TIDMBHP
RNS Number : 1802P
BHP Group PLC
15 February 2021
Release IMMEDIATE
Time
Date 16 February 2021
Number 02/21
BHP RESULTS FOR THE HALF YEARED 31 DECEMBER 2020
Note: All guidance is subject to further potential impacts from
COVID-19 during the 2021 financial year.
Keeping our people and communities safe
-- There were no fatalities at our operated assets over the last
two years.
-- Our focus on safety, health and wellbeing has enabled us to
deliver strong safety and operational performance.
Maximise cash flow: Strong operational performance and free cash
flow generation, with a margin of 59%
-- Strong underlying operational performance, with record
production achieved at Western Australia Iron Ore (WAIO) and record
average concentrator throughput delivered at Escondida.
-- Profit from operations of US$9.8 billion, up 17%. Underlying
EBITDA(i) of US$14.7 billion at a margin(i) of 59%, with full year
unit cost guidance unchanged for our major assets (at guidance
exchange rates(ii) ).
-- Attributable profit of US$3.9 billion (includes an
exceptional loss of US$2.2 billion predominantly related to the
impairments of New South Wales Energy Coal (NSWEC) and associated
deferred tax assets, and Cerrejón). Underlying attributable
profit(i) of US$6.0 billion up 16% from the prior period.
-- Net operating cash flow of US$9.4 billion and free cash
flow(i) of US$5.2 billion reflects higher iron ore and copper
prices and strong operational performance.
Capital discipline: Spence Growth Option delivered on time and
budget, and our balance sheet remains strong
-- Capital and exploration expenditure(i) of US$3.6 billion.
Guidance for the 2021 financial year has increased by US$0.3
billion to US$7.3 billion due to a stronger Australian dollar.
Guidance for the 2022 financial year remains unchanged at
approximately US$8.5 billion (at guidance exchange rates).
-- Our four major projects under development are progressing
well, with first production achieved from the Spence Growth Option
(SGO) on time and budget in December 2020. South Flank is on track
to deliver first production by mid-calendar year 2021, and remains
on budget.
-- In petroleum, we completed the acquisition of an additional
28% interest in Shenzi, a tier one asset with optionality.
-- In exploration, we continue to add to our early stage
optionality in future facing commodities, with a signed agreement
for nickel exploration in Canada and an Option Agreement for the
Elliott Copper Project in Australia.
-- Our balance sheet is strong with net debt(i) of US$11.8
billion, following strong free cash flow generation throughout the
period.
Value and returns: Record half year dividend of US$1.01 per
share and ROCE up to 24%
-- The Board has determined to pay an interim dividend of
US$1.01 per share (or US$5.1 billion), equivalent to an
85% payout ratio on an underlying basis.
-- The divestment process for our interests in BHP Mitsui Coal
(BMC), NSWEC and Cerrejón is progressing, with extensive due
diligence being undertaken to assess both demerger and trade sale
opportunities.
-- Underlying return on capital employed(i) strengthened further
to 24%.
1
2020 2019 Change
Half year ended 31 December US$M US$M %
----------------------------------------------- ------ ------- --------
Profit from operations 9,750 8,314 17%
Attributable profit 3,876 4,868 (20%)
Basic earnings per share (cents) 76.6 96.3 (20%)
Interim dividend per share (cents) 101.0 65.0 55%
Net operating cash flow 9,369 7,442 26%
Capital and exploration expenditure 3,614 3,795 (5%)
Net debt 11,839 12,679 (7%)
Underlying EBITDA 14,680 12,084 21%
Underlying attributable profit 6,036 5,186 16%
Underlying basic earnings per share (cents)(i) 119.4 102.6 16%
Results for the half year ended 31 December 2020
BHP Chief Executive Officer, Mike Henry:
"BHP has delivered a strong set of results for the first half of
the 2021 financial year.
Our continued delivery of reliable operational performance
during the half supported record production at Western Australia
Iron Ore and record concentrator throughput at Escondida.
Our operations generated robust cash flows, return on capital
employed increased to 24 per cent and our balance sheet remains
strong with net debt at the bottom of our target range. The Board
has announced a record half year dividend of US$1.01 per share,
bringing BHP's shareholder returns to more than US$30 billion over
the past three years.
I am grateful to BHP employees and contractors for their
resilience and unwavering resolve in the face of the pandemic, and
for the continued support of the communities, suppliers, customers,
governments and traditional owners. Their efforts have made this
strong set of results possible.
We further grew value in the business during the half through
achieving first production at the Spence Growth Option and through
the acquisition of an additional interest in Shenzi. Our other
major projects in iron ore, petroleum and potash are progressing to
schedule.
Creating and securing more options in future facing commodities
remains a priority. In nickel and copper, we established further
new partnerships, acquired new tenements and progressed
exploration.
Our outlook for global economic growth and commodity demand
remains positive, with policymakers in key economies signalling a
durable commitment to growth and signalling ambitions to tackle
climate change. These factors, combined with population growth and
rising living standards, are expected to drive continuing growth in
demand for energy, metals and fertilisers.
Our leadership team is in place and accelerating our agenda to
be safer, lower cost and more productive. We are well positioned,
with a portfolio of essential products that will support a cleaner
and more prosperous world while generating sustainable returns for
our shareholders and value for our communities."
Social value underpins everything we do
Safety and sustainability
Our priority is the safety, health and wellbeing of our
workforce and the communities in which we operate and we have
continued to demonstrate this throughout the COVID-19 pandemic. We
have provided significant support to local businesses, and regional
and Indigenous communities in our areas of operation in response to
COVID-19 and we have established programs to support the public
health response.
2
Our operated assets have continued to operate safely. We remain
vigilant and will continue with social distancing and hygiene
practices, and other additional protocols as appropriate to protect
our workforce and communities from the spread of COVID-19, in line
with guidelines from local and national government bodies and
expert health advice in the countries where we operate. While many
of these measures remain in place, our Australian operations have
effectively managed the rapidly changing environment relating to
interstate travel and border restrictions. In Chile, the operating
environment is expected to remain challenging as COVID-19 cases in
the country have risen materially in recent months, with reductions
in our workforce forecast to remain substantial during the coming
months.
Despite the challenges, our people have maintained their
commitment to safety. Our global safety improvement programs are
progressing well and our safety leading indicators have continued a
strong positive trend underpinning the current safety performance.
We have now had over two years without a fatality at our operated
assets but retain a heightened awareness in the workplace to the
risks.
Support for local communities and wider sustainability
objectives remains a critical part of our social value
contribution. Our community and social investment commitment, which
began 20 years ago, is aligned with our broader business priorities
and supports projects and provides donations with the primary
purpose of contributing to the resilience of the communities and
environment where we have a presence. As part of this investment,
we also fund the BHP Foundation, which continues to work with
partner organisations globally to address some of the world's most
critical sustainable development challenges. These efforts are
designed to enhance the contribution that the global resources
sector can make to achieve many of the United Nations Sustainable
Development Goals, and they focus on the governance of natural
resources, environmental resilience and education equity. Further
information can be found at: bhp.com/foundation
Climate change
We have also continued to make good progress in addressing the
urgent global challenge of climate change.
We are committed to continuing to reduce emissions in our
operations and to our goal of achieving net zero operational
emissions by 2050. Many of our operations are already at the
lower-end of their respective emissions intensity curves reflecting
our efforts to date. We are on track to meet our current short-term
target to maintain 2022 financial year total operational emissions
at or below 2017 levels, with agreements for renewable electricity
use at Escondida and Spence commencing from 2022, as part of our
aim to achieve 100 per cent renewable supply at both operations by
the mid-2020s.
Our 2020 Climate Change Report, published on 10 September 2020,
provided an update on our actions; our new climate commitments; and
how we will integrate climate change into our corporate strategy
and portfolio decisions. This included:
-- setting a medium-term target to reduce our operational
greenhouse gas (GHG) emissions (Scope 1 and Scope 2) by at least 30
per cent from 2020 levels by 2030, establishing the trajectory to
achieve our 2050 goal of net-zero operational emissions;
-- actions to address Scope 3 emissions to contribute to decarbonisation in our value chain;
-- strengthening the link between executive remuneration and delivery of BHP's climate plan; and
-- providing insight into the performance of BHP's portfolio in
a transition to a 1.5degC scenario.
3
Acting on these commitments, in September 2020, BHP signed a
renewable power purchasing agreement (PPA) to meet half of its
electricity needs across its Queensland Coal mines from low
emissions sources, including solar and wind. The agreement will
help BHP reduce emissions from electricity use in its Queensland
operations by 50 per cent by 2025, based on 2020 levels. We also
executed a 15-year contract extension to our PPA at Nickel West
which provides the additional ability to integrate renewable
electricity generation, including solar and wind. Study phases for
renewable energy supply and carbon emissions reduction under the
extended PPA are under way and these projects have the potential to
reduce Nickel West's Scope 2 electricity GHG emissions by up to 15
per cent by 2023, based on 2020 levels.
To support decarbonisation of our industry, in September 2020,
we awarded the world's first LNG-fuelled bulk carrier tender, with
the aim of reducing GHG emissions by 30 per cent per voyage,
including virtually eliminating SO(x) (sulphur oxide) and NO(x)
(nitrogen oxide) emissions. Following this, we awarded the first
LNG bunkering agreement to Shell in December 2020.
In November 2020, we signed a memorandum of understanding (MOU)
with world leading steel producer, China Baowu, with the intention
to invest up to US$35 million and share technical knowledge to help
address the challenge of reducing greenhouse gas emissions in the
global steel industry. The five-year partnership will focus on the
development of low carbon technologies such as hydrogen injection
in the blast furnace, and pathways capable of emission intensity
reduction in integrated steelmaking. Under the MOU, the deployment
of carbon capture, utilisation and storage in the steel sector will
also be investigated at one of China Baowu's production
facilities.
In February 2021, we also signed a MOU with a large Japanese
steel producer, JFE, to jointly study technologies and pathways
capable of making material reductions to greenhouse gas emissions
from the integrated steelmaking process . The five-year partnership
will focus on the role of our raw materials to increase efficiency
and reduce emissions from the blast furnace and direct reduced iron
(DRI) steel making routes . We have agreed to invest up to US$15
million over the five-year partnership, which builds on the strong
history of technical research and collaboration between the two
companies.
Over the course of last year, we developed and published our
Global Climate Policy Standards, which are intended to provide
greater clarity on how our policy positions on climate change
should be reflected in our own advocacy and that of associations to
which we belong, and announced key changes to our approach to
industry associations. We will continue to advocate for action as
BHP and in industry associations which have the capacity to play a
key role in advancing the development of standards, best practices
and constructive policy.
4
Key indicators scorecard
H1 H2 H1
Target FY21 FY20 FY20 FY20 Comment
----------------------------- --------------------------------- ---- ----- ---- ----- --------------------------------
Fatalities Zero work-related fatalities 0 0 0 0 No fatalities at our operated
assets over the last 24 months.
High Potential Injury (HPI)
frequency(iii) (per million Year-on-year improvement in HPI
hours worked) frequency 0.20 0.14 0.32 0.24 17 per cent decrease from FY20.
TRIF(iii) Year-on-year improvement in TRIF 3.5 3.7 4.6 4.2 16 per cent reduction from FY20.
(per million hours worked)
Operational greenhouse gas Maintain FY22 operational GHG 8.1 7.9 7.9 15.8 On track to meet our FY22 and
emissions(iii) (Mt CO(2) -e) emissions at or below FY17 FY30 targets with the reductions
levels(1) and reduce emissions by in emissions from renewable
at least 30 per cent from FY20 power contracts at Escondida,
levels(2) by FY30 Spence, Queensland Coal and
Nickel West.
Value chain emissions(iii) Steelmaking: Goal to support - - - On track to deliver FY30 goal
industry to develop technologies with MOU with China Baowu signed
and pathways capable of 30 per in H1 FY21 and MOU with JFE
cent emissions intensity signed in H2 FY21.
reduction(3)
Transportation: Goal to support - - - On track to deliver FY30 goal
40 per cent emissions intensity with award of a LNG-fuelled bulk
reduction of BHP-chartered carrier tender and LNG bunkering
shipping of our products agreement in H1 FY21.
Reduce FY22 fresh water
Fresh water withdrawals(iii) withdrawal by 15 per cent from On track to meet our five-year
(GL) FY17 levels(4) 52.6 52.0 75.0 127.0 target.
Community and social No less than one per cent of 35.4 119.8 29.8 149.6 19 per cent increase on H1 FY20
investment pre--tax profit (three-year due to continued community
(US$M) rolling average) support for COVID-19 response
and
recovery in addition to planned
community and social investment.
Local procurement spend Support the growth of local 947 972 949 1,922 US$1.9 billion directed to local
(US$M) businesses in the regions where suppliers in each of the past
we operate two financial years.
Female workforce Aspirational goal for gender 27.4 26.5 24.8 26.5 Nine percentage point increase
participation(iii) (%) balance by CY25 from FY16, with 41 per cent
female external hires in H1
FY21.
Indigenous workforce Australia: aim to achieve 8.0 per 6.7 6.5 5.8 6.5 Assets continue to focus on
participation(iii) (%) cent by the end of FY25(5) Indigenous employment, supported
by 11.2 per cent representation
in Operations Services.
Chile: increase representation from the previous financial Continued increase throughout H1
year(6)(7) 6.7 6.6 6.3 6.6 FY21.
(1) In FY17, our operational GHG emissions were 14.6 Mt CO2-e
(excluding Onshore US). Greenhouse gas emissions are subject to
final sustainability assurance review.
(2) FY17 and FY20 baseline will be adjusted for any material
acquisitions and divestments based on GHG emissions at the time of
the transaction. Carbon offsets will be used as required. FY17
baseline is on a Continuing operations basis and has been adjusted
for divestments.
(3) With widespread adoption expected post-2030.
(4) In FY17, our fresh water withdrawals were 156.1 GL (on an
adjusted basis, excluding Onshore US).
(5) New medium term target established to achieve 8.0 per cent
Aboriginal and Torres Strait Islander representation in our
employee and contractor workforce by the end of FY25.
(6) Subject to verification of underlying data by the CONADI
(National Indigenous Development Corporation).
(7) Work is underway to establish medium term targets for
Indigenous workforce participation in Chile.
5
Samarco
BHP remains committed to supporting the Renova Foundation and
its work to progress the remediation and compensatory programs to
restore the environment and re-establish communities affected by
the Samarco tragedy. In total, Renova had spent R$11.3 billion
(approximately US$2.8 billion(iv) ) on remediation and compensation
programs by 31 December 2020.
Compensation and financial assistance of approximately R$3.1
billion (US$770 million(iv) ) has been paid to support
approximately 320,000 people affected by the Fundão dam failure up
until 31 December 2020. In addition, more than 5,000 claims have
been settled over the five months to January 2021 under the
court-mandated "Novel payment" system designed to ensure
compensation for claimants who had struggled to prove their damages
in the most informal sectors of the economy across 14 territories.
More than 10,000 general damages claims have been resolved, in
addition to approximately 270,000 claims for temporary interruption
to water supplies immediately following the dam failure. The Renova
Foundation has also been assisting more than 14,700 families with
financial support.
Resettlement of communities is a priority social program for the
Renova Foundation and involves ongoing engagement and consultation
with a large number of stakeholders. The timeline for resettlement
completion continues to be impacted by the implementation of
precautionary measures to minimise the spread of COVID-19.
Resettlement works in the municipality of Mariana are continuing
with a reduced number of people on site. At Bento Rodrigues, civil
works and the healthcare facility are now complete, while the
public school construction is almost complete and construction of
housing is progressing (with some houses complete). At Paracatu,
infrastructure works and the construction of some public buildings
and the first houses are underway. At Gesteira, the Renova
Foundation is progressing alternatives to urban resettlement, with
an option for individual resettlement in which families from the
original small community would be able to purchase individual
properties.
Since December 2019, riverbanks and floodplains have been
vegetated, river margins stabilised and, in general, water and
sediment qualities returned to historic conditions. Long-term
remediation work is continuing with landowners and regulators to
re-establish agricultural production. In addition, the Renova
Foundation has allocated R$1.5 billion (approximately US$290
million(iv) ) to forest restoration initiatives.
Progress continues to be made with the 12th Federal Court of
Belo Horizonte in Brazil which is seeking to expedite the
remediation process related to the Fundão dam failure. The R$155
billion (approximately US$30 billion(iv) ) Federal Public
Prosecution Office claim is suspended pending a decision from the
Court on a request by public defenders to resume the claim.
In December 2020, Samarco re-commenced iron ore pellet
production as part of a gradual restart of mining and processing
operations, after meeting the licensing requirements to restart
operations at the Germano complex in Minas Gerais and Ubu complex
in Espírito Santo, Brazil. Samarco's gradual restart of operations
incorporates one concentrator at the Germano complex and a
pelletising plant at Ubu, as well as a new system of tailings
disposal combining a confined pit and tailings filtering system for
dry stacking. Production capacity of approximately 8 Mtpa (100 per
cent basis) is expected once ramped up.
In the December 2020 half year, BHP reported an exceptional loss
of US$377 million (after tax) in relation to the Samarco dam
failure. This predominantly reflected an increase in cost estimates
for the Samarco dam failure provision, primarily as a result of
delays and cost estimate increases across resettlement programs,
including impacts due to COVID-19, and Samarco working capital
funding. Additional commentary is included on page 50.
6
Financial performance
Note: All guidance is subject to further potential impacts from
COVID-19 during the 2021 financial year
Earnings and margins
-- Attributable profit of US$3.9 billion includes an exceptional
loss of US$2.2 billion (31 December 2019: US$4.9 billion, which
includes an exceptional loss of US$318 million).
-- The exceptional loss of US$2.2 billion (after tax) relates to
an impairment charge in relation to our energy coal assets of
US$1.6 billion (NSWEC and associated tax losses of US$1.2 billion,
and Cerrejón of US$0.4 billion), COVID-19 related costs of US$0.2
billion and the current half year impact of the Samarco dam failure
of US$0.4 billion. The impairment charge for NSWEC and associated
tax losses reflects current market conditions for thermal coal, the
strengthening Australian dollar, changes to the mine plan and
updated assessment of the likelihood of recovering tax losses. The
impairment charge for Cerrejón reflects current market conditions
for thermal coal and the status of the Group's intended exit.
-- Underlying attributable profit of US$6.0 billion (31 December
2019: US$5.2 billion) reflects higher prices and strong operational
performance.
-- Profit from operations of US$9.8 billion (31 December 2019:
US$8.3 billion) increased as a result of higher iron ore and copper
prices, record production at WAIO and record average concentrator
throughput at Escondida, solid cost performance supported by cost
reduction initiatives across our assets and other net movements.
This was partially offset by the unfavourable impacts of a stronger
Australian dollar, planned maintenance, natural field decline at
petroleum, copper grade decline, adverse weather and inflation.
-- The total impact from COVID-19 on our operations was US$436
million (pre-tax) in the 31 December 2020 half year. This
represents the following impacts: lower volumes at our operated
assets of US$138 million and additional direct costs of US$298
million (exceptional item) incurred, such as increased social
distancing measures including additional charter flights,
accommodation, security and health and hygiene services (US$0.2
billion) combined with higher demurrage and other standby charges
related to delays caused by COVID-19 (US$0.1 billion).
-- Underlying EBITDA of US$14.7 billion (31 December 2019:
US$12.1 billion), with higher iron ore and copper prices, record
iron ore production volumes and concentrator throughput at
Escondida, disciplined cost performance, lower fuel and energy
costs and lower deferred stripping depletion at Escondida and other
net movements. This was partially offset by unfavourable impacts of
a stronger Australian dollar, planned maintenance, natural field
decline at petroleum, copper grade decline, adverse weather and
inflation.
-- Stronger Underlying EBITDA margin of 59 per cent (31 December 2019: 56 per cent).
-- Underlying return on capital employed strengthened to 23.6
per cent (31 December 2019: 19.1 per cent).
Costs
-- Full year unit cost guidance remains unchanged for our major
assets (based on exchange rates of AUD/USD 0.70 and USD/CLP
769).
-- Strong underlying performance across the portfolio, including
record production volumes at WAIO and record average concentrator
throughput at Escondida, offset by the impacts from planned
maintenance across a number of our assets, natural field decline in
Petroleum, overall grade decline at our copper assets and adverse
weather.
7
-- Unit costs(i) tracking well at Petroleum, Escondida and WAIO
(based on exchange rates of AUD/USD 0.70 and USD/CLP 769).
Petroleum and Escondida unit costs were below guidance and reflect
optimisation of maintenance activity at Petroleum, and strong cost
management, higher by-product credits, a gain from the optimised
outcome from renegotiation of cancelled power contracts and record
average concentrator throughput at Escondida. WAIO unit costs, on a
C1 basis excluding third party royalties, were lower than the prior
period at US$12.46 per tonne (31 December 2019: US$12.75 per tonne)
driven by record production volumes.
-- Queensland Coal unit costs (based on exchange rates of
AUD/USD 0.70) are tracking above full year guidance at the half
year, due to higher planned maintenance costs in the first half and
lower volumes as expected, further reduced following significant
wet weather impacts during the December 2020 quarter. A stronger
second half performance is expected at Queensland Coal with higher
volumes and less planned maintenance, subject to any potential
impacts on volumes from restrictions on coal imports into China and
further significant wet weather during the remainder of the 2021
financial year.
-- Costs related to the impact from COVID-19 are reported as an
exceptional item and are not included in unit costs for the 2021
half year. At our major assets these additional costs were: US$1.42
per tonne at Queensland Coal, US$0.56 per tonne at WAIO, US$0.25
per barrel of oil equivalent at Petroleum and US$0.02 per pound at
Escondida.
-- Historical costs and guidance are summarised below:
H1 FY21(2) at
guidance realised H1 FY21(2)(3)
Medium-term FY21 exchange exchange vs
guidance(1) guidance(1) rates(1) rates(3) H1 FY20 H1 FY20
---------------------------------- ------------ ------------ --------- --------- ------- -------------
Petroleum unit cost (US$/boe) <13 11 - 12 10.16 10.30 9.56 8%
Escondida unit cost (US$/lb) <1.10 1.00 - 1.25 0.86 0.90 1.10 (18%)
WAIO unit cost (US$/t)(4) <13 13 - 14 13.30 14.38 13.03 10%
Queensland Coal unit cost (US$/t) 58 - 66 69 - 75 78.82 84.92 70.66 20%
(1) FY21 and medium-term unit cost guidance are based on
exchange rates of AUD/USD 0.70 and USD/CLP 769.
(2) H1 FY21 unit costs excludes the impact from COVID-19 that
was reported as an exceptional item, refer page 18.
(3) Average exchange rates for H1 FY21 of AUD/USD 0.72 and
USD/CLP 771.
(4) WAIO unit costs exclude freight and royalties. C1 unit
costs, excluding third party royalties, are detailed on page
26.
-- Production and guidance are summarised below:
FY21 H1 FY21 vs
Production Medium-term guidance guidance H1 FY21 H1 FY20 H1 FY20
--------------------------- -------------------- ------------ ----------------------- ------- ------- ----------
Petroleum (MMboe) 106(1) 95 - 102 Upper half of range 50 57 (12%)
Copper (kt) 1,510 -1,645 841 885 (5%)
Escondida (kt) 1,200(2) 970 - 1,030 Narrowed range 572 602 (5%)
Other copper(3) (kt) 540 - 615 Unchanged 269 283 (5%)
Iron ore (Mt) 245 - 255 Samarco 1-2 Mt for FY21 128 121 6%
WAIO (100% basis) (Mt) 290(4) 276 - 286 Unchanged 145 137 5%
Metallurgical coal (Mt) 46 - 52 40 - 44 19 20 (5%)
Queensland Coal (100%
basis) (Mt) 71 - 77 Lower half of range 34 36 (5%)
Energy coal (Mt) 21 - 23 8 12 (30%)
NSWEC (Mt) 15 - 17 Lower half of range 7 7 (7%)
Cerrejón (Mt) 6 Lowered 1 4 (68%)
Nickel (kt) 85 - 95 Unchanged 46 35 31%
(1) Represents average over medium term, with 103 MMboe expected
in FY25.
(2) Represents annual average copper production over the medium
term.
(3) Other copper comprises Pampa Norte, Olympic Dam and
Antamina.
(4) WAIO's current licenced export capacity is 290 Mtpa.
8
-- Group copper equivalent production(v) was broadly flat in the
December 2020 half year, as record production at WAIO, record
average concentrator throughput at Escondida and strong underlying
operational performance across our assets offset the impacts of
planned maintenance, natural field decline, copper grade decline
and adverse weather.
-- WAIO, Queensland Coal and NSWEC production guidance for the
2021 financial year remains unchanged despite adverse weather
impacts during January and February 2021, with Queensland Coal and
NSWEC volumes expected to be at the lower half of the guidance
range.
Cash flow and balance sheet
-- Net operating cash flows of US$9.4 billion (31 December 2019:
US$7.4 billion) reflects strong iron ore and copper prices and a
strong operating performance during the period. This includes the
impact of higher prices on working capital as well as an inventory
build at WAIO, following strong mine performance combined with a
strategic build of pre-crushed stock to support South Flank ramp
up, and a planned build at Spence in the lead up to SGO
commissioning, contributing to a total unfavourable working capital
movement of US$1.6 billion.
-- Free cash flow of US$5.2 billion for the half year, after
capital and exploration expenditure of US$3.6 billion.
-- Our balance sheet remains strong with net debt at US$11.8
billion at 31 December 2020 (30 June 2020: US$12.0 billion; 31
December 2019: US$12.7 billion). The decrease of US$0.2 billion in
net debt in the half year (or US$0.9 billion from 31 December 2019)
reflects strong free cash flow generation by the operations and
includes an adverse foreign exchange impact on expenses and capital
expenditure. This more than offset US$0.9 billion of lease
additions (mainly related to SGO) and US$0.4 billion in premiums
paid on value accretive hybrid repurchase programs during the
period, as previously highlighted.
H1 FY20
H1 FY21 US$M
US$M Restated
------- ---------
Net debt at the beginning of the period 12,044 9,446
IFRS 16 transition - 1,778
Lease additions 909 179
Free cash flow (5,160) (3,710)
Dividends paid 2,767 3,934
Dividends paid to NCI 762 610
Other movements 517 442
Net debt at the end of the period 11,839 12,679
-- We remain committed to a strong balance sheet through the
commodity price cycle, and expect net debt to remain towards the
lower end of the target range of US$12 to US$17 billion in the near
term.
