if events or changes in circumstances
indicate that it might be impaired, and is carried at cost less accumulated impairment losses. Gains or losses on the disposal
of an entity include the carrying amount of goodwill relating to the entity sold. Goodwill is allocated to CGUs for the purpose of
impairment testing. An impairment loss is recognised for the amount by which the asset’s carrying amount exceeds its recoverable
amount. The recoverable amount of an asset or CGU is the greater of its value-in-use and its fair value less cost of disposal. In
assessing value-in-use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that
reflects current market assessments of the time value of money and the risks specific to the asset. Goodwill acquired in a business
combination is allocated to groups of CGUs that are expected to benefit from the synergies of the combination. Impairment losses
are recognised in profit or loss unless the asset has previously been revalued, in which case the impairment is recognised as a
reversal to the extent of that previous revaluation with any excess recognised in profit or loss. Refer to note 9 for further information
regarding critical accounting estimates and judgements used for impairment testing.
Amortisation methods and useful lives
The group amortises intangible assets with a limited useful life using the straight-line method over the following periods:
– IT software – 5 years
At Cost
Accumulated Amortisation
Intangible Assets at 30 June 2021
Reconciliation of movement in intangible assets
Balance at beginning of financial year
Additions
Amortisation
Intangible Assets at 30 June 2021
At Cost
Accumulated Amortisation
Intangible Assets at 30 June 2020
Reconciliation of movement in intangible assets
Balance at beginning of financial year
Additions
Amortisation
Intangible Assets at 30 June 2020
12. Interests in joint operations
Goodwill
$ million
Software
$ million
Total
$ million
57.1
–
57.1
57.1
–
–
57.1
39.8
(19.8)
20.0
21.7
3.9
(5.6)
20.0
96.9
(19.8)
77.1
78.8
3.9
(5.6)
77.1
Goodwill
$ million
Software
$ million
Total
$ million
57.1
–
57.1
57.1
–
–
57.1
35.9
(14.2)
21.7
21.3
5.8
(5.4)
21.7
93.0
(14.2)
78.8
78.4
5.8
(5.4)
78.8
Exploration and production activities are conducted through joint arrangements governed by joint operating agreements, production
sharing contracts or similar contractual relationships. A joint operation involves the joint control, and often the joint ownership,
of one or more assets contributed to, or acquired for the purpose of the joint operation and dedicated to the purposes of the joint
operation. The assets are used to obtain benefits for the parties to the joint operation. Each party may take a share of the output
from the assets and each bears an agreed share of expenses incurred. Each party has control over its share of future economic
benefits through its share of the joint operation. The interests of the Group in joint operations are brought to account by recognising
in the financial statements the Group’s share of jointly controlled assets, share of expenses and liabilities incurred, and the income
from the sale or use of its share of the production of the joint operation in accordance with the Group’s revenue policy.
102
Notes to the Financial Statements Accounting for interests in other entities
Judgement is required in assessing the level of control obtained in a transaction to acquire an interest in another entity; depending
upon the facts and circumstances in each case, Beach may obtain control, joint control or significant influence over the entity or
arrangement. Judgement is applied when determining the relevant activities of a project and if joint control is held over them.
Relevant activities include, but are not limited to, work program and budget approval, investment decision approval, voting rights
in joint operating committees, amendments to permits and changes to joint arrangement participant holdings. Transactions which
give Beach control of a business are business combinations.
If Beach obtains joint control of an arrangement, judgement is also required to assess whether the arrangement is a joint operation
or a joint venture. If Beach has neither control nor joint control, it may be positioned to exercise significant influence over the entity,
which is then accounted for as an associate.
The Group has a direct interest in a number of unincorporated joint operations with those significant joint operation interests
shown below.
Joint Operation
Oil and Gas interests
Australia
Cooper Basin (South Australia)
Ex PEL 92 (PRLs 85-104)
Ex PEL 513 (PRLs 191-206)
Ex PEL 632 (PRLs 131-134)
PEL 630
SA Fixed Factor Area
SA Unit
Cooper Basin (Queensland)
Naccowlah Block
ATP 299 (Tintaburra)
Total 66 Block
SWQ Unit
Otway Basin (Victoria/Tasmania)
Otway Gas Project
Bass Basin (Tasmania) (1)
BassGas Project
Trefoil
Perth Basin (Western Australia)
Beharra Springs
Waitsia Gas Project
International
Taranaki Basin (New Zealand)
Kupe Gas Project
Principal activities
Oil production
Gas production and exploration
Gas production and exploration
Oil and gas exploration
Oil and gas production
Oil production
Oil production
Oil production
Oil production
Gas production
Gas production
Gas production
Gas development
Gas production
Gas production
% interest
2021
2020
75.0
40.0
40.0
50.0
33.4
33.4
38.5
40.0
30.0
39.9
75.0
40.0
40.0
50.0
33.4
33.4
38.5
40.0
30.0
39.9
60.0
60.0
88.8
90.3
50.0
50.0
53.8
50.3
50.0
50.0
Gas production
50.0
50.0
(1)
Increased ownership interests shown at 30 June 2021 were subject to completion on 31 July 2021 of the acquisition of Mitsui’s interests in the Bass Basin under an asset purchase agreement
executed in January 2021.
Details of commitments for expenditure and contingent liabilities incorporating the Group’s interests in joint operations are shown in
Notes 15 and 27 respectively.
103
Beach Energy Limited Annual Report 2021 Estimated costs in the provision currently assume that all major
sub-sea pipelines will be left in-situ noting that, whilst the
removal of offshore pipelines is the default requirement under
current legislation, the existing guidelines provide options other
than complete removal if the titleholder can demonstrate that
the alternative approach delivers equal or better environmental,
safety and well integrity outcomes. The Group currently has
plans that we believe would deliver these equal or better
outcomes and have prepared the provision using our best
estimate of these plans. In addition, cost savings have also been
embedded in the cost estimates assuming that restoration
activities can be undertaken in an efficient manner, such as part
of a campaign. Should the future outcome of negotiations with
regulators change these plans or impact our ability to realise the
campaign cost savings, these decommissioning activities may
need to be expanded or brought forward which may result in
additional costs which are not included in our best estimate and
the associated provision recorded at 30 June 2021.
Actual costs and cash outflows can differ from current
estimates because of changes in laws and regulations, public
expectations, prices, discovery and analysis of site conditions
and changes in clean-up technology. The timing and amount
of future expenditures relating to decommissioning and
environmental liabilities are reviewed annually, together
with the interest rate used in discounting the cash flows.
The interest rates used to determine the balance sheet
obligations at 30 June 2021 were within the range 0.0% to
2.2% (2020 within the range 0.3% to 1.5%), and were based
on applicable government bonds with a tenure aligned to the
tenure of the liability. Given the continuing lack of correlation
between long term inflation rate forecasts and nominal long
term bond rates, management have revised their inflation
rate assumptions to reflect the lower long term bond rates in
the current environment.
Changes in assumptions in relation to the Group’s provisions
could result in a material change in their carrying amounts
within the next financial year. A 0.5% change in the
nominal discount rate or inflation rate could have an impact of
approximately –$60/+$10 million respectively on the value
of the Group’s provisions. The impact on the Group income
statement would not be significant as the majority of the
Group’s provisions relate to decommissioning costs with
adjustments recorded against the carrying value of the
Group’s assets.
13. Provisions
A provision for rehabilitation and restoration is provided by
the Group where there is a present obligation as a result of
exploration, development, production, transportation or storage
activities having been undertaken, and it is probable that an
outflow of economic benefits will be required to settle the
obligation. The estimated future obligations include the costs of
removing facilities, abandoning wells and restoring the affected
areas once petroleum reserves are exhausted. Restoration
liabilities are discounted to present value and capitalised as
a component part of petroleum assets and exploration and
evaluation assets. The capitalised costs are amortised over
the life of the petroleum assets and the provision revised at
the end of each reporting period through the profit or loss
as the discounting of the liability unwinds. The unwinding of
discounting on the provision is recognised as a finance cost.
Estimate of restoration costs
The Group holds provisions for the future removal costs
of offshore and onshore oil and gas platforms, production
facilities and pipelines at different stages of the development,
construction and end of their economic lives. Most of these
decommissioning events are many years in the future and the
precise requirements that will have to be met when the removal
event occurs are uncertain. Decommissioning technologies and
costs are constantly changing, as are political, environmental,
safety and public expectations. The timing and amounts of
future cash flows are subject to significant uncertainty and
estimation is required in determining the amounts of provisions
to be recognised. Any changes in the expected future costs are
reflected in both the provision and the asset.
The provision for environmental liabilities represents the
Group’s best estimate based on current industry practice,
current regulations, technology, price levels and expected
plans for end of life remediation. Within Beach’s provision the
following costs have been provided:
– For offshore assets provision has been made for installation
of permanent well barriers, sever casings and conductors,
recovery of nearshore subsea flowlines, umbilicals and
manifolds, platform preparation, jacket and topside
removal, cutting of piles, removal and disposal of recovered
components. It is currently the Group’s intention to leave all
subsea piles in-situ.
– For onshore assets provision has been made for demolition
and removal of facilities, removal of aboveground pipelines
and services, flush and clean and leave in-situ below
ground pipelines, removal of contaminated soil, site
contouring and revegetation.
– For non-operated joint venture assets, the provision recorded
represents the Group’s share of the relevant Joint Venture
operator estimate as responsibility for the restoration will
reside with the operator who has the best knowledge and
understanding of the assets. The Group regularly assesses
the operator estimates with the assistance of Group
appointed experts.
104
Notes to the Financial Statements Estimate of employee entitlements
Annual and long service leave is measured at the present value of benefits accumulated up to the end of the reporting period.
The liability is discounted using an appropriate discount rate. Management requires judgement to determine key assumptions
used in the calculation including future increases in salaries and wages, future on-cost rates and future settlement dates
of employees’ departures.
Current
Employee entitlements
Restoration
Total
Non-Current
Employee entitlements
Restoration
Total
Movement in the Group’s provisions are set out below:
Balance at 1 July 2020
Provision made or reversed during the year
Provision paid/used during the year
Unwind of discount
Acquisitions/disposals
Foreign exchange movements
Balance at 30 June 2021
Consolidated
2021
$million
2020
$million
19.5
23.4
42.9
0.8
938.7
939.5
16.9
14.0
30.9
1.0
797.9
798.9
Restoration
$million
Employee
entitle-
ments
$million
811.9
57.6
(11.6)
8.1
95.7
0.4
962.1
17.9
9.1
(6.7)
–
–
–
20.3
105
Beach Energy Limited Annual Report 2021 14. Leases
Recognition and measurement as a lessee
Leases are recognised as a lease asset and a corresponding
liability at the date at which the leased asset is available for
use by the Group. A lease is a contract (i.e., an agreement
between two or more parties that creates enforceable rights
and obligations), or part of a contract, that conveys the right to
use an asset for a period of time in exchange for consideration.
To be a lease, a contract must convey the right to control the
use of an identified asset. Contracts may contain both lease and
non-lease components. The Group allocates the consideration
in the contract to the lease and non-lease components based on
their relative stand-alone prices. The Group has lease contracts
for various items of plant, machinery, vehicles, buildings and
other equipment used in its operations. The Group has several
lease contracts that include extension and termination options.
These options are negotiated by management to provide
flexibility in managing the leased-asset portfolio and align with
the Group’s business needs. Management exercises significant
judgement in determining whether these extension and
termination options are reasonably certain to be exercised.
