Results for the half year ended 31 December 2020

16 February 2021, 07:00

Source - LSE Regulatory

RNS Number : 1802P

BHP Group PLC

15 February 2021

Release Time	IMMEDIATE
Date	16 February 2021
Number	02/21

BHP RESULTS FOR THE HALF YEAR ENDED 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%.

Half year ended 31 December	2020 US$M	2019 US$M	Change %
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.

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 1.5°C scenario.

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.

Key indicators scorecard

	Target	H1 FY21	H2 FY20	H1 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 hours worked)	Year-on-year improvement in HPI frequency	0.20	0.14	0.32	0.24	17 per cent decrease from FY20.
TRIF⁽ⁱⁱⁱ⁾ (per million hours worked)	Year-on-year improvement in TRIF	3.5	3.7	4.6	4.2	16 per cent reduction from FY20.
Operational greenhouse gas emissions⁽ⁱⁱⁱ⁾ (Mt CO₂-e)	Maintain FY22 operational GHG emissions at or below FY17 levels⁽¹⁾ and reduce emissions by at least 30 per cent from FY20 levels⁽²⁾ by FY30	8.1	7.9	7.9	15.8	On track to meet our FY22 and FY30 targets with the reductions in emissions from renewable power contracts at Escondida, Spence, Queensland Coal and Nickel West.
Value chain emissions⁽ⁱⁱⁱ⁾	Steelmaking: Goal to support industry to develop technologies and pathways capable of 30 per cent emissions intensity reduction⁽³⁾		-	-	-	On track to deliver FY30 goal with MOU with China Baowu signed in H1 FY21 and MOU with JFE signed in H2 FY21.
	Transportation: Goal to support 40 per cent emissions intensity reduction of BHP-chartered shipping of our products		-	-	-	On track to deliver FY30 goal with award of a LNG-fuelled bulk carrier tender and LNG bunkering agreement in H1 FY21.
Fresh water withdrawals⁽ⁱⁱⁱ⁾ (GL)	Reduce FY22 fresh water withdrawal by 15 per cent from FY17 levels⁽⁴⁾	52.6	52.0	75.0	127.0	On track to meet our five-year target.
Community and social investment (US$M)	No less than one per cent of pre‑tax profit (three-year rolling average)	35.4	119.8	29.8	149.6	19 per cent increase on H1 FY20 due to continued community support for COVID-19 response and recovery in addition to planned community and social investment.
Local procurement spend (US$M)	Support the growth of local businesses in the regions where we operate	947	972	949	1,922	US$1.9 billion directed to local suppliers in each of the past two financial years.
Female workforce participation⁽ⁱⁱⁱ⁾ (%)	Aspirational goal for gender balance by CY25	27.4	26.5	24.8	26.5	Nine percentage point increase from FY16, with 41 per cent female external hires in H1 FY21.
Indigenous workforce participation⁽ⁱⁱⁱ⁾ (%)	Australia: aim to achieve 8.0 per cent by the end of FY25⁽⁵⁾	6.7	6.5	5.8	6.5	Assets continue to focus on Indigenous employment, supported by 11.2 per cent representation in Operations Services.
	Chile: increase representation from the previous financial year⁽⁶⁾⁽⁷⁾	6.7	6.6	6.3	6.6	Continued increase throughout H1 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.

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.

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.

· 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
	Medium-term guidance⁽¹⁾	FY21 guidance⁽¹⁾	guidance exchange rates⁽¹⁾	realised exchange rates⁽³⁾	H1 FY20	H1 FY21⁽²⁾⁽³⁾ vs 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:

Production	Medium-term guidance	FY21 guidance		H1 FY21	H1 FY20	H1 FY21 vs 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.

· 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 FY21 US$M	H1 FY20 US$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.

· 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 US$M	H1 FY21 US$M	H1 FY20 US$M	FY20 US$M
	FY21e US$M	H1 FY21 US$M	H1 FY20 US$M	FY20 US$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.