-- Gearing ratio(i) of 18.1 per cent (30 June 2020: 18.8 per
cent; 31 December 2019: 19.5 per cent).
Dividends
-- The dividend policy provides for a minimum 50 per cent payout
of underlying attributable profit at every reporting period. The
minimum dividend payment for the December 2020 half year period is
60 US cents per share or US$3.0 billion.
-- The Board has determined to pay an additional amount of 41 US
cents per share or US$2.1 billion, taking the interim dividend to
US$ 1.01 per share or US$5.1 billion. This is equivalent to an 85
per cent payout ratio (31 December 2019: 63 per cent) on an
underlying basis.
-- The dividend determined for the half year is approximately
equal to the free cash flow generated during the period.
9
-- We have consistently delivered high cash returns, with more
than US$30 billion of total announced returns (dividends and
buybacks) to shareholders over the last three years.
Capital and exploration
-- Capital and exploration expenditure of US$3.6 billion in the
December 2020 half year included maintenance expenditure(vi) of
US$1.1 billion and exploration of US$281 million.
-- Capital and exploration expenditure guidance for the 2021
financial year has increased from approximately US$7 billion to
US$7.3 billion due to a six per cent stronger Australian dollar.
Guidance for the 2022 financial year is unchanged at approximately
US$8.5 billion (based on exchange rates of AUD/USD 0.70 and USD/CLP
769), and at 31 December 2020 exchange rates, it would increase to
approximately US$8.8 billion.
-- This guidance includes a US$0.6 billion exploration program
being executed for the 2021 financial year and is approximately
US$50 million lower than previous guidance due to a change in
timing of activities. It reflects our US$450 million petroleum
exploration and appraisal program (additional details on page 22)
and our minerals exploration and appraisal program (additional
details on page 30).
-- Historical capital and exploration expenditure and guidance are summarised below:
FY21e H1 FY21 H1 FY20 FY20
US$M US$M US$M US$M
----- ------- ------- -----
Maintenance(1)(2) 2,400 1,085 1,016 1,853
Development
Minerals 3,200 1,801 2,069 4,243
Petroleum(2) 1,100 447 320 804
Capital expenditure (purchases of property, plant and equipment) 6,700 3,333 3,405 6,900
Add: exploration expenditure 600 281 390 740
Capital and exploration expenditure 7,300 3,614 3,795 7,640
(1) Includes capitalised deferred stripping of US$800 million
for FY21 and US$396 million for H1 FY21 (H1 FY20: US$472 million;
FY20: US$698 million).
(2) Petroleum capital expenditure for FY21 includes US$1.1
billion of development and US$0.1 billion of maintenance.
-- Average annual sustaining capital expenditure guidance over
the medium term, excluding costs associated with our automation
programs, is unchanged and forecast to be approximately:
- US$4 per tonne for WAIO, including the capital cost for South Flank; and
- US$9 per tonne for Queensland Coal.
Projects
-- Our latent capacity projects are tracking to plan:
- West Barracouta project is on schedule and budget, and is
expected to achieve first production in the 2021 calendar year;
and
- WAIO is expected to sustainably achieve supply chain capacity
of 290 Mtpa over the medium-term. For the 2020 calendar year, WAIO
achieved shipments of 290 Mt, following strong performance across
the supply chain, with significant improvements in car dumper
productivity and reliability.
-- The Spence Growth Option achieved first copper production in
December 2020, on schedule and budget, with first production of
molybdenum expected around the middle of the 2021 calendar year
following completion of the molybdenum plant.
-- At the end of the December 2020 half year, BHP had four major
projects under development in petroleum, iron ore and potash with a
combined budget of US$8.5 billion over the life of the
projects.
10
-- The Jansen Stage 1 potash project in Canada is expected to be
presented to the BHP Board for Final Investment Decision in the
middle of the 2021 calendar year.
-- On 15 January 2021, the Final Environmental Impact Study
(FEIS) was published for the Resolution Copper Mining (RCM)
project, which is a joint venture between Rio Tinto (55 per cent)
and BHP (45 per cent), managed by Rio Tinto. The FEIS and
subsequent Land Exchange are steps in an independent governmental,
social and environmental assessment and licencing process. Any mine
construction is expected to be several years away and will be
subject to additional regulatory and government approvals and
stakeholder consultation, including with the relevant Native
American tribes to seek consent.
-- Engineering work continues to progress at Scarborough, with
production licences awarded for WA-1-R (Scarborough) and WA-62-R
(North Scarborough) in November 2020. The project is expected to be
presented to the BHP Board for Final Investment Decision in the
second half of the 2021 calendar year, in line with the timing
currently indicated by Woodside (the operator).
-- The acquisition of an additional 28 per cent working interest
in Shenzi was completed on 6 November 2020. This transaction is
consistent with our strategy of targeting counter-cyclical
acquisitions in high-quality producing or near producing assets and
brings BHP's working interest to 72 per cent. This adds
approximately 11,000 barrels of oil equivalent per day of
production (90 per cent oil) as of the transaction closing date of
6 November 2020 and increases our medium term production guidance
to 106 MMboe.
-- Major projects are summarised below:
Capital Date of
Project and expenditure(1) initial
Commodity ownership Project scope / capacity(1) US$M production Progress / comments
--------- -------------------- -------------------------------------------------------------------------------------------------- -------------- ---------- ---------------------------------------------------------------------
Budget Target
Projects achieved first production during the December 2020 half year
Petroleum Atlantis Phase 3 New subsea production system that will tie back to the existing Atlantis facility, with capacity 696 CY20 First production achieved in July 2020, ahead of schedule and on
(US Gulf of Mexico) to produce up to 38,000 gross barrels of oil equivalent per day. budget.
44% (non-operator)
Copper Spence Growth Option New 95 ktpd concentrator is expected to increase Spence's payable copper in concentrate production 2,460 FY21 First production achieved in December 2020, on schedule and budget.
by approximately 185 ktpa in the first 10 years of operation and extend the mining operations
by more than 50 years.
(Chile)
100%
Projects in execution at 31 December 2020
Iron Ore South Flank Sustaining iron ore mine to replace production from the 80 Mtpa Yandi mine. 3,061 Mid-CY21 On schedule and budget. The overall project is 90% complete.
(Australia)
85%
Petroleum Ruby Five production wells tied back into existing operated processing facilities, with capacity 283 CY21 On schedule and budget. The overall project is 62% complete.
(Trinidad & Tobago) to produce up to 16,000 gross barrels of oil per day and 80 million gross standard cubic feet
68.46% (operator) of natural gas per day.
Petroleum Mad Dog Phase 2 New floating production facility with the capacity to produce up to 140,000 gross barrels 2,154 CY22 On schedule and budget. The overall project is 86% complete.
(US Gulf of Mexico) of crude oil per day.
23.9% (non-operator)
Other projects in progress at 31 December 2020
Potash(2) Jansen Potash Investment to finish the excavation and lining of the production and service shafts, and to 2,972 The project is 89% complete.
continue the installation of essential surface infrastructure and utilities.
(Canada)
100%
11
(1) Unless noted otherwise, references to capacity are on a 100
per cent basis, references to capital expenditure from subsidiaries
are reported on a 100 per cent basis and references to capital
expenditure from joint operations reflect BHP's share.
(2) Potash capital expenditure of approximately US$260 million
is expected for FY21.
-- Good progress is being achieved on the implementation of
autonomous trucks across our Australian iron ore and coal mine
sites.
- At the Newman East (Eastern Ridge) iron ore mine, all 22
autonomous trucks have been fully deployed since November 2020.
- At the Goonyella Riverside mine in Queensland, the first coal
site to implement autonomous haul trucks, the deployment of 86
autonomous trucks continues in line with the plan and is expected
to be completed early in the 2022 calendar year, on schedule and
budget.
- At the Daunia coal mine in Central Queensland, the second coal
operation to implement autonomous haul trucks, the first trucks
began operating in January 2021. The rollout is expected to be
completed early in the 2022 calendar year, on schedule and
budget.
Operations Services and apprenticeships
In Australia, we have created 3,600 permanent jobs, with
Operations Services now deployed across 20 locations in WAIO,
Queensland Coal and NSWEC, and successfully accelerated safety and
productivity improvements through the operation of a total fleet
size of 26 loading units and 156 trucks. Operations Services has
maintained strong diversity with 33 per cent female representation
and 11 per cent Indigenous representation. In addition, over half
of the workforce reside in the regional and rural areas in which we
operate.
On 1 October 2020, we announced our commitment to the training
and funding for 3,500 new Australian apprenticeship and training
positions over the next five years. An increase of 2,500
apprenticeship and traineeships through the BHP FutureFit Academy
and a further 1,000 skills development opportunities across a range
of sectors in regional areas. The BHP FutureFit Academy, launched
in May 2020, currently has 438 apprentices and maintenance
associates enrolled across the two locations at Mackay in
Queensland and Perth in Western Australia. Graduates of the
FutureFit Academy will be deployed to an Operations Services team
from the 2021 calendar year.
Capital Allocation Framework
Adherence to our Capital Allocation Framework aims to balance
value creation, cash returns to shareholders and balance sheet
strength in a transparent and consistent manner.
H1 FY21 H1 FY20 FY20
US$B US$B US$B
------- ------- -----
Net operating cash flow 9.4 7.4 15.7
Our priorities for capital
Maintenance capital 1.1 1.0 1.9
Strong balance sheet
Minimum 50% payout ratio dividend 1.9 2.7 5.0
Excess cash (1) 5.4 3.0 7.7
Balance sheet 1.5 (1.0) 0.1
Additional dividends 0.9 1.2 1.9
Buy-back - - -
Organic development 2.5 2.8 5.7
Acquisitions 0.5 - -
(1) Includes total net cash outflow of US$1.0 billion (H1 FY20:
US$0.7 billion) which comprises dividends paid to non-controlling
interests of US$0.8 billion (H1 FY20: US$0.6 billion); net
investment and funding of equity accounted investments of US$0.4
billion (H1 FY20: US$0.3 billion) and an adjustment for exploration
expenses of US$(0.2) billion (H1 FY20: US$(0.2) billion) which is
classified as organic development in accordance with the Capital
Allocation Framework.
12
Outlook
Economic outlook
The outlook for the short term remains uncertain, but with
vaccine deployment underway, albeit with some uncertainty as to
timing and efficacy, a major downside risk to the plausible range
has been substantially mitigated. Additionally, the scale of
stimulus that has been applied in key economies should provide
solid support for recovery.
We now estimate that the world economy will be 4 1/2 per cent
smaller in the 2021 calendar year than it would have been if
COVID-19 had not occurred: 1 1/2 per cent stronger than our view of
six months ago. The difference reflects the speed of the rebound in
ex-China markets in the second half of the 2020 calendar year, led
by India and the US, plus additional stimulus measures in developed
countries. The Chinese economy has met our above-consensus
expectations.
Inflation trends and exchange rates have been volatile. Looking
ahead, we expect that many commodity-linked uncontrollable costs
will remain lower in absolute terms than anticipated pre-COVID for
some years, even though change period-on-period may be quite
variable. To illustrate this, a number of uncontrollable cost
drivers across our worldwide minerals business such as diesel,
explosives, acid, rubber and steel-linked products have been
increasing in price as the most recent half has gone on, in most
cases in line with movements in underlying commodity prices. While
this recovery has not always been strong enough, or early enough,
to produce an uplift on average half-on-half, point-to-point over
the half (end of June to end of December) some material increases
have been registered.
We remain positive in our outlook for long-term global economic
growth and commodity demand. The 2020s hold great promise in this
regard, with policymakers in key economies (for example China,
Japan and the US) signalling a durable commitment to pro-growth
agendas alongside heightened ambitions to tackle climate change.
Population growth, the infrastructure of decarbonisation and rising
living standards are expected to drive demand for energy, metals
and fertilisers for decades to come.
Commodities outlook
As in the macroeconomic sphere, the deployment of vaccines in
key economies, albeit with some uncertainty as to timing and
efficacy, removes a material amount of downside risk to the short
term demand and price outlook for our portfolio commodities. With
Chinese demand looking robust and the rest of the world (ROW) on an
improving trajectory, a precondition for maintaining robust price
performance is in place. Where the price recovery is more nascent,
there is potential for a further uplift.
Global crude steel production was unbalanced in the 2020
calendar year, with strong growth in China offset by a steep fall
in ROW. We note the momentum in ROW has been picking up markedly,
with average utilisation rates now close to pre-COVID levels, while
margins are benefiting from higher prices. In the 2021 calendar
year, we anticipate a continuation of strong end-use demand
conditions in China and ongoing recovery in the rest of world. Over
the long-term, we anticipate that global steel production will
expand at a similar rate to population growth in coming decades,
with a plateau and then slow decline in China offset by growth in
the developing world, led by India. Growth in pig iron is expected
to trail the growth in steel, principally reflecting the higher
long-term proportion of steel sourced from scrap. Efforts to
decarbonise steel making are expected to proceed at different rates
in different regions, based on availability of lower carbon raw
feedstock (including but not exclusively scrap), the age of
existing facilities, variable levels of policy support, net trade
positions and differential demands for affordable steel.
13
Iron ore prices have been elevated since the Brumadinho tailings
dam tragedy in Brazil first disrupted the market in early 2019.
Conditions were particularly tight in the second half of the 2020
calendar year. The combined impact of very strong Chinese pig iron
production and Brazilian exports being unable to lift materially
from depressed levels in the 2019 calendar year outweighed record
shipments from Australia. Our analysis indicates that before prices
can correct meaningfully from their current high levels, one or
both of the Chinese demand/Brazilian supply factors will need to
change materially. In the second half of the 2020s, China's demand
for iron ore is expected to be lower than today as crude steel
production plateaus and the scrap-to-steel ratio rises. In the
long-term, prices are expected to be determined by high cost
production, on a value-in-use adjusted basis, from Australia or
Brazil. Quality differentiation is expected to remain a factor in
determining iron ore prices.
Metallurgical coal prices faced by Australian producers in the
free-on-board (FOB) market have been weak. A steep, COVID-19
induced decline in ROW demand, which normally comprises around
four-fifths of the seaborne trade, was the major factor driving
lower prices for much of the 2020 calendar year, with China serving
as the effective clearing market. However, late in the 2020
calendar year, these positions reversed, with ROW demand beginning
to improve, while uncertainty about China's import policy towards
Australian coals spiked. Trade flows are adjusting to account for
the available opportunities. The industry faces a difficult and
uncertain period ahead. Long term, w e believe that a wholesale
shift away from blast furnace steel making, which depends on
metallurgical coal, is still decades in the future. That assessment
is based on our bottom-up analysis of likely regional steel
decarbonisation pathways, as discussed above. Demand for seaborne
Hard Coking Coals (HCC) is expected to grow alongside the growth of
the steel industry in HCC importing countries such as India. There
is a developing mismatch between the expected evolution of customer
demand and the cost-competitive growth options available to
producers, which are skewed towards lower quality coals. As a
result, we view the medium to long-term fundamentals for higher
quality metallurgical coals as attractive.
Energy coal prices recovered from their COVID-19 induced lows
late in the 2020 calendar year, assisted by a pick-up in demand due
to cold weather in North Asia and a bounce in Indian industrial
activity. China's policy in respect of energy coal imports remains
a key uncertainty.
Copper prices have been strong in recent times. With ROW demand
recovering and China continuing to perform well, the short term
outlook for demand is constructive. On the supply side, we note
near term risks from the escalation of COVID-19 cases in Chile, and
the fact that a number of wage negotiations at Chilean mines are
scheduled for the current calendar year, spread across both halves.
Longer term, end-use demand is expected to be solid, while broad
exposure to the electrification mega-trend offers attractive
upside. Long term prices are expected to also reflect grade
decline, resource depletion, water constraints, the increased depth
and complexity of known development options and a scarcity of high
quality future development opportunities after a poor decade for
industry-wide exploration in the 2010s.
Nickel prices have been driven by positive sentiment towards
pro-growth assets, supply uncertainty and a strong rebound from the
battery-electric vehicle (EV) complex in the second half of the
2020 calendar year. Longer term, we believe that nickel will be a
substantial beneficiary of the global electrification mega-trend
and that nickel sulphides will be particularly attractive given the
relatively lower cost of production of battery-suitable class-1
nickel than for laterites, which are expected to set the long-run
nickel price. This view is supported by our assessment of the
likely rate of growth in EVs and of the likely battery chemistry
that will underpin this. We have revised our already aggressive
long run EV ranges to reflect even more supportive policy, such as
accelerated bans for internal combustion engine vehicles in Europe,
the policy platform of the Biden administration and net zero
objectives in China, Japan and South Korea.
14
Crude oil prices have recovered to around US$60 per barrel
range. Our base case is that prices should build upon their recent
recovery, but the pace of gains is likely going to be modest
initially given potential headwinds from currently curtailed supply
returning. However, if we look beyond this phase, our bottom-up
analysis of demand, allied to systematic field decline rates,
points to a long run structural demand-supply gap. Considerable
investment in conventional oil is going to be required to fill that
gap. The medium to long term supply deficit has been amplified by
the global retreat from capital spending across the industry in
response to the pandemic. Deepwater assets are the most likely
major supply segment to balance the market in the longer term. The
price expectation required to trigger investment in deepwater
projects is expected to be significantly higher than the prices we
face today.
The Japan-Korea Marker price for LNG has been extraordinarily
volatile. Spot prices hit record lows as COVID-19 demand
destruction hit a market already facing excess supply and large
storage builds in the first half of the 2020 calendar year. The
market then reversed course sharply during the northern winter,
printing record high prices. The winter price squeeze came about
due to disrupted supply, strong power and heating demand in North
Asia, shipping congestion preventing US supply moving promptly into
the Pacific as well as high freight rates. Longer term, the
commodity offers a combination of systematic base decline and an
attractive demand trajectory. Within global gas, LNG is expected to
gain share. Against this backdrop, LNG assets advantaged by their
proximity to existing infrastructure or customers, or both, are
expected to be attractive.
Potash stands to benefit from the intersection of a number of
global megatrends: rising population, changing diets and the need
for the sustainable intensification of agriculture. We anticipate
trend demand growth of 1.5 to 2.0 Mt per year (between two and
three per cent per annum) through the 2020s. This would
progressively absorb the excess capacity currently present in the
industry, with opportunity for new supply expected by the late
2020s or early 2030s. More immediately, we estimate that producer
sales hit a record 79 Mt annualised in the June quarter of 2020,
halting the downtrend in price of the prior twelve months that was
exacerbated by the pandemic. Robust demand has carried over into
subsequent quarters. Buoyant crop prices are lifting farm incomes
and market sentiment. Import prices in the US (New Orleans) have
moved above US$300 per tonne.
Further information on BHP's economic and commodity outlook can
be found at: bhp.com/prospects
Portfolio
The commodities we produce are essential for global economic
growth and the world's ability to transition to and thrive in a low
carbon future. Our existing portfolio is built upon an industry
leading set of large, low cost, expandable resource bases. We have
exposure to large, growing commodity markets, which enable low cost
assets to generate attractive returns through the cycle.
However, the world is rapidly changing with decarbonisation of
energy sources, population growth and the drive for higher living
standards in the developing world being key drivers today and in
the future. Our diversified portfolio is resilient under different
long-term scenarios but we are further strengthening it for the
near, medium and long term. In this changing world, to ensure that
we mitigate the risks and take advantage of the many opportunities
to grow value, we continuously manage our portfolio for value and
risk, taking into account the latest science and our scenario
analysis.
Even against the backdrop of the decarbonisation of the global
economy, we believe that metallurgical coal will remain an
essential input into the steel-making process for a long time yet.
That assessment is based on our bottom-up analysis of likely
regional steel decarbonisation pathways, as discussed earlier in
the Outlook section. We anticipate that markets will evolve to
place an even higher relative value on higher quality hard coking
coals that increase blast furnace productivity and reduce emissions
intensity of steel production. Consistent with this view, in order
to focus our coal portfolio on higher quality hard coking coals, we
are pursuing options to divest our interests in BMC, NSWEC and
Cerrejón. The process is progressing and extensive due diligence is
being undertaken to assess both demerger and trade sale
opportunities. We remain open to all options and continue
consultation with stakeholders including our joint venture
partners.
15
We continue to optimise our petroleum portfolio through our
exploration and appraisal program; progressing high return growth
projects; exiting later life assets, including progressing an exit
from Bass Strait, and farming-down longer dated options; and
potential targeted counter-cyclical acquisitions in producing or
near producing high quality assets. Consistent with this strategy,
we acquired an additional 28 per cent working interest in Shenzi
during the period, bringing our working interest to 72 per cent.
The acquisition was made at an attractive price, and Shenzi is a
tier one asset with optionality and key to BHP's Gulf of Mexico
heartland. An additional Shenzi infill well has been sanctioned for
execution in second half of 2021 financial year, realising further
value from the successful acquisition. This infill opportunity
represents a low-risk, high-value investment, with the well
location enhanced through Ocean Bottom Node (OBN) seismic completed
in 2019 and covering the Shenzi field.
Creating and securing more options in future-facing commodities
remains a priority. We intend to increase our options in these
through a focus on technical innovation, to help unlock further
options within our existing resources, as well as through
exploration, early stage entry and potentially value-enhancing
acquisitions tested against our strict Capital Allocation
Framework. We have made further good progress during the half year.
In copper, we executed an Option Agreement with Encounter Resources
covering the 4,500 km(2) prospective Elliott Copper Project in the
Northern Territory. The Oak Dam copper discovery has moved from
Exploration to the Planning and Technical team for assessment and
next stage resource definition drilling. In nickel, we completed
the acquisition of the Honeymoon Well tenements and signed an
agreement with Midland Exploration to undertake an exploration
alliance in north-eastern Quebec. In potash, we have progressed the
Jansen project, further de-risking the option, as we focus on
getting it ready to present to the Board for a Final Investment
Decision in the middle of the 2021 calendar year.
Through the combination of continuing to drive exceptional
operational performance, creating and securing more options in
future facing commodities and applying our disciplined approach to
capital allocation, we will continue to reliably grow value and
returns for decades to come.
Income statement
Underlying attributable profit and Underlying EBITDA are
presented below.
Underlying attributable profit
2020 2019
Half year ended 31 December US$M US$M
------------------------------------------------------------ ----- -----
Profit after taxation attributable to BHP shareholders 3,876 4,868
Total exceptional items attributable to BHP shareholders(1) 2,160 318
Underlying attributable profit 6,036 5,186
Weighted basic average number of shares (million) 5,057 5,057
Underlying basic earnings per ordinary share 119.4 102.6
(1) Refer to page 18 and to note 3 Exceptional items and note 10
Significant events - Samarco dam failure of the Financial Report
for further information.
Underlying EBITDA
2020 2019
Half year ended 31 December US$M US$M
-------------------------------------------------------- ------ ------
Profit from operations 9,750 8,314
Exceptional items included in profit from operations(1) 1,542 727
Underlying EBIT 11,292 9,041
Depreciation and amortisation expense 3,245 3,014
Net impairments 690 29
Exceptional item included in Depreciation, amortisation
and impairments(2) (547) -
Underlying EBITDA 14,680 12,084
(1) Exceptional items loss of US$1,542 million excludes net
finance costs of US$41 million related to the Samarco dam failure.
Refer to page 18 and to note 3 Exceptional items and note 10
Significant events - Samarco dam failure of the Financial Report
for further information.
(2) Relates to impairment charges in relation to NSWEC and
Cerrejón. Refer to page 18 and to note 3 Exceptional items.
16
Underlying EBITDA
The following table and commentary describe the impact of the
principal factors(i) that affected Underlying EBITDA for the
December 2020 half year compared with the December 2019 half
year:
US$M
Half year ended 31 December 2019 12,084
---------------------------------------- ------
Net price impact:
Change in sales prices 3,105 Higher average realised prices for iron ore and copper, partially
offset by lower average
realised prices for metallurgical and thermal coal, petroleum and
nickel.
Price-linked costs (230) Increased royalties reflect higher realised prices for iron ore
offset by decreased royalties
for metallurgical and thermal coal, and petroleum products.
2,875
Change in volumes 241 Record production at WAIO with strong performance across the supply
chain, record average
concentrator throughput at Escondida and increased volumes at Nickel
West following resource
transition and completion of major four yearly planned maintenance
shutdowns in the prior
period. This was partially offset by lower copper concentrator feed
grade at Escondida, planned
maintenance at Spence and lower volumes at Queensland Coal due to
significant wet weather
and planned maintenance at Saraji and Caval Ridge.
Lower petroleum volumes of US$(187) million largely due to lower gas
demand at Bass Strait
and North West Shelf, impacts from significant hurricane activities
in the Gulf of Mexico,
unfavourable weather impacts at North West Shelf, and natural field
decline across the portfolio.
This was partially offset by planned maintenance in the prior
period.
Change in controllable cash costs:
Operating cash costs 86 Solid cost performance supported by cost reduction initiatives
across our assets, lower net
maintenance spend and a gain from the optimised outcome from
renegotiation of cancelled power
contracts at Escondida and Spence. This was partially offset by a
drawdown in inventories
aligned with strong smelter run time at Olympic Dam and increased
volumes at Nickel West following
planned maintenance shutdowns in the prior period.
Exploration and business development (11) Higher exploration expenses due to expensing the Broadside-1
exploration well and seismic
costs in the Gulf of Mexico and Trinidad and Tobago.
75
Change in other costs:
Exchange rates (711) Impact of the stronger Australian dollar, partially offset by the
weakening Chilean peso,
against the US dollar.
Inflation (115) Impact of inflation on the Group's cost base.
Fuel and energy 182 Predominantly lower diesel prices at our minerals assets.
Non-Cash 142 Lower deferred stripping depletion at Escondida in line with planned
development phase of
the mines.
One-off items (138) Copper cathodes volume loss at Escondida due to reduced operational
workforce as a result
of COVID-19.
(640)
Asset sales -
Ceased and sold operations (13) Predominantly related to the sale of the Minerva Gas Plant in the
prior period.
Other items 58 Other includes higher average realised sales prices received by
Antamina, partially offset
by higher demurrage costs related to China's coal import
restrictions.