Lease assets are measured at cost, less any accumulated
depreciation, and adjusted for any remeasurement of lease
liabilities and for impairment losses, assessed in accordance
with the Group’s impairment policies. The cost of lease assets
includes the amount of lease liabilities recognised, initial direct
costs incurred, and lease payments made at or before the
commencement date less any lease incentives received. The
recognised lease assets are depreciated on a straight-line basis
over the shorter of its estimated useful life and the lease term.
Contracts may contain both lease and non-lease components.
The Group allocates the consideration in the contract to
the lease and non-lease components based on their relative
stand-alone prices. Judgement is required to determine the
Group’s rights and obligations for lease contracts within joint
operations, to assess whether lease liabilities are recognised
gross (100%) or in proportion to the Group’s participating
interest in the joint operation. This includes an evaluation of
whether the lease arrangement contains a sublease with the
joint operation. Instances where the payments regarding a
lease contract are part of a joint operations and the Group
is the responsible party for payment, the Group recognises
the full lease liability, and recognises other income for the
portion of payment that is recovered through other parties
within the joint venture arrangement. Instances where a
sublease is entered into, the Group recognises the full lease
liability, and recognises a sublease receivable for the portion
of payment that is recovered through other parties within the
sublease arrangement.
At the commencement date of the lease, the Group recognises
lease liabilities measured at the present value of lease payments
to be made over the lease term. In calculating the present value
of lease payments, the lease payments are discounted using
the interest rate implicit in the lease. If that rate cannot be
readily determined, which is generally the case for leases in the
Group, the Group’s incremental borrowing rate is used, being
the rate that the Group would have to pay to borrow the funds
necessary to obtain an asset of similar value to the lease asset
in a similar economic environment with similar terms, security
and conditions. After the commencement date, the amount of
lease liabilities is increased by the interest cost and reduced
for the lease payments made. In addition, the carrying amount
of lease liabilities is remeasured if there is a modification, a
change in the lease term, a change in the in-substance fixed
lease payments or a change in the assessment to purchase the
underlying asset. Lease liabilities include the net present value
of the following lease payments:
– Fixed payments (including in-substance fixed payments),
less any lease incentives receivable;
– Variable lease payment that are based on an index or a
rate, initially measured using the index or rate as at the
commencement date;
– Amounts expected to be payable by the Group under
residual value guarantees;
– The exercise price of a purchase option if the Group is
reasonably certain to exercise that option;
– Lease payments to be made under reasonably certain
extension options; and
– Payments of penalties for terminating the lease, if the lease
term reflects the Group exercising that option.
The Group is exposed to potential future increases in variable
lease payments based on an index or rate, which are not
included in the lease liability until they take effect. When
adjustments to lease payments based on an index or rate take
effect, the lease liability is reassessed and adjusted against the
lease asset.
Lease payments are allocated between principal and finance
cost. The finance cost is charged to profit or loss over the lease
period to produce a constant periodic rate of interest on the
remaining balance of the liability for each period. Instances
where the underlying costs regarding a lease contract would
previously have been capitalised, the depreciation on the lease
asset is capitalised. Payments associated with short-term
leases and all leases of assets considered to be of low value
are recognised on a straight-line basis as an expense in profit
or loss. Short-term leases are leases with a lease term of
12 months or less.
106
Notes to the Financial Statements Set out below are the carrying amounts of lease assets recognised and the movements during the period:
Lease Assets at the beginning of the financial year
Additions
Lease remeasurement
Depreciation expense (1)
Total Lease Assets
Consolidated
2021
$million
2020
$million
58.7
70.2
(13.3)
(43.4)
72.2
96.8
30.1
(11.5)
(56.7)
58.7
(1)
Instances where the underlying costs regarding a lease contract would previously have been capitalised, the depreciation on the lease asset is capitalised. The Group capitalisation of
depreciation is $27.3m.
Set out below are the carrying amounts of lease liabilities and the movements during the period:
Lease Liabilities at the beginning of the financial year
Additions
Repayments (2) (3)
Lease remeasurement
Accretion of interest
Foreign exchange movements
Total Lease Liabilities
Current
Non-current
Consolidated
2021
$million
2020
$million
62.1
103.7
(53.8)
(13.3)
2.0
2.3
103.0
77.0
26.0
96.8
30.1
(57.6)
(11.5)
3.4
0.9
62.1
26.8
35.3
(2)
(3)
Instances where the payments regarding a lease contract are part of a joint arrangement and the Group is the responsible party for payment, the Group recognises the full lease liability, and
recognises other income for the portion of payment that is recovered through other parties within the joint venture arrangement. The Group recognised $9.8m of other income relating to joint
venture recoveries.
Instances where the payments regarding a lease contract are part of sublease arrangement and the Group is the responsible party for payment, the Group recognises the full lease liability, and
recognises a sublease receivable for the portion of payment that is recovered through other parties within the sublease arrangement. The Group received $9.0m of sublease repayments from
other parties and has a sublease receivable of $25.6m at 30 June 2021.
Payments of $42 million for short-term leases (lease term of 12 months or less) and payments of $6 million for leases of low value
assets were also accounted for in the year ended 30 June 2021.
Other income associated with lease arrangements
Where it has been determined that the Group directs the use of the leased asset, and is the only party with legal obligation to
pay the lessor, the Group recognises other income for any amount of the lease payments that are recoverable from other parties,
representing “other income related to joint venture lease recoveries” in other income. For the year ending 30 June 2021, the amount
recognised was $9.8 million.
107
Beach Energy Limited Annual Report 2021 15. Commitments for expenditure
Capital Commitments
The Group has contracted the following amounts for capital expenditure at the end of the reporting period for
which no amounts have been provided for in the financial statements.
Due within 1 year
Due within 1–5 years
Due later than 5 years
Consolidated
2021
$million
2020
$million
69.6
–
–
69.6
48.6
–
–
48.6
Minimum Exploration Commitments
The Group is required to meet minimum expenditure requirements of various government regulatory bodies and joint arrangements.
These obligations may be subject to renegotiation, may be farmed out or may be relinquished and have not been provided for in the
financial statements.
Due within 1 year
Due within 1–5 years
Due later than 5 years
Consolidated
2021
$million
2020
$million
35.2
47.0
4.2
86.4
25.4
51.5
4.1
81.0
The Group’s share of the above commitments that relate to its interest in joint arrangements are $68.3 million (FY20 $43.8 million)
for capital commitments and $25.0 million (FY20 $80.6 million) for minimum exploration commitments.
Default on permit commitments by other joint arrangement participants could increase the Group’s expenditure commitments
over the forthcoming 5 year period and/or result in relinquishment of tenements. Any increase in the Group’s commitments that
arises from a default by a joint arrangement party may be accompanied by a proportionate increase in the Group’s equity in the
tenement concerned.
Lease Commitments
The Group has contracted the following amounts for lease commitments at the end of the reporting period for which no amounts
have been provided for in the financial statements.
Consolidated
2021
$million
2020
$million
–
–
14.7
14.7
Due within 1 year
108
Notes to the Financial Statements Financial and risk management
This section provides details on the Group’s debt and related financing costs, interest income, cash flows and the fair values of items
in the Group’s statement of financial position. It also provides details of the Group’s market, credit and liquidity risks and how they
are managed.
16. Finances and borrowings
Borrowings are recognised initially at fair value, net of directly attributable transaction costs incurred. Subsequent to initial
recognition, borrowings are stated at amortised cost with any difference between cost and redemption being recognised in the profit
or loss over the period of the borrowings on an effective interest basis. Transaction costs are amortised on a straight line basis over
the term of the facility. The unwinding of present value discounting on debt and provisions is also recognised as a finance cost.
Borrowing costs relating to major oil and gas assets under development are capitalised as a component of the cost of development.
Where funds are borrowed specifically for qualifying projects, the actual borrowing costs incurred are capitalised. Where the
projects are funded through general borrowings, the borrowing costs are capitalised based on the weighted average cost of
borrowing. Borrowing costs incurred after commencement of commercial operations are expensed to the income statement.
Borrowings are classified as current liabilities unless the Group has an unconditional right to defer settlement of the liability for
at least 12 months after the end of the reporting period. Interest income is recognised in the profit or loss as it accrues using the
effective interest method and if not received at balance date, is reflected in the balance sheet as a receivable.
Net finance expenses/(income)
Finance costs
Interest expense
Discount unwinding on net present value assets and liabilities
Finance costs associated with lease liabilities
Less borrowing costs capitalised
Total finance expenses
Interest income
Net finance expenses
Non-current Borrowings
Bank debt
Less debt issuance costs
Total non-current borrowings
Consolidated
2021
$million
2020
$million
4.4
2.3
4.8
2.0
(7.1)
6.4
(0.9)
5.5
175.0
(0.9)
174.1
6.0
0.7
12.4
3.4
(6.5)
16.0
(2.0)
14.0
60.0
(3.3)
56.7
Beach currently has a Senior Secured Debt Facility in place for $525 million, comprised of a $450 million revolving debt facility
(Facility C) and a $75 million Letter of Credit facility (Facility D), both of which have a maturity date of November 2022. As at
30 June 2021 $175 million of Facility C was drawn with $275 million remaining undrawn, with $73 million of Facility D being
utilised predominantly by way of bank guarantees. Bank debt bears interest at the relevant reference rate plus a margin, with the
effective interest rate in FY21 of 1.48% (FY20 2.06%).
109
Beach Energy Limited Annual Report 2021 17. Cash flow reconciliation
For the purpose of the statement of cash flows, cash and cash equivalents includes cash on hand, cash at bank, term deposits with
banks, and highly liquid investments in money market instruments, net of outstanding bank overdrafts subject to them being an
insignificant risk of change in value and a short term maturity.
(a) Reconciliation of cash and cash equivalents
Cash at bank
Cash and cash equivalents
(b) Reconciliation of net profit to net cash provided by operating activities
Net profit after tax
Less items classified as investing/financing activities:
– Loss/(gain) on disposal of non-current assets
– Loss/(gain) on sale of joint operation interests
– Recognition of deferred tax assets on items direct in equity
Add/(less) non-cash items:
– Share based payments
– Depreciation and amortisation
Impairment expense
–
– Exploration expense
– Foreign exchange loss
– Discount unwinding on provision for restoration
– Provision for stock obsolescence movement
– Gain on reversal of acquired liabilities
– Gain on cessation of overseas operations
– Capitalised borrowing costs
– Amortisation of borrowing costs
Net cash provided by operating activities before changes in assets and liabilities
Changes in assets and liabilities net of acquisitions/disposal of subsidiaries:
– Decrease/(increase) in trade and other receivables
– Decrease/(increase) in inventories
– Decrease/(increase) in other current assets
– Decrease/(increase) in other non-current assets
– Decrease/(increase) in deferred tax assets
–
–
–
–
–
Increase/(decrease) in provisions
Increase/(decrease) in current tax liability
Increase/(decrease) in deferred tax liability
Increase/(decrease) in trade and other payables
Increase/(decrease) in net contract liabilities
Net cash provided by operating activities
(c) Reconciliation of liabilities arising from financing activities to financing cash flows
Opening Balance
Financing cash flows (1)
Non-cash changes
Closing Balance
Consolidated
2021
$million
2020
$million
126.7
126.7
109.9
109.9
316.5
499.1
0.8
0.9
–
(0.6)
(8.9)
0.8
318.2
490.4
2.6
429.5
117.0
56.7
0.8
8.1
(0.7)
(35.4)
–
(6.6)
2.4
892.6
(96.5)
14.6
(28.6)
(18.8)
33.6
(10.6)
(80.9)
15.1
62.2
(22.9)
759.8
56.7
115.0
2.4
174.1
3.3
454.8
1.6
20.7
1.0
11.9
4.2
(37.8)
(8.7)
(6.5)
2.7
937.6
61.7
(11.6)
(39.3)
(16.1)
46.1
(0.4)
(114.9)
(5.7)
63.9
(47.4)
873.9
–
60.0
(3.3)
56.7
(1)
Financing cash flows consist of the net amount of proceeds from borrowing ($260 million) and repayments of borrowings ($145 million) in the statement of cash flows.