· 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:

Commodity	Project and ownership	Project scope / capacity⁽¹⁾	Capital expenditure⁽¹⁾ US$M	Date of initial production	Progress / comments
			Budget	Target
Projects achieved first production during the December 2020 half year
Petroleum	Atlantis Phase 3 (US Gulf of Mexico) 44% (non-operator)	New subsea production system that will tie back to the existing Atlantis facility, with capacity to produce up to 38,000 gross barrels of oil equivalent per day.	696	CY20	First production achieved in July 2020, ahead of schedule and on budget.
Copper	Spence Growth Option (Chile) 100%	New 95 ktpd concentrator is expected to increase Spence's payable copper in concentrate production by approximately ~185 ktpa in the first 10 years of operation and extend the mining operations by more than 50 years.	2,460	FY21	First production achieved in December 2020, on schedule and budget.
Projects in execution at 31 December 2020
Iron Ore	South Flank (Australia) 85%	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.
Petroleum	Ruby (Trinidad & Tobago) 68.46% (operator)	Five production wells tied back into existing operated processing facilities, with capacity to produce up to 16,000 gross barrels of oil per day and 80 million gross standard cubic feet of natural gas per day.	283	CY21	On schedule and budget. The overall project is 62% complete.
Petroleum	Mad Dog Phase 2 (US Gulf of Mexico) 23.9% (non-operator)	New floating production facility with the capacity to produce up to 140,000 gross barrels of crude oil per day.	2,154	CY22	On schedule and budget. The overall project is 86% complete.
Other projects in progress at 31 December 2020
Potash⁽²⁾	Jansen Potash (Canada) 100%	Investment to finish the excavation and lining of the production and service shafts, and to continue the installation of essential surface infrastructure and utilities.	2,972			The project is 89% complete.

(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 US$B	H1 FY20 US$B	FY20 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.

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 4½ per cent smaller in the 2021 calendar year than it would have been if COVID-19 had not occurred: 1½ 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.

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, we 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.

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.

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 km² 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

Half year ended 31 December	2020 US$M	2019 US$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

Half year ended 31 December	2020 US$M	2019 US$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.

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

Prices and exchange rates

The average realised prices achieved for our major commodities are summarised in the following table:

Average realised prices⁽¹⁾	H1 FY21	H1 FY20	H2 FY20	FY20	H1 FY21 vs H1 FY20	H1 FY21 vs H2 FY20	H1 FY21 vs 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 Half year ended 31 December 2020	Average Half year ended 31 December 2019	As at 31 December 2020	As at 31 December 2019	As at 30 June 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.

Taxation expense

	2020			2019
Half year ended 31 December	Profit before taxation US$M	Income tax expense US$M	%	Profit before taxation US$M	Income tax expense US$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.

Half year ended 31 December 2020	Gross US$M	Tax US$M	Net 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.

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 York Stock Exchange (NYSE)	4 March 2021
Record Date	5 March 2021
DRP and Currency Election date (including announcement of currency conversion for ASX and LSE)	8 March 2021
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.

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

Committee

Nomination and Governance Committee

Remuneration

Committee

Sustainability

Committee

Terry Bowen (Chair)

Xiaoqun Clever

Ian Cockerill

Anita Frew

Christine O'Reilly

Ken MacKenzie (Chair)

Terry Bowen

Malcolm Broomhead

Susan Kilsby

John Mogford

Susan Kilsby (Chair)

Anita Frew

Gary Goldberg (SID)⁽¹⁾

Christine O'Reilly

Dion Weisler

John Mogford (Chair)

Malcolm Broomhead

Ian Cockerill

Gary Goldberg (SID)

(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 2020 US$M	Revenue⁽²⁾	Underlying EBITDA⁽³⁾	Underlying EBIT⁽³⁾	Exceptional items⁽⁴⁾	Net operating assets⁽³⁾	Capital expenditure	Exploration gross⁽⁵⁾	Exploration 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).