Half year ended 31 December 2020 14,680
17
Prices and exchange rates
The average realised prices achieved for our major commodities
are summarised in the following table:
H1 FY21 H1 FY21 H1 FY21
vs vs vs
Average realised prices(1) H1 FY21 H1 FY20 H2 FY20 FY20 H1 FY20 H2 FY20 FY20
------------------------------------- ------- ------- ------- ------ -------- -------- -------
Oil (crude and condensate) (US$/bbl) 41.40 60.64 37.51 49.53 (32%) 10% (16%)
Natural gas (US$/Mscf)(2) 3.83 4.26 3.76 4.04 (10%) 2% (5%)
LNG (US$/Mscf) 4.45 7.62 6.87 7.26 (42%) (35%) (39%)
Copper (US$/lb) 3.32 2.60 2.39 2.50 28% 39% 33%
Iron ore (US$/wmt, FOB) 103.78 78.30 76.67 77.36 33% 35% 34%
Metallurgical coal (US$/t) 97.61 140.94 121.25 130.97 (31%) (19%) (25%)
Hard coking coal (HCC) (US$/t)(3) 106.30 154.01 133.51 143.65 (31%) (20%) (26%)
Weak coking coal (WCC) (US$/t)(3) 73.17 101.06 84.43 92.59 (28%) (13%) (21%)
Thermal coal (US$/t)(4) 44.35 58.55 55.91 57.10 (24%) (21%) (22%)
Nickel metal (US$/t) 15,140 15,715 12,459 13,860 (4%) 22% 9%
(1) Based on provisional, unaudited estimates. Prices exclude
sales from equity accounted investments, third party product and
internal sales, and represent the weighted average of various sales
terms (for example: FOB, CIF and CFR), unless otherwise noted.
Includes the impact of provisional pricing and finalisation
adjustments.
(2) Includes internal sales.
(3) Hard coking coal (HCC) refers generally to those
metallurgical coals with a Coke Strength after Reaction (CSR) of 35
and above, which includes coals across the spectrum from Premium
Coking to Semi Hard Coking coals, while weak coking coal (WCC)
refers generally to those metallurgical coals with a CSR below
35.
(4) Export sales only; excludes Cerrejón. Includes thermal coal
sales from metallurgical coal mines.
In Copper, the provisional pricing and finalisation adjustments
increased Underlying EBITDA by US$323 million in the December 2020
half year and are included in the average realised copper price in
the above table.
The following exchange rates relative to the US dollar have been
applied in the financial information:
Average Average
Half year ended Half year ended As at As at As at
31 December 31 December 31 December 31 December 30 June
2020 2019 2020 2019 2020
----------------- ----------------- ------------- ------------- ---------
Australian dollar(1) 0.72 0.68 0.77 0.70 0.68
Chilean peso 771 729 711 749 816
(1) Displayed as US$ to A$1 based on common convention.
Depreciation, amortisation and impairments
Depreciation, amortisation and impairments excluding exceptional
items increased by US$345 million to US$3.4 billion, reflecting
higher depreciation and amortisation at Petroleum following a
decrease in estimated remaining reserves at Bass Strait due to
underperformance of the reservoir in the Turrum field and lower
overall condensate and natural gas liquids (NGL) recovery from the
Bass Strait gas fields and higher depreciation at WAIO due to a
decrease in Yandi's life of mine.
Net finance costs
Net finance costs increased by US$400 million to US$924 million
due to premiums of US$395 million paid as part of the value
accretive multi-currency hybrid repurchase programs completed
during the period.
18
Taxation expense
2020 2019
Profit before Profit before
Half year ended 31 taxation Income tax expense taxation Income tax expense
December US$M US$M % US$M US$M %
-------------------- ------------------- ------------------- ---- ------------------- ------------------- ----
Statutory effective
tax rate 8,826 (3,998) 45.3 7,790 (2,600) 33.4
Adjusted for:
Exchange rate
movements - (135) - 5
Exceptional items(1) 1,583 587 784 (271)
Adjusted effective
tax rate 10,409 (3,546) 34.1 8,574 (2,866) 33.4
(1) Refer exceptional items below for further details.
The Group's adjusted effective tax rate, which excludes the
influence of exchange rate movements and exceptional items, was
34.1 per cent (31 December 2019: 33.4 per cent) and is above 30 per
cent primarily due to higher withholding tax on current and future
dividends from Chilean operations and current period losses which
are not considered recoverable. The adjusted effective tax rate is
higher than at 31 December 2019 predominantly due to an increase in
current period losses which are not considered recoverable
(including NSWEC and certain Petroleum exploration projects). The
adjusted effective tax rate for the 2021 financial year remains
unchanged and is expected to be in the range of 32 to 37 per
cent.
Other royalty and excise arrangements which are not profit based
are recognised as operating costs within Profit before taxation.
These amounted to US$1.4 billion during the period (31 December
2019: US$1.2 billion).
Exceptional items
The following table sets out the exceptional items for the
December 2020 half year. Additional commentary is included on page
42.
Gross Tax Net
Half year ended 31 December 2020 US$M US$M US$M
----------------------------------------------------------- ------- ----- -------
Exceptional items by category
Samarco dam failure (358) (19) (377)
COVID-19 related costs (298) 79 (219)
Impairment of Energy coal assets and associated tax losses (927) (647) (1,574)
Total (1,583) (587) (2,170)
Attributable to non-controlling interests (15) 5 (10)
Attributable to BHP shareholders (1,568) (592) (2,160)
Debt management and liquidity
BHP remains in a position of strong liquidity.
During the half year, BHP has successfully reduced gross debt by
a total of US$4.1 billion (excluding standard repayments on final
maturity). Two multi-currency hybrid repurchase programs were
completed (US$1.7 billion on 17 September 2020 and US$1.1 billion
on 23 November 2020) and were funded from surplus cash. These
programs will reduce future interest costs while also reducing the
Group's gross debt balance, and were strongly value accretive, with
the reduction of future interest costs being higher than the
premium paid to acquire the hybrids. This premium over book value
generated an upfront accounting loss of US$395 million (pre-tax),
which is reported in net finance costs. BHP also redeemed US$1.0
billion of 6.250 per cent hybrid notes on 19 October 2020 on the
notes' first call date, and the remaining US$0.3 billion of 6.750
per cent hybrid notes on 30 December 2020 at par under the notes'
Substantial Repurchase Event clause, triggered by the second
repurchase program. Both redemptions were also completed using
surplus cash.
At the subsidiary level, Escondida refinanced US$0.2 billion of
maturing long-term debt.
19
The Group completed a one-year extension to the US$5.5 billion
revolving credit facility which is now due to mature in October
2025. This facility backs a US$5.5 billion commercial paper
program. As at 31 December 2020, the Group had no outstanding US
commercial paper, no drawn amount under the revolving credit
facility and US$9.3 billion in cash and cash equivalents.
Dividend
The BHP Board today determined to pay an interim dividend of
US$1.01 per share (US$5.1 billion). The interim dividend to be paid
by BHP Group Limited will be fully franked for Australian taxation
purposes.
BHP's Dividend Reinvestment Plan (DRP) will operate in respect
of the interim dividend. Full terms and conditions of the DRP and
details about how to participate can be found at: bhp.com
Events in respect of the interim dividend Date
-------------------------------------------------------------------------------------------- ----------------
Announcement of currency conversion into RAND 26 February 2021
Last day to trade cum dividend on Johannesburg Stock Exchange Limited (JSE) 2 March 2021
Ex-dividend Date JSE 3 March 2021
Ex-dividend Date Australian Securities Exchange (ASX), London Stock Exchange (LSE) and New 4 March 2021
York Stock Exchange (NYSE)
Record Date 5 March 2021
DRP and Currency Election date (including announcement of currency conversion for ASX and 8 March 2021
LSE)
Payment Date 23 March 2021
DRP Allocation Date (ASX and LSE) within 10 business days after the payment date 6 April 2021
DRP Allocation Date (JSE), subject to the purchase of shares by the Transfer Secretaries in
the open market, Central Securities Depository Participant (CSDP) accounts credited/updated
on or about 6 April 2021
BHP Group Plc shareholders registered on the South African
section of the register will not be able to dematerialise or
rematerialise their shareholdings between the dates of 3 March 2021
and 5 March 2021 (inclusive), nor will transfers between the UK
register and the South African register be permitted between the
dates of 26 February 2021 and 5 March 2021 (inclusive). American
Depositary Shares (ADSs) each represent two fully paid ordinary
shares and receive dividends accordingly. Details of the currency
exchange rates applicable for the dividend will be announced to the
relevant stock exchanges following conversion and will appear on
the Group's website.
Any eligible shareholder who wishes to participate in the DRP,
or to vary a participation election should do so in accordance with
the timetable above, or, in the case of shareholdings on the South
African branch register of BHP Group Plc, in accordance with the
instructions of your CSDP. The DRP Allocation Price will be
calculated in each jurisdiction as an average of the price paid for
all shares actually purchased to satisfy DRP elections. The
Allocation Price applicable to each exchange will made available
at: bhp.com/DRP
Corporate governance
David Lamont commenced as the Chief Financial Officer of BHP on
1 December 2020, as announced on 17 June 2020.
On 4 September 2020, we announced the appointment of Christine
O'Reilly to the Board as an independent Non-executive Director, and
a member of the Risk and Audit Committee and the Remuneration
Committee, effective 12 October 2020.
On 3 December 2020, we announced that Stefanie Wilkinson has
been appointed Group Company Secretary of BHP Group Limited and BHP
Group PLC, effective 1 March 2021.
20
On 22 December 2020, we announced that Susan Kilsby will step
down as BHP's Senior Independent Director, effective immediately,
and as the Chair of BHP's Remuneration Committee, effective 1 March
2021. Gary Goldberg will replace Susan as BHP's Senior Independent
Director, and Christine O'Reilly will replace Susan as the Chair of
BHP's Remuneration Committee. Susan has informed the Board of her
intention to retire as a BHP Director during the 2021 calendar
year, and no later than the 2021 Annual General Meetings.
The current members of the Board's committees are:
Risk and Audit Nomination and Governance Committee Remuneration Sustainability
Committee Committee Committee
------------------- ----------------------------------- ----------------------- --------------------
Terry Bowen (Chair) Ken MacKenzie (Chair) Susan Kilsby (Chair) John Mogford (Chair)
Xiaoqun Clever Terry Bowen Anita Frew Malcolm Broomhead
Ian Cockerill Malcolm Broomhead Gary Goldberg (SID)(1) Ian Cockerill
Anita Frew Susan Kilsby Christine O'Reilly Gary Goldberg (SID)
Christine O'Reilly John Mogford Dion Weisler
(1) Senior Independent Director (SID).
Segment summary(1)
A summary of performance for the December 2020 and December 2019
half years is presented below .
Half year ended
31 December Net
2020 Underlying Underlying Exceptional operating Capital Exploration Exploration
US$M Revenue(2) EBITDA(3) EBIT(3) items(4) assets(3) expenditure gross(5) to profit(6)
--------------- ---------- ---------- ---------- ----------- ---------- ------------ ----------- -------------
Petroleum 1,619 789 (112) (31) 8,511 498 195 242
Copper 7,067 3,738 2,899 (38) 26,623 1,108 18 18
Iron Ore 14,058 10,244 9,320 (500) 19,026 1,101 49 26
Coal 2,170 (201) (601) (959) 8,792 320 11 4
Group and
unallocated
items(7) 749 110 (214) (14) 3,929 306 8 8
Inter-segment
adjustment(8) (24) - - - - - - -
Total Group 25,639 14,680 11,292 (1,542) 66,881 3,333 281 298
Half year ended
31 December 2019
(Restated)
US$M Revenue(2) Underlying EBITDA(3) Underlying EBIT(3) Exceptional items Net operating assets(3)(9) Capital expenditure Exploration gross(5) Exploration to profit(6)
------------------ ---------- -------------------- ------------------ ----------------- -------------------------- ------------------- -------------------- ------------------------
Petroleum 2,453 1,579 813 - 8,535 372 306 164
Copper 5,602 2,355 1,545 (778) 25,168 1,190 20 20
Iron Ore 10,375 7,124 6,344 24 18,453 1,201 45 28
Coal 3,266 898 506 - 9,936 297 10 10
Group and
unallocated
items(7) 625 128 (167) 27 3,992 345 9 9
Inter-segment
adjustment(8) (27) - - - - - - -
Total Group 22,294 12,084 9,041 (727) 66,084 3,405 390 231
(1) Group and segment level information is reported on a
statutory basis which reflects the application of the equity
accounting method in preparing the Group Financial Statements - in
accordance with IFRS. Underlying EBITDA of the Group and the
reportable segments, includes depreciation, amortisation and
impairments (D&A), net finance costs and taxation expense of
US$261 million (H1 FY20: US$230 million) related to equity
accounted investments. It excludes exceptional items loss of US$678
million (H1 FY20: US$36 million gain) related to share of
profit/loss from equity accounted investments, related impairments
and expenses.
Group profit before taxation comprised Underlying EBITDA,
exceptional items, depreciation, amortisation and impairments of
US$4,930 million (H1 FY20: US$3,770 million) and net finance costs
of US$924 million (H1 FY20: US$524 million).
(2) Revenue is based on Group realised prices and includes third
party products. Sale of third party products by the Group
contributed revenue of US$961 million and Underlying EBITDA of
US$58 million (H1 FY20: US$676 million and US$22 million).
(3) For more information on the reconciliation of certain
alternative performance measures to our statutory measures, reasons
for usefulness and calculation methodology, please refer to
alternative performance measures set on pages 63 to 74.
(4) Exceptional items loss of US$1,542 million excludes net
finance costs of US$41 million included in the total loss before
taxation of US$358 million related to the Samarco dam failure.
Refer to note 3 Exceptional items and note 10 Significant events -
Samarco dam failure of the Financial Report for further
information.
(5) Includes US$44 million capitalised exploration (H1 FY20:
US$159 million).
21
(6) Includes US$61 million of exploration expenditure previously
capitalised, written off as impaired (included in depreciation and
amortisation) (H1 FY20: US$ nil).
(7) Group and unallocated items includes functions, other
unallocated operations including Potash, Nickel West, legacy
assets, and consolidation adjustments. Revenue not attributable to
reportable segments comprises the sale of freight and fuel to third
parties, as well as revenues from unallocated operations.
Exploration and technology activities are recognised within
relevant segments.
(8) Comprises revenue of US$24 million generated by Petroleum
(H1 FY20: US$26 million) and US$ nil generated by Coal (H1 FY20:
US$1 million).
(9) Net operating assets has been restated to reflect changes to
the Group's accounting policy following a decision by the IFRS
Interpretations Committee on IAS 12 'Income Tax', resulting in the
retrospective recognition of US$950 million of Goodwill at Olympic
Dam . Note, an offsetting increase in Deferred tax liabilities of
US$1,021 million which is not included in Net Operating Assets
above. Refer to note 2 Impact of new accounting standards and
changes in accounting policies of the Financial Report for further
information.
Half year ended
31 December 2020 Underlying Underlying Net operating Capital Exploration Exploration
US$M Revenue EBITDA(3) D&A EBIT(3) assets(3) expenditure gross to profit
------------------ ------- ---------- --- ---------- -------------------- ------------ ----------- -----------
Potash - (80) 1 (81) 4,203 105 - -
Nickel West 737 121 52 69 175 130 8 8
Half year
ended
31 December
2019 Underlying Underlying Net operating Capital Exploration Exploration
US$M Revenue EBITDA(3) D&A EBIT(3) assets(3) expenditure gross to profit
-------------- ------- ------------- --- ------------- ------------- ------------- ------------- -------------
Potash - (53) 2 (55) 3,937 110 - -
Nickel West 603 (2) 23 (25) 131 153 9 9
Petroleum
Underlying EBITDA for the December 2020 half year decreased by
US$790 million to US$789 million.
US$M
Underlying EBITDA
for the half year
ended 31 December
2019 1,579
--------------------------- -----
Net price impact (518) Lower average realised prices:
Crude and condensate oil US$41.40/bbl
(H1 FY20: US$60.64/bbl);
Natural gas US$3.83/Mscf (H1 FY20: US$4.26/Mscf);
LNG US$4.45/Mscf (H1 FY20: US$7.62/Mscf).
Change in volumes (187) Lower volumes due to lower gas demand
at Bass Strait and North West Shelf,
impacts from significant hurricane activity
in the Gulf of Mexico, unfavourable weather
conditions at North West Shelf, planned
tie-in and commissioning activities at
Atlantis, and natural field decline across
the portfolio. This was partially offset
by planned maintenance at North West
Shelf in the prior period.
Change in controllable (35) Higher exploration expenses due to expensing
cash costs the Broadside-1 well and seismic costs
in the Gulf of Mexico and Trinidad and
Tobago. This was partially offset by
optimisation of maintenance costs.
Ceased and sold operations (28) Sale of our interests in the Minerva
Gas Plant in the prior period.
Other (22) Other includes unfavourable exchange
movements, inflation, the revaluation
of embedded derivatives in Trinidad and
Tobago gas contract of US$1 million loss
(H1 FY20: US$18 million gain), and other
items.
Underlying EBITDA
for the half year
ended 31 December
2020 789
Petroleum unit costs increased by eight per cent to US$10.30 per
barrel of oil equivalent as lower volumes and higher exploration
expenses offset the impact from maintenance optimisation during the
half year compared to prior period. Unit cost guidance for the 2021
financial year remains unchanged at between US$11 and US$12 per
barrel (based on an exchange rate of AUD/USD 0.70), with unit costs
expected to be towards the lower end of the guidance range. In the
medium term, we expect unit costs to be less than US$13 per barrel
(based on an exchange rate of AUD/USD 0.70) primarily as a result
of natural field decline. In response to market conditions, we
continue to explore opportunities to lower costs and improve
competitiveness.
22
Reflecting the acquisition of an additional 28 per cent working
interest in Shenzi, our medium term production guidance increases
from 104 MMboe to 106 MMboe.
Petroleum unit costs
(US$M) H1 FY21 H2 FY20 H1 FY20 FY20
-------------------------- ------- ------- ------- -----
Revenue 1,619 1,617 2,453 4,070
Underlying EBITDA 789 628 1,579 2,207
Gross costs 830 989 874 1,863
Less: exploration expense 181 230 164 394
Less: freight 29 56 54 110
Less: development and
evaluation 106 111 55 166
Less: other(1) (1) 75 56 131
Net costs 515 517 545 1,062
Production (MMboe, equity
share) 50 52 57 109
Cost per Boe (US$)(2)(3) 10.30 9.94 9.56 9.74
(1) Other includes non-cash profit on sales of assets, inventory
movements, foreign exchange and the impact from revaluation of
embedded derivatives in the Trinidad and Tobago gas contract.
(2) H1 FY21 based on an exchange rate of AUD/USD 0.72.
(3) H1 FY21 excludes COVID-19 related costs of US$0.25 per
barrel of oil equivalent that are reported as exceptional
items.
In December 2020, BHP and the North West Shelf joint venture
partners executed fully-termed Gas Processing Agreements for
processing third-party gas from Pluto and Waitsia projects through
the North West Shelf facilities.
In January 2021, the first of two Shenzi North development wells
planned for tie-back to the Shenzi tension-leg platform reached
final depth and successfully encountered hydrocarbons as expected,
meeting target objectives. An additional Shenzi infill well has
been sanctioned for execution in second half of 2021 financial
year, realising further value from the successful acquisition of an
additional 28 per cent working interest in Shenzi in November 2020.
This infill opportunity represents a low-risk, high-value
investment, with the well location enhanced through Ocean Bottom
Node (OBN) seismic acquisition completed in 2019 and covering the
Shenzi field.
We note the US Department of Interior's order issued on 20
January 2021 and the Biden Administrations Climate Executive Order
on 27 January 2021 in relation to natural gas and oil development
on federal lands and waters. We will continue to monitor
developments of this order, and will analyse and assess the
potential implications as more details are released.
Petroleum exploration
Petroleum exploration expenditure for the December 2020 half
year was US$195 million, of which US$181 million was expensed. An
approximately US$450 million exploration and appraisal program is
being executed for the 2021 financial year.
In Trinidad and Tobago, the Broadside-1 exploration well in the
Southern Licence reached the main reservoir on 22 October 2020 and
did not encounter hydrocarbons. The well was a dry hole and was
plugged and abandoned on 8 November 2020. The results are under
evaluation to determine next steps on the Southern Licences.
In Mexico, we commenced an Ocean Bottom Node seismic
acquisition(vii) over the Trion field on 9 November 2020, as part
of our ongoing evaluation and analysis. The survey was completed in
early January 2021, with the results to be incorporated into the
current evaluation of the Trion opportunity. In addition, we
received formal approval for a 124-day extension for the evaluation
and exploration periods through 1 July 2021 and 1 July 2022
respectively, as a result of the suspension of activities in 2020
due to COVID-19.
In the US Gulf of Mexico, following Lease Sale 254 we were
awarded Blocks AC36, AC80 and AC81 in the western Gulf of Mexico in
July 2020.
23
Financial information for Petroleum for the December 2020 and
December 2019 half years is presented below.
Half year ended Net
31 December 2020 Underlying Underlying operating Capital Exploration Exploration
US$M Revenue(1) EBITDA D&A EBIT assets expenditure gross(2) to profit(3)
----------------------- ---------- ---------- --- ---------- ---------- ------------ ----------- -------------
Australia Production
Unit(4) 123 80 95 (15) 176 14
Bass Strait 478 319 396 (77) 1,407 33
North West Shelf 402 311 120 191 1,224 47
Atlantis 212 127 71 56 1,131 125
Shenzi 137 89 59 30 1,005 10
Mad Dog 88 61 26 35 1,774 164
Trinidad/Tobago 68 40 19 21 439 70
Algeria 75 54 - 54 95 1
Exploration - (181) 80 (261) 1,122 1
Other(5) 39 (109) 37 (146) 138 33
Total Petroleum
from Group production 1,622 791 903 (112) 8,511 498
Third party products 3 - - - - -
Total Petroleum 1,625 791 903 (112) 8,511 498 195 242
Adjustment for equity
accounted
investments(6) (6) (2) (2) - - - - -
Total Petroleum
statutory result 1,619 789 901 (112) 8,511 498 195 242
Half year ended Net
31 December 2019 Underlying Underlying operating Capital Exploration Exploration
US$M Revenue(1) EBITDA D&A EBIT assets expenditure gross(2) to profit(3)
----------------------- ---------- ---------- --- ---------- ---------- ------------ ----------- -------------
Australia Production
Unit(4) 190 155 96 59 431 -
Bass Strait 704 503 259 244 1,918 26
North West Shelf 600 441 126 315 1,358 42
Atlantis 381 317 98 219 1,051 48
Shenzi 153 104 63 41 571 22
Mad Dog 133 105 28 77 1,407 192
Trinidad/Tobago 101 77 25 52 315 30
Algeria 106 89 12 77 61 7
Exploration - (164) 19 (183) 1,219 -
Other(5) 55 (45) 42 (87) 204 5
Total Petroleum
from Group production 2,423 1,582 768 814 8,535 372
Third party products 38 (1) - (1) - -
Total Petroleum 2,461 1,581 768 813 8,535 372 306 164
Adjustment for equity
accounted
investments(6) (8) (2) (2) - - - - -
Total Petroleum
statutory result 2,453 1,579 766 813 8,535 372 306 164
(1) Total Petroleum statutory result revenue includes: crude oil
US$769 million (H1 FY20: US$1,293 million), natural gas US$434
million (H1 FY20: US$564 million), LNG US$292 million (H1 FY20:
US$418 million), NGL US$96 million (H1 FY20: US$115 million) and
other US$28 million (H1 FY20: US$63 million) which includes third
party products.
(2) Includes US$14 million of capitalised exploration (H1 FY20:
US$142 million).
(3) Includes US$61 million of exploration expenditure previously
capitalised, written off as impaired (included in depreciation and
amortisation) (H1 FY20: US$ nil).
(4) Australia Production Unit includes Macedon, Pyrenees and
Minerva (divested in December 2019).
(5) Predominantly divisional activities, business development
and Neptune. Also includes the Caesar oil pipeline and the
Cleopatra gas pipeline, which are equity accounted investments. The
financial information for the Caesar oil pipeline and the Cleopatra
gas pipeline presented above, with the exception of net operating
assets, reflects BHP's share.
(6) Total Petroleum statutory result revenue excludes US$6
million (H1 FY20: US$8 million) revenue related to the Caesar oil
pipeline and the Cleopatra gas pipeline. Total Petroleum statutory
result Underlying EBITDA includes US$2 million (H1 FY20: US$2
million) D&A related to the Caesar oil pipeline and the
Cleopatra gas pipeline.
24
Copper
Underlying EBITDA for the December 2020 half year increased by
US$1.4 billion to US$3.7 billion.
US$M
Underlying EBITDA
for the half year
ended 31 December
2019 2,355
----------------------- -----
Net price impact 1,317 Higher average realised price:
Copper US$3.32/lb (H1 FY20: US$2.60/lb).
Change in volumes 8 Record average concentrator throughput
at Escondida was partially offset by
expected lower concentrator feed grade.
Cathode sales were lower at Spence, largely
due to planned maintenance. Higher copper
volumes at Olympic Dam reflected improved
smelter and refinery performance as well
as planned refinery maintenance in the
prior period.
Change in controllable 76 Strong cost performance at Escondida,
cash costs an US$99 million gain from the optimised
outcome from renegotiation of cancelled
power contracts at Escondida and Spence,
and favourable oxide leach pad inventory
movements at Escondida and at Spence
in the lead up to SGO commissioning.
This was partially offset by a drawdown
in inventories aligned with strong smelter
run time at Olympic Dam.
Change in other costs:
Exchange rates (176)
Inflation (55)
Non-cash 146 Lower deferred stripping depletion at
Escondida, in line with planned development
phase of the mines.
One-off items (138) Copper cathodes volume loss at Escondida
due to reduced operational workforce
as a result of COVID-19.
Other 205 Other includes increased profit at Antamina
driven by higher realised prices for
both copper and zinc, and favourable
impacts from lower fuel and energy prices
of US$38 million.
Underlying EBITDA
for the half year
ended 31 December
2020 3,738
Escondida unit costs decreased by 18 per cent to US$0.90 per
pound, reflecting record average concentrator throughput, strong
cost management, lower deferred stripping costs, higher by-product
credits and a gain from the optimised outcome from renegotiation of
cancelled power contracts as part of a shift towards 100 per cent
renewable energy at the mine. This more than offset the impact of a
four per cent decline in concentrator feed grade and higher
desalinated water costs.