110
Notes to the Financial Statements 18. Financial risk management
The Group’s activities expose it to a variety of financial risks
including currency, commodity, interest rate, credit and liquidity
risk. Management identifies and evaluates all financial risks
and may enter into financial risk instruments such as foreign
exchange contracts, commodity contracts and interest rate
swaps to hedge certain risk exposures and minimise potential
adverse effects of these risk exposures in accordance with
the Group’s financial risk management policy as approved by
the Board. The Group does not trade in derivative financial
instruments for speculative purposes.
The Board actively reviews all financial risks and any hedging
on a regular basis with updates provided to the Board from
independent consultants/banking analysts to keep them
fully informed of the current status of the financial markets.
Reports providing detailed analysis of any hedging in place
are monitored against the Group’s financial risk management
policy on a regular basis.
The Group classifies its financial instruments in the following
categories: financial assets at amortised cost, financial assets
at fair value through profit or loss (FVTPL), financial assets
at fair value through other comprehensive income (FVOCI),
financial liabilities at amortised cost and derivative instruments.
The classification depends on the purpose for which the
financial instruments were acquired, which is determined
at initial recognition based upon the business model of the
Group and the characteristics of the contractual cash flows
of the instrument.
With the exception of trade receivables, the Group initially
measures a financial asset at its fair value plus, in the case
of a financial asset not at fair value through profit or loss,
transaction costs. Trade receivables are measured at the
transaction price determined under AASB 15.
Financial assets at amortised cost: A financial asset is
classified in this category if the asset is held with the objective
of collecting contractual cash flows and the contractual
terms give rise on specified dates to cash flows that are
solely payments of principal and interest. These assets are
subsequently measured using the effective interest (EIR)
method and are subject to impairment. Gains and losses are
recognised in profit or loss when the asset is derecognised,
modified or impaired.
Financial assets at fair value through other comprehensive
income: A financial asset is classified in this category if it relates
to debt securities where the contractual cash flows are solely
principal and interest and the objective of the Group’s business
model is achieved both by collecting contractual cash flows and
selling financial assets. Upon disposal, any balance within the
OCI reserve for these debt investments is reclassified to the
statement of profit or loss.
Financial assets at fair value through profit or loss: A financial
asset is classified in this category if it is held for trading,
designated upon initial recognition at fair value through profit
or loss, or mandatorily required to be measured at fair value.
Financial assets are classified as held for trading if they are
acquired for the purpose of selling or repurchasing in the
near term. Derivatives are also classified as held for trading
unless they are designated as effective hedging instruments.
Financial assets with cash flows that are not solely payments
of principal and interest are classified and measured at fair
value through profit or loss, irrespective of the business model.
A financial asset is classified in this category if acquired
principally for the purpose of selling in the near term. Realised
and unrealised gains and losses arising from changes in the fair
value of these assets are included in profit or loss in the period
in which they arise.
Financial liabilities: On initial recognition, the Group
measures a financial liability at its fair value minus, in the
case of a financial liability not at fair value through profit or
loss, transaction costs that are directly attributable to the
issue of the financial liability. After initial recognition, these
financial liabilities are stated at amortised cost. Policies for
the recognition and subsequent measurement of derivative
liabilities are as outlined below.
Derivative instruments: Derivative financial instruments may
be entered into by the Group for the purpose of managing
its exposures to market risks arising in the normal course of
business. Any such instruments would be assessed for hedge
accounting. The principal derivatives that may be used are
commodity derivatives, forward foreign exchange contracts and
interest rate swaps. The use of derivative financial instruments
is subject to a set of policies, procedures and limits approved
by the Board of Directors. The Group does not trade in
derivative financial instruments for speculative purposes.
(a) Fair values
Certain assets and liabilities of the Group are recognised in the
statement of financial position at their fair value in accordance
with accounting standard AASB 13 Fair Value Measurement.
The methods used in estimating fair value are made according
to how the available information to value the asset or liability
fits with the following fair value hierarchy:
– Level 1 – the fair value is calculated using quoted prices in
active markets for identical assets or liabilities;
– Level 2 – the fair value is estimated using inputs other than
quoted prices included in Level 1 that are observable for
substantially the full term of the asset or liability; and
– Level 3 – the fair value is estimated using inputs for the asset
or liability that are not based on observable market data.
111
Beach Energy Limited Annual Report 2021 18. Financial risk management (continued)
(a) Fair values (continued)
The Group’s financial assets and financial liabilities measured and recognised at fair value is set out below:
Carrying amount
Financial assets
Cash and cash equivalents
Receivables
Lease assets
Other
Financial liabilities
Payables
Lease liabilities
Interest bearing liabilities
Financial assets/
financial liabilities
at amortised cost
Note
2021
$million
2020
$million
14
14
16
126.7
355.0
72.2
118.8
672.7
267.7
103.0
175.0
545.7
109.9
215.8
58.7
84.8
469.2
282.0
62.1
60.0
404.1
The methods and valuation techniques used for the purpose of measuring fair value are unchanged compared to the previous
reporting period.
The following summarises the significant methods and assumptions used in estimating the fair values of financial instruments:
The Group did not measure any financial assets or financial liabilities at fair value on a non-recurring basis as at 30 June 2021 and
there have been no transfers between the levels of the fair value hierarchy during the year ended 30 June 2021.
The Group also has a number of other financial assets and liabilities including cash and cash equivalents, receivables and payables
which are recorded at their carrying value which is considered to be a reasonable approximation of their fair value.
(b) Market Risk
The Group is exposed to commodity price fluctuations through the sale of petroleum products and other oil-linked contracts.
Derivatives may be used by the Group to manage its forward commodity risk exposure. The Group policy to manage commodity
price exposure may include the use of Australian dollar denominated oil options. Changes in fair value of these derivatives are
recognised immediately in the profit or loss and other comprehensive income, having regard to whether they are defined as
accounting hedges.
Foreign exchange risk arises when future commercial transactions and recognised assets and liabilities are denominated in a
currency that is not the entity’s functional currency. The Group sells a portion of its products and commits to some contracts
in US dollars or NZ dollars. Australian dollar oil option contracts may be used by the Group to manage its foreign currency risk
exposure. Any foreign currencies held which are surplus to forecast needs are converted to Australian dollars as required.
There were no commodity hedges outstanding at 30 June 2020 or 30 June 2021.
112
Notes to the Financial Statements The Group’s interest rate risk arises from the interest bearing cash held on deposit and its bank loan facility which is subject to
variable interest rates. The interest rate profile of the Group’s interest-bearing financial instruments is as follows:
Variable rate instruments:
Cash and cash equivalents
Interest bearing liabilities
Consolidated
2021
$million
2020
$million
126.7
(175.0)
(48.3)
109.9
(60.0)
49.9
Sensitivity analysis for all market risks
The following table demonstrates the estimated sensitivity to changes in the relevant market parameter, with all variables held
constant, on post tax profit and equity, which are the same as the profit impact flows through to equity. These sensitivities should
not be used to forecast the future effect of a movement in these market parameters on future cash flows which may be different as a
result of the Group commodity hedge book.
Impact on post-tax profit and equity
A$/$US – 10% increase in Australian/US dollar exchange rate
A$/$US – 10% decrease in Australian/US dollar exchange rate
US$ oil price – increase of $10/bbl
US$ oil price – decrease of $10/bbl
Interest rates – increase of 1%
Interest rates – decrease of 1%
Consolidated
2021
$million
2020
$million
(46.4)
56.7
88.5
(90.2)
(0.7)
(0.2)
(52.4)
64.1
109.4
(109.4)
0.2
(0.2)
(c) Credit risk
Credit risk arises from cash and cash equivalents, derivative financial instruments and deposits with banks and financial institutions,
as well as credit exposures to customers, including outstanding receivables and committed transactions, and represents the
potential financial loss if counterparties fail to perform as contracted. Management monitors credit risk on an ongoing basis. Gas
sales contracts are spread across major Australian and New Zealand energy retailers and industrial users with liquid hydrocarbon
products sales being made to major multi-national energy companies based on international market pricing.
113
Beach Energy Limited Annual Report 2021 18. Financial risk management (continued)
(c) Credit risk (continued)
The Group applied the simplified approach to providing for expected credit losses prescribed by AASB 9, which permits the use
of the lifetime expected loss provision for all trade receivables and contract assets. Under this method, determination of the loss
allowance provision and expected loss rate incorporates past experience and forward-looking information, including the outlook for
market demand and forward-looking interest rates. As the expected loss rate at 30 June 2021 is 0.1% (FY20 0.2%), a loss allowance
has been recorded at 30 June 2021 of $0.2 million (FY20 $0.4 million).
Ageing of Receivables :
Receivables not yet due
Receivables past due
Considered impaired
Total Receivables
Consolidated
2021
$million
2020
$million
355.0
0.2
(0.2)
355.0
215.8
0.4
(0.4)
215.8
The Group manages its credit risk on financial assets by predominantly dealing with counterparties with an investment grade credit
rating. Customers who wish to trade on unsecured credit terms are subject to credit verification procedures.
Cash is placed on deposit amongst a number of financial institutions to minimise the risk of counterparty default.
(d) Liquidity Risk
Prudent liquidity risk management implies maintaining sufficient cash and marketable securities, the availability of funding through an
adequate amount of committed credit facilities and the ability to close out market positions. The Group aims at maintaining flexibility in
funding to meet ongoing operational requirements, exploration and development expenditure, and small-to-medium-sized opportunistic
projects and investments, by keeping committed credit facilities available. Details of Beach’s financing facilities are outlined in Note 16.
The Group’s exposure to liquidity risk for each class of financial liabilities is set out below:
Less than 1 year
1 to 5 years
Greater than 5 years
Total
2021
2020
2021
2020
2021
2020
2021
2020
Note
$million
$million
$million
$million
$million
$million
$million
$million
Carrying amount
Financial liabilities
Payables
Lease liabilities
Interest bearing
liabilities
14
16
263.2
77.0
276.4
26.8
–
–
340.2
303.2
2.5
18.3
175.0
195.8
2.9
22.2
60.0
85.1
2.0
7.7
–
9.7
2.7
13.1
–
15.8
267.7
103.0
175.0
545.7
282.0
62.1
60.0
404.1
114
Notes to the Financial Statements Equity and group structure
This section provides information which will help users understand the equity and group structure as a whole including information
on equity, reserves, dividends, subsidiaries, the parent company, related party transactions and other relevant information.
19. Contributed equity
Ordinary shares are classified as equity. Transaction costs of an equity transaction are accounted for as a reduction to the proceeds
received, net of any related income tax benefit. Transaction costs are the costs that are incurred directly in connection with the issue
of those equity instruments and which would not have been incurred had those instruments not been issued.
Issued and fully paid ordinary shares at 30 June 2019
Issued during the FY20 financial year
Shares issued on vesting/exercise of unlisted performance rights
Repayment of employee loans and sale of employee shares
Shares purchased on market (Treasury shares), net of tax
Issued and fully paid ordinary shares at 30 June 2020
Issued during the FY21 financial year
Shares issued on vesting/exercise of unlisted performance rights
Repayment of employee loans and sale of employee shares
Shares purchased on market (Treasury shares), net of tax
Utilisation of Treasury shares on vesting of shares and rights under employee
and executive incentive plans
Number
of Shares
2,278,249,104
$million
1,860.6
2,559,073
–
–
–
1.3
(0.7)
2,280,808,177
1,861.2
525,479
–
–
–
–
0.2
(4.0)
2.1
Issued and fully paid ordinary shares at 30 June 2021
2,281,333,656
1,859.5
Treasury shares
Treasury shares are held to satisfy the obligations under the employee and executive incentive plans. Shares are accounted for at the
weighted average cost for the period. During the year $5.6 million (FY20: $1.0 million) of Treasury shares were purchased on market.