(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 US$M	Revenue	Underlying EBITDA⁽³⁾	D&A	Underlying EBIT⁽³⁾	Net operating assets⁽³⁾	Capital expenditure	Exploration gross	Exploration 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 US$M	Revenue	Underlying EBITDA⁽³⁾	D&A	Underlying EBIT⁽³⁾	Net operating assets⁽³⁾	Capital expenditure	Exploration gross	Exploration 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 cash costs	(35)	Higher exploration expenses due to expensing 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.

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.

Financial information for Petroleum for the December 2020 and December 2019 half years is presented below.

Half year ended 31 December 2020 US$M	Revenue⁽¹⁾	Underlying EBITDA	D&A	Underlying EBIT	Net operating assets	Capital expenditure	Exploration gross⁽²⁾	Exploration 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 31 December 2019 US$M	Revenue⁽¹⁾	Underlying EBITDA	D&A	Underlying EBIT	Net operating assets	Capital expenditure	Exploration gross⁽²⁾	Exploration 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.

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 cash costs	76	Strong cost performance at Escondida, 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.

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 31 December 2020 US$M	Revenue	Underlying EBITDA	D&A	Underlying EBIT	Net operating assets	Capital expenditure	Exploration gross	Exploration 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) US$M	Revenue	Underlying EBITDA	D&A	Underlying EBIT	Net operating assets	Capital expenditure	Exploration gross	Exploration 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.

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).

Financial information for Iron Ore for the December 2020 and December 2019 half years is presented below.

Half year ended 31 December 2020 US$M	Revenue	Underlying EBITDA	D&A	Underlying EBIT	Net operating assets	Capital expenditure	Exploration gross⁽¹⁾	Exploration 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 US$M	Revenue	Underlying EBITDA	D&A	Underlying EBIT	Net operating assets	Capital expenditure	Exploration gross⁽¹⁾	Exploration 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 cash costs	(24)	Increased maintenance costs at Queensland 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)

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.

Financial information for Coal for the December 2020 and December 2019 half years is presented below.

Half year ended 31 December 2020 US$M	Revenue	Underlying EBITDA	D&A	Underlying EBIT	Net operating assets	Capital expenditure	Exploration gross	Exploration 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 31 December 2019 US$M	Revenue	Underlying EBITDA	D&A	Underlying EBIT	Net operating assets	Capital expenditure	Exploration gross	Exploration 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.

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 km² 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 (CO₂-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

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.

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.

Further information on BHP can be found at: bhp.com

Authorised for lodgement by:

The Board of BHP Group Limited and BHP Group Plc

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BHP

Financial Report

Half year ended
31 December 2020

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

Consolidated Income Statement for the half year ended 31 December 2020

	Notes	Half year ended 31 Dec 2020 US$M	Half year ended 31 Dec 2019 US$M	Year ended 30 June 2020 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.

Consolidated Statement of Comprehensive Income for the half year ended 31 December 2020

	Half year ended 31 Dec 2020 US$M	Half year ended 31 Dec 2019 US$M	Year ended 30 June 2020 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.

Consolidated Balance Sheet as at 31 December 2020

	Notes	31 Dec 2020 US$M	30 June 2020 US$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.

Consolidated Cash Flow Statement for the half year ended 31 December 2020

	Half year ended 31 Dec 2020 US$M	Half year ended 31 Dec 2019 US$M	Year ended 30 June 2020 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.

Consolidated Statement of Changes in Equity for the half year ended 31 December 2020

	Attributable to BHP shareholders

	Share capital		Treasury shares

US$M	BHP Group Limited	BHP Group Plc	BHP Group Limited	BHP Group Plc	Reserves	Retained earnings	Total equity attributable to BHP shareholders	Non- controlling interests	Total 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.

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.

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.

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.

Half year ended 31 December 2020	Gross US$M	Tax US$M	Net 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.

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.