Unit cost guidance for the 2021 financial year remains unchanged
at between US$1.00 and US$1.25 per pound (based on an exchange rate
of USD/CLP 769), with unit costs expected to be towards the lower
end of the guidance range. In the medium term, we expect unit costs
to be less than US$1.10 per pound (based on an exchange rate of
USD/CLP 769), with further operational efficiency and maintenance
improvements expected to offset higher power consumption and water
costs, as well as grade decline.
Escondida unit costs
(US$M) H1 FY21 H2 FY20 H1 FY20 FY20
------------------------------ ------- ------- ------- -----
Revenue 4,516 3,136 3,583 6,719
Underlying EBITDA 3,019 1,708 1,827 3,535
Gross costs 1,497 1,428 1,756 3,184
Less: by-product credits 272 186 221 407
Less: freight 79 84 94 178
Net costs 1,146 1,158 1,441 2,599
Sales (kt) 576 571 593 1,164
Sales (Mlb) 1,270 1,259 1,308 2,567
Cost per pound (US$)(1)(2)(3) 0.90 0.92 1.10 1.01
(1) H1 FY21 based on an average exchange rate of USD/CLP
771.
(2) H1 FY21 excludes COVID-19 related costs of US$0.02 per pound
that are reported as exceptional items.
(3) H1 FY21 includes a gain from the optimised outcome from
renegotiation of cancelled power contracts of US$0.07 per
pound.
25
The Spence Growth Option achieved first copper concentrate
production in December 2020, on schedule and on budget, with first
copper sales expected during the March 2021 quarter. Ramp up to
full production capacity is expected to take approximately 12
months, following which Spence is expected to average 300 ktpa of
production (including cathodes) over the first four years. The
commissioning of the new desalinated water plant, with capacity of
1,000 litres per second and the capitalisation of the associated
US$603 million lease, also occurred in December 2020. This will
enable the expansion to operate with 100 per cent desalinated
water. This follows investments at Escondida of more than US$4
billion in desalinated water since 2006, which enabled Escondida to
eliminate drawdown from aquifers for operational supply in December
2019, 10 years ahead of its 2030 target.
In the 2022 financial year, Escondida and Spence will transition
to four renewable power contracts to increase flexibility for our
power portfolio, reduce energy prices at both operations by an
estimated 20 per cent and ensure security of supply. We aim to
supply Escondida and Spence's energy requirements from 100 per cent
renewable energy sources from the mid-2020s.
Financial information for Copper for the December 2020 and
December 2019 half years is presented below.
Half year ended Net
31 December 2020 Underlying Underlying operating Capital Exploration Exploration
US$M Revenue EBITDA D&A EBIT assets expenditure gross to profit
-------------------------- ------- ---------- ---- ---------- ---------- ------------ ----------- -----------
Escondida(1) 4,516 3,019 491 2,528 11,994 328
Pampa Norte(2) 700 327 191 136 4,304 332
Antamina(3) 751 515 72 443 1,385 117
Olympic Dam 913 169 155 14 8,896 442
Other(3)(4) - (105) 3 (108) 44 6
Total Copper from
Group production 6,880 3,925 912 3,013 26,623 1,225
Third party products 938 55 - 55 - -
Total Copper 7,818 3,980 912 3,068 26,623 1,225 21 19
Adjustment for equity
accounted investments(5) (751) (242) (73) (169) - (117) (3) (1)
Total Copper statutory
result 7,067 3,738 839 2,899 26,623 1,108 18 18
Half year ended
31 December 2019
(Restated)
Net
Underlying Underlying operating Capital Exploration Exploration
US$M Revenue EBITDA D&A EBIT assets expenditure gross to profit
-------------------------- ------- ---------- ---- ---------- ---------- ------------ ----------- -----------
Escondida(1) 3,583 1,827 545 1,282 12,098 521
Pampa Norte(2) 719 320 113 207 3,237 400
Antamina(3) 515 314 64 250 1,420 137
Olympic Dam(6) 691 114 149 (35) 8,422 255
Other(3)(4) - (85) 4 (89) (9) 14
Total Copper from
Group production 5,508 2,490 875 1,615 25,168 1,327
Third party products 609 21 - 21 - -
Total Copper 6,117 2,511 875 1,636 25,168 1,327 25 23
Adjustment for equity
accounted investments(5) (515) (156) (65) (91) - (137) (5) (3)
Total Copper statutory
result 5,602 2,355 810 1,545 25,168 1,190 20 20
(1) Escondida is consolidated under IFRS 10 and reported on a
100 per cent basis.
(2) Includes Spence and Cerro Colorado.
(3) Antamina, SolGold and Resolution are equity accounted
investments and their financial information presented above with
the exception of net operating assets reflects BHP Group's
share.
(4) Predominantly comprises divisional activities, greenfield
exploration and business development. Includes Resolution and
SolGold.
(5) Total Copper statutory result revenue excludes US$751
million (H1 FY20: US$515 million) revenue related to Antamina.
Total Copper statutory result Underlying EBITDA includes US$73
million (H1 FY20: US$65 million) D&A and US$169 million (H1
FY20: US$91 million) net finance costs and taxation expense related
to Antamina, Resolution and SolGold that are also included in
Underlying EBIT. Total Copper Capital expenditure excludes US$117
million (H1 FY20: US$137 million) related to Antamina. Exploration
gross excludes US$3 million (H1 FY20: US$5 million) related to
SolGold of which US$1 million (H1 FY20: US$3 million) was
expensed.
(6) Net operating assets has been restated to reflect changes to
the Group's accounting policy following a decision by the IFRS
Interpretations Committee on IAS 12 'Income Tax', resulting in the
retrospective recognition of US$950 million of Goodwill at Olympic
Dam . Note, an offsetting increase in Deferred tax liabilities of
US$1,021 million which is not included in Net Operating Assets
above. Refer to note 2 Impact of new accounting standards and
changes in accounting policies of the Financial Report for further
information.
26
Iron Ore
Underlying EBITDA for the December 2020 half year increased by
US$3.1 billion to US$10.2 billion.
US$M
Underlying EBITDA for the half year ended 31 December
2019 7,124
------------------------------------------------------- ------
Net price impact 2,849 Higher average realised price:
Iron ore US$103.78/wmt, FOB (H1 FY20: US$78.30/wmt,
FOB).
Change in volumes 456 Record production volumes at WAIO reflecting
continued improvements in productivity and
reliability
across the supply chain.
Change in controllable cash costs 16 Favourable inventory movements, partially offset by
increased maintenance costs.
Change in other costs:
Exchange rates (197)
Inflation (25)
Other 21 Other includes favourable impacts from lower fuel and
energy prices of US$79 million offset
by an increase in non-cash production stripping
depletion at Newman and other items.
Underlying EBITDA for the half year ended 31 December
2020 10,244
WAIO unit costs increased by 10 per cent to US$14.38 per tonne
(or US$12.46 per tonne on a C1 basis excluding third party
royalties(4) ) due to the impact of a six per cent stronger
Australian dollar and price-linked third party royalties. In local
currency terms, unit costs decreased by two per cent reflecting
record production volumes following strong performance across the
supply chain and the planned inventory build at mines to support
maintenance activities and the Mining Area C and South Flank major
tie-in activity. Costs related to the impact from COVID-19 are
reported as an exceptional item and are not included in unit costs.
These additional costs were approximately US$0.56 per tonne,
bringing WAIO unit costs to a total of US$14.94 per tonne (or
US$12.76 per tonne on a C1 basis excluding third party
royalties(3)(4) ).
Unit cost guidance for the 2021 financial year remains unchanged
at between US$13 and US$14 per tonne (based on an exchange rate of
AUD/USD 0.70). In the medium term, we expect to lower our unit
costs to less than US$13 per tonne (based on an exchange rate of
AUD/USD 0.70) reflecting ongoing improvements across the supply
chain.
WAIO unit costs
(US$M) H1 FY21 H2 FY20 H1 FY20 FY20
--------------------------------------- ------- ------- ------- -------
Revenue 13,992 10,363 10,300 20,663
Underlying EBITDA 10,220 7,421 7,087 14,508
Gross costs 3,772 2,942 3,213 6,155
Less: freight(1) 826 596 863 1,459
Less: royalties 1,101 772 759 1,531
Net costs 1,845 1,574 1,591 3,165
Sales (kt, equity
share) 128,273 128,537 122,061 250,598
Cost per tonne (US$)(2)(3) 14.38 12.25 13.03 12.63
Cost per tonne on a C1 basis excluding
third party royalties (US$)(3)(4) 12.46 10.96 12.75 11.82
(1) H1 FY21 freight costs rebounded following a decline in H2
FY20 which reflected seasonal, but severe, iron ore export
disruptions and COVID-19 demand impacts.
(2) H1 FY21 based on an average exchange rate of AUD/USD
0.72.
(3) H1 FY21 excludes COVID-19 related costs of US$0.56 per tonne
(including US$0.30 per tonne relating to operations and US$0.26 per
tonne of demurrage) that are reported as exceptional items. An
additional US$0.20 per tonne relating to capital projects is also
reported as an exceptional item.
(4) Excludes third party royalties of US$1.68 per tonne (H1
FY20: US$1.23 per tonne), net inventory movements US$(1.30) per
tonne (H1 FY20: US$(0.95) per tonne), depletion of production
stripping US$0.72 per tonne (H1 FY20: USD$0.53 per tonne),
operational readiness costs relating to South Flank US$0.19 per
tonne (H1 FY20: US$0 per tonne), exploration expenses, Marketing
purchases, demurrage, exchange rate gains/losses, and other income
US$0.63 per tonne (H1 FY20: US$(0.53) per tonne).
27
Financial information for Iron Ore for the December 2020 and
December 2019 half years is presented below.
Half year ended Net
31 December 2020 Underlying Underlying operating Capital Exploration Exploration
US$M Revenue EBITDA D&A EBIT assets expenditure gross(1) to profit
------------------------- ------- ---------- --- ---------- ---------- ------------ ----------- -----------
Western Australia
Iron Ore 13,992 10,220 911 9,309 20,942 1,100
Samarco(2) - - - - (2,158) -
Other(3) 58 21 13 8 242 1
Total Iron Ore from
Group production 14,050 10,241 924 9,317 19,026 1,101
Third party products(4) 8 3 - 3 - -
Total Iron Ore 14,058 10,244 924 9,320 19,026 1,101 49 26
Adjustment for equity
accounted investments - - - - - - - -
Total Iron Ore statutory
result 14,058 10,244 924 9,320 19,026 1,101 49 26
Half year
ended
31 December
2019 Underlying Underlying Net operating Capital Exploration Exploration
US$M Revenue EBITDA D&A EBIT assets expenditure gross(1) to profit
-------------- ------- ------------- --- ------------- ------------- ------------- ------------- -------------
Western
Australia
Iron Ore 10,300 7,087 768 6,319 19,935 1,200
Samarco(2) - - - - (1,721) -
Other(3) 67 34 12 22 239 1
Total Iron Ore
from Group
production 10,367 7,121 780 6,341 18,453 1,201
Third party
products(4) 8 3 - 3 - -
Total Iron Ore 10,375 7,124 780 6,344 18,453 1,201 45 28
Adjustment for
equity
accounted
investments - - - - - - - -
Total Iron Ore
statutory
result 10,375 7,124 780 6,344 18,453 1,201 45 28
(1) Includes US$23 million of capitalised exploration (H1 FY20:
US$17 million).
(2) Samarco is an equity accounted investment and its financial
information presented above, with the exception of net operating
assets, reflects BHP Billiton Brasil Ltda's share. All financial
impacts following the Samarco dam failure have been reported as
exceptional items in both reporting periods.
(3) Predominantly comprises divisional activities, towage
services, business development and ceased operations.
(4) Includes inter-segment and external sales of contracted gas
purchases.
Coal
Underlying EBITDA for the December 2020 half year decreased by
US$1.1 billion to a loss of US$201 million.
US$M
Underlying EBITDA
for the half year
ended 31 December
2019 898
----------------------- -----
Net price impact (720) Lower average prices:
Hard coking coal US$106.30/t (H1 FY20:
US$154.01/t);
Weak coking coal US$73.17/t (H1 FY20:
US$101.06/t);
Thermal coal US$44.35/t (H1 FY20: US$58.55/t).
Change in volumes (183) Decreased volumes at Queensland Coal
due to significant wet weather impacts
from La Niña across most operations,
planned wash plant maintenance and lower
yields at South Walker Creek and Poitrel.
Lower volumes at NSWEC due to significant
weather impacts, higher strip ratios
and an increased proportion of washed
coal.
Change in controllable (24) Increased maintenance costs at Queensland
cash costs Coal due to planned earth moving equipment
maintenance, asset integrity works and
wash plant shutdowns, and increased stripping
costs due to higher contractor stripping
rates and higher strip ratios at South
Walker Creek, partially offset by cost
reduction initiatives.
Change in other costs:
Exchange rates (207)
Inflation (20)
Other 55 Other includes favourable impacts from
lower fuel and energy prices of US$66
million.
Underlying EBITDA
for the half year
ended 31 December
2020 (201)
28
Queensland Coal unit costs increased by 20 per cent to US$85 per
tonne due to the impact of a six per cent stronger Australian
dollar, lower volumes following significant wet weather during the
December 2020 quarter and planned wash plant maintenance at BHP
Mitsubishi Alliance (BMA). This was partially offset by lower fuel
and energy costs, driven by lower prices, and cost reduction
initiatives.
Unit cost guidance for the 2021 financial year remains unchanged
at between US$69 and US$75 per tonne (based on an exchange rate of
AUD/USD 0.70). A stronger second half performance is expected at
Queensland Coal following completion of planned maintenance in the
first half, subject to any potential impacts on volumes from
restrictions on coal imports into China and further significant wet
weather during the remainder of the 2021 financial year. In the
medium term, we expect to lower our unit costs to between US$58 and
US$66 per tonne (based on an exchange rate of AUD/USD 0.70)
reflecting higher volumes (with focus on higher quality coals and
subject to market conditions), lower strip ratios, optimised
maintenance strategies and continued efficiency improvements.
Queensland Coal unit costs (US$M) H1 FY21 H2 FY20 H1 FY20 FY20
---------------------------------- ------- ------- ------- ------
Revenue 1,856 2,526 2,831 5,357
Underlying EBITDA 59 880 1,055 1,935
Gross costs 1,797 1,646 1,776 3,422
Less: freight 45 61 86 147
Less: royalties 136 231 267 498
Net costs 1,616 1,354 1,423 2,777
Sales (kt, equity share) 19,030 20,947 20,139 41,086
Cost per tonne (US$)(1)(2) 84.92 64.64 70.66 67.59
(1) H1 FY21 based on an average exchange rate of AUD/USD
0.72.
(2) H1 FY21 excludes COVID-19 related costs of US$1.42 per tonne
that are reported as exceptional items.
NSWEC unit costs increased by 11 per cent to US$66 per tonne due
to the impact of a stronger Australian dollar and lower volumes as
a result of significant weather impacts, higher strip ratios and an
increased proportion of washed coal in response to reduced port
capacity, following damage to a shiploader at the Newcastle port in
November 2020, and widening price quality differentials. This was
partially offset by lower fuel and energy costs, driven by lower
prices, as well as cost reduction initiatives.
Unit cost guidance for the 2021 financial year remains unchanged
at between US$55 and US$59 per tonne (based on an exchange rate of
AUD/USD 0.70). Work continues at NSWEC to optimise mine planning to
structurally reduce costs in the near term and ensure a viable
mining operation, which is resilient during low price cycles, with
some cost savings already realised during this period.
NSWEC unit costs (US$M) H1 FY21 H2 FY20 H1 FY20 FY20
--------------------------- ------- ------- ------- ------
Revenue 314 451 435 886
Underlying EBITDA (180) (29) (50) (79)
Gross costs 494 480 485 965
Less: royalties 25 35 33 68
Net costs 469 445 452 897
Sales (kt, equity
share) 7,108 8,274 7,594 15,868
Cost per tonne (US$)(1)(2) 65.98 53.78 59.52 56.53
(1) H1 FY21 based on an average exchange rate of AUD/USD
0.72.
(2) H1 FY21 excludes COVID-19 related costs of US$0.56 per tonne
that are reported as exceptional items.
29
Financial information for Coal for the December 2020 and
December 2019 half years is presented below.
Half year ended Net
31 December 2020 Underlying Underlying operating Capital Exploration Exploration
US$M Revenue EBITDA D&A EBIT assets expenditure gross to profit
--------------------------- ------- ---------- ---- ---------- ---------- ------------ ----------- -----------
Queensland Coal 1,856 59 329 (270) 8,137 278
New South Wales Energy
Coal(1) 358 (130) 78 (208) 288 31
Colombia(1) 63 (13) 39 (52) 355 8
Other(2) - (50) 7 (57) 12 11
Total Coal from Group
production 2,277 (134) 453 (587) 8,792 328
Third party products - - - - - -
Total Coal 2,277 (134) 453 (587) 8,792 328 11 4
Adjustment for equity
accounted
investments(3)(4) (107) (67) (53) (14) - (8) - -
Total Coal statutory result 2,170 (201) 400 (601) 8,792 320 11 4
Half year ended Net
31 December 2019 Underlying Underlying operating Capital Exploration Exploration
US$M Revenue EBITDA D&A EBIT assets expenditure gross to profit
------------------ ------- ------------ ---- ------------- ------------ ------------ ------------ ------------
Queensland Coal 2,831 1,055 327 728 8,471 253
New South Wales
Energy Coal(1) 480 (20) 74 (94) 901 44
Colombia(1) 219 55 62 (7) 828 16
Other(2) - (90) 5 (95) (264) -
Total Coal from
Group production 3,530 1,000 468 532 9,936 313
Third party
products - - - - - -
Total Coal 3,530 1,000 468 532 9,936 313 10 10
Adjustment for
equity accounted
investments(3)(4) (264) (102) (76) (26) - (16) - -
Total Coal
statutory result 3,266 898 392 506 9,936 297 10 10
(1) Newcastle Coal Infrastructure Group and Cerrejón are equity
accounted investments and their financial information presented
above with the exception of net operating assets reflects BHP
Group's share.
(2) Predominantly comprises divisional activities and ceased
operations.
(3) Total Coal statutory result revenue excludes US$63 million
(H1 FY20: US$219 million) revenue related to Cerrejón. Total Coal
statutory result Underlying EBITDA includes US$39 million (H1 FY20:
US$62 million) D&A and US$22 million net finance costs and
taxation benefits (H1 FY20: US$10 million net finance costs and
taxation expense) related to Cerrejón, that are also included in
Underlying EBIT. Total Coal statutory result Capital expenditure
excludes US$8 million (H1 FY20: US$16 million) related to
Cerrejón.
(4) Total Coal statutory result revenue excludes US$44 million
(H1 FY20: US$45 million) revenue related to Newcastle Coal
Infrastructure Group. Total Coal statutory result excludes US$50
million (H1 FY20: US$30 million) Underlying EBITDA, US$14 million
(H1 FY20: US$14 million) D&A and US$36 million (H1 FY20: US$16
million) Underlying EBIT related to Newcastle Coal Infrastructure
Group until future profits exceed accumulated losses.
Greenfield minerals exploration
Consistent with our exploration focus on future facing
commodities, in the December 2020 half year greenfield minerals
exploration was predominantly focused on advancing copper targets
within Chile, Ecuador, Mexico, Peru, Canada, Australia and the
south-west United States.
At Oak Dam in South Australia, the exploration project has been
transferred to the Minerals Australia Planning and Technical team
for assessment, and next stage resource definition drilling to
inform future design is expected to commence around the middle of
the 2021 calendar year. This follows successful exploration results
in previous drilling phases, which confirmed high-grade mineralised
intercepts of copper, with associated gold, uranium and silver.
30
During the half year, we added to our early stage optionality in
future facing commodities. In August 2020, we signed an agreement
with Midland Exploration to undertake a nickel exploration alliance
in north-eastern Quebec, Canada. The main objective of this
agreement is to identify, test and develop high quality exploration
targets that have the potential to become significant new nickel
discoveries. In September 2020, we completed the acquisition of the
nickel Honeymoon Well tenements and a 50 per cent interest in the
Albion Downs North and Jericho exploration joint ventures. The
Honeymoon Well increases Nickel West's position in one of the
world's major nickel sulphide provinces and the exploration joint
ventures provide us with new access to prospective tenements.
Several deposits are under consideration and are expected to be
included in Nickel West long term plans in the future. In September
2020, we also entered into an Option Agreement with Encounter
Resources covering the 4,500 km(2) prospective Elliott Copper
Project in the Northern Territory. It provides the right, following
the completion of a jointly designed validation program, to enter
an earn-in and joint venture agreement to earn up to 75 per cent
interest in Elliott by spending up to A$22 million over 10
years.
Group and unallocated items
Underlying EBITDA for Group and unallocated items decreased by
US$18 million to US$110 million in the December 2020 half year
primarily due the impact of a six per cent stronger Australian
dollar and higher demurrage costs related to China's coal import
restrictions. This was partially offset by an increase in EBITDA at
Nickel West.
Nickel West's Underlying EBITDA increased from a loss of US$2
million to positive US$121 million in the December 2020 half year,
reflecting higher volumes following resource transition and
completion of major four yearly planned maintenance shutdowns in
the prior period.
The Financial Report set out on pages 35 to 55 for the half year
ended 31 December 2020 has been prepared on the basis of accounting
policies and methods of computation consistent with those applied
in the 30 June 2020 financial statements contained within the
Annual Report of the Group, with the exception of new accounting
standards and interpretations which became effective from 1 July
2020 an other changes in accounting policies applied with effect
from 1 July 2020. This news release including the Financial Report
is unaudited. Variance analysis relates to the relative financial
and/or production performance of BHP and/or its operations during
the December 2020 half year compared with the December 2019 half
year, unless otherwise noted. Operations includes operated and
non-operated assets, unless otherwise noted. Medium term refers to
our five year plan. Numbers presented may not add up precisely to
the totals provided due to rounding.
The following abbreviations may have been used throughout this
report: barrels (bbl); billion cubic feet (bcf); barrels of oil
equivalent (boe); billion tonnes (Bt); cost and freight (CFR);
cost, insurance and freight (CIF), carbon dioxide equivalent (CO(2)
-e), dry metric tonne unit (dmtu); free on board (FOB); giga litres
(GL); grams per tonne (g/t); kilograms per tonne (kg/t); kilometre
(km); metre (m); million barrels of oil equivalent (MMboe); million
barrels of oil equivalent per day (MMboe/d); thousand cubic feet
equivalent (Mcfe); million cubic feet per day (MMcf/d); million
ounces per annum (Mozpa); million pounds (Mlb); million tonnes
(Mt); million tonnes per annum (Mtpa); ounces (oz); pounds (lb);
thousand barrels of oil equivalent (Mboe); thousand ounces (koz);
thousand ounces per annum (kozpa); thousand standard cubic feet
(Mscf); thousand tonnes (kt); thousand tonnes per annum (ktpa);
thousand tonnes per day (ktpd); tonnes (t); total recordable injury
frequency (TRIF); and wet metric tonnes (wmt).
The following footnotes apply to this Results Announcement:
(i) We use various alternative performance measures to reflect
our underlying performance. For further information on the
reconciliations of certain alternative performance measures to our
statutory measures, reasons for usefulness and calculation
methodology, please refer to alternative performance measures set
out on pages 63 to 74.
(ii) FY21 and medium-term unit cost guidance are based on
exchange rates of AUD/USD 0.70 and USD/CLP 769.
(iii) We use various key indicators to reflect our
sustainability performance. For further information on the reasons
for usefulness and calculation methodology, please refer to
"Definition and calculation of Key Indicator terms" set out on
pages 75 to 79.
(iv) Amounts spent are converted to USD based on actual
transactional (historical) exchange rates related to Renova
funding. Amounts yet to be spent are converted to USD based on 31
December 2020 exchange rates.
(v) Copper equivalent (Cueq) production based on 2020 financial
year average realised commodity prices, refer page 17. The
calculation applied the following formula: Cueq= (commodity
production tonnes x (commodity price/copper price)).
(vi) Maintenance capital includes non-discretionary spend for
the following purposes: deferred development and production
stripping; risk reduction, compliance and asset integrity .
(vii) Permit: EIA - ASEA/UGI/DGGEERNCM/0122/2018, expedient
28TM2018X0042. CNH Revised Appraisal Plan Approval - Resolucion
CNH.14.001/2020
31
Forward-looking statements
This release contains forward-looking statements, including
statements regarding: trends in commodity prices and currency
exchange rates; demand for commodities; production forecasts;
plans, strategies and objectives of management; closure or
divestment of certain assets, operations or facilities (including
associated costs); anticipated production or construction
commencement dates; capital costs and scheduling; operating costs
and shortages of materials and skilled employees; anticipated
productive lives of projects, mines and facilities; provisions and
contingent liabilities; and tax and regulatory developments.
Forward-looking statements may be identified by the use of
terminology, including, but not limited to, 'intend', 'aim',
'project', 'anticipate', 'estimate', 'plan', 'believe', 'expect',
'may', 'should', 'will', 'would', 'continue', 'annualised' or
similar words. These statements discuss future expectations
concerning the results of assets or financial conditions, or
provide other forward-looking information.
These forward-looking statements are based on the information
available as at the date of this release and are not guarantees or
predictions of future performance, and involve known and unknown
risks, uncertainties and other factors, many of which are beyond
our control, and which may cause actual results to differ
materially from those expressed in the statements contained in this
release. BHP cautions against reliance on any forward-looking
statements or guidance, particularly in light of the current
economic climate and the significant volatility, uncertainty and
disruption arising in connection with COVID-19.
For example, our future revenues from our assets, projects or
mines described in this release will be based, in part, upon the
market price of the minerals, metals or petroleum produced, which
may vary significantly from current levels. These variations, if
materially adverse, may affect the timing or the feasibility of the
development of a particular project, the expansion of certain
facilities or mines, or the continuation of existing assets.
Other factors that may affect the actual construction or
production commencement dates, costs or production output and
anticipated lives of assets, mines or facilities include our
ability to profitably produce and transport the minerals, petroleum
and/or metals extracted to applicable markets; the impact of
foreign currency exchange rates on the market prices of the
minerals, petroleum or metals we produce; activities of government
authorities in the countries where we sell our products and in the
countries where we are exploring or developing projects, facilities
or mines, including increases in taxes; changes in environmental
and other regulations, the duration and severity of the COVID-19
pandemic and its impact on our business; political uncertainty;
labour unrest; and other factors identified in the risk factors
discussed in BHP's filings with the U.S. Securities and Exchange
Commission (the 'SEC') (including in Annual Reports on Form 20-F)
which are available on the SEC's website at www.sec.gov.