Movement in Treasury shares
Balance at 30 June 2019
Shares purchased on market during FY20
Utilisation of Treasury shares on vesting of shares under employee incentive plan
Balance at 30 June 2020
Shares purchased on market during FY21
Utilisation of Treasury shares on vesting of rights under executive incentive plan
Balance at 30 June 2021
Number
–
541,053
(20,728)
520,325
3,523,725
(1,069,650)
2,974,400
In accordance with Corporations Act 2001 shares issued do not have a par value as there is no limit on the authorised share capital
of the Company. All shares issued under the Company’s employee incentive plan are accounted for as a share-based payment
(refer Note 4 and 20 for further details). Shares issued under the Company’s dividend reinvestment plan and employee incentive
plan represent non-cash investing and financing activities. On a show of hands, every person qualified to vote, whether as a member
or proxy or attorney or representative, shall have one vote. Upon a poll, every member shall have one vote for each ordinary share
held. Pursuant to the employee share plan trust, the trustee shall not vote any shares held in respect of the employee incentive plan
or executive incentive plan, except where it is incidental to providing shares to the participants in the plan.
Details of shares and rights issued and outstanding under the Employee Incentive Plan and Executive Incentive Plan are provided in Note 4.
115
Beach Energy Limited Annual Report 2021 19. Contributed equity (continued)
Dividend Reinvestment Plan
The Board suspended the operation of the Dividend Reinvestment Plan on 21 August 2017 on the basis that this form of capital
management is not required at this time.
Capital management
Management is responsible for managing the capital of the Group, on behalf of the Board, in order to maintain an appropriate debt
to equity ratio, provide shareholders with adequate returns and ensure the Group can fund its operations with secure, cost-effective
and flexible sources of funding. The Group debt and capital includes ordinary shares, borrowings and financial liabilities supported by
financial assets. Management effectively manages the capital of the Group by assessing the financial risks and adjusting the capital
structure in response to changes in these risks and in the market. The responses include the management of debt levels, dividends
to shareholders and share issues. The Group net gearing ratio is 1.5% (FY20 nil). Net gearing has been calculated as interest bearing
liabilities less cash and cash equivalents, as a proportion of these items plus shareholder’s equity.
20. Reserves
The Share based payments reserve is used to recognise the fair value of shares, options and rights issued to employees of the Company.
The Foreign currency translation reserve is used to record foreign exchange differences arising from the translation of the financial
statements of subsidiaries with functional currencies other than Australian dollars.
The Profit distribution reserve represents an amount allocated from retained earnings that is preserved for future dividend payments.
Share based payments reserve
Foreign currency translation reserve
Profit distribution reserve
Total reserves
21. Dividends
Consolidated
2021
$million
2020
$million
36.5
(5.0)
835.6
867.1
36.0
(5.3)
881.2
911.9
A provision is recognised for dividends when they have been announced, determined or publicly recommended by the directors on or
before the reporting date.
Final dividend of 1.0 cent (2020 1.0 cent)
Interim dividend of 1.0 cent (2020 1.0 cent)
Total dividends paid or payable
Consolidated
2021
$million
2020
$million
22.8
22.8
45.6
22.8
22.8
45.6
Franking credits available in subsequent financial years based on a tax rate of 30% (2020: 30%)
475.3
354.5
116
Notes to the Financial Statements 22. Subsidiaries
Name of Company
Beach Energy Limited (1)
Beach Petroleum (NZ) Pty Ltd
Beach Oil and Gas Pty Ltd
Beach Production Services Pty Ltd
Beach Petroleum (Cooper Basin) Pty Ltd
Beach (Tanzania) Pty Ltd
Beach Petroleum (Tanzania) Limited
Beach Energy (Operations) Limited (1)
Beach Energy (Perth Basin) Pty Ltd (1)
Beach Energy (Bonaparte) Pty Ltd
Beach Energy (Bass Gas) Limited
Beach Energy Services Pty Ltd
Beach Energy Finance Pty Ltd
Beach Energy (Offshore) Pty Ltd
Beach Energy (Otway) Limited
Beach Petroleum (NT) Pty Ltd
Territory Oil & Gas Pty Ltd
Adelaide Energy Pty Ltd
Australian Unconventional Gas Pty Ltd
Deka Resources Pty Ltd
Well Traced Pty Ltd
Australian Petroleum Investments Pty Ltd (1)
Delhi Holdings Pty Ltd
Delhi Petroleum Pty Ltd (1)
Impress Energy Pty Ltd (1)
Impress (Cooper Basin) Pty Ltd (1)
Springfield Oil and Gas Pty Ltd (1)
Mazeley Ltd
Mawson Petroleum Pty Ltd
Drillsearch Energy Pty Ltd (1)
Circumpacific Energy (Australia) Pty Ltd
Drillsearch Gas Pty Ltd
Drillsearch (Field Ops) Pty Ltd
Drillsearch (513) Pty Ltd
Drillsearch (Central) Pty Ltd
Ambassador Oil & Gas Pty Ltd
Ambassador (US) Oil & Gas LLC
Ambassador Exploration Pty Ltd
Acer Energy Pty Ltd
Great Artesian Oil & Gas Pty Ltd (1)
Beach Energy Resources NZ (Holdings) Limited
Beach Energy Resources NZ (Kupe) Limited
Beach Energy (Kupe) Limited
Kupe Mining (No.1) Limited
Beach Energy Resources NZ (Clipper) Limited
Beach Energy Resources NZ (Tawhaki) Limited
Beach Energy Resources NZ (Tawn) Limited
Beach Energy Resources NZ (Wherry No.1) Limited (2)
Beach Energy Resources NZ (Wherry No.2) Limited (2)
All shares held are ordinary shares, other than Mazeley Ltd which is held by a bearer share.
(1) Company in Closed Group in FY20 and FY21 (refer Note 23).
(2) Company created and registered during FY21.
Place of incorporation
South Australia
South Australia
New South Wales
South Australia
Victoria
Victoria
Tanzania
South Australia
Australian Capital Territory
South Australia
UK
Victoria
Victoria
South Australia
UK
Victoria
Northern Territory
South Australia
South Australia
South Australia
South Australia
Victoria
Victoria
South Australia
Western Australia
Victoria
Western Australia
Liberia
Queensland
Victoria
New South Wales
Queensland
New South Wales
New South Wales
Victoria
Victoria
USA
Victoria
Queensland
New South Wales
New Zealand
New Zealand
New Zealand
New Zealand
New Zealand
New Zealand
New Zealand
New Zealand
New Zealand
Percentage of shares held
%
2021
%
2020
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
–
–
117
Beach Energy Limited Annual Report 2021
23. Deed of cross guarantee
Pursuant to ASIC (wholly-owned companies) Instrument 2016/785, certain wholly-owned subsidiaries can be relieved from the
Corporations Act 2001 requirements for preparation, audit and lodgement of their financial reports.
As a condition of the Class Order, Beach and each of the subsidiaries that opted for relief during the year (the Closed Group) entered
into a Deed of Cross Guarantee (Deed). The effect of the Deed is that Beach has guaranteed to pay any deficiency in the event of
winding up of any of the subsidiaries under certain provisions of the Corporations Act 2001. The Subsidiaries have also given a similar
guarantee in the event that Beach is wound up. Those companies in the Closed Group for each year are referred to in Note 22.
The consolidated statement of profit or loss and other comprehensive income, summary of movements in retained earnings/
(accumulated losses) and statement of financial position of the Closed Group are as follows:
Consolidated Statement of Profit or Loss and Other Comprehensive Income
Revenue
Cost of sales
Gross profit
Other income
Other expenses
Operating profit before financing costs
Interest income
Finance expenses
Profit before income tax expense
Income tax expense
Profit after tax for the year
Other comprehensive income/(loss) net of tax
Total comprehensive income/(loss) after tax
Summary of movements in the Closed Group’s retained earnings/(accumulated losses)
Retained earnings at beginning of the year
Net profit for the year
Transfer to profit distribution reserve
Retained earnings/(accumulated losses) at end of the year
Closed Group
2021
$million
2020
$million
1,382.3
(867.6)
1,542.9
(989.9)
514.7
11.6
(68.7)
457.6
0.2
(11.8)
446.0
(131.1)
314.9
–
553.0
172.0
(29.1)
695.9
1.1
(21.0)
676.0
(186.7)
489.3
–
314.9
489.3
(238.6)
314.9
–
76.3
72.1
489.3
(800.0)
(238.6)
118
Notes to the Financial Statements Consolidated Statement of Financial Position
Current assets
Cash and cash equivalents
Receivables
Inventories
Other
Total current assets
Non-current assets
Property, plant and equipment
Petroleum assets
Exploration and evaluation assets
Lease assets
Intangible Assets
Deferred tax assets
Other financial assets
Total non-current assets
Total assets
Current liabilities
Payables
Provisions
Current tax liability
Lease liabilities
Contract liabilities
Total current liabilities
Non-current liabilities
Payables
Provisions
Lease liabilities
Contract liabilities
Deferred Tax Liability
Interest bearing liabilities
Total non-current liabilities
Total liabilities
Net assets
Equity
Contributed equity
Reserves
Retained earnings/(accumulated losses)
Total equity
Closed Group
2021
$million
2020
$million
113.0
411.2
92.6
71.2
688.0
8.6
3,173.8
213.0
70.1
77.1
–
266.0
3,808.6
4,496.6
209.5
38.5
10.1
76.4
12.0
346.5
408.9
730.6
24.5
3.9
1.3
174.1
1,343.3
1,689.8
2,806.8
1,857.8
872.7
76.3
90.8
329.9
94.5
52.3
567.5
9.6
2,681.6
269.7
45.9
78.8
63.7
244.0
3,393.3
3,960.8
202.3
19.8
83.6
15.3
15.3
336.3
343.4
645.8
32.8
5.9
–
56.7
1,084.6
1,420.9
2,539.9
1,860.6
917.9
(238.6)
2,806.8
2,539.9
119
Beach Energy Limited Annual Report 2021 24. Parent entity financial information
Selected financial information of the parent entity, Beach Energy Limited, is set out below:
Financial performance
Net profit after tax
Other comprehensive income/(loss), net of tax
Total comprehensive income after tax
Total current assets
Total assets
Total current liabilities
Total liabilities
Issued capital
Share based payments reserve
Profits distribution reserve
Other reserve
Retained earnings
Total equity
Expenditure Commitments
Parent
2021
$million
34.0
–
34.0
963.3
2020
$million
805.7
–
805.7
787.1
2,532.8
2,374.3
626.1
910.0
1,859.5
36.5
835.6
0.6
(1,109.4)
1,622.8
583.0
738.6
1,861.2
36.0
881.3
0.6
(1,143.4)
1,635.7
The Company’s contracted expenditure at the end of the reporting period for which no amounts have been provided for in the
financial statements.
Capital expenditure commitments
Minimum exploration commitments
Contingent liabilities and guarantees
Parent
2021
$million
2020
$million
1.3
–
3.4
0.2
Details of contingent liabilities for the Company in respect of service agreements, bank guarantees and parent company guarantees
are disclosed in Note 27.
Beach Energy Limited and a number of its wholly owned subsidiaries are parties to a Deed of Cross Guarantee as disclosed in
Note 23. The effect of the Deed is that Beach Energy Limited has guaranteed to pay any deficiency in the event of winding up of any
of the listed subsidiary companies under certain provisions of the Corporations Act 2001.