Except as required by applicable regulations or by law, BHP does
not undertake to publicly update or review any forward-looking
statements, whether as a result of new information or future
events.
Past performance cannot be relied on as a guide to future
performance.
No offer of securities
Nothing in this release should be construed as either an offer,
or a solicitation of an offer, to buy or sell BHP securities in any
jurisdiction, or be treated or relied upon as a recommendation or
advice by BHP.
Reliance on third party information
The views expressed in this release contain information that has
been derived from publicly available sources that have not been
independently verified. No representation or warranty is made as to
the accuracy, completeness or reliability of the information. This
release should not be relied upon as a recommendation or forecast
by BHP.
No financial or investment advice - South Africa
BHP does not provide any financial or investment 'advice' as
that term is defined in the South African Financial Advisory and
Intermediary Services Act, 37 of 2002, and we strongly recommend
that you seek professional advice.
32
BHP and its subsidiaries
In this release, the terms 'BHP', the 'Company, the 'Group',
'BHP Group', 'our business', 'organisation', 'we', 'us', 'our' and
ourselves' refer to BHP Group Limited, BHP Group plc and, except
where the context otherwise requires, their respective subsidiaries
as defined in note 29 'Subsidiaries' in section 5.1 of BHP's 30
June 2020 Annual Report and Form 20-F.Those terms do not include
non-operated assets.
This release covers BHP's assets (including those under
exploration, projects in development or execution phases, sites and
closed operations) that have been wholly owned and/or operated by
BHP and that have been owned as a joint venture(1) operated by BHP
(referred to in this release as 'operated assets' or 'operations')
during the period from 1 July 2020 to 31 December 2020. Our
functions are also included.
BHP also holds interests in assets that are owned as a joint
venture but not operated by BHP (referred to in this release as
'non-operated joint ventures' or 'non-operated assets'). Our
non-operated assets include Antamina, Cerrejón, Samarco, Atlantis,
Mad Dog, Bass Strait and North West Shelf. Notwithstanding that
this release may include production, financial and other
information from non-operated assets, non-operated assets are not
included in the BHP Group and, as a result, statements regarding
our operations, assets and values apply only to our operated assets
unless stated otherwise.
(1) References in this release to a 'joint venture' are used for
convenience to collectively describe assets that are not wholly
owned by BHP. Such references are not intended to characterise the
legal relationship between the owners of the asset.
33
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34
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35
BHP
Financial Report
Half year ended
31 December 2020
36
Contents
Half Year Financial Statements Page
Consolidated Income Statement for the half year ended
31 December 2020 38
Consolidated Statement of Comprehensive Income for the
half year ended 31 December 2020 39
Consolidated Balance Sheet as at 31 December 2020 40
Consolidated Cash Flow Statement for the half year ended
31 December 2020 41
Consolidated Statement of Changes in Equity for the
half year ended 31 December 2020 42
Notes to the Financial Statements 43
1. Basis of preparation 43
2. Impact of new accounting standards and changes in
accounting policies 44
3. Exceptional items 45
4. Interests in associates and joint venture entities 47
5. Net finance costs 47
6. Income tax expense 48
7. Earnings per share 49
8. Dividends 50
9. Financial risk management - Fair values 51
10. Significant events - Samarco dam failure 53
11. Business combination 60
12. Subsequent events 60
Directors' Report 60
Directors' Declaration of Responsibility 63
Auditor's Independence Declaration to the Directors
of BHP Group Limited 64
Independent Review Report 65
37
Consolidated Income Statement for the half year ended 31
December 2020
Notes Half year Half year Year
ended ended ended
31 Dec 31 Dec 30 June
2020 2019 2020
US$M US$M US$M
Revenue 25,639 22,294 42,931
Other income 156 209 777
Expenses excluding net finance costs (15,570) (14,315) (28,775)
(Loss)/profit from equity accounted investments, related impairments and
expenses 4 (475) 126 (512)
Profit from operations 9,750 8,314 14,421
Financial expenses (972) (741) (1,262)
Financial income 48 217 351
Net finance costs 5 (924) (524) (911)
Profit before taxation 8,826 7,790 13,510
Income tax expense (3,981) (2,525) (4,708)
Royalty-related taxation (net of income tax benefit) (17) (75) (66)
Total taxation expense 6 (3,998) (2,600) (4,774)
Profit after taxation 4,828 5,190 8,736
Attributable to non-controlling interests 952 322 780
Attributable to BHP shareholders 3,876 4,868 7,956
Basic earnings per ordinary share (cents) 7 76.6 96.3 157.3
Diluted earnings per ordinary share (cents) 7 76.5 96.0 157.0
The accompanying notes form part of this half year Financial
Report .
38
Consolidated Statement of Comprehensive Income for the half year
ended 31 December 2020
Half year Half year Year
ended ended ended
31 Dec 31 Dec 30 June
2020 2019 2020
US$M US$M US$M
Profit after taxation 4,828 5,190 8,736
Other comprehensive income
Items that may be reclassified subsequently to the income statement:
Hedges:
Gains/(losses) taken to equity 1,074 13 (315)
(Gains)/losses transferred to the income statement (1,000) (26) 297
Exchange fluctuations on translation of foreign operations taken to equity - - 1
Tax recognised within other comprehensive income (22) 4 5
Total items that may be reclassified subsequently to the income statement 52 (9) (12)
Items that will not be reclassified to the income statement:
Re-measurement losses on pension and medical schemes (4) (7) (81)
Equity investments held at fair value 2 (1) (2)
Tax recognised within other comprehensive income 1 12 26
Total items that will not be reclassified to the income statement (1) 4 (57)
Total other comprehensive income/(loss) 51 (5) (69)
Total comprehensive income 4,879 5,185 8,667
Attributable to non-controlling interests 953 322 769
Attributable to BHP shareholders 3,926 4,863 7,898
The accompanying notes form part of this half year Financial
Report .
39
Consolidated Balance Sheet as at 31 December 2020
Notes 31 Dec 30 June
2020 2020
US$M US$M
Restated
ASSETS
Current assets
Cash and cash equivalents 9,291 13,426
Trade and other receivables 4,573 3,364
Other financial assets 227 84
Inventories 4,511 4,101
Current tax assets 295 366
Other 113 130
Total current assets 19,010 21,471
Non-current assets
Trade and other receivables 270 267
Other financial assets 2,269 2,522
Inventories 1,159 1,221
Property, plant and equipment 73,711 72,362
Intangible assets 2 1,508 1,574
Investments accounted for using the equity
method 2,094 2,585
Deferred tax assets 3,178 3,688
Other 34 43
Total non-current assets 84,223 84,262
Total assets 103,233 105,733
LIABILITIES
Current liabilities
Trade and other payables 5,663 5,767
Interest bearing liabilities 3,560 5,012
Other financial liabilities 237 225
Current tax payable 1,184 913
Provisions 2,631 2,810
Deferred income 86 97
Total current liabilities 13,361 14,824
Non-current liabilities
Trade and other payables - 1
Interest bearing liabilities 19,159 22,036
Other financial liabilities 1,187 1,414
Non-current tax payable 173 109
Deferred tax liabilities 2 3,603 3,779
Provisions 12,128 11,185
Deferred income 199 210
Total non-current liabilities 36,449 38,734
Total liabilities 49,810 53,558
Net assets 53,423 52,175
EQUITY
Share capital - BHP Group Limited 1,111 1,111
Share capital - BHP Group Plc 1,057 1,057
Treasury shares (30) (5)
Reserves 2,335 2,306
Retained earnings 2 44,449 43,396
Total equity attributable to BHP shareholders 48,922 47,865
Non-controlling interests 4,501 4,310
Total equity 53,423 52,175
The accompanying notes form part of this half year Financial
Report .
40
Consolidated Cash Flow Statement for the half year ended 31
December 2020
Half year Half year Year
ended ended ended
31 Dec 31 Dec 30 June
2020 2019 2020
US$M US$M US$M
Operating activities
Profit before taxation 8,826 7,790 13,510
Adjustments for:
Depreciation and amortisation expense 3,245 3,014 6,112
Impairments of property, plant and equipment, financial assets and intangibles 690 29 494
Net finance costs 924 524 911
Loss/(profit) from equity accounted investments, related impairments and expenses 475 (126) 512
Other 236 401 720
Changes in assets and liabilities:
Trade and other receivables (1,191) 100 291
Inventories (348) (441) (715)
Trade and other payables 70 (710) (755)
Provisions and other assets and liabilities (156) 436 1,188
Cash generated from operations 12,771 11,017 22,268
Dividends received 365 108 137
Interest received 60 221 385
Interest paid (450) (643) (1,225)
(Settlements)/proceeds of cash management related instruments (202) 69 85
Net income tax and royalty-related taxation refunded 202 5 48
Net income tax and royalty-related taxation paid (3,377) (3,335) (5,992)
Net operating cash flows 9,369 7,442 15,706
Investing activities
Purchases of property, plant and equipment (3,333) (3,405) (6,900)
Exploration expenditure (281) (390) (740)
Exploration expenditure expensed and included in operating cash flows 237 231 517
Investment in subsidiaries, operations and joint operations, net of cash (482) - -
Net investment and funding of equity accounted investments (362) (292) (618)
Proceeds from sale of assets 127 172 265
Other investing (115) (48) (140)
Net investing cash flows (4,209) (3,732) (7,616)
Financing activities
Proceeds from interest bearing liabilities 218 300 514
Proceeds/(settlements) of debt related instruments 90 - (157)
Repayment of interest bearing liabilities (6,200) (653) (2,047)
Purchase of shares by Employee Share Ownership Plan (ESOP) Trusts (174) (103) (143)
Dividends paid (2,767) (3,934) (6,876)
Dividends paid to non-controlling interests (762) (610) (1,043)
Net financing cash flows (9,595) (5,000) (9,752)
Net decrease in cash and cash equivalents (4,435) (1,290) (1,662)
Cash and cash equivalents, net of overdrafts, at the beginning of the period 13,426 15,593 15,593
Foreign currency exchange rate changes on cash and cash equivalents 300 18 (505)
Cash and cash equivalents, net of overdrafts, at the end of the period 9,291 14,321 13,426
The accompanying notes form part of this half year Financial
Report.
41
Consolidated Statement of Changes in Equity for the half year
ended 31 December 2020
Attributable to BHP shareholders
Share capital Treasury shares
Total equity
BHP BHP BHP BHP attributable
Group Group Group Group Retained to BHP Non- controlling Total
US$M Limited Plc Limited Plc Reserves earnings shareholders interests equity
Balance as at 1
July 2020
(restated) 1,111 1,057 (5) - 2,306 43,396 47,865 4,310 52,175
Total
comprehensive
income - - - - 53 3,873 3,926 953 4,879
Transactions with
owners:
Purchase of
shares by ESOP
Trusts - - (171) (3) - - (174) - (174)
Employee share
awards exercised
net of employee
contributions
net of tax - - 147 2 (106) (43) - - -
Vested employee
share awards
that have
lapsed, been
cancelled or
forfeited - - - - (2) 2 - - -
Accrued employee
entitlement for
unexercised
awards net of
tax - - - - 84 - 84 - 84
Dividends - - - - - (2,779) (2,779) (762) (3,541)
Balance as at 31
December 2020 1,111 1,057 (29) (1) 2,335 44,449 48,922 4,501 53,423
Balance as at 1
July 2019 1,111 1,057 (32) - 2,285 42,819 47,240 4,584 51,824
Impact of change
in accounting
policies (Note
2) - - - - - (71) (71) - (71)
Restated balance
as at 1 July
2019 1,111 1,057 (32) - 2,285 42,748 47,169 4,584 51,753
Total
comprehensive
income - - - - (8) 4,871 4,863 322 5,185
Transactions with
owners:
Purchase of
shares by ESOP
Trusts - - (101) (2) - - (103) - (103)
Employee share
awards exercised
net of employee
contributions
net of tax - - 119 2 (79) (42) - - -
Vested employee
share awards
that have
lapsed, been
cancelled or
forfeited - - - - (5) 5 - - -
Accrued employee
entitlement for
unexercised
awards net of
tax - - - - 68 - 68 - 68
Dividends - - - - - (3,946) (3,946) (610) (4,556)
Balance as at 31
December 2019
(restated) 1,111 1,057 (14) - 2,261 43,636 48,051 4,296 52,347
The accompanying notes form part of this half year Financial
Report.
42
Notes to the Financial Statements
1. Basis of preparation
This general purpose Financial Report for the half year ended 31
December 2020 is unaudited and has been prepared in accordance with
IAS 34 'Interim Financial Reporting' as issued by the International
Accounting Standards Board (IASB) and as adopted by the European
Union (EU), AASB 134 'Interim Financial Reporting' as issued by the
Australian Accounting Standards Board (AASB) and the Disclosure and
Transparency Rules of the Financial Conduct Authority in the United
Kingdom and the Australian Corporations Act 2001 as applicable to
interim financial reporting.
Segment Reporting disclosures from IAS 34/AASB 134 'Interim
Financial Reporting' have been disclosed within the Segment summary
on page 20 outside of this Financial Report.
The half year Financial Statements represent a 'condensed set of
Financial Statements' as referred to in the UK Disclosure Guidance
and Transparency Rules issued by the Financial Conduct Authority.
Accordingly, they do not include all of the information required
for a full annual report and are to be read in conjunction with the
most recent annual financial report. The comparative figures for
the financial year ended 30 June 2020 are not the statutory
accounts of the Group for that financial year. Those accounts,
which were prepared under IFRS, have been reported on by the
Company's auditor and delivered to the registrar of companies. The
auditor has reported on those accounts; the report was unqualified,
did not include a reference to any matters to which the auditors
drew attention by way of emphasis without qualifying their report
and did not contain statements under Section 498 (2) or (3) of the
UK Companies Act 2006.
The directors have made an assessment of the Group's ability to
continue as a going concern for the 12 months from the date of
approval of this Financial Report and consider it appropriate to
adopt the going concern basis of accounting in preparing the half
year Financial Statements.
The half year Financial Statements have been prepared on a basis
of accounting policies and methods of computation consistent with
those applied in the 30 June 2020 annual Financial Statements
contained within the Annual Report of the Group with the exception
of the following:
-- Adoption of amendments to existing accounting standards and
interpretations which became effective from 1 July 2020;
-- Adoption of the revised Conceptual Framework for Financial
Reporting which became effective from 1 July 2020;
-- Changes to Group's accounting policy for deferred taxes applied from 1 July 2020.
Note 2 'Impact of new accounting standards and changes in
accounting policies' describes the impact of the above, in the half
year Financial Statements. A number of other accounting standards
and interpretations, have been issued, and will be applicable in
future periods. While these remain subject to ongoing assessment,
no significant impacts have been identified to date. These
standards have not been applied in the preparation of these half
year Financial Statements.
All amounts are expressed in US dollars unless otherwise stated.
The Group's presentation currency and the functional currency of
the majority of its operations is US dollars as this is the
principal currency of the economic environment in which it
operates. Amounts in this Financial Report have, unless otherwise
indicated, been rounded to the nearest million dollars.
43
Impact of COVID-19 pandemic
The Group continues to actively monitor the impact of the
COVID-19 pandemic, including the impact on economic activity and
financial reporting. During the period the Group continued to
experience lower volumes at our operated assets and to incur
incremental directly attributable costs including those associated
with the increased provision of health and hygiene services, the
impacts of maintaining social distancing requirements and demurrage
and other standby charges related to delays caused by COVID-19.
These incremental costs have been classified as an exceptional
item, as outlined in note 3 'Exceptional items'.
As the pandemic continues to evolve, with the extent and timing
of impacts varying across the Group's key operating locations, it
is difficult to predict the full extent and duration of resulting
operational and economic impacts for the Group. This uncertainty
impacts judgements made by the Group, including those relating to
assessing collectability of receivables and determining the
recoverable values of the Group's non-current assets.
The ongoing uncertainty has also been considered in the Group's
assessment of the appropriateness of adopting the going concern
basis of preparation of the half year Financial Statements. The
Group's financial forecasts demonstrate that the Group believes
that it has sufficient financial resources to meet its obligations
as they fall due throughout the going concern period. As such, the
half year Financial Statements continue to be prepared on the going
concern basis.
2. Impact of new accounting standards and changes in accounting policies
Amended accounting standards
The adoption of amendments and revisions to accounting
pronouncements applicable from 1 July 2020, including the change in
definition of a business under the amendments to IFRS 3 'Business
Combinations' and revisions to the Conceptual Framework for
Financial Reporting did not have a significant impact on the
Group's Financial Statements.
Changes in accounting policies
On 29 April 2020, the IFRS Interpretations Committee issued a
decision on the application of IAS 12 'Income Tax' when the
recovery of the carrying amount of an asset gives rise to multiple
tax consequences, concluding that an entity must account for
distinct tax consequences separately. As a result, the Group has
changed its accounting policy for assets that have no deductible or
depreciable amount for income tax purposes, but do have a
deductible amount for capital gains tax (CGT) when determining
deferred tax. The Group's policy had been to use only the amount
deductible for CGT purposes whereas the Group will now account for
the distinct income tax and CGT consequences arising from the
expected manner of recovery. The assets impacted by the change
predominately relate to mineral rights.
Retrospective application of the accounting policy change has
resulted in the following adjustments:
Consolidated Balance Sheet
The consolidated balance sheet as at 1 July 2019 has been
updated for the following:
US$M
Increase in Deferred tax liabilities 1,021
Increase in Goodwill (included within Intangible assets) 950
Decrease in Retained earnings (71)
The goodwill recognised as a result of the change in accounting
policy relates to Olympic Dam and has been tested for impairment in
the period, with no impairment charge being required. The
comparative balance sheet as at 30 June 2020 has been restated to
reflect these amounts.
44
Consolidated Statement of Changes in Equity
The consolidated statement of changes in equity as at 1 July
2019 has been updated to reflect the reduction in retained earnings
of US$71 million.
Consolidated Income Statement, Consolidated Statement of
Comprehensive Income
The impact of the accounting policy change on the consolidated
income statement and consolidated statement of comprehensive income
is de minimus and therefore the comparative information has not
been restated.
Consolidated Cash Flow Statement
The change in accounting policy has no impact on the
consolidated cash flow statement.
3. Exceptional items
Exceptional items are those gains or losses where their nature,
including the expected frequency of the events giving rise to them,
and impact is considered material to the Financial Statements. Such
items included within the Group's profit for the half year are
detailed below.
Gross Tax Net
Half year ended 31 December 2020 US$M US$M US$M
Exceptional items by category
Samarco dam failure (358) (19) (377)
COVID-19 related costs (298) 79 (219)
Impairment of Energy coal assets and associated tax losses (927) (647) (1,574)
Total (1,583) (587) (2,170)
Attributable to non-controlling interests (15) 5 (10)
Attributable to BHP shareholders (1,568) (592) (2,160)
Samarco Mineração SA (Samarco) dam failure
The loss of US$377 million (after tax) related to the Samarco
dam failure in November 2015 comprises the following:
Half year ended 31 December 2020 US$M
Other income -
Expenses excluding net finance costs:
Costs incurred directly by BHP Brasil and other BHP entities in relation to the Samarco dam
failure (19)
Loss from equity accounted investments, related impairments and expenses:
Samarco impairment expense (90)
Samarco Germano dam decommissioning -
Samarco dam failure provision (300)
Fair value change on forward exchange derivatives 92
Net finance costs (41)
Income tax expense (19)
Total(1) (377)
(1) Refer to note 10 Significant events - Samarco dam failure
for further information.
COVID-19 related costs
COVID-19 can be considered a single protracted globally
pervasive event with financial impacts expected over a number of
reporting periods. The exceptional item reflects the directly
attributable COVID-19 pandemic related additional costs for the
Group for the half year ended 31 December 2020, including costs
associated with the increased provision of health and hygiene
services, the impacts of maintaining social distancing requirements
and demurrage and other standby charges related to delays caused by
COVID-19.
45
Impairment of Energy coal assets and associated tax losses
The Group recognised an impairment charge of US$1,194 million
(after tax) in relation to NSWEC and associated deferred tax
assets. This reflects current market conditions for Australian
thermal coal, the strengthening Australian dollar, changes to the
mine plan and updated assessment of the likelihood of recovering
tax losses.
The impairment charge of US$380 million (after tax) for Cerrejón
reflects current market conditions for thermal coal and the status
of the Group's intended exit.
Recoverable amount used for both assessments was determined
based on fair value less costs to sell.
The exceptional items relating to the half year ended 31
December 2019 and the year ended 30 June 2020 are detailed
below.
Gross Tax Net
Half year ended 31 December 2019 US$M US$M US$M
Exceptional items by category
Samarco dam failure (6) - (6)
Cancellation of power contracts (778) 271 (507)
Total (784) 271 (513)
Attributable to non-controlling interests (282) 87 (195)
Attributable to BHP shareholders (502) 184 (318)
Gross Tax Net
Year ended 30 June 2020 US$M US$M US$M
Exceptional items by category
Samarco dam failure (176) - (176)
Cancellation of power contracts (778) 271 (507)
COVID-19 related costs (183) 53 (130)
Cerro Colorado impairment (409) (83) (492)
Total (1,546) 241 (1,305)
Attributable to non-controlling interests (291) 90 (201)
Attributable to BHP shareholders (1,255) 151 (1,104)
46
4. Interests in associates and joint venture entities
The Group's major shareholdings in associates and joint venture
entities, including their (loss)/profit, are listed below:
Ownership interest at the Group's reporting (Loss)/profit from equity accounted investments,
date related impairments and expenses
31 Dec 31 Dec 30 June Half year ended Half year ended Year ended
2020 2019 2020 31 Dec 2020 31 Dec 2019 30 June 2020
% % % US$M US$M US$M
Share of profit/(loss) of equity
accounted investments:
Cerrej n 33.33 33.33 33.33 (30) (16) (68)
Compañia Minera
Antamina SA 33.75 33.75 33.75 275 160 212
Samarco
Mineração
SA(1) 50.00 50.00 50.00 - - -
Other (42) (54) (148)
Share of profit/(loss) of equity accounted investments 203 90 (4)
Samarco impairment
expense(1) (90) (27) (95)
Samarco dam failure provision(1) (300) 56 (459)
Samarco Germano dam decommissioning(1) - 7 46
Fair value change on forward exchange derivatives(1) 92 - -
Cerrej n impairment expense(2) (380) - -
(Loss)/profit from equity accounted investments, related impairments
and expenses (475) 126 (512)
(1) Refer to note 10 Significant events - Samarco dam failure
for further information.
(2) Refer to note 3 Exceptional items for further
information.
5. Net finance costs
Year
Half year ended Half year ended ended
31 Dec 31 Dec 30 June
2020 2019 2020
US$M US$M US$M
Financial expenses
Interest expense using the effective interest rate method:
Interest on bank loans, overdrafts and all other borrowings 346 593 1,099
Interest capitalised at 3.01% (31 December 2019: 4.51%; 30 June 2020:
4.14%)(1) (136) (155) (308)
Interest on lease liabilities 44 48 90
Discounting on provisions and other liabilities 238 256 452
Other gains and losses:
Fair value change on hedged loans (288) (12) 721
Fair value change on hedging derivatives 248 (6) (788)
Loss on bond repurchase(2) 395 - -
Exchange variations on net debt 121 12 (18)
Other 4 5 14
Total financial expenses 972 741 1,262
Financial income
Interest income (48) (217) (351)
Net finance costs 924 524 911
(1) Interest has been capitalised at the rate of interest
applicable to the specific borrowings financing the assets under
construction or, where financed through general borrowings, at a
capitalisation rate representing the average interest rate on such
borrowings.
(2) Relates to the additional cost on settlement of two
multi-currency hybrid debt repurchase programs and the unwind of
the associated hedges, included in a total cash payment of US$3,402
million disclosed in repayment of interest bearing liabilities in
the Cash Flow Statement.
47
6. Income tax expense
Year
Half year ended Half year ended ended
31 Dec 31 Dec 30 June
2020 2019 2020
US$M US$M US$M
Total taxation expense comprises:
Current tax expense 3,664 2,900 5,109
Deferred tax expense/(benefit) 334 (300) (335)
3,998 2,600 4,774
Year
Half year ended Half year ended ended
31 Dec 31 Dec 30 June
2020 2019 2020
US$M US$M US$M
Factors affecting income tax expense for the year
Income tax expense differs to the standard rate of corporation tax as
follows:
Profit before taxation 8,826 7,790 13,510
Tax on profit at Australian prima facie tax rate of 30 per cent 2,648 2,337 4,053
Non-tax effected operating losses and capital gains 1,342 201 707
Tax effect of (loss)/profit from equity accounted investments, related
impairments and expenses(1) 170 (38) 154
Tax on remitted and unremitted foreign earnings 114 148 225
Amounts under/(over) provided in prior years 65 (11) 64
Tax rate changes - - (8)
Recognition of previously unrecognised tax assets (5) (8) (30)
Investment and development allowance (68) (50) (99)
Foreign exchange adjustments (135) 5 20
Impact of tax rates applicable outside of Australia (245) (114) (167)
Other 95 55 (211)
Income tax expense 3,981 2,525 4,708
Royalty-related taxation (net of income tax benefit) 17 75 66
Total taxation expense 3,998 2,600 4,774
(1) The (loss)/profit from equity accounted investments and
related expenses is net of income tax, with the exception of the
Samarco forward exchange derivatives described in note 10
Significant events - Samarco dam failure. This item removes the
prima facie tax effect on such profits and related expenses,
excluding the impact of the Samarco forward exchange derivatives
which are taxable.
48
7. Earnings per share
Year
Half year ended Half year ended ended
31 Dec 31 Dec 30 June
2020 2019 2020
Earnings attributable to BHP shareholders (US$M)(1) 3,876 4,868 7,956
Weighted average number of shares (Million)
- Basic(2) 5,057 5,057 5,057
- Diluted(3) 5,069 5,070 5,069
Earnings per ordinary share (US cents)(4)
- Basic 76.6 96.3 157.3
- Diluted 76.5 96.0 157.0
Headline earnings per ordinary share (US cents)(5)
- Basic 98.8 97.1 171.1
- Diluted 98.6 96.8 170.7
(1) Diluted earnings attributable to BHP shareholders are equal
to earnings attributable to BHP shareholders.
(2) The calculation of the number of ordinary shares used in the
computation of basic earnings per share is the aggregate of the
weighted average number of ordinary shares of BHP Group Limited and
BHP Group Plc outstanding during the period after deduction of the
number of shares held by the Billiton Employee Share Ownership
Trust and the BHP Billiton Limited Employee Equity Trust.
(3) For the purposes of calculating diluted earnings per share,
the effect of 12 million of dilutive shares has been taken into
account for the half year ended 31 December 2020 (31 December 2019:
13 million shares; 30 June 2020: 12 million shares). The Group's
only potential dilutive ordinary shares are share awards granted
under employee share ownership plans. Diluted earnings per share
calculation excludes instruments which are considered
antidilutive.
At 31 December 2020, there are no instruments which are
considered antidilutive (31 December 2019: nil; 30 June 2020:
nil).
(4) Each American Depositary Share represents twice the earnings
for BHP ordinary shares.
(5) Headline earnings is a Johannesburg Stock Exchange defined
performance measure and is reconciled from earnings attributable to
ordinary shareholders as follows:
Year
Half year ended Half year ended ended
31 Dec 31 Dec 30 June
2020 2019 2020
US$M US$M US$M
Earnings attributable to BHP shareholders 3,876 4,868 7,956
Adjusted for:
Loss/(gain) on sales of PP&E, Investments and Operations(i) 3 (7) 4
Impairments of property, plant and equipment, financial assets and
intangibles 690 29 494
Samarco impairment expense 90 27 95
Cerrej n impairment expense 380 - -
Other(ii) - - 48
Tax effect of above adjustments (41) (7) 54
Subtotal of adjustments 1,122 42 695
Headline earnings 4,998 4,910 8,651
Diluted headline earnings 4,998 4,910 8,651
(i) Included in other income.
(ii) Mainly represent BHP share of impairment embedded in the
statutory income statement of the Group's equity accounted
investments.
49
8. Dividends
Half year ended Half year ended Year ended
31 Dec 2020 31 Dec 2019 30 June 2020
Per share Total Per share Total Per share Total
US cents US$M US cents US$M US cents US$M
Dividends paid during the period(1)
Prior year final dividend 55.0 2,779 78.0 3,946 78.0 3,946
Interim dividend N/A - N/A - 65.0 3,288
55.0 2,779 78.0 3,946 143.0 7,234
(1) 5.5 per cent dividend on 50,000 preference shares of GBP1
each determined and paid annually (31 December 2019: 5.5 per cent;
30 June 2020: 5.5 per cent).
Dividends paid during the period differs from the amount of
dividends paid in the Cash Flow Statement as a result of foreign
exchange gains and losses relating to the timing of equity
distributions between the record date and the payment date. An
additional derivative settlement of US$13 million was made as part
of the funding of the final dividend and is disclosed in
(Settlements)/proceeds of cash management related instruments in
the Cash Flow Statement.
The Dual Listed Company merger terms require that ordinary
shareholders of BHP Group Limited and BHP Group Plc are paid equal
cash dividends on a per share basis. Each American Depositary Share
(ADS) represents two ordinary shares of BHP Group Limited or BHP
Group Plc. Dividends determined on each ADS represent twice the
dividend determined on BHP ordinary shares.
Dividends are determined after period-end and contained within
the announcement of the results for the period. Interim dividends
are determined in February and paid in March. Final dividends are
determined in August and paid in September. Dividends determined
are not recorded as a liability at the end of the period to which
they relate. Subsequent to the half year, on 16 February 2021, BHP
Group Limited and BHP Group Plc determined an interim ordinary
dividend of US$1.01 per share (US$5,107 million), which will be
paid on 23 March 2021 (31 December 2019: interim dividend of 65.0
US cents per share - US$3,287 million; 30 June 2020: final dividend
of 55.0 US cents per share - US$2,782 million).
At 31 December 2020, BHP Group Limited had 2,945 million
ordinary shares on issue and held by the public and BHP Group Plc
had 2,112 million ordinary shares on issue and held by the public.
No shares in BHP Group Limited were held by BHP Group Plc at 31
December 2020 (31 December 2019: nil; 30 June 2020: nil).
BHP Group Limited dividends for all periods presented are, or
will be, fully franked based on a tax rate of 30 per cent.
50
9. Financial risk management - Fair values
All financial assets and financial liabilities, other than
derivatives and trade receivables, are initially recognised at the
fair value of consideration paid or received, net of transaction
costs as appropriate. Financial assets are initially recognised on
their trade date. Financial assets are subsequently carried at fair
value or amortised cost based on the Group's purpose, or business
model, for holding the financial asset and whether the financial
asset's contractual terms give rise to cash flows that are solely
payments of principal and interest.
With the exception of derivative contracts and provisionally
priced trade payables, the Group's financial liabilities are
classified as subsequently measured at amortised cost. The Group
may in addition elect to designate certain financial assets or
liabilities at fair value through profit or loss or to apply hedge
accounting where they are not mandatorily held at fair value
through profit or loss. Derivatives are initially recognised at
fair value on the date the contract is entered into and are
subsequently remeasured at their fair value.
The carrying amount of financial assets and liabilities measured
at fair value is principally calculated based on inputs other than
quoted prices that are observable for these financial assets or
liabilities, either directly (i.e. as unquoted prices) or
indirectly (i.e. derived from prices). Where no price information
is available from a quoted market source, alternative market
mechanisms or recent comparable transactions, fair value is
estimated based on the Group's views on relevant future prices, net
of valuation allowances to accommodate liquidity, modelling and
other risks implicit in such estimates.
The inputs used in fair value calculations are determined by the
relevant segment or function. The functions support the assets and
operate under a defined set of accountabilities authorised by the
Executive Leadership Team. Movements in the fair value of financial
assets and liabilities may be recognised through the income
statement or in other comprehensive income.
For financial assets and liabilities carried at fair value, the
Group uses the following to categorise the method used based on the
lowest level input that is significant to the fair value
measurement as a whole:
IFRS 13 Fair value
hierarchy Level 1 Level 2 Level 3
Valuation method Based on quoted prices Based on inputs other than Based on inputs not
(unadjusted) in active quoted prices included observable in the market
markets for identical within Level 1 that are using appropriate valuation
financial assets and observable for the models, including
liabilities. financial asset or discounted cash flow
liability, either directly modelling.
(i.e. as unquoted prices)
or indirectly (i.e.
derived from prices).
The financial assets and liabilities are presented by class in
the following table at their carrying values, which generally
approximate to fair value. In the case of US$3,019 million (30 June
2020: US$3,019 million) of fixed rate debt not swapped to floating
rate, the fair value at 31 December 2020 was US$4,343 million (30
June 2020: US$4,114 million). The fair value is determined using a
method that can be categorised as Level 2 and uses inputs based on
benchmark interest rates, alternative market mechanisms or recent
comparable transactions.
For financial instruments that are carried at fair value on a
recurring basis, the Group determines whether transfers have
occurred between levels in the hierarchy by reassessing
categorisation at the end of each reporting period. There were no
transfers between categories during the period.
51
Financial assets and liabilities
IFRS
13 Fair 30 June
value 31 Dec 2020
hierarchy 2020 US$M
Level(1) IFRS 9 Classification US$M Restated
Current cross currency Fair value through profit
and interest rate swaps(2) 2 or loss 155 3
Current other derivative Fair value through profit
contracts(3) 2,3 or loss 61 45
Fair value through profit
Current other investments(4) 1,2 or loss 11 36
Non-current cross currency
and interest rate swaps Fair value through profit
(2) 2 or loss 1,702 2,009
Non-current other derivative Fair value through profit
contracts(3) 2,3 or loss 211 159
Non-current investment Fair value through other
in shares 3 comprehensive income 35 32
Fair value through profit
Non-current other investments(4)(5) 1,2,3 or loss 321 322
Total other financial assets 2,496 2,606
Cash and cash equivalents Amortised cost 9,291 13,426
Trade and other receivables(6) Amortised cost 2,201 1,633
Provisionally priced trade Fair value through profit
receivables 2 or loss 2,117 1,480
Loans to equity accounted
investments Amortised cost 40 40
Total financial assets 16,145 19,185
Non-financial assets 87,088 86,548
Total assets 103,233 105,733
Current cross currency Fair value through profit
and interest rate swaps(2) 2 or loss - 165
Current other derivative Fair value through profit
contracts(3) 2,3 or loss 155 60
Current other financial Amortised cost 82 -
liabilities(7)
Non-current cross currency Fair value through profit
and interest rate swaps(2) 2 or loss 641 1,414
Non-current other financial Amortised cost 546 -
liabilities(7)
Total other financial liabilities 1,424 1,639
Trade and other payables(8) Amortised cost 5,096 5,354
Provisionally priced trade Fair value through profit
payables 2 or loss 461 269
Bank loans(9) Amortised cost 2,304 2,492
Notes and debentures(9) Amortised cost 16,856 21,045
Lease liabilities 3,559 3,443
Other(9) Amortised cost - 68
Total financial liabilities 29,700 34,310
Non-financial liabilities 20,110 19,248
Total liabilities 49,810 53,558
(1) All of the Group's financial assets and financial
liabilities recognised at fair value were valued using market
observable inputs categorised as Level 2 with the exception of the
specified items in the following footnotes.
(2) Cross currency and interest rate swaps are measured at
forward rate and swap models and present value calculations.
(3) Includes other derivative contracts of US$179 million (30
June 2020: US$179 million) categorised as Level 3. Significant
items are derivatives embedded in physical commodity purchase and
sales contracts of gas in Trinidad and Tobago with net assets fair
value of US$179 million (30 June 2020: US$180 million).
(4) Includes investments held by BHP Foundation which are
restricted and not available for general use by the Group of US$285
million (30 June 2020: US$296 million) of which other investments
(US Treasury Notes) of US$83 million is categorised as Level 1 (30
June 2020: US$87 million).
(5) Includes other investments of US$47 million (30 June 2020:
US$47 million) categorised as Level 3.
(6) Excludes input taxes of US$485 million (30 June 2020: US$478
million) included in other receivables.
(7) Includes the discounted settlement liability in relation to
the cancellation of power contracts at the Group's Escondida
operations.
(8) Excludes input taxes of US$106 million (30 June 2020: US$145
million) included in other payables.
(9) All interest bearing liabilities, excluding lease
liabilities, are unsecured.
52
Sensitivity of level 3 financial assets and liabilities
Financial instruments categorised as Level 3 are shares, other
investments, and other derivative contracts. The potential effect
of using reasonably possible alternative assumptions in these
models, based on a change in the most significant input, such as
commodity prices, by an increase/(decrease) of 10 per cent while
holding all other variables constant will increase/(decrease)
profit after taxation by US$25 million (31 December 2019: US$36
million).
10. Significant events - Samarco dam failure
As a result of the Samarco dam failure on 5 November 2015, BHP
Billiton Brasil Ltda (BHP Brasil) and other Group entities continue
to incur costs and maintain liabilities for future costs. The
information presented in this note should be read in conjunction
with section 1.8 'Samarco' and Financial Statements note 4
'Significant events - Samarco dam failure' in the 30 June 2020
Annual Report.
The financial impacts of the Samarco dam failure on the Group's
income statement, balance sheet and cash flow statement for the
half year ended 31 December 2020 are shown below and have been
treated as an exceptional item.
Half year Half year Year
ended ended ended
31 Dec 31 Dec 30 June
2020 2019 2020
Financial impacts of Samarco dam failure US$M US$M US$M
Income statement
Other income(1) - 40 489
Expenses excluding net finance costs:
Costs incurred directly by BHP Brasil and other BHP entities in relation to the
Samarco dam
failure(2) (19) (25) (64)
Loss from equity accounted investments, related impairments and expenses:
Samarco impairment expense(3) (90) (27) (95)
Samarco Germano dam decommissioning(4) - 7 46
Samarco dam failure provision(5) (300) 56 (459)
Fair value change on forward exchange derivatives(6) 92 - -
(Loss)/profit from operations (317) 51 (83)
Net finance costs(7) (41) (57) (93)
Loss before taxation (358) (6) (176)
Income tax expense(8) (19) - -
Loss after taxation (377) (6) (176)
Balance sheet movement
Trade and other payables 6 - (5)
Derivatives (net of taxes payable) 73 - -
Provisions (114) 186 (137)
Net (liabilities)/assets (35) 186 (142)
53
Half year ended Half year ended Year ended
31 Dec 2020 31 Dec 2019 30 June 2020
US$M US$M US$M
Cash flow statement
Loss before taxation (358) (6) (176)
Adjustments for:
Samarco impairment expense(3) 90 27 95
Samarco Germano dam decommissioning(4) - (7) (46)
Samarco dam failure provision(5) 300 (56) 459
Fair value change on forward exchange derivatives(6) (92) - -
Net finance costs(7) 41 57 93
Changes in assets and liabilities:
Trade and other payables (6) - 5
Net operating cash flows (25) 15 430
Net investment and funding of equity accounted investments(9) (317) (207) (464)
Net investing cash flows (317) (207) (464)
Net decrease in cash and cash equivalents (342) (192) (34)
(1) Proceeds from insurance settlements.
(2) Includes legal and advisor costs incurred.
(3) Impairment expense from working capital funding provided
during the period.
(4) US$12 million change in estimate and US$(12) million
exchange translation.
(5) US$(205) million change in estimate and US$(95) million
exchange translation.
(6) During the period the Group entered into forward exchange
contracts to limit the Brazilian reais exposure on the dam failure
provisions. While not applying hedge accounting, the fair value
changes in the forward exchange instruments are recorded within
(Loss)/profit from equity accounted investments, related
impairments and expenses in the Income Statement.
(7) Amortisation of discounting of provision.
(8) Income tax on forward exchange derivatives.
(9) Includes US$(90) million funding provided during the period,
US$(221) million utilisation of the Samarco dam failure provision
and US$(6) million utilisation of the Samarco Germano
decommissioning provision.
54
Equity accounted investment in Samarco
BHP Brasil's investment in Samarco remains at US$ nil. BHP
Brasil provided US$90 million funding under a working capital
facility during the period and recognised impairment losses of
US$90 million. No dividends have been received by BHP Brasil from
Samarco during the period and Samarco currently does not have
profits available for distribution.
Provisions related to the Samarco dam failure
31 Dec 2020 30 June 2020
US$M US$M
At the beginning of the reporting period 2,051 1,914
Movement in provisions 114 137
Comprising:
Utilised (227) (369)
Adjustments charged to the income statement:
Change in estimate - Samarco dam failure provision 205 916
Change in estimate - Samarco Germano dam decommissioning (12) 37
Amortisation of discounting impacting net finance costs 41 93
Exchange translation 107 (540)
At the end of the reporting period 2,165 2,051
Comprising:
Current 622 896
Non-current 1,543 1,155
At the end of the reporting period 2,165 2,051
Comprising:
Samarco dam failure provision 1,939 1,824
Samarco Germano dam decommissioning provision 226 227
Provision for Samarco dam failure
On 2 March 2016, BHP Brasil, Samarco and Vale, entered into an
agreement with the Federal Government of Brazil, the states of
Espírito Santo and Minas Gerais and certain other public
authorities to establish a foundation (Fundação Renova) to develop
and execute environmental and socio-economic programs (Programs) to
remediate and provide compensation for damage caused by the Samarco
dam failure (the Framework Agreement). Key Programs include those
for financial assistance and compensation of impacted persons,
including fisherfolk impacted by the dam failure, and those for
remediation of impacted areas and resettlement of impacted
communities. A committee (Interfederative Committee) comprising
representatives from the Brazilian Federal and State Governments,
local municipalities, environmental agencies, impacted communities
and Public Defence Office oversees the activities of the Fundação
Renova in order to monitor, guide and assess the progress of
actions agreed in the Framework Agreement. In addition, the 12th
Federal Court is supervising the work of the Fundação Renova and
the Court's decisions relating to financial compensation for
impacted persons have been considered in the Samarco dam failure
provision. Further decisions are anticipated during the second half
of FY2021.
To the extent that Samarco does not meet its funding obligations
during the 15 year term of the Framework Agreement, each of BHP
Brasil and Vale has funding obligations under the Framework
Agreement in proportion to its 50 per cent shareholding in
Samarco.
Samarco recommenced operations in December 2020, however, there
remains significant uncertainty regarding Samarco's future cash
flow generation. In light of these uncertainties and based on
currently available information, BHP Brasil's provision for its
obligations under the Framework Agreement Programs is US$1.9
billion before tax and after discounting at 31 December 2020 (30
June 2020: US$1.8 billion).
55
Under a Governance Agreement ratified on 8 August 2018, BHP
Brasil, Samarco and Vale were to establish a process to renegotiate
the Programs over two years to progress settlement of the R$155
billion (approximately US$30 billion) Federal Public Prosecution
Office claim (described below). Pre-requisites established in the
Governance Agreement, for re-negotiation of the Framework Agreement
were not implemented during the two year period and on 30 September
2020, Brazilian Federal and State prosecutors and public defenders
filed a request for the immediate resumption of the R$155 billion
(approximately US$30 billion) claim, which has been suspended from
the date of ratification of the Governance Agreement. A decision
from the court remains pending.
BHP Brasil, Samarco and Vale maintain security comprising R$1.3
billion (approximately US$250 million) in insurance bonds and a
charge of R$800 million (approximately US$155 million) over
Samarco's assets. A further R$100 million (approximately US$20
million) in liquid assets previously maintained as security was
released during FY2020 for COVID-19 related response efforts in
Brazil. The security was maintained for a period of 30 months from
ratification of the Governance Agreement, after which BHP Brasil,
Vale and Samarco will maintain security of an amount equal to the
Fundação Renova's annual budget up to a limit of R$2.2 billion
(approximately US$425 million).
Samarco Germano dam decommissioning
Samarco is currently progressing plans for the accelerated
decommissioning of its upstream tailings dams (the Germano dam
complex). Given the significant uncertainties surrounding Samarco's
future cash flow generation, BHP Brasil's provision for a 50 per
cent share of the expected Germano decommissioning costs is US$226
million at 31 December 2020 (30 June 2020: US$227 million). Plans
for the decommissioning are at an early engineering level and as a
result, further engineering work and required validation by
Brazilian authorities could lead to material changes to estimates
in future reporting periods.
Contingent liabilities
The following matters are disclosed as contingent liabilities
and given the status of proceedings it is not possible to provide a
range of possible outcomes or a reliable estimate of potential
future exposures for BHP, unless otherwise stated. Ultimately, all
the legal matters disclosed as contingent liabilities could have a
material adverse impact on BHP's business, competitive position,
cash flows, prospects, liquidity and shareholder returns.
Federal Public Prosecution Office claim
BHP Brasil is among the defendants named in a claim brought by
the Federal Public Prosecution Office on 3 May 2016, seeking R$155
billion (approximately US$30 billion) for reparation, compensation
and moral damages in relation to the Samarco dam failure.
The 12th Federal Court previously suspended the Federal Public
Prosecution Office claim, including a R$7.7 billion (approximately
US$1.5 billion) injunction request. On 30 September 2020, Brazilian
Federal and State prosecutors and public defenders filed a request
for the immediate resumption of the R$155 billion (approximately
US$30 billion) claim, which has been suspended since the date of
ratification of the Governance Agreement. A decision from the court
remains pending.
United States class action complaint - Samarco bond holders
On 14 November 2016, a putative class action complaint
(Bondholder Complaint) was filed in the U.S. District Court for the
Southern District of New York on behalf of purchasers of Samarco's
ten-year bond notes (Plaintiff) due 2022-2024 between 31 October
2012 and 30 November 2015. The Bondholder Complaint was initially
filed against Samarco and the former chief executive officer of
Samarco.
56
The Bondholder Complaint was subsequently amended to include BHP
Group Limited, BHP Group Plc, BHP Brasil, Vale S.A. and officers of
Samarco, including four of Vale S.A. and BHP Brasil's nominees to
the Samarco Board. On 5 April 2017, the Plaintiff discontinued its
claims against the individual defendants.
The complaint, along with a second amended complaint, has
previously been dismissed by the Court. The Plaintiff filed a
motion for reconsideration, or leave to file a third amended
complaint, which was denied by the Court on 30 October 2019. The
Plaintiff has appealed this decision and the appeal remains pending
before the Court.
Australian class action complaints
Three separate shareholder class actions were filed in the
Federal Court of Australia on behalf of persons who acquired shares
in BHP Group Ltd on the Australian Securities Exchange or shares in
BHP Group Plc on the London Stock Exchange and Johannesburg Stock
Exchange in periods prior to the Samarco dam failure.
Following an appeal to the Full Court of the Federal Court, two
of the actions have been consolidated into one action and the third
action was permanently stayed. The amount of damages sought in the
consolidated action is unspecified.
United Kingdom group action complaint
BHP Group Plc and BHP Group Ltd were named as defendants in
group action claims for damages filed in the courts of England.
These claims were filed on behalf of certain individuals,
governments, businesses and communities in Brazil allegedly
impacted by the Samarco dam failure. On 9 November 2020, the court
dismissed the claims. The decision is still subject to appeal.
Criminal charges
The Federal Prosecutors' Office has filed criminal charges
against BHP Brasil, Samarco and Vale and certain employees and
former employees of BHP Brasil (Affected Individuals) in the
Federal Court of Ponte Nova, Minas Gerais. On 3 March 2017, BHP
Brasil filed its preliminary defences. The Federal Court terminated
the charges against eight of the Affected Individuals. The Federal
Prosecutors' Office has appealed seven of those decisions with
hearings of the appeals still pending. BHP Brasil rejects outright
the charges against the company and the Affected Individuals and
will defend the charges and fully support each of the Affected
Individuals in their defence of the charges.
Other claims
BHP Brasil is among the companies named as defendants in a
number of legal proceedings initiated by individuals,
non-governmental organisations (NGOs), corporations and
governmental entities in Brazilian Federal and State courts
following the Samarco dam failure. The other defendants include
Vale, Samarco and Fundação Renova. The lawsuits include claims for
compensation, environmental rehabilitation and violations of
Brazilian environmental and other laws, among other matters. The
lawsuits seek various remedies including rehabilitation costs,
compensation to injured individuals and families of the deceased,
recovery of personal and property losses, moral damages and
injunctive relief. In addition, government inquiries and
investigations relating to the Samarco dam failure have been
commenced by numerous agencies of the Brazilian government and are
ongoing.
Additional lawsuits and government investigations relating to
the Samarco dam failure could be brought against BHP Brasil and
possibly other BHP entities in Brazil or other jurisdictions.
57
BHP insurance
BHP has various third party liability insurances for claims
related to the Samarco dam failure made directly against BHP Brasil
or other BHP entities, their directors and officers, including
class actions. External insurers have been notified of the Samarco
dam failure, the third party claims and the class actions referred
to above and in the period since the dam failure to 31 December
2020, the Group has recognised US$539 million other income from
insurance proceeds relating to the dam failure.
As at 31 December 2020, an insurance receivable has not been
recognised for any potential recoveries in respect of ongoing
matters.
Commitments
Under the terms of the Samarco joint venture agreement, BHP
Brasil does not have an existing obligation to fund Samarco.
BHP has agreed to fund a total of US$765 million for the Renova
Foundation programs and Samarco's working capital during calendar
year 2021. This comprises US$725 million relating to Renova
Foundation programs until 31 December 2021, which will be offset
against the Group's provision for the Samarco dam failure, and a
short-term working capital facility of up to US$40 million to be
made available to Samarco until 31 December 2021. Any additional
requests for funding or future investment provided would be subject
to a future decision by BHP, accounted for at that time.
58
Key judgements and estimates
Judgements
The outcomes of litigation are inherently difficult to predict and significant
judgement has been applied in assessing the likely outcome of legal
claims and determining which legal claims require recognition of a provision
or disclosure of a contingent liability. The facts and circumstances
relating to these cases are regularly evaluated in determining whether
a provision for any specific claim is required.
Management have determined that a provision can only be recognised for
obligations under the Framework Agreement and Samarco Germano dam decommissioning
as at 31 December 2020. It is not yet possible to provide a range of
possible outcomes or a reliable estimate of potential future exposures
to BHP in connection to the contingent liabilities noted above, given
their status.
Estimates
The provisions for Samarco dam failure and Samarco Germano dam decommissioning
currently reflect the estimated remaining costs to complete Programs
under the Framework Agreement and estimated costs to complete the Germano
dam decommissioning and require the use of significant judgements, estimates
and assumptions. Based on current estimates, it is expected that approximately
75 per cent of remaining costs for Programs under the Framework Agreement
will be incurred by December 2022.
While the provisions have been measured based on information available
as at 31 December 2020, likely changes in facts and circumstances in
future reporting periods may lead to revisions to these estimates. However,
it is currently not possible to determine what facts and circumstances
may change, therefore the possible revisions in future reporting periods
cannot be reliably measured.
The key estimates that may have a material impact upon the provisions
in the next and future reporting periods include:
* number of people eligible for financial assistance
and compensation and the corresponding amount of
expected compensation; and
* costs to complete resettlement of the Bento Rodrigues,
Gesteira and Paracatu communities.
The provision may also be affected by factors including but not limited
to:
* resolution of existing and potential legal claims;
* potential changes in scope of work and funding
amounts required under the Framework Agreement
including the impact of the decisions of the
Interfederative Committee along with further
technical analysis and community participation
required under the Governance Agreement and rulings
made by the 12(th) Federal Court;
* timing of repealing the fishing ban along the Rio
Doce, which is subject to certain regulatory
approvals and could impact upon the length of certain
financial assistance and compensation payments;
* the outcome of ongoing negotiations with State and
Federal Prosecutors, including review of
Fundação Renova's Programs as provided in
the Governance Agreement ;
* actual costs incurred;
* resolution of uncertainty in respect of the nature
and extent of Samarco's future operations;
* costs to complete the Germano dam decommissioning;
and
* updates to discount and foreign exchange rates.
Given these factors, future actual expenditures may differ from the
amounts currently provided and changes to key assumptions and estimates
could result in a material impact to the provision in the next and future
reporting periods.
59
11. Business combination
In October 2020, the Group signed a Membership Interest Purchase
and Sale Agreement with Hess Corporation (Hess) to acquire an
additional 28 per cent working interest in Shenzi, a six-lease
development in the deepwater Gulf of Mexico. The transaction was
completed on 6 November 2020 for a purchase price of US$482 million
before customary post-closing adjustments.