Parent entity financial information has been prepared using the same accounting policies as the consolidated financial statements
except for investments in controlled entities which are included in other financial assets and are initially recorded in the financial
statements at cost. These investments may have subsequently been written down to their recoverable amount determined by
reference to the net assets of the controlled entities at the end of the reporting period where this is less than cost.
120
Notes to the Financial Statements 25. Related party disclosures
Transactions with related parties are on normal commercial terms and conditions no more favourable than those available to other
parties unless otherwise stated.
Remuneration for Key Management Personnel
Short term benefits
Share based payments
Other long term benefits
Total
Subsidiaries
Interests in subsidiaries are set out in Note 22.
Transactions with other related parties
Consolidated
2021
$
2020
$
5,401,866
1,381,716
85,447
5,688,692
1,869,206
(36,919)
6,869,029
7,520,979
During the financial year ended 30 June 2021, Beach incurred costs of $847,529 (FY20 $341,956) to Coates Hire Operations Pty Ltd,
an entity of which Ryan Stokes is a director, for the hire of equipment on arm’s length commercial terms.
Directors fees payable to Mr Davis for the year ended 30 June 2021 of $289,750 (FY20 $305,000) were paid directly to
DMAW Lawyers.
26. Acquisitions and disposals
The acquisition method of accounting is used to account for all business combinations, including business combinations involving
entities or businesses under common control, regardless of whether equity instruments issued or liabilities incurred or assumed
at the date of exchange. Where equity instruments are issued in an acquisition, the fair value of the instruments is their published
market price as at the date of exchange unless, in rare circumstances, it can be demonstrated that the published price at the date of
exchange is an unreliable indicator of fair value and that other evidence and valuation methods provide a more reliable measure of
fair value. Transaction costs arising on the issue of equity instruments are recognised directly in equity. Identifiable assets acquired
and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition
date, irrespective of the extent of any non-controlling interest. Transaction costs incurred in relation to the business combination are
expensed as incurred to the Statement of Profit or Loss. The excess of the cost of acquisition over the fair value of the consolidated
entity’s share of the identifiable net assets acquired is recorded as goodwill.
Asset acquisitions which are not business combinations are accounted for by allocating the purchase consideration, including
capitalised transaction costs, against identifiable assets and liabilities acquired, based on their relative fair values determined on
acquisition date.
Beach executed an asset purchase agreement with Senex Energy in November 2020 to acquire Senex’s Cooper Basin assets for a
cash consideration of $87.5 million. The transaction was subject to a number of conditions precedent and completed on 1 March 2021
with an adjustment made to the acquisition price based on cash flows from 1 July 2020 to the completion date.
Beach also entered into an asset purchase agreement in January 2021 with Mitsui subsidiaries AWE Petroleum Pty Ltd and AWE
(Bass Gas) Pty Ltd to acquire all of its interests in the Bass Basin. These assets include Mitsui’s 35.0% interest in the BassGas
Project (comprising the onshore Lang Lang Gas Plant and Yolla gas field), as well as its 40.0% interest in the Trefoil development
project and surrounding retention leases. The transaction, the terms of which are confidential, was subject to regulatory approvals
and third-party consents and completed on 31 July 2021 with an adjustment made to the acquisition price based on cash flows from
1 July 2020 to the completion date.
121
Beach Energy Limited Annual Report 2021
26. Acquisitions and disposals (continued)
Both acquisitions have been accounted for as asset acquisitions as they meet the requirements of the optional concentration
test under AASB 3 Business Combinations. Details of the combined purchase consideration and purchase price allocation to net
identifiable assets acquired for both acquisitions are as follows:
Purchase consideration
Transaction costs
Total purchase consideration
Fair Value of assets acquired
Assets and liabilities held at acquisition date:
– Receivables
–
Inventory
– Petroleum assets
– Exploration and evaluation assets
– Current payables
– Restoration provision
– Other non-current provisions
Net assets acquired
Purchase consideration
Add amount to be received on completion
Less accrued transactions costs
Net cash outflow on acquisition
$million
71.7
4.6
76.3
8.1
5.2
117.9
48.8
(5.4)
(98.1)
(0.2)
76.3
76.3
11.6
(3.7)
84.2
In the prior financial year, a gain on sale of joint operations interests was $8.9 million was recognised in relation to:
– The sale of Beach’s interest in ex PEL 103 (Innamincka Dome) with Beach realising a gain of approximately $5.9 million from the
removal of all associated liabilities;
– The sale of 17% interest in production licences L11 and L22 (Beharra Springs), exploration permit EP 320 and pipeline licence PL 18
in the Perth Basin to Mitsui to align ownership interests at 50:50 resulted to a gain on sale of $2.6 million.
– An adjustment to the gain on sale of 40% of Beach’s Victorian Otway assets to O.G. Energy Holdings Ltd. of $0.4 million.
In the prior financial year, activities for Beach Petroleum (Tanzania) Limited effectively ceased resulting in the release of a cumulative
gain of $8.7 million on the historic translation of this entity from other comprehensive income to the statement of profit or loss in FY20.
122
Notes to the Financial Statements Other information
Additional information required to be disclosed under
Australian Accounting Standards.
27. Contingent liabilities
The directors are of the opinion that the recognition of a
provision is not required in respect of the following matters,
as it is not probable that a future sacrifice of economic benefits
will be required or the amount of the obligation cannot be
measured with sufficient reliability.
Service agreements
Service agreements exist with executive officers under which
termination benefits may, in appropriate circumstances,
become payable. The maximum contingent liability at
30 June 2021 under the service agreements for the executive
officers is $2,083,910 (FY20 $1,688,879).
Bank guarantees
As at 30 June 2021, Beach has been provided with a
$75 million letter of credit facility, of which $73 million had
been utilised by way of bank guarantees or letters of credit
as security predominantly for our environmental obligations
and work programs (refer Note 16 for further details on the
corporate debt facility).
Joint Venture Operations
In the ordinary course of business, the Group participates in a
number of joint ventures which is a common form of business
arrangement designed to share risk and other costs. Failure of
the Group’s joint venture partners to meet financial and other
obligations may have an adverse financial impact on the Group.
Tax obligations
In the ordinary course of business, the Group is subject to
audits from government revenue authorities which could result
in an amendment to historical tax positions.
Parent Company Guarantees
Beach has provided parent company guarantees in respect
of performance obligations for certain exploration interests.
Restoration obligations (refer Note 13)
The Group holds provisions for the future removal costs of
offshore and onshore oil and gas platforms, production facilities
and pipelines at different stages of the development, construction
and end of their economic lives. Most of these decommissioning
events are many years in the future and the precise requirements
that will have to be met when the removal event occurs are
uncertain. Decommissioning technologies and costs are
constantly changing, as are political, environmental, safety and
public expectations. The timing and amounts of future cash flows
are subject to significant uncertainty and estimation is required
in determining the amounts of provisions to be recognised with
the provision representing the Group’s best estimate based on
current industry practice, regulations, technology, price levels and
expected plans for end of life remediation.
Estimated costs in the provision currently assume that all major
sub-sea pipelines will be left in-situ noting that, whilst the
removal of offshore pipelines is the default requirement under
current legislation, the existing guidelines provide options other
than complete removal if the titleholder can demonstrate that
the alternative approach delivers equal or better environmental,
safety and well integrity outcomes. The Group currently has
plans that we believe would deliver these equal or better
outcomes and have prepared the provision using our best
estimate of these plans. In addition, cost savings have also been
embedded in the cost estimates assuming that restoration
activities can be undertaken in an efficient manner, such as part
of a campaign. Should the future outcome of negotiations with
regulators change these plans or impact our ability to realise the
campaign cost savings, these decommissioning activities may
need to be expanded or brought forward which may result in
additional costs which are not included in our best estimate and
the associated provision recorded at 30 June 2021.
In April 2021 the Federal Government issued a draft Offshore
Petroleum and Greenhouse Gas Storage Amendment (Titles
Administration and Other Measures) Bill aiming to strengthen
and clarify Australia’s offshore oil and gas regulatory
framework. The Bill is currently subject to ongoing consultation
with industry. The Bill includes amendments relating to ‘call
back’ on previous titleholders to decommission and remediate
the environment where the current titleholder is unable to do so
(also known as trailing liability). If passed, these provisions may
give rise to potential trailing liabilities for any petroleum titles
issued under Commonwealth offshore petroleum legislation
that Beach has divested.
Under the current framework a titleholder can only be ‘called
back’ when a title has ceased through termination, expiration,
revocation, cancellation or has been surrendered. The enhanced
framework would empower the regulator and the responsible
Commonwealth Minister to ‘call back’ a previous titleholder to
remediate the title area, regardless of how its interest in the title
ceased. Requiring a former titleholder to decommission and
remediate the environment is intended to be an option of last
resort where all other regulatory options have been exhausted.
The final form of the Bill is not expected to be finalised until
FY22 and, based on the assumption that the final legislation
will not have retrospective application, it is not expected to
materially impact the financial position or performance of the
Group at 30 June 2021.
123
Beach Energy Limited Annual Report 2021 27. Contingent liabilities (continued)
Legal proceedings and claims
The Group may be involved in various other legal proceedings and claims in the ordinary course of business, including contractual,
third party, contractor and regulatory claims. While the outcome of these legal proceedings and claims cannot be predicted with
certainty, it is the directors’ opinion that as of the date of this report, it is unlikely these claims will have a material adverse impact
on the Group.
28. Remuneration of auditors
Fees to Ernst & Young (Australia)
Auditing or reviewing the financial statements of the Group
Other assurance services required by legislation
Other assurance services not required by legislation
Other services
Total fees to Ernst & Young (Australia)
Fees to other overseas member firms of Ernst & Young (Australia)
Auditing the financial statements of controlled entities
Other assurance services not required by legislation
Total fees to other overseas member firms of Ernst & Young (Australia)
Fees to other audit firms
Auditing financial statements of controlled entities
Total fees to other firms
Total auditor’s remuneration
29. Subsequent events
Consolidated
2021
$000
2020
$000
801
35
74
225
1,135
135
20
155
14
14
801
35
125
35
996
135
20
155
19
19
1,304
1,170
The acquisition by Beach of Mitsui’s 35.0% interest in the BassGas Project (comprising the onshore Lang Lang Gas Plant and Yolla
gas field), as well as its 40.0% interest in the Trefoil development project and surrounding retention lease completed in July 2021
with an adjustment made to the acquisition price based on cash flows from the effective date of 1 July 2020 to the completion date.
The Group has received a favourable arbitral outcome in relation to a contractual dispute under one of its long term gas sales
agreements in New Zealand regarding the allocation of carbon emission obligations between the parties. A one-off cash payment of
circa NZ$42m (plus interest) will be received in reimbursement of costs incurred to satisfy the emission obligations under the gas
sales agreement during the period of the dispute. The details of the dispute are confidential.
Other than the matters described above, there has not arisen in the interval between 30 June 2021 and up to the date of this report,
any item, transaction or event of a material and unusual nature likely, in the opinion of the directors, to affect substantially the
operations of the Group, the results of those operations or the state of affairs of the Group in subsequent financial years, unless
otherwise noted in the financial report.
124
Notes to the Financial Statements
Independent Auditor’s Report
Ernst & Young
121 King William Street
Adelaide SA 5000 Australia
GPO Box 1271 Adelaide SA 5001
Tel: +61 8 8417 1600
Fax: +61 8 8417 1775
ey.com/au
Independent auditor’s report to the members of Beach Energy Limited
Report on the audit of the financial report
Opinion
We have audited the financial report of Beach 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 statement of profit or loss and 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.