The transaction increases the Group's working interest from 44
per cent to 72 per cent. Shenzi will continue to be accounted for
as a joint operation because BHP continues to have joint
decision-making rights with the other joint venture partner
(Repsol). The assets and liabilities related to the acquired
interests have been accounted for in line with the principles of
IFRS 3 'Business Combinations' with no remeasurement of the Group's
previous interest. The acquisition resulted in provisional
increases in assets of US$661 million and liabilities of US$179
million.
Provisional estimates of fair value of the identifiable assets
and liabilities approximate the consideration paid to Hess and
therefore no goodwill or bargain purchase gain has been recognised
for the acquisition. The fair values are provisional due to the
complexity of the valuation process. The finalisation of the fair
value of the assets and liabilities acquired will be completed
within 12 months of the acquisition.
There were no other significant acquisitions during the half
year ended 31 December 2020, half year ended 31 December 2019 or
the year ended 30 June 2020.
12. Subsequent events
Other than the matters outlined elsewhere in this Financial
Report, no matters or circumstances have arisen since the end of
the half year that have significantly affected, or may
significantly affect, the operations, results of operations or
state of affairs of the Group in subsequent accounting periods.
Directors' Report
The Directors present their report together with the half year
Financial Statements for the half year ended 31 December 2020 and
the auditor's review report thereon.
Review of Operations
A detailed review of the Group's operated and non-operated
assets, the results of those operations during the half year ended
31 December 2020 and likely future developments are given on pages
1 to 33. The Review of Operations has been incorporated into, and
forms part of, this Directors' Report.
60
Principal Risks and Uncertainties
Due to the international scope of the Group's operated and
non-operated assets and the industries in which it is engaged,
there are a number of risk factors and uncertainties which could
have an effect on the Group's results and operations over the next
six months. The principal risks affecting the Group are described
on pages 31 to 43 of the Group's Annual Report for the year ended
30 June 2020 (a copy of which is available on the Group's website
at www.bhp.com) and are grouped into the following categories of
risks. There are no material changes in those risk factors for the
six months of this financial year except to the extent described in
the 'Outlook' section.
* Asset integrity and tailings storage facilities: * Climate change: Risks associated with changes in
Risks associated with operational integrity, tailings climate patterns, as well as risks arising from
storage facilities and performance of our assets. policy, regulatory, legal, technological, market or
other societal responses to the challenges posed by
climate change.
* Occupational and process safety (including * Cybersecurity: Cyber-related risk events, including
geotechnical failures and underground fires or attacks on our enterprise or incidents relating to
explosions): Risks associated with the safety of BHP human error, online and web-based operations and
employees and contractors in performing their work infrastructure.
and the containment of hazardous materials.
* Geopolitics and stakeholder relations (including * Third party performance: Risks associated with
access to markets): Risks associated with non-operated joint ventures and the delivery of
geopolitical changes and government actions that products and services by third parties engaged by BHP,
affect the macroeconomic outlook, commodity demand including contractors.
and supply and/or impact our ability to access
resources, markets and the operational or other
inputs needed to realise our strategy; as well as
relationships with key stakeholders whose support is
needed to realise our strategy and purpose.
* Capital allocation, and assets and growth options: * Legal, regulatory, ethics and compliance: Risks
Risks associated with the allocation of capital associated with legal, regulatory, ethics and
through annual planning and other processes, to make compliance obligations.
investment decisions and to discover, maintain and
grow assets suited to our capabilities and strategy.
* Commodity prices: Risks associated with the prices of * Balance sheet and liquidity: Risks associated with
commodities, including sustained price shifts our ability to maintain a robust and effective
relative to the price of extraction. balance sheet, raise debt, return value to
shareholders and remain financially liquid.
* Community and human rights: Risks that have the
potential to impact human rights and/or communities
and affect support for our business with stakeholders,
including communities, governments or the general
public.
61
Dividend
Full details of dividends are given on page 19.
Board of Directors
The Directors of BHP at any time during or since the end of the
half year are:
Ken MacKenzie - Chairman since September 2017 (a Director since
September 2016)
Mike Henry - an Executive Director since January 2020
Terry Bowen - a Director since October 2017
Malcolm Broomhead - a Director since March 2010
Xiaoqun Clever - a Director since October 2020
Ian Cockerill - a Director since April 2019
Anita Frew - a Director since September 2015
Gary Goldberg - a Director since February 2020
Susan Kilsby - a Director since April 2019
Lindsay Maxsted - a former Director from March 2011 to September
2020
John Mogford - a Director since October 2017
Christine O'Reilly - a Director since October 2020
Shriti Vadera - a former Director from January 2011 to October
2020
Dion Weisler - a Director since June 2020
Auditor's independence declaration
Ernst & Young in Australia are the auditors of BHP Group
Limited. Their auditor's independence declaration under Section
307C of the Australian Corporations Act 2001 is set out on page 59
and forms part of this Directors' Report.
Rounding of amounts
BHP Group Limited is an entity to which Australian Securities
and Investments Commission (ASIC) Corporations (Rounding in
Financial/Directors' Reports) Instrument 2016/191 dated 24 March
2016 applies. Amounts in the Directors' Report and half year
Financial Statements have been rounded to the nearest million
dollars in accordance with ASIC Instrument 2016/191.
Signed in accordance with a resolution of the Board of
Directors.
Ken MacKenzie - Chairman
Mike Henry - Chief Executive Officer
Dated this 16th day of February 2021
62
Directors' Declaration of Responsibility
The half year Financial Report is the responsibility of, and has
been approved by, the Directors. In accordance with a resolution of
the Directors of BHP Group Limited and BHP Group Plc, the Directors
declare that:
(a) in the Directors' opinion and to the best of their
knowledge, the half year Financial Statements and notes, set out on
pages 35 to 55, have been prepared in accordance with IAS 34
'Interim Financial Reporting' as issued by the IASB, IAS 34
'Interim Financial Reporting' as adopted by the EU, AASB 134
'Interim Financial Reporting' as issued by the AASB, the Disclosure
Guidance and Transparency Rules of the Financial Conduct Authority
in the United Kingdom and the Australian Corporations Act 2001,
including:
(i) complying with applicable accounting standards and the
Australian Corporations Regulations 2001; and
(ii) giving a true and fair view of the financial position of
the Group as at 31 December 2020 and of its performance for the
half year ended on that date;
(b) to the best of the Directors' knowledge, the Directors'
Report, which incorporates the Review of Operations on pages 1 to
33, includes a fair review of the information required by:
(i) DTR4.2.7R of the Disclosure Guidance and Transparency Rules
in the United Kingdom, being an indication of important events
during the first six months of the current financial year and their
impact on the half year Financial Statements, and a description of
the principal risks and uncertainties for the remaining six months
of the year; and
(ii) DTR4.2.8R of the Disclosure Guidance and Transparency Rules
in the United Kingdom, being related party transactions that have
taken place in the first six months of the current financial year
and that have materially affected the financial position or
performance of the Group during that period, and any changes in the
related party transactions described in the last annual report that
could have such a material effect; and
(c) in the Directors' opinion, there are reasonable grounds to
believe that each of BHP Group Limited, BHP Group Plc and the Group
will be able to pay its debts as and when they become due and
payable.
Signed on behalf of the Directors in accordance with a
resolution of the Board of Directors.
Ken MacKenzie - Chairman
Mike Henry - Chief Executive Officer
Dated this 16th day of February 2021
63
Auditor's Independence Declaration to the Directors of BHP Group
Limited
As lead auditor for the review of the half year financial report
of BHP Group Limited for the half year ended 31 December 2020, I
declare to the best of my knowledge and belief, there have
been:
a) No contraventions of the auditor independence requirements of
the Corporations Act 2001 in relation to the review; and
b) No contraventions of any applicable code of professional conduct in relation to the review.
This declaration is in respect of BHP Group Limited and the
entities it controlled during the financial period.
Ernst & Young
Tim Wallace
Partner
16 February 2021
64
Independent Review Report
Independent Auditors' Review Report of Ernst & Young ('EY
Australia') to the members of BHP Group Limited and Ernst &
Young LLP ('EY UK') to the members of BHP Group Plc
For the purpose of these reports, and unless otherwise stated,
the terms 'we' and 'our' denote both EY Australia in relation to
Australian responsibilities and reporting obligations to the
members of BHP Group Limited, and EY UK in relation to United
Kingdom responsibilities and reporting obligations to the members
of BHP Group Plc.
BHP ('the Group') consists of BHP Group Limited, BHP Group Plc
and the entities they controlled during the half year ended 31
December 2020.
We have reviewed the accompanying half year financial statements
of the Group which comprises the Consolidated Balance Sheet as at
31 December 2020, the Consolidated Income Statement, Consolidated
Statement of Comprehensive Income, Consolidated Statement of
Changes in Equity and Consolidated Cash Flow Statement for the half
year ended on that date, notes comprising a summary of significant
accounting policies and other explanatory information.
The Directors' Declaration is considered to be part of the half
year financial report for the purposes of EY Australia's review
conclusion.
We have read the other information contained in the half year
financial report and considered whether it contains any apparent
misstatements or material inconsistencies with the information in
the half year financial statements.
Conclusion of EY Australia
Based on our review, which is not an audit, nothing has come to
our attention that causes us to believe that the half year
financial statements, together with the directors' declaration, in
the half year financial report of the Group are not in accordance
with the Australian Corporations Act 2001, including:
a) giving a true and fair view of the consolidated financial
position of the Group as at 31 December 2020 and of its
consolidated financial performance for the half year ended on that
date; and
b) complying with Australian Accounting Standard AASB 134
Interim Financial Reporting and the Australian Corporations
Regulations 2001.
Conclusion of EY UK
Based on our review, nothing has come to our attention that
causes us to believe that the half year financial statements in the
half year financial report for the six months ended 31 December
2020 are not prepared, in all material respects, in accordance with
International Accounting Standard 34 Interim Financial Reporting as
adopted by the European Union ('EU') and the Disclosure Guidance
and Transparency Rules of the United Kingdom's Financial Conduct
Authority.
Directors' Responsibility for the half year Financial Report
The half year financial report is the responsibility of, and has
been approved by, the Directors. The Directors are responsible for
preparing the half year financial report:
-- that gives a true and fair view in accordance with Australian
Accounting Standards and the Australian Corporations Act 2001 and
for such internal control as the Directors determine is necessary
to enable the preparation of the half year financial report that is
free from material misstatement, whether due to fraud or error.
65
-- in accordance with the Disclosure Guidance and Transparency
Rules of the United Kingdom's Financial Conduct Authority. As
disclosed in note 1, the annual financial statements of the Group
are prepared in accordance with IFRSs as issued by the
International Accounting Standards Board (IASB) and adopted by the
EU. The half year financial statements included in this half year
financial report have been prepared in accordance with
International Accounting Standard 34 Interim Financial Reporting,
as adopted by the EU.
Auditor's Responsibility
EY Australia's responsibility is to express to the members of
BHP Group Limited a conclusion on the half year financial report,
including the Directors' Declaration, in the half year financial
report based on our review.
EY UK's responsibility is to express to the members of BHP Group
Plc a conclusion on the half year financial statements in the half
year financial report based on our review.
Scope of Review
A review of a half year financial report consists of making
enquiries, primarily of persons responsible for financial and
accounting matters, and applying analytical and other review
procedures. A review is substantially less in scope than an audit
conducted in accordance with Australian Auditing Standards and
International Standards on Auditing (UK) and consequently does not
enable us to obtain assurance that we would become aware of all
significant matters that might be identified in an audit.
Accordingly, we do not express an audit opinion.
EY Australia conducted its review in accordance with Australian
Auditing Standard on Review Engagements ASRE 2410 Review of a
Financial Report Performed by the Independent Auditor of the
Entity, in order to state whether, on the basis of the procedures
described, anything has come to our attention that causes us to
believe that the half year financial statements, together with the
directors' declaration, in the half year financial report are not
in accordance with the Australian Corporations Act 2001 including:
giving a true and fair view of the Group's consolidated financial
position as at 31 December 2020 and its consolidated financial
performance for the half year ended on that date; and complying
with Australian Accounting Standard AASB 134 Interim Financial
Reporting and the Australian Corporations Regulations 2001. As the
auditor of the Group, ASRE 2410 requires that we comply with the
ethical requirements relevant to the audit of the annual financial
report.
EY UK conducted its review in accordance with International
Standard on Review Engagements 2410 (UK and Ireland) Review of
Interim Financial Information Performed by the Independent Auditor
of the Entity issued by the Auditing Practices Board for use in the
United Kingdom.
Independence
In conducting our review, EY Australia has complied with the
independence requirements of the Australian Corporations Act
2001.
66
Use of EY UK's review report
EY UK's report is made solely to BHP Group Plc in accordance
with guidance contained in International Standard on Review
Engagements 2410 (UK and Ireland) Review of Interim Financial
Information Performed by the Independent Auditor of the Entity
issued by the Auditing Practices Board.
Ernst & Young Ernst & Young LLP
Tim Wallace
Partner
Melbourne London
16 February 2021 16 February 2021
In respect of BHP Group Limited In respect of BHP Group Plc
Ernst & Young, an Australian partnership and Ernst &
Young LLP, a limited liability partnership registered in England
and Wales, are member firms of Ernst & Young Global
Limited.
EY Australia liability limited by a scheme approved under
Professional Standards Legislation.
67
This page is left blank intentionally.
68
BHP
Alternative performance measures
Half year ended
31 December 2020
69
Alternative performance measures
We use various alternative performance measures (APMs) to
reflect our underlying financial performance.
These APMs are not defined or specified under the requirements
of IFRS, but are derived from the Group's Financial Statements for
the half year ended 31 December 2020 (Financial Report) prepared in
accordance with IFRS. The APMs and below reconciliations included
in this document for the half year ended 31 December 2020 and
comparative periods are unaudited. The APMs are consistent with how
management review financial performance of the Group with the Board
and the investment community.
We consider Underlying attributable profit to be a key measure
that allows for the comparability of underlying financial
performance by excluding the impacts of exceptional items. It is
also the basis on which our dividend payout ratio policy is
applied.
Underlying EBITDA is a key APM that management uses internally
to assess the performance of the Group's segments and make
decisions on the allocation of resources. In the Group's view, this
is a relevant measure for capital intensive industries with
long-life assets. Underlying EBITDA and Underlying EBIT are
included in the Group's Financial Report, as required by IFRS 8
'Operating Segments'.
The "Definition and calculation of alternative performance
measures" section outlines why we believe the APMs are useful and
the calculation methodology. We believe these APMs provide useful
information, but they should not be considered as an indication of,
or as a substitute for, statutory measures as an indicator of
actual operating performance (such as profit or net operating cash
flow) or any other measure of financial performance or position
presented in accordance with IFRS, or as a measure of a company's
profitability, liquidity or financial position.
The following tables provide reconciliations between the APMs
and their nearest respective IFRS measure.
Exceptional items
To improve the comparability of underlying financial performance
between reporting periods some of our APMs adjust the relevant IFRS
measures for exceptional items. Refer to the Group's Financial
Report for further information on exceptional items.
69
Exceptional items are those gains or losses where their nature,
including the expected frequency of the events giving rise to them,
and impact is considered material to the Group's Financial
Statements. The exceptional items included within the Group's
profit for the period are detailed below.
2020 2019
Half year ended 31 December US$M US$M
-----------------------------------------------------------
Revenue - -
Other income - 40
Expenses excluding net finance costs, depreciation,
amortisation and impairments (317) (803)
Depreciation and amortisation - -
Net impairments (547) -
(Loss)/profit from equity accounted investments,
related impairments and expenses (678) 36
Profit/(loss) from operations (1,542) (727)
Financial expenses (41) (57)
Financial income - -
Net finance costs (41) (57)
Profit/(loss) before taxation (1,583) (784)
Income tax (expense)/benefit (587) 271
Royalty-related taxation (net of income tax
benefit) - -
Total taxation (expense)/benefit (587) 271
Profit/(loss) after taxation (2,170) (513)
Total exceptional items attributable to non-controlling
interests (10) (195)
Total exceptional items attributable to BHP
shareholders (2,160) (318)
Exceptional items attributable to BHP shareholders
per share (US cents) (42.8) (6.3)
Weighted basic average number of shares (Million) 5,057 5,057
70
APMs derived from Consolidated Income Statement
Underlying attributable profit
2020 2019
Half year ended 31 December US$M US$M
Profit after taxation attributable to BHP shareholders 3,876 4,868
Total exceptional items attributable to BHP shareholders(1) 2,160 318
Underlying attributable profit 6,036 5,186
(1) Refer to Exceptional items for further information.
Underlying basic earnings per share
2020 2019
Half year ended 31 December US cents US cents
Basic earnings per ordinary share 76.6 96.3
Exceptional items attributable to BHP shareholders per share(1) 42.8 6.3
Underlying basic earnings per ordinary share 119.4 102.6
(1) Refer to Exceptional items for further information.
Underlying EBITDA
2020 2019
Half year ended 31 December US$M US$M
Profit from operations 9,750 8,314
Exceptional items included in profit from operations(1) 1,542 727
Underlying EBIT 11,292 9,041
Depreciation and amortisation expense 3,245 3,014
Net impairments 690 29
Exceptional item included in Depreciation, amortisation and impairments(1) (547) -
Underlying EBITDA 14,680 12,084
(1) Refer to Exceptional items for further information.
71
Underlying EBITDA margin
Group
Half year ended 31 December and unallocated
2020 Iron items/
US$M Petroleum Copper Ore Coal eliminations(1) Total Group
Revenue - Group production 1,616 6,129 14,050 2,170 713 24,678
Revenue - Third party products 3 938 8 - 12 961
Revenue 1,619 7,067 14,058 2,170 725 25,639
Underlying EBITDA - Group
production 789 3,683 10,241 (201) 110 14,622
Underlying EBITDA - Third
party products - 55 3 - - 58
Underlying EBITDA(2) 789 3,738 10,244 (201) 110 14,680
Segment contribution to the
Group's Underlying EBITDA(3) 5% 26% 70% (1%) 100%
Underlying EBITDA margin(4) 49% 60% 73% (9%) 59%
Group
Half year ended 31 December and unallocated
2019 Iron items/
US$M Petroleum Copper Ore Coal eliminations(1) Total Group
Revenue - Group production 2,415 4,993 10,367 3,266 577 21,618
Revenue - Third party products 38 609 8 - 21 676
Revenue 2,453 5,602 10,375 3,266 598 22,294
Underlying EBITDA - Group
production 1,580 2,334 7,121 898 129 12,062
Underlying EBITDA - Third
party products (1) 21 3 - (1) 22
Underlying EBITDA(2) 1,579 2,355 7,124 898 128 12,084
Segment contribution to the
Group's Underlying EBITDA(3) 13% 20% 60% 7% 100%
Underlying EBITDA margin(4) 65% 47% 69% 27% 56%
(1) Group and unallocated items includes functions, other
unallocated operations including Potash, Nickel West, legacy assets
and consolidation adjustments.
(2) Refer to Underlying EBITDA for further information.
(3) Percentage contribution to Group Underlying EBITDA,
excluding Group and unallocated items.
(4) Underlying EBITDA margin excludes Third party products.
APMs derived from Consolidated Cash Flow Statement
Capital and exploration expenditure
2020 2019
Half year ended 31 December US$M US$M
Capital expenditure (purchases of property, plant and equipment) 3,333 3,405
Add: Exploration expenditure 281 390
Capital and exploration expenditure (cash basis) 3,614 3,795
----- -----
Free cash flow
2020 2019
Half year ended 31 December US$M US$M
Net operating cash flows 9,369 7,442
Net investing cash flows (4,209) (3,732)
Free cash flow 5,160 3,710
72
APMs derived from Consolidated Balance Sheet
Vessel lease contracts, under IFRS 16, are required to be
remeasured at each reporting date to the prevailing freight index.
While these liabilities are included in the Group interest bearing
liabilities, they are excluded from the net debt calculation as
they do not align with how the Group assesses net debt for decision
making in relation to the capital allocation framework. In
addition, the freight index has historically been volatile which
creates significant short-term fluctuation in these liabilities. As
of 1 January 2020, the Group excludes these liabilities from its
net debt calculation and 31 December 2019 net debt has been
restated to reflect the change in net debt calculation.
Net debt and gearing ratio
30 June 2020 31 Dec 2019
31 Dec 2020 US$M US$M
US$M Restated Restated
Interest bearing liabilities - Current 3,560 5,012 4,273
Interest bearing liabilities - Non current 19,159 22,036 22,535
Total interest bearing liabilities 22,719 27,048 26,808
Comprising:
Borrowing 19,160 23,605 24,230
Lease liabilities 3,559 3,443 2,578
Less: Lease liability associated with index-linked freight contracts 483 1,160 164
Less: Cash and cash equivalents 9,291 13,426 14,321
Less: Net debt management related instruments(1) 1,216 433 (233)
Less: Net cash management related instruments(2) (110) (15) (123)
Less: Total derivatives included in net debt 1,106 418 (356)
Net debt 11,839 12,044 12,679
Net assets(3) 53,423 52,175 52,347
Gearing 18.1% 18.8% 19.5%
(1) Represents the net cross currency and interest rate swaps
included within current and non-current other financial assets and
liabilities.
(2) Represents the net forward exchange contracts related to
cash management included within current and non-current other
financial assets and liabilities.
(3) 30 June 2020 and 31 December 2019 net assets have been
restated to r eflect changes to Group's accounting policy following
a decision by the IFRS Interpretations Committee on IAS 12 'Income
Tax' resulting in a retrospective decrease of US$71 million . Refer
to note 2 - Impact of new accounting standards and changes in
accounting policies.
Net debt waterfall
31 Dec 2019
31 Dec 2020 US$M
US$M Restated
Net debt at the beginning of the period (12,044) (9,446)
Net operating cash flows 9,369 7,442
Net investing cash flows (4,209) (3,732)
Net financing cash flows (9,595) (5,000)
Net decrease in cash and cash equivalents (4,435) (1,290)
Carrying value of interest bearing liability repayments 5,587 267
Carrying value of debt related instruments proceeds (90) -
Carrying value of cash management related instruments settlements/(proceeds) 180 (98)
Fair value adjustment on debt (including debt related instruments) 39 6
Foreign exchange impacts on cash (including cash management related instruments) 24 21
IFRS16 leases taken on at 1 July - (1,778)
Lease additions (909) (179)
Other (191) (182)
Non-cash movements (1,037) (2,112)
Net debt at the end of the period (11,839) (12,679)
73
Net operating assets
31 Dec 2019
31 Dec 2020 US$M
US$M Restated
Net assets(1) 53,423 52,347
Less: Non-operating assets
Cash and cash equivalents (9,291) (14,321)
Trade and other receivables(2) (202) (273)
Other financial assets(3) (2,225) (1,098)
Current tax assets (295) (137)
Deferred tax assets (3,178) (3,866)
Add: Non-operating liabilities
Trade and other payables(4) 218 288
Interest bearing liabilities 22,719 26,808
Other financial liabilities(5) 752 1,067
Current tax payable 1,184 1,104
Non-current tax payable 173 112
Deferred tax liabilities 3,603 4,053
Net operating assets 66,881 66,084
(1) 31 December 2019 balance sheet has been restated to r eflect
changes to Group's accounting policy following a decision by the
IFRS Interpretations Committee on IAS 12 'Income Tax' . Refer to
note 2 - Impact of new accounting standards and changes in
accounting policies.
(2) Represents loans to associates, external finance receivable
and accrued interest receivable included within other
receivables.
(3) Represents cross currency and interest rate swaps, forward
exchange contracts related to cash management and investment in
shares and other investments.
(4) Represents accrued interest payable included within other
payables.
(5) Represents cross currency and interest rate swaps and
forward exchange contracts related to cash management.
74
Other APMs
Principal factors that affect Revenue, Profit from operations
and Underlying EBITDA
The following table describes the impact of the principal
factors that affected Revenue, Profit from operations and
Underlying EBITDA for half year ended December 2020 and relates
them back to our Consolidated Income Statement.
Total expenses,
Other income Depreciation,
and (Loss)/profit amortisation
from equity and impairments
accounted Profit and Exceptional Underlying
Revenue investments from operations Items EBITDA
US$M US$M US$M US$M US$M
Half year ended 31 December
2019
Revenue 22,294
Other income 209
Expenses excluding net finance
costs (14,315)
(Loss)/profit from equity
accounted investments, related
impairments and expenses 126
------------------
Total other income, expenses
excluding net finance costs
and (Loss)/profit from equity
accounted investments, related
impairments and expenses (13,980)
Profit from operations 8,314
Depreciation, amortisation
and impairments 3,043
Exceptional items 727
Underlying EBITDA 12,084
Change in sales prices 2,993 112 3,105 - 3,105
Price-linked costs - (230) (230) - (230)
Net price impact 2,993 (118) 2,875 - 2,875
Change in volumes 318 (77) 241 - 241
Operating cash costs - 86 86 - 86
Exploration and business
development - (11) (11) - (11)
Change in controllable cash
costs - 75 75 - 75
Exchange rates 25 (736) (711) - (711)
Inflation on costs - (115) (115) - (115)
Fuel and energy - 182 182 - 182
Non-cash - 142 142 - 142
One-off items (178) 40 (138) - (138)
Change in other costs (153) (487) (640) - (640)
Asset sales - - - - -
Ceased and sold operations (24) 11 (13) - (13)
Other 211 (153) 58 - 58
Depreciation, amortisation
and impairments - (345) (345) 345 -
Exceptional items - (815) (815) 815 -
Half year ended 31 December
2020
Revenue 25,639
Other income 156
Expenses excluding net finance
costs (15,570)
(Loss)/profit from equity
accounted investments, related
impairments and expenses (475)
------------------
Total other income, expenses
excluding net finance costs
and (Loss)/profit from equity
accounted investments, related
impairments and expenses (15,889)
Profit from operations 9,750
Depreciation, amortisation
and impairments 3,935
Exceptional item included in
Depreciation, amortisation and
impairments (547)
Exceptional items 1,542
Underlying EBITDA 14,680
75
Underlying return on capital employed (ROCE)
31 Dec 2019
31 Dec 2020 US$M
US$M Restated
Profit after taxation 4,828 5,190
Exceptional items(1) 2,170 513
Subtotal 6,998 5,703
Adjusted for:
Net finance costs 924 524
Exceptional items included within net finance costs(1) (41) (57)
Income tax expense on net finance costs (230) (149)
Profit after taxation excluding net finance costs and exceptional items 7,651 6,021
Annualised Profit after taxation excluding net finance costs and exceptional items 15,302 12,042
Net assets at the beginning of the period 52,175 51,753
Net debt at the beginning of the period 12,044 9,446
Capital employed at the beginning of the period(2) 64,219 61,199
Net assets at the end of the period 53,423 52,347
Net debt at the end of the period 11,839 12,679
Capital employed at the end of the period(2) 65,262 65,026
Average capital employed 64,741 63,113
Underlying Return on Capital Employed 23.6% 19.1%
(1) Refer to Exceptional items for further information.
(2) The Underlying ROCE calculation uses the restated net debt
and net assets for the comparative period.
Underlying return on capital employed (ROCE) by segment
Half year ended 31 December 2020 Group and unallocated items/
US$M Petroleum Copper Iron Ore Coal eliminations(1) Total Group
Annualised profit after taxation
excluding net finance costs and
exceptional items (236) 3,918 12,454 (1,066) 232 15,302
Average capital employed 9,853 23,941 16,367 8,743 5,837 64,741
Underlying Return on Capital
Employed (2%) 16% 76% (12%) - 23.6%
Half year ended 31 December 2019
US$M Group and unallocated items/
Restated(2) Petroleum Copper Iron Ore Coal eliminations(1) Total Group
Annualised profit after taxation
excluding net finance costs and
exceptional items 903 1,963 8,864 488 (176) 12,042
Average capital employed 9,067 23,004 16,159 8,807 6,076 63,113
Underlying Return on Capital
Employed 10% 9% 55% 6% - 19.1%
(1) Group and unallocated items includes functions, other
unallocated operations including Potash, Nickel West, legacy assets
and consolidation adjustments.
(2) The Underlying ROCE calculation uses the restated net debt
and net assets for the comparative period.
76
Underlying return on capital employed (ROCE) by asset
Half year New
ended 31 South
December Western Wales
2020 Australia Pampa Olympic Queensland Energy Total
US$M Iron Ore Antamina Escondida Norte Petroleum(1) Potash Dam Coal Cerrejon Coal Other Group
Annualised
profit
after
taxation
excluding
net finance
costs and
exceptional
items 12,458 522 3,292 172 208 78 78 (330) (58) (482) (636) 15,302
Average
capital
employed 18,614 1,364 10,593 3,752 8,678 4,468 8,028 7,622 519 557 546 64,741
Underlying
Return on
Capital
Employed 67% 38% 31% 5% 2% 2% 1% (4%) (11%) (87%) - 23.6%
Half year
ended 31 New
December South
2019 Western Wales
US$M Australia Pampa Olympic Queensland Energy Total
Restated(2) Iron Ore Antamina Escondida Norte Petroleum(1) Potash Dam Coal Cerrejon Coal Other Group
Annualised
profit
after
taxation
excluding
net finance
costs and
exceptional
items 8,849 307 1,641 219 1,167 (14) (65) 937 (28) (152) (819) 12,042
Average
capital
employed 18,119 1,332 11,054 3,066 7,938 4,160 7,452 7,150 822 837 1,183 63,113
Underlying
Return on
Capital
Employed 49% 23% 15% 7% 15% (0%) (1%) 13% (3%) (18%) - 19.1%
(1) Excludes Exploration.
(2) The Underlying ROCE calculation uses the restated net debt
and net assets for the comparative period.
77
Definition and calculation of alternative performance
measures
Alternative Performance Measures Reasons why we believe the APMs are Calculation methodology
(APMs) useful
Underlying attributable profit Allows the comparability of underlying Profit after taxation attributable to
financial performance by excluding the BHP shareholders excluding any
impacts of exceptional exceptional items attributable
items and is also the basis on which to BHP shareholders.
our dividend payout ratio policy is
applied.
Underlying basic earnings per share On a per share basis, allows the Underlying attributable profit divided
comparability of underlying financial by the weighted basic average number
performance by excluding of shares.
the impacts of exceptional items.
Underlying EBITDA Used to help assess current Earnings before net finance costs,
operational profitability excluding depreciation, amortisation and
the impacts of sunk costs impairments, taxation expense,
(i.e. depreciation from initial discontinued operations and
investment). Each is a measure that exceptional items. Underlying EBITDA
management uses internally includes BHP's share of profit/(loss)
to assess the performance of the from investments accounted for using
Group's segments and make decisions on the equity method including net
the allocation of finance costs, depreciation,
resources. amortisation and impairments and
taxation expense/(benefit).
Underlying EBITDA margin Underlying EBITDA excluding third
party product EBITDA, divided by
revenue excluding third
party product revenue.
Underlying EBIT Used to help assess current Earnings before net finance costs,
operational profitability excluding taxation expense, discontinued
net finance costs and taxation operations and any exceptional
expense (each of which are managed at items. Underlying EBIT includes BHP's
the Group level) as well as share of profit/(loss) from
discontinued operations investments accounted for
and any exceptional items. using the equity method including net
finance costs and taxation
expense/(benefit).
Profit from operations Earnings before net finance costs,
taxation expense and discontinued
operations. Profit from
operations includes Revenue, Other
income, Expenses excluding net finance
costs and BHP's
share of profit/(loss) from
investments accounted for using the
equity method including net
finance costs and taxation
expense/(benefit).
Capital and exploration expenditure Used as part of our Capital Allocation Purchases of property, plant and
Framework to assess efficient equipment and exploration expenditure.
deployment of capital.
Represents the total outflows of our
operational investing expenditure.
Free cash flow It is a key measure used as part of Net operating cash flows less net
our Capital Allocation Framework. investing cash flows.
Reflects our operational
cash performance inclusive of
investment expenditure, which helps to
highlight how much cash
was generated in the period to be
available for the servicing of debt
and distribution to
shareholders.
78
Net debt Net debt shows the position of gross Interest bearing liabilities less
debt less index-linked freight liability associated with index-linked
contracts offset by cash freight contracts
immediately available to pay debt if less cash and cash equivalents less
required and any associated derivative net cross currency and interest rate
financial instruments. swaps less net cash
Liability associated with index-linked management related instruments for the
freight contracts are excluded from Group at the reporting date.
the net debt calculation
due to the short term volatility of
the index they relate to not aligning
with how the Group
uses net debt for decision making in
relation to the Capital Allocation
Framework. Net debt,
along with the gearing ratio, is used
to monitor the Group's capital
management by relating
net debt relative to equity from
shareholders.
Gearing ratio Ratio of Net debt to Net debt plus Net
assets.
Net operating assets Enables a clearer view of the assets Operating assets net of operating
deployed to generate earnings by liabilities, including the carrying
highlighting the net value of equity accounted
operating assets of the business investments and predominantly excludes
separate from the financing and tax cash balances, loans to associates,
balances. This measure interest bearing
helps provide an indicator of the liabilities, derivatives hedging our
underlying performance of our assets net debt and tax balances.
and enhances comparability
between them.
Underlying return on capital employed Indicator of the Group's capital Profit after taxation excluding
(ROCE) efficiency and is provided on an exceptional items and net finance
underlying basis to allow costs (after taxation) divided
comparability of underlying financial by average capital employed.
performance by excluding the impacts Profit after taxation excluding
of exceptional exceptional items and net finance
items. costs (after taxation) is
profit after taxation from Continuing
and Discontinued operations excluding
exceptional items,
net finance costs and the estimated
taxation impact of net finance costs.
These are annualised
for a half year end reporting period.
The estimated tax impact is calculated
using a prima facie taxation rate on
net finance costs
(excluding any foreign exchange
impact).
Average capital employed is calculated
as the average of net assets less net
debt for the
last two reporting periods.
Adjusted effective tax rate Provides an underlying tax basis to Total taxation expense/(benefit)
allow comparability of underlying excluding exceptional items and
financial performance exchange rate movements included
by excluding the impacts of in taxation expense/(benefit) divided
exceptional items. by Profit before taxation and
exceptional items.
79
Unit cost Used to assess the controllable financial Ratio of net costs of the assets to the equity share of
performance of the Group's assets for each sales tonnage. Net costs is defined
unit as revenue less Underlying EBITDA and excludes freight and
of production. Unit costs are adjusted for other costs, depending on the nature
site specific non controllable factors to of each asset. Freight is excluded as the Group believes it
enhance provides a similar basis of comparison
comparability between the Group's assets. to our peer group.
Petroleum unit costs exclude:
* exploration, development and evaluation expense as
these costs do not represent our cost performance in
relation to current production and the Group believes
it provides a similar basis of comparison to our peer
group;
* other costs that do not represent underlying cost
performance of the business.
Escondida unit costs exclude:
* by-product credits being the favourable impact of
by-products (such as gold or silver) to determine the
directly attributable costs of copper production.
WAIO, Queensland Coal and NSWEC unit costs exclude
royalties as these are costs that are not
deemed to be under the Group's control, and the Group
believes exclusion provides a similar
basis of comparison to our peer group.
80
Definition and calculation of principal factors
The method of calculation of the principal factors that affect
the period on period movements of Revenue, Profit from operations
and Underlying EBITDA are as follows:
Principal factor Method of calculation
Change in sales prices Change in average realised price for each operation from
the prior period to the current period,
multiplied by current period sales volumes.
Price-linked costs Change in price-linked costs (mainly royalties) for each
operation from the prior period to
the current period, multiplied by current period sales
volumes.
Change in volumes Change in sales volumes for each operation multiplied by
the prior year average realised price
less variable unit cost.
Controllable cash costs Total of operating cash costs and exploration and business
development costs.
Operating cash costs Change in total costs, other than price-linked costs,
exchange rates, inflation on costs,
fuel and energy costs, non-cash costs and one-off items as
defined below for each operation
from the prior period to the current period.
Exploration and business development Exploration and business development expense in the
current period minus exploration and business
development expense in the prior period.
Exchange rates Change in exchange rate multiplied by current period local
currency revenue and expenses.
Inflation on costs Change in inflation rate applied to expenses, other than
depreciation and amortisation, price-linked
costs, exploration and business development expenses,
expenses in ceased and sold operations
and expenses in new and acquired operations.
Fuel and energy Fuel and energy expense in the current period minus fuel
and energy expense in the prior period.
Non-cash Change in net impact of capitalisation and depletion of
deferred stripping from the prior
period to the current period.
One-off items Change in costs exceeding a pre-determined threshold
associated with an unexpected event that
had not occurred in the last two years and is not
reasonably likely to occur within the next
two years.
Asset sales Profit/(loss) on the sale of assets or operations in the
current period minus profit/(loss)
on sale of assets or operations in the prior period.
Ceased and sold operations Underlying EBITDA for operations that ceased or were sold
in the current period minus Underlying
EBITDA for operations that ceased or were sold in the
prior period.
Share of profit/(loss) from equity accounted investments Share of profit/(loss) from equity accounted investments
for the current period minus share
of profit/(loss) from equity accounted investments in the
prior period.
Other Variances not explained by the above factors.
80
Definition and calculation of Key Indicator terms
We use various Key Indicators to reflect our sustainability
performance.
Management uses these Key Indicators to evaluate BHP's
performance against both positive and negative impacts of
operational activities and our progress against our sustainability
commitments and targets.
This section outlines why we believe the Key Indicators are
useful to the Board, management, investors and other stakeholders,
and the methodology behind the metrics. A definition and
explanation of each of the Key Indicators are provided in the
tables below.
Health and safety-related metrics
Our highest priority is the safety of our people and the
communities in which we operate. This is why we are focussed on
introducing more reliable and effective controls across our safety
risk profile and improving human and organisational performance,
enabling our people to work safely each day. Our work in fatality
elimination is underpinned by our field leadership program,
ensuring our leaders are spending quality time in field engaging
with our workforce. The health and safety Key Indicators allow the
Board, management, investors and other stakeholders to measure and
track health and safety performance at our operated assets.
Key Indicator Calculation methodology
High Potential Injury (HPI) High potential injury frequency (HPIF) is an indicator which measures the
number of injuries
with fatal potential per million hours. HPIFR equals the sum of (lost time
cases + restricted
work cases + medical treatment cases + first aid cases) x 1,000,000 ÷
total hours worked.
High potential injuries remain a primary focus to assess progress against
our most important
safety objective: to eliminate fatalities.
The basis of calculation for high potential injuries was revised in FY2020
from event count
to injury count as part of a safety reporting methodology improvement. In
some events, multiple
people are injured.
This methodology has been prepared in accordance with GRI standard 403-9.
Total Recordable Injury Frequency (TRIF) Total recordable injury frequency (TRIF) is an indicator which measures
the number of recordable
injuries per million hours. TRIF equals the sum of (fatalities + lost-time
cases + restricted
work cases + medical treatment cases) x 1,000,000 ÷ total hours
worked total exposure
hours. BHP adopts the US Government Occupational Safety and Health
Administration (OSHA) guidelines
for the recording and reporting of occupational injury and illnesses. TRIF
statistics exclude
non-operated assets.
Year-on-year improvement of TRIF is one of our five-year sustainability
targets and is one
of the indicators used to assess our safety performance.
This methodology has been prepared in accordance with GRI standard 403-9
and OSHA guidelines.
Climate change-related metrics
We recognise the impacts of climate change may impact BHP in a
range of areas. Climate-related risks include the potential
physical impacts of acute and chronic risks, and transition impacts
arising from the transition to a lower carbon economy. Our climate
change Key Indicators help us monitor our climate change
commitments to mitigate the risks and potential impacts associated
with climate change to BHP, as well as fulfil our regulatory
reporting obligations. The Key Indicators allow the Board,
management, investors and other stakeholders to measure BHP's
performance against these commitments.
81
Key Calculation methodology
Indicator
Operational Definition
greenhouse Scope 1 greenhouse gas emissions are direct emissions from operations that are owned or controlled
gas by BHP, primarily emissions from fuel consumed by haul trucks at our operated assets, as well
emissions as fugitive methane emissions from coal and petroleum production at our operated assets. Scope
1 refers to direct GHG emissions from our operated assets.
Scope 2 greenhouse gas emissions are indirect emissions from the generation of purchased or
acquired electricity, steam, heat or cooling that is consumed by operations that are owned
or controlled by BHP. Our Scope 2 emissions have been calculated using the market-based method
using supplier-specific emission factors unless otherwise specified. A residual mix is currently
unavailable to account for voluntary purchases and this may result in double counting between
electricity consumers.
Scope 1 and 2 emissions have been calculated on an operational control basis in accordance
with mandatory minimum performance requirements for HSEC reporting, which are in line with
the Greenhouse Gas Protocol definitions and are measured in tonnes of carbon dioxide equivalent,
and in line with the Greenhouse Gas Protocol Corporate Accounting and Reporting Standard and
the Greenhouse Gas Protocol Scope 2 Guidance.
Calculation methodology
The emissions figures are calculated using the activity data collected at our operated assets.
Activity data is multiplied by an energy content (where necessary) and emission factors to
derive the energy consumption and GHG emissions associated with a process or an operation.
Examples of activity data include kilowatt-hours of electricity used or quantity of fuel used.
Energy and Scope 1 emissions for facilities already reporting to mandatory local regulatory
programs are required to use the same emission factors and methodologies for reporting under
BHP's operational control boundary. This ensures a single emissions and energy inventory is
maintained for consistency and efficiency. Local regulatory programs were applicable to the
majority of BHP's Scope 1 emissions inventory in FY2020 (operational control boundary), as
listed in the table below. A local regulatory program in this context refers to any scheme
requiring emissions to be calculated using mandated references (e.g. the Green Tax legislation
in Chile, which requires emissions to be calculated using the Intergovernmental Panel on Climate
Change (IPCC) factors) or mandated emission factors (e.g. the Australian National Greenhouse
and Energy Reporting (NGER) Scheme or US EPA GHG reporting program, which publish factors
specific to the programs). In the absence of local mandatory regulations, the Australian NGER
(Measurement) Determination has been set as the default source for emission factors and methodologies
for consistency with the majority of the emissions inventory. Asset Location Local regulations
BMA, BMC, NSW Australia National Greenhouse and Energy
Energy Coal, Reporting Scheme
Olympic Dam,
Nickel West,
WA Iron ore,
Petroleum -
Australia
Escondida, Chile Green Tax legislation (referencing
Pampa Norte IPCC factors)
Petroleum - USA US EPA GHG reporting program
Gulf of Mexico
Potash - Canada Canada Canadian Greenhouse Gas Reporting
Program (referencing IPCC factors)
Petroleum - Trinidad None
Trinidad
82
Scope 2 emissions totals are reported using the market-based method (default calculation approach
unless otherwise stated) and the location-based method, as recommended by the GHG Protocol
Scope 2 Guidance. Definitions of location and market-based reporting used in BHP's accounting
are consistent with the Greenhouse Gas Protocol terminology as follows:
* Market-based reporting: Scope 2 GHG emissions based
on the generators (and therefore the generation fuel
mix from which the reporter contractually purchases
electricity and/or is directly provided electricity
via a direct line transfer).
* Location-based reporting: Scope 2 GHG emissions based
on average energy generation emission factors for
defined geographic locations, including local,
subnational or national boundaries (i.e. grid
factors). In the case of a direct line transfer, the
location-based emissions are equivalent to the
market-based emissions.
For facilities where market-based reporting is required, electricity emission factors are
sourced directly from the supplier in the first instance. An emission factor in the public
domain, which is specific to the generation plant supplying the facility, is considered equivalent
to a supplier-specific factor in this context.
Where supplier-specific factors are not available, a default emission factor for off-grid
electricity is used instead, as published in local regulations or industry frameworks (or
the default off-grid electricity emission factor from the Australian NGER (Measurement) Determination)
in the case where no local default is available.
The location-based method is applied using electricity emission factors for the relevant grid
network, as sourced from local regulations, industry frameworks or publications from the local
grid administrator.
These methodologies have been prepared in accordance with GRI standard 305-1 and GRI standard
305-2.
More information on the calculation methodologies for other reported categories, boundaries
assumptions and key references used in the preparation of our Scope 1 and Scope 2 emissions
data can be found in the BHP Scope 1, 2 and 3 Emissions Calculation Methodology, available
at bhp.com/climate .
Value chain Scope 3 emissions have been calculated on a carbon dioxide equivalent basis using methodologies
emissions consistent with the Greenhouse Gas Protocol Corporate Value Chain (Scope 3) Accounting and
Reporting Standard (Scope 3 Standard). Scope 3 emissions refers to all other indirect emissions
(not included in Scope 2) that occur in BHP's value chain, primarily emissions resulting from
our customers using the fossil fuel commodities and processing the non-fossil fuel commodities
we sell, as well as upstream emissions associated with the extraction, production and transportation
of the goods, services, fuels and energy we purchase for use at our operated assets; emissions
resulting from the transportation and distribution of our products; and operational emissions
(on an equity basis) from our non-operated joint ventures. Scope 3 emissions reporting necessarily
requires a degree of overlap in reporting boundaries due to our involvement at multiple points
in the life cycle of the commodities we produce and consume. A significant example of this
is that Scope 3 emissions reported under Category 10: 'Processing of sold products' include
the processing of our iron ore to steel. This third party activity also consumes metallurgical
coal as an input, a portion of which is produced by us. For reporting purposes, we account
for Scope 3 emissions from combustion of metallurgical coal with all other fossil fuels under
the Category 11: 'Use of sold products', such that a portion of metallurgical coal emissions
is accounted for under two categories. This is an expected outcome of emissions reporting
between the different scopes defined under the standard GHG accounting practices and is not
considered to detract from the overall value of our Scope 3 emissions disclosure. This double
counting means that the emissions reported under each category should not be added up, as
to do so would give an inflated total figure. For this reason, we do not report a total Scope
3 emissions figure.
83
The below methodology describes the emissions from Category 10: Processing of sold products
and Category 11: Use of sold products. These categories are the most material Scope 3 emission
categories and together account for almost 95 per cent of Scope 3 emissions.
Category 10: Processing of sold products
Emissions from the processing of intermediate products sold in the reporting year by downstream
companies (e.g. manufacturers) subsequent to sale by the reporting company.
Calculation methodology
The average-data method as described in the Greenhouse Gas Protocol Technical Guidance for
Calculating Scope 3 Emissions (Scope 3 Guidance) is used to calculate these emissions, with
industry-average emission factors applied to production volumes (on an equity basis) for each
commodity to calculate an overall emissions estimate for this category.
Assumptions
* To estimate emissions from the processing of iron ore,
all iron ore production is assumed to be processed to
steel. To estimate the higher-end estimate, the crude
steel emission factor is applied to the volume of
crude steel produced from BHP's iron ore.
* To estimate the lower-end emissions number from the
processing of iron ore, it is assumed that the crude
steel emission factor already takes into account
emissions from both iron ore and metallurgical coal.
Therefore, the crude steel emission factor is
apportioned based on the ratio of iron ore and
metallurgical coal input to produce 1,000 kilograms
of crude steel (based on World Steel Association's
integrated blast furnace and basic oxygen furnace
route). The crude steel emission factor is split to
estimate the emissions from iron ore and
metallurgical coal (calculated in Category 11: Use of
sold products). The split factor is applied to the
volume of crude steel produced from BHP's iron ore.
The estimated crude steel produced with BHP's iron
ore is significantly higher than with BHP's
metallurgical coal (due to higher iron ore
production). Therefore, this approach does not
capture third party metallurgical coal emissions in
the steelmaking process.
* To estimate emissions from the processing of copper,
we apply an emission factor for the processing of
copper to copper wire (rather than alternative
products such as tubes or sheets), as this is the
most emissions-intensive process and therefore the
most 'conservative' assumption.
Category 11: Use of sold products
Emissions from the end use of goods and services sold by the reporting company in the reporting
year.
Calculation methodology
The method recommended in the Scope 3 Guidance for 'direct use-phase' emissions calculations
for 'Fuels and feedstocks' is used to calculate these emissions, with industry-average emission
factors applied to production volumes (on an equity basis) for each commodity to calculate
an overall emissions estimate for this category.
For the lower-end estimate emissions from metallurgical coal, the average-data method as described
in the Scope 3 Guidance is used to calculate these emissions, with industry-average emission
factors applied to production volumes (on an equity basis) for metallurgical coal to calculate
an overall emissions estimate for this category.
84
Assumptions
* All metallurgical coal (higher end estimate), energy
coal, natural gas and petroleum products are assumed
to be combusted.
* In practice, metallurgical coal is primarily used in
steelmaking and a portion of the carbon content
remains embedded in the final steel product and is
not released to the atmosphere; the quantities
involved vary according to the feedstocks, processing
technologies and output specifications of the process
route used.
* To estimate the lower-end emissions number from the
use of metallurgical coal, it is assumed that crude
steel emission factor already takes into account
emissions from both iron ore and metallurgical coal.
Therefore, the crude steel emission factor is
apportioned based on the ratio of iron ore and
metallurgical coal input to produce 1,000 kilograms
of crude steel (based on World Steel Association's
integrated blast furnace and basic oxygen furnace
route). The crude steel emission factor is split to
estimate the emissions from metallurgical coal and
iron ore (calculated in Category 10: Processing of
sold products). The split factor is applied to the
volume of crude steel produced from BHP's
metallurgical coal. It should be noted that in
reality, BHP's metallurgical coal may not end up with
the same customer as our iron ore.
* All energy coal is assumed to be bituminous, which
has a mid-range energy content among the three
sub-categories of black coal (the others being
sub-bituminous coal and anthracite) listed in the
NGER Measurement Determination published by the
Australian Government (Australian NGER Determination),
from which these emission factors are sourced.
* All crude oil and condensates are assumed to be
refined and combusted as diesel (rather than
alternative products such as gasoline) as the most
emissions-intensive, therefore the most conservative
assumption. The energy content of the crude oil and
condensate volumes is used to estimate the
corresponding quantity of diesel that would be
produced, assuming that no fuel is 'lost' during the
refining process.
* Emissions from LPG and ethane volumes are included in
emissions reported for 'natural gas liquids' (NGL)
production and are assumed to be combusted with the
same NGL emission factors. This assumption has
minimal impact on estimated emissions due to the
small volumes involved.
This methodology has been prepared in accordance with GRI standard 305-3.
More information on the calculation methodologies for other reported categories, boundaries
assumptions and key references used in the preparation of our Scope 3 emissions data can be
found in the associated BHP Scope 1, 2 and 3 Emissions Calculation Methodology, available
at bhp.com/climate .
Fresh water withdrawals
We acknowledge the nature of our operations can have significant
environmental impacts. Our water withdrawal metrics allow the Board
and management to manage and monitor the inherent risks relating
to, and any adverse impacts our operations may have on, water
resources. They also allow the Board, management, investors and
other stakeholders to measure and track our performance towards our
water-use commitments. Water withdrawal metrics assist the Board
and management in understanding the significance of our water
resource use, collectively for the Group and by individual operated
assets, and to assess trends over time. It also helps inform
investment in infrastructure to reduce water withdrawals and
improve efficiency of water use.
85
Key Indicator Calculation methodology
Fresh water withdrawals The volume of freshwater, in megalitres (ML), received and intended for use within the
reporting
period by the operated asset from the water environment and/or a third party supplier.
Fresh water is defined as waters other than seawater, wastewater from third parties and
hypersaline
groundwater. Freshwater withdrawal also excludes entrained water that would not be
available
for other uses. These exclusions have been made to align with the target's intent to reduce
the use of freshwater sources subject to competition from other users or the environment.
People-related metrics
Our global workforce is the foundation of our business and we
believe that supporting the wellbeing of our people and promoting
an inclusive and diverse culture are vital for maintaining a
competitive advantage. The proportion of the workforce that are
female or Indigenous workers are key indicators, which allow the
Board, management, investors and other stakeholders to measure and
track our near and long-term progress.
Key Indicator Calculation methodology
Female workforce participation (%) The number of female employees as a proportion of the total workforce on the
last day of the
respective reporting period, used in internal management reporting for the
purposes of monitoring
progress against our goals.
Indigenous workforce participation (%) The number of Indigenous employees as a proportion of the total workforce in
the relevant
countries on the last day of the respective reporting period, used in
internal management
reporting for the purposes of monitoring progress against our goals.
There is no significant seasonal variation in employment numbers.
These methodologies have been prepared in accordance with GRI standard 102-8
and GRI standard
405-1.
86
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