A member firm of Ernst & Young Global Limited
Liability limited by a scheme approved under Professional Standards Legislation
125
Beach Energy Limited Annual Report 2021
Independent Auditor’s Report
Page 2
Carrying value of petroleum assets
Why significant
How our audit addressed the key audit matter
At 30 June 2021 the Group had petroleum assets of
$3,431.6 million.
Australian Accounting Standards require the Group to assess
throughout the reporting period whether there is any
indication that an asset may be impaired, or that reversal of
a previously recognised impairment may be required. If any
such indication exists an entity shall estimate the
recoverable amount of the asset.
The Group identified impairment indicators in respect of
certain petroleum asset cash generating units (‘CGUs’).
Impairment testing was undertaken which resulted in an
impairment charge of $35.3 million being recorded during
the year, as set out in Note 9 of the financial report.
The assessment of indicators of impairment and reversal of
impairment is judgemental and includes an assessment of a
range of external and internal factors which could impact the
recoverable amount of the CGUs.
Where impairment indicators are identified, forecasting
cashflows for the purpose of determining the recoverable
amount of a CGU involves critical accounting estimates and
judgements and is affected by expected future performance
and market conditions. The key forecast assumptions such
as, discount rates, foreign exchange rate, and commodity
prices used in the Group’s impairment assessment are set
out in the Financial Report in Note 9.
As a result, we considered the impairment testing of the
Group’s petroleum asset CGUs and the related disclosures in
the financial report to be a key audit matter.
In completing our audit procedures, we:
• Assessed the Group’s definition of CGU in accordance
with Australian Accounting Standards.
• Evaluated the assumptions, methodologies and
conclusions used by the Group in assessing for indicators
of impairment and impairment reversal, in particular,
those relating to the forecast cash flows and inputs used
to formulate them. This included assessing, in
conjunction with our valuation specialists, the discount
rates, foreign exchange rates and commodity prices with
reference to market prices (where available), market
research, market practice, market indices, broker
consensus and historical performance.
• Used the work of the Group’s internal and external
experts with respect to the hydrocarbon reserve
assumptions used in the cash flow forecasts. This
included understanding the reserve estimation processes
carried out, and assessing the qualifications, competence
and objectivity of the Group’s experts, the scope and
appropriateness of their work.
• Analysed forecast cost assumptions against historical
performance and the latest approved budgets and
forecasts.
• Considered the Group’s market capitalisation.
• Considered the carrying value of producing assets against
recent comparable market transactions and the market
value of comparable companies, where available.
• Assessed the adequacy of the disclosures in Note 9 and
basis of preparation of the financial report
Impairment assessment of capitalised exploration and evaluation expenditure
Why significant
How our audit addressed the key audit matter
At 30 June 2021 the Group had exploration and evaluation
assets of $334.8 million.
For exploration and evaluation assets, in completing our
audit procedures, we:
The carrying value of exploration and evaluation assets is
subjective based on the Group’s ability and intention, to
continue to explore the assets. The carrying value may also
be impacted by the results of exploration work indicating
that the oil and gas resources may not be commercially
viable for extraction. The Group is required to assess
whether any indicators of impairment are present.
Key assumptions, judgements and estimates used in the
impairment indicator assessment can lead to significant
changes in respect to whether economic quantities of
hydrocarbons can be commercialised or whether further
exploration and evaluation work is underway or planned to
support the continued carry forward of capitalised costs.
The Group identified impairment indicators in respect of
certain exploration and evaluation assets. The impairment
testing of those assets resulted in an impairment charge of
$81.7 million being recorded during the year, as set out in
Note 10 of the financial report.
• Assessed whether any impairment indicators, as set out
in AASB 6 Exploration for and Evaluation of Mineral
Resources, were present, and assessed the conclusions
reached by management.
• Assessed the Group’s definition of area of interest in
accordance with Australian Accounting Standards.
• Considered the Group’s right to explore in the relevant
exploration area which included obtaining and assessing
supporting documentation such as license agreements
and correspondence with relevant government agencies.
• Considered the Groups intention to carry out significant
exploration and evaluation activities in relevant
exploration areas or plans to transfer the assets to
petroleum assets. This included the assessment of the
Group’s forecasts with comparison to approved budgets
and enquiries with senior exploration management and
directors as to the intentions and strategy of the Group.
A member firm of Ernst & Young Global Limited
Liability limited by a scheme approved under Professional Standards Legislation
126
Page 3
Why significant
How our audit addr essed t he key audit mat t er
As a result, we considered the impairment testing of the
Group’s exploration and evaluat ion asset s and the related
disclosures in the financial report to be a key audit matter
• Assessed the carrying value of explorat ion and evaluat ion
asset s where recent exploration activity, in a given
licensed area, provided negat ive indicators as to the
recoverability of amounts capitalised.
• Considered the commercial viability of results relat ing to
the exploration and evaluation activities carried out in the
relevant licensed areas.
• Assessed the Group’s ability t o finance any planned
future exploration and evaluation activity.
• Assessed the adequacy of the disclosures in Note 10 of
the financial report.
Provisionally priced oil revenue
Why significant
How our audit addr essed t he key audit mat t er
At 30 June 2021 the Group recorded $110.9 million of
provisionally priced oil revenue (30 June 2020: $89.1
million), which represent s a significant port ion (18%) of total
annual oil revenue (30 June 2020: 11%).
In accordance with cont ractual terms within the Crude Oil
sale and Purchase Agreement (‘COSPA’), risk and t itle of oil
produced in the Cooper Basin is t ransferred to the South
Aust ralian Cooper Basin Joint Venture (‘SACBJV’), when the
oil reaches the Moomba processing facility. The supply of oil
to the Moomba processing facility is the point the Group
satisfies the performance obligat ion to the SACBJV in
respect of the supply of oil Revenue is calculated using
forecast oil price est imates when title has passed with actual
invoices not raised until the oil has shipped from Port
Bonyt hon.
Given the complexity in calculating the volume of oil supplied
and judgement in the application of the estimated
transaction price, there can be significant variat ions in the
final revenue value recorded on invoicing. As such, this was
considered a key audit matter.
Disclosure regarding this matter can be found in Note 2 of
the Financial Report .
In completing our audit procedures, we:
• Assessed the point and recognition of revenue with
reference to executed contracts bet ween the parties and
the requirements of Australian Account ing Standards.
• Obtained directly from the SACBJV an independent
confirmation of barrels of oil received at the Moomba
processing facility, but not yet shipped via Port
Bonyt hon.
• For all provisionally priced revenue barrels sold, we
assessed the est imated sales price applied by the Group
to forward commodity price assumptions together with
estimates of quality premiums and exchange rates for the
period in which set tlement is likely to occur with
reference to contractual arrangement s and Brent oil price
futures.
• Selected shipment s which occurred close to the period
end and assessed whether revenue was recorded in the
correct period.
• Selected and examined evidence of subsequent cash
receipt.
Informat ion ot her t han t he financial report and audit or’s report t hereon
The directors are responsible for the other information. The other information comprises the
information included in the Company’s 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, with the exception of the Remuneration Report
and our related assurance opinion.
In connection wit h our audit of the financial report, our responsibility is to read the other information
and, in doing so, consider whether the other information is materially inconsistent with the financial
report or our knowledge obtained in the audit or otherwise appears to be materially misstated.
A member firm of Ernst & Young Global Limited
Liability limited by a scheme approved under Professional Standards Legislat ion
127
Beach Energy Limited Annual Report 2021 Independent Auditor’s Report
Page 4
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.
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.
A member firm of Ernst & Young Global Limited
Liability limited by a scheme approved under Professional Standards Legislation
128
Page 5
► 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.
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 pages 62 to 78 of the directors’ report for the
year ended 30 June 2021.
In our opinion, the Remuneration Report of Beach 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
Anthony Jones
Partner
Adelaide
16 August 2021
A member firm of Ernst & Young Global Limited
Liability limited by a scheme approved under Professional Standards Legislation
129
Beach Energy Limited Annual Report 2021
Glossary
A$ or $
1C
2C
3C
3D
1P
2P
3P
AASB
AGM
AOI
ASX
ATP
Alinta Energy
BassGas Project
bbl
Bcf
Beach
Beharra Springs
boe
Board
Bridgeport
CAGR
CCS
CGU
Company
Cooper Energy
Cooper Basin
CBJV (Cooper
Basin JV)
Australian dollars
Contingent resource low estimate(1)
Contingent resource best estimate(1)
Contingent resource high estimate(1)
Three dimensional
Proved reserve estimate(1)
Proved and probable reserve estimate(1)
Proved, probable and possible reserve
estimate(1)
Australian Accounting Standards Board
Annual General Meeting
Area of interest
Australian Securities Exchange
Authority To Prospect (QLD)
Alinta Energy Retail Sales Pty Ltd
The BassGas Project (Beach 53.75% and
operator, MEPAU 35%, Prize Petroleum
International 11.25%), produces gas from
the offshore Yolla gas field in the Bass Basin
in production licence T/L1. Beach also holds
a 50.25% operated interest in licenses
TR/L2, TR/L4 and TR/L5. On 31 July 2021
Beach completed its acquisition of MEPAU’s
35% participating interest in T/ L1 and
40% participating interest in TR/L2, TR/L4
and T/RL5, Beach will then hold a 88.75%
interest in the BassGas Project and 90.25%
interest in TR/L2, TR/L4 and TR/L5
Barrels
Billion cubic feet
Beach Energy Limited
Beach 50% and operator, MEPAU 50%.
Consists of the Beharra Springs, Redback
Terrace and Tarantula gas fields and the
Beharra Springs gas processing facilities
Barrels of oil equivalent – the volume of
hydrocarbons expressed in terms of the
volume of oil which would contain an
equivalent volume of energy
Board of Directors of Beach
Bridgeport (Cooper Basin) Pty Ltd
Compounded annual growth rate
Carbon Capture and Storage
Cash generating unit
Beach and its subsidiaries
Cooper Energy Ltd
Includes both Cooper and Eromanga Basins
The various joint venture interests owned by
Beach’s wholly owned subsidiaries Delhi and
Beach Energy (Operations) in the SACB JVs
and SWQ JVs
DBNGP
Delhi
DTA
EBITDA
EIP
EP
EPS
Ex PEL 91
Ex PEL 92
Ex PEL 104/111
Ex PEL 106
Ex PEL 513
Ex PEL 632
FEED
FID
Free cash flow
FY21
Genesis
Group
GSA
GJ
HBWS
H1 FY21
IFRS
JV
kbbl
kboe
kbopd
km
KMP
KPI
kt
Kupe
LNG
LPG
LTI
Dampier to Bunbury Natural Gas Pipeline
Delhi Petroleum Pty Ltd
Deferred tax assets
Earnings before interest, tax, depreciation
and amortisation
Executive Incentive Plan
Exploration Permit (NT)
Earnings per share
PRLs 151 to 172 and various production
licences
PRLs 85 to 104 and various production
licences
PRLs 136 to 150 and various production
licences
PRLs 129 and 130 and various production
licences
PRLs 191 and 206 and various production
licences
PRLs 131 to 134 and various production
licences
Front-End Engineering Design
Final Investment Decision
Operating cash flow less investing cash flow
(excluding acquisitions and divestitures)
Financial year 2021
Genesis Energy Limited and its subsidiaries
Beach and its subsidiaries
Gas sales agreement
Gigajoule
Halladale/Black Watch/Speculant fields
in the offshore Otway Basin in licenses
VIC/L1(v) and VIC/P42(v)
First half year period of FY21
International Financial Reporting Standards
Joint Venture
Thousand barrels of oil
Thousand barrels of oil equivalent
Thousand barrels of oil per day
Kilometre
Key management personnel
Key performance indicator
Thousand tonnes
Kupe Gas Project. Beach 50% and operator,
Genesis 46%, NZOG 4%. Consists of
offshore Kupe gas field in the Taranaki Basin,
the Kupe offshore platform, Kupe gas plant
and associated infrastructure
Liquefied natural gas
Liquefied petroleum gas
Long term incentive
(1) Complete definitions for Reserves and contingent resources are contained within “Petroleum Resources Management Systems (revised June 2018)” better known as PRMS 2018.
130
SGH
SPE
STI
Seven Group Holdings Limited
Society of Petroleum Engineers
Short Term Incentive
SWQ JVs
South West Queensland Joint Ventures
South West
Queensland Joint
Ventures
Includes the SWQ Gas Unit and exploration
and oil production licences – various equity
interests (Beach 30–52.2%)
Tcf
TFR
TJ
TRIFR
TSR
Trillion cubic feet
Total Fixed Remuneration
Terajoule
Total recordable injury frequency rate
Total shareholder return
Udacha Block
PRL 26
US$
Waitsia
United States $
Beach 50%, MEPAU 50% and operator.
The project consists of the Waitsia Gas
Project, an interest in the Xyris production
facility and other in-field pipelines
MEPAU
Mitsui
MMbbl
MMboe
MMscf
MMscfd
Net Gearing
NPAT
NZ
NZOG
O.G. Energy
OGP
OMV
Origin
Otway Sale
PACE
PCP
PEL
PEP
Perth Basin
PL
PPL
PJ
Prize
PRL
PRMS
PRRT
Q1 FY21
ROC
SACB JVs
Mitsui E&P Australia
Mitsui &Co., Ltd and its subsidiaries
Million barrels of oil
Million barrels of oil equivalent
Million standard cubic feet of gas
Million standard cubic feet of gas per day
The ratio of net debt/(cash) to the sum of
net debt/(cash) and total book equity
Net profit after tax
New Zealand
New Zealand Oil & Gas Limited and
its subsidiaries
O.G. Energy Holdings Limited, a member of
the Ofer Global group of companies
Otway Gas Project. Beach 60% and operator.
Consists of offshore gas fields Thylacine
and Geographe, the Thylacine Well Head
Platform, Otway Gas Plant and associated
infrastructure
OMV Group and its subsidiaries
Origin Energy Limited and its subsidiaries
Sale of 40% of Beach’s Victorian Otway
interests to O.G. Energy (for additional
information please refer to ASX
announcement REF: #047/18)
The South Australian Plan for Accelerating
Exploration gas grant scheme
Prior corresponding period
Petroleum Exploration Licence (SA)
Petroleum Exploration Permit
(Victoria and NZ)
Includes Beach’s assets Waitsia and
Beharra Springs
Petroleum Lease (QLD)
Petroleum Production Licence (SA)
Petajoule
Prize Petroleum Licence
Petroleum Retention Licence (SA)
Petroleum Resources Management System
Petroleum Resource Rent Tax
First quarter of FY21
Return on capital
South Australian Cooper Basin Joint Ventures
South Australian
Cooper Basin Joint
Ventures
The Fixed Factor Area (Beach 33.4%, Santos
66.6%) and the Patchawarra East Block
(Beach 27.68%, Santos 72.32%)
Santos
SAWA
Senex
Santos Limited and its subsidiaries
South Australia Western Australia reporting
segment
Senex Energy Limited
131
Beach Energy Limited Annual Report 2021 Schedule of Tenements
For the year ended 30 June 2021
Cooper/Eromanga – Queensland
Subsidiary Company Tenement
Subsidiary Company
Tenement
Maw 6.50%
Delhi 32%
Delhi 22.5%
BE(OP)L 25%
Delhi 20%
BE(OP)L 25%
Delhi 25.2%
BE(OP)L 27%
Delhi
Delhi
Delhi 28.8%
BE(OP)L 10%
Delhi
Delhi 23.2%
BE(OP)L 16.7375%
DLS
ATP 1189 ex ATP 259
(Naccowlah Block) (1)
ATP 1189 ex ATP 259
(Aquitaine A Block) (2)
ATP 1189 ex ATP 259
(Aquitaine B Block) (3)
ATP 1189 ex ATP 259
(Aquitaine C Block) (4)
ATP 1189 ex ATP 259
(Innamincka Block) (5)
ATP 1189 ex ATP 259
(Total 66 Block) (6)
ATP 1189 ex ATP 259
(Wareena Block) (7)
PL 55 (50/40/10)
SWQ Gas Unit (8)
ex ATP 299
(Tintaburra Block) (9)
Circumpacific
ATP 940
Cooper/Eromanga – South Australia
Subsidiary Company Tenement
Impress (CB)
PPL 203 (Acrasia Oil Field)
BPT
BPT
Impress (CB)
Impress (CB)
PPL 204 (Sellicks Oil Field)
PPL 205 (Christies Oil Field)
PPL 207 (Worrior Field)
PPL 208
(Derrilyn West Field) (10)
Impress (CB)
PPL 209 (Harpoono Field)
BPT
Impress (CB)
BPT 40%
DLS 30%
GAOG 30%
Impress (CB)
Impress (CB)
Impress (CB)
Impress (CB)
Impress (CB)
BPT
PPL 210 (Aldinga Oil Field)
PPL 211
(Reg Sprigg West Field) (18)
PPL 212
(Kiana Oil Field)
PPL 213 (Mirage Field)
PPL 214 (Ventura Field)
PPL 215 (Toparoa Field) (10)
PPL 217 (Arwon West Field)
PPL 218 (Arwon East Field)
PPL 220
(Callawonga Oil Field)
Impress (CB)
PPL 221 (Padulla Field)
132
%
38.5%
47.5%
45%
52.2%
30%
30%
38.8%
40%
39.9375%
BPT
BPT 50%
GAOG 50%
PPL 224 (Parsons Oil Field)
PPL 239
(Middleton/Brownlow Fields)
Impress (CB) 85%
Springfield 15%
PPL 240
(Snatcher Oil Field)
Impress (CB)
PPL 241 (Vintage Crop Field)
Impress (CB) 85%
Springfield 15%
PPL 242
(Growler Oil Field)
Impress (CB) 85%
Springfield 15%
PPL 243
(Mustang Oil Field)
BPT
BPT
BPT
BPT
BPT
BPT
PPL 245 (Butlers Oil Field)
PPL 246 (Germein Oil Field)
PPL 247 (Perlubie Oil Field)
PPL 248 (Rincon Oil Field)
PPL 249 (Elliston Oil Field)
PPL 250 (Windmill Oil Field)
Impress (CB)
PPL 251 (Burruna Field)
40%
100%
%
100%
75%
75%
70%
100%
100%
50%
100%
100%
100%
100%
100%
100%
100%
75%
100%
BPT 40%
GAOG 60%
BPT 40%
GAOG 60%
BPT 40%
GAOG 60%
BPT 40%
GAOG 60%
BPT 50%
GAOG 50%
PPL 253
(Bauer/Bauer-North/
Chiton/Arno Oil Fields)
PPL 254
(Congony/
Kalladeina Oil Fields)
PPL 255
(Hanson/Snelling Oil Fields)
PPL 256
(Sceale Oil Field)
PPL 257
(Canunda/Coolawang Fields)
Impress (CB) 85%
Springfield 15%
PPL 258
(Spitfire Oil Field)
BPT 40%
GAOG 60%
BPT 40%
GAOG 60%
BPT 40%
GAOG 60%
PPL 260
(Stunsail Oil Field)
PPL 261
(Pennington Oil Field)
PPL 262
(Balgowan Oil Field)
Impress (CB) 85%
Springfield 15%
PPL 263
(Martlett North Oil Field) (11)
Impress (CB) 85%
Springfield 15%
PPL 264
(Martlett Oil Field)
Impress (CB) 85%
Springfield 15%
PPL 265
(Marauder Oil Field)
Impress (CB) 85%
Springfield 15%
PPL 266
(Breguet Oil Field)
Impress (CB) 57%
Acer 43%
PPL 268
(Vanessa Gas Field)
%
75%
100%
100%
100%
100%
100%
75%
75%
75%
75%
75%
75%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
Subsidiary Company Tenement
%
Subsidiary Company Tenement
Impress (CB)
PPL 270 (Gemba Field)
Impress (CB) 85%
Springfield 15%
PRL 15 (Growler Block)
Impress (CB)
PRL 16 (Dunoon-2)
BPT 25%
DLS Gas 30%
GAOG 45%
BPT
Impress (CB)
Impress (CB)
PRL 26 (Udacha Unit)
PRLs 35, 37, 38, 41,
43-45, 48, 49
(ex PEL 218 Permian)
PRL 73
(ex PEL 90C)
PRLs 76 to 77
(ex PEL 102)
Impress (CB)
PRLs 78 to 84 (ex PEL 113)
BPT
Impress (CB)
Impress (CB)
Impress (CB)
BPT 50%
GAOG 50%
GAOG
PRLs 85 to 104
(ex PEL 92)
PRLs 105, 106, 116, 117
(ex PEL 115)
PRLs 108 to 110
(ex PEL 105)
PRLs 120 and 128
(ex PEL 514)
PRLs 129 and 130
(ex PEL 106)
PRLs 131 to 134
(ex PEL 632)
Impress (CB) 57%
Acer 43%
PRL 135
(Vanessa Gas Field) (12)
Impress (CB) 85%
Springfield 15%
PRLs 136 to 150
(ex PEL 104 and PEL 111) (13)
BPT 40%
GAOG 60%
Acer
BPT 40%
DLS 20%
GAOG 40%
Impress (CB)
DLS (513)
PRLs 151 to 172
(ex PEL 91)
PRLs 173 to 174
(ex PEL 101)
PRLs 175 to 179
(ex PEL 107)
PRLs 183 to 190
(ex PEL 110) (14)
PRLs 191 to 206
(ex PEL 513)
Impress (CB)
Impress (CB)
Impress (CB)
Impress (CB)
100%
100%
100%
100%
100%
PRLs 207 to 209
(ex PEL 100) (15)
PRLs 210 to 220
(ex PEL 637)
PRLs 221 to 230
(ex PEL 638)
PRLs 231 to 233 and 237
(ex PEL 93) (16)
Impress (CB) 57%
Acer 43%
PRLs 238 to 244
(ex PEL 182)
PRLs 245 to 246
(ex PEL 90k)
PEL 94 (17)
PEL 95
PEL 182
PEL 516
PEL 570
PEL 630
PEL 639
GSEL 634 (ex PEL 92)
GSEL 645
(ex Udacha Unit)
GSEL 646
(ex PEL 106)
GSEL 648
(ex PEL 91)
GSEL 653
(ex PEL 107)
100%
Impress (CB)
100%
100%
75%
BPT 50%
Impress (BCB) 15%
BPT
Impress (CB) 57%
Acer 43%
100%
Impress (CB)
Ambassador
BPT
Impress (CB)
BPT
BPT 25%
DLS Gas 30%
GAOG 45%
BPT 50%
GAOG 50%
BPT 40%
GAOG 60%
BPT 40%
DLS 20%
GAOG 40%
Delhi 12.86%
BE(OP)L 7.902%
Delhi 17.14%
BE(OP)L 10.536%
Delhi 20.21%
BE(OP)L 13.19%
Delhi 20.21%
BE(OP)L 13.19%
100%
100%
100%
40%
100%
100%
100%
100%
100%
80%
40%
%
55%
100%
100%
70%
100%
100%
65%
50%
100%
100%
47.5%
50%
100%
75%
100%
100%
100%
100%
Reg Sprigg West Unit
20.759%
Patchawarra East (19)
27.676%
Fixed Factor Agreement (20)
33.4%
SA Unit
33.4%
133
Beach Energy Limited Annual Report 2021 Schedule of Tenements
Otway – South Australia
Subsidiary Company
Tenement
ADE
ADE
ADE
ADE
ADE
ADE
ADE
ADE
ADE
ADE
PEL 494
GSEL 654
PPL 62 (Katnook)
PPL 168 (Redman)
PPL 202 (Haselgrove)
PRL 1 (Wynn)
PRL 2 (Limestone Ridge)
PRL 32 (ex PEL 255)
GSRL 27
PEL 680
Onshore Otway – Victoria
Subsidiary Company
Tenement
BPT
BPT
BPT
PPL 6 (McIntee Gas Field)
PPL 9 (Lavers Gas Field)
PEP 168
Nearshore Otway Victoria
Subsidiary Company
Tenement
BE(OP)L
BE(OP)L
BE(OP)L
Vic/L1(V)
Vic/P42(V)
Vic/P007192(V) (21) (24)
Offshore Otway – Victoria
Subsidiary Company
Tenement
BE(OP)L
BE(OP)L
BE(OP)L 55%
BE(Ot)L 5%
Vic/P43
Vic/P73
Vic/L23
Browse – Western Australia
Subsidiary Company
Tenement
BPT
WA-80-R
%
9.7637%
Bonaparte Basin – Western Australia
Subsidiary Company
Tenement
BE(OP)L
BE(B)PL
BE(O)PL
BE(B)PL
WA-454-P
WA-6-R
WA-545-P
WA-548-P
Otway (Offshore) – Tasmania
Subsidiary Company
Tenement
BE(OP)L
BE(OP)L 55%
BE(Ot)L 5%
BE(OP)L 55%
BE(Ot)L 5%
T/30P
T/L2
(Thylacine)
T/L3
(Thylacine South)
Bass Basin – Tasmania
Subsidiary Company
Tenement
BE(OP)L 72.5%
BE(BG)L 5%
BPT 11.25%
BE(OP)L 79%
BPT 11.25%
BE(OP)L 79%
BPT 11.25%
BE(OP)L 79%
BPT 11.25%
T/L1 (Yolla) (21) (22)
T/RL2 (21) (23)
T/RL4 (21) (23)
T/RL5 (21) (23)
%
50%
5.75%
10%
5.75%
%
100%
60%
60%
%
88.75%
90.25%
90.25%
90.25%
%
70%
70%
100%
100%
100%
100%
100%
70%
100%
70%
%
10%
10%
50%
%
60%
60%
60%
%
60%
60%
60%
134
Perth Basin – Western Australia
Subsidiary Company
Tenement
BE(PB)PL
BE(PB)PL
BE(PB)PL
EP 320
L11/L22
(Beharra Springs)
L1/L2
(Waitsia Excluding Dongara,
Mondarra and Yardarino)
Bonaparte – Northern Territory
Subsidiary Company
Tenement
BE(OP)L
BE(B)PL
BE(B)PL
NT/P82 (21)
NT/P88
NT/RL1
Taranaki Basin – New Zealand
Subsidiary Company
Tenement
BERNZKL
Kupe Mining No.1 Ltd
PML 38146
(Kupe)
%
50%
50%
50%
%
0%
5.75%
5.75%
%
50%
(1) The Naccowlah Block consists of ATP 1189 ex ATP 259 (Naccowlah) and PLs 23 – 26, 35,
36, 62, 76 – 78, 79 (PLA 1078 replacement), 82 (PL 1079 replacement), 87 (PLA 1080
replacement), 133 (PLA 1085 replacement), 149, 175, 181, 182, 287, 302, 495, 496, 1026.
PLAs 1047, 1060, 1078, 1079, 1085, 1093. Note sub-leases of PLs (gas) to SWQ Unit.
(2) The Aquitaine A Block consists of ATP 1189 ex ATP 259 (Aquitaine A) and PLs 86, 131,
146, 177, 254, 1051, PLA 1058. Note sub-leases of part PLs (gas) to SWQ Unit.
(3) The Aquitaine B Block consists of ATP 1189 ex ATP 259 (Aquitaine B) and PLs 59 60
(PLA 1072 replacement), 61 (PLA 1073 replacement), 81, 83 (PLA 1092 replacement),
85, 108, 111 (PLA 1090 replacement), 112, 132 (PLA 1091 replacement), 135, 139, 147
(PLA 1075 replacement), 151, 152, 155, 205 (PLA 1076 replacement), 288, 508, 509,
1013, 1014, 1035. PLA 1108. Note sub-leases of part of PLs (gas) to SWQ Unit.
(4) The Aquitaine C Block consists of ATP 1189 ex ATP 259 (Aquitaine C) and PLs 138
and 154.
(5) The Innamincka Block consists of ATP 1189 ex ATP 259 (Innamincka) and PLs 58, 80, 136,
137, 156, 159, 249, 1087. Note sub-leases of part PLs (gas) to SWQ Unit.
(6) The Total 66 Block consists of ATP 1189 ex ATP 259 (Total 66) and PLs 34, 37, 63, 68, 75,
84, 88, 110 (PL 497 replacement), 129, 130, 134, 140, 142, 143 (PLA replacement 1057),
144, 150, 186, 193 (PLA 513 replacement), 241, 255, 301, 497, 502, 1046, 1056 and 1077.
Note sub-leases of part of PLs (gas) to SWQ Unit.
(7) The Wareena Block consists of ATP 1189 ex ATP 259 (Wareena) and PLs 113, 141, 145, 148,
153, 158 (PLA 1105 replacement), 187, 1016, 1054, 1055 and 1107. Note sub-leases of part
of PLs (gas) to SWQ Unit.
(8) The SWQ Gas Unit consists of subleases of PLs within the gas production area of
Naccowlah Block, Aquitaine A Block, Aquitaine B Block, Innamincka Block, Wareena Block
and Total 66 Block.
(9) ex ATP 299 (Tintaburra) consists of PLs 29, 38, 39, 52, 57, 95, 169, 170, 293, 294, 295,
298, PLA 1027, PLA 1029.
(10) Derrilyn Unitisation Agreement for PPL 206, PPL 208 and PPL 215 – Impress (CB)
acquisition of 35% interest subject to regulatory approval.
(11) PPL 265 – Impress (CB) acquisition of 60% interest subject to regulatory approval.
(12) PRL 135 (Vanessa Gasfield) – Impress (CB) acquisition of 57% interest subject to
regulatory approval.
(13) PRLs 136 to 150 (ex PEL 104 and PEL 111) – Impress (CB) further acquisition of 60%
subject to regulatory approval.
(14) PRLs 183 to 190 (ex PEL 110) – Impress (CB) acquisition of 80% interest subject to
regulatory approval.
(15) PRLs 207 to 209 (ex PEL 100) – Impress (CB) acquisition of 55% subject to
regulatory approval.
(16) PRLs 231 to 233 and 237 (ex PEL 93) – Impress (CB) acquisition of 70% subject to
regulatory approval, and in relation to PRL 237 also subject to completion.
(17) PEL 94 – Impress (CB) acquisition of 15% subject to regulatory approval.
(18) Reg Sprigg West Unitisation Agreement for well consists of PPL 211 (Impress CB) and
PPL 94 (Patchawarra East).
(19) Patchawarra East consists of PPLs 26, 76, 77, 118, 121 – 123, 125, 131, 136, 147, 152, 156, 158,
167, 182, 187, 194, 201 and 229.
(20) The Fixed Factor Agreement consists of PPLs 6 – 20, 22 – 25, 27, 29 – 33, 35 – 48, 51 – 61,
63 – 70, 72 – 75, 78 – 81, 83, 84, 86 – 92, 94, 95, 98 – 111, 113 – 117, 119, 120, 124, 126 – 130,
132 – 135, 137 – 140, 143 – 146, 148 – 151, 153 – 155, 159 – 166, 172, 174 – 180, 189, 190, 193,
195, 196, 228 and 230 – 238.
(21) Transfer of interest subject to Government approvals.
(22) BE(OP)L acquired an additional 35.00% interest in T/L1 from MEPAU which completed
on 31 July 2021.
(23) BE(OP)L acquired an additional 40.00% interest in T/RL2, T/RL4, T/RL5 from MEPAU
which completed on 31 July 2021.
(24) BE(OP)L has transferred a 40.00% interest to OGOG with an effective date of
9 July 2020.
135
Beach Energy Limited Annual Report 2021 Schedule of Tenements
Subsidiary Companies
Acer
Ambassador
ADE
BPT
BE(Op)L
BE(B)PL
BE(Ot)L
BE(PB)PL
BERNZ(K)L
BE(BG)L
BE(O)PL
Circumpacific
Delhi
DLS (513)
DLS
DLS Gas
GAOG
Impress (CB)
Maw
Springfield
Acer Energy Pty Ltd
Ambassador Exploration Pty Ltd
Adelaide Energy Pty Ltd
Beach Energy Limited
Beach Energy (Operations) Limited
Beach Energy (Bonaparte) Pty Limited
Beach Energy (Otway) Limited
Beach Energy (Perth Basin) Pty Limited
Beach Energy Resources NZ (Kupe) Limited
Beach Energy (Bass Gas) Limited
Beach Energy (Offshore) Pty Ltd
Circumpacific Energy (Australia) Pty Ltd
Delhi Petroleum Pty Ltd
Drillsearch (513) Pty Ltd
Drillsearch Energy Ltd
Drillsearch Gas Pty Ltd
Great Artesian Oil & Gas Pty Ltd
Impress (Cooper Basin) Pty Ltd
Mawson Petroleum Pty Ltd
Springfield Oil and Gas Pty Ltd
Tenements Acquired
VIC/P007192(V), PEL 680, Impress (CB) tenements, WA-545-P, WA-548-P, NT/P88
Tenements Divested
PEP 57080, PEP 38264, PEP 52717, PEP 50119, PRL 13, NT/P84, NT/P85, WA-359-P, T/RL3, Wareena PLs
136
Shareholder information
Share details – Distribution as at 2 August 2021
Range
1 – 1000
1,001 – 5,000
5,001 – 10,000
10,001 – 100,000
100,001 Over
Rounding
Rounding Total
Unmarketable Parcels
Minimum $ 500.00 parcel at $ 1.2350 per unit
Total holders
Units
% Units
9,403
14,339
6,938
9,697
693
4,874,332
39,685,065
53,020,211
270,852,880
1,912,901,168
0.21
1.74
2.32
11.87
83.85
0.01
41,070 2,281,333,656
100.00
Minimum
Parcel Size
405
Holders
3,728
Units
709,868
Substantial shareholders as disclosed by notices received by Beach as at 2 August 2021
Name
Seven Group Holdings and others
Australian Capital Equity Pty Ltd, Wroxby Pty Ltd, North Aston Pty Ltd and others (ACE Group);
Ashblue Holdings Pty Ltd, Tiberius (Seven Investments) Pty Ltd, Tiberius Pty Ltd and others
(Tiberius Group); Mr Kerry Matthew Stokes AC and Kemast Investments Pty Ltd
Number of voting
shares held
Date of
Notice
684,774,056 30 April 2021
684,774,056 30 April 2021
Twenty largest shareholders as at 2 August 2021
Rank Name
Units
% Units
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
HSBC CUSTODY NOMINEES (AUSTRALIA) LIMITED
NETWORK INVESTMENT HOLDINGS PTY LTD
NETWORK INVESTMENT HOLDINGS PTY LTD
J P MORGAN NOMINEES AUSTRALIA PTY LIMITED
CITICORP NOMINEES PTY LIMITED
BNP PARIBAS NOMS PTY LTD
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