Half year ended 31 December 2019	Gross US$M	Tax US$M	Net 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)

Year ended 30 June 2020	Gross US$M	Tax US$M	Net 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)

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 date			(Loss)/profit from equity accounted investments, related impairments and expenses

	31 Dec 2020 %	31 Dec 2019 %	30 June 2020 %	Half year ended 31 Dec 2020 US$M	Half year ended 31 Dec 2019 US$M	Year ended 30 June 2020 US$M

Share of profit/(loss) of equity accounted investments:
Cerrejόn	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	−	−

Cerrejόn 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

	Half year ended 31 Dec 2020 US$M	Half year ended 31 Dec 2019 US$M	Year ended 30 June 2020 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.

6. Income tax expense

	Half year ended 31 Dec 2020 US$M	Half year ended 31 Dec 2019 US$M	Year ended 30 June 2020 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

	Half year ended 31 Dec 2020 US$M	Half year ended 31 Dec 2019 US$M	Year ended 30 June 2020 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.

7. Earnings per share

	Half year ended 31 Dec 2020	Half year ended 31 Dec 2019	Year ended 30 June 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:

	Half year ended 31 Dec 2020 US$M	Half year ended 31 Dec 2019 US$M	Year ended 30 June 2020 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
Cerrejόn 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.

8. Dividends

	Half year ended 31 Dec 2020		Half year ended 31 Dec 2019		Year ended 30 June 2020

	Per share US cents	Total US$M	Per share US cents	Total US$M	Per share US cents	Total 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 £1 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.

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 (unadjusted) in active markets for identical financial assets and liabilities.	Based on inputs other than quoted prices included within Level 1 that are observable for the financial asset or liability, either directly (i.e. as unquoted prices) or indirectly (i.e. derived from prices).	Based on inputs not observable in the market using appropriate valuation models, including discounted cash flow modelling.

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.

Financial assets and liabilities

	IFRS 13 Fair value hierarchy Level⁽¹⁾	IFRS 9 Classification	31 Dec 2020 US$M	30 June 2020 US$M Restated

Current cross currency and interest rate swaps⁽²⁾	2	Fair value through profit or loss	155	3
Current other derivative contracts⁽³⁾	2,3	Fair value through profit or loss	61	45
Current other investments⁽⁴⁾	1,2	Fair value through profit or loss	11	36
Non-current cross currency and interest rate swaps ⁽²⁾	2	Fair value through profit or loss	1,702	2,009
Non-current other derivative contracts⁽³⁾	2,3	Fair value through profit or loss	211	159
Non-current investment in shares	3	Fair value through other comprehensive income	35	32
Non-current other investments⁽⁴⁾⁽⁵⁾	1,2,3	Fair value through profit 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 receivables	2	Fair value through profit 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 and interest rate swaps⁽²⁾	2	Fair value through profit or loss	−	165
Current other derivative contracts⁽³⁾	2,3	Fair value through profit or loss	155	60
Current other financial liabilities⁽⁷⁾		Amortised cost	82	−
Non-current cross currency and interest rate swaps⁽²⁾	2	Fair value through profit or loss	641	1,414
Non-current other financial liabilities⁽⁷⁾		Amortised cost	546	−
Total other financial liabilities			1,424	1,639
Trade and other payables⁽⁸⁾		Amortised cost	5,096	5,354
Provisionally priced trade payables	2	Fair value through profit 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.

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.

Financial impacts of Samarco dam failure	Half year ended 31 Dec 2020 US$M	Half year ended 31 Dec 2019 US$M	Year ended 30 June 2020 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)

	Half year ended 31 Dec 2020 US$M		Half year ended 31 Dec 2019 US$M		Year ended 30 June 2020 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.

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 US$M		30 June 2020 US$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).

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.

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.

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.

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.

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.

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: Risks associated with operational integrity, tailings storage facilities and performance of our assets.		- Climate change: Risks associated with changes in climate patterns, as well as risks arising from policy, regulatory, legal, technological, market or other societal responses to the challenges posed by climate change.
- Occupational and process safety (including geotechnical failures and underground fires or explosions): Risks associated with the safety of BHP employees and contractors in performing their work and the containment of hazardous materials.		- Cybersecurity: Cyber-related risk events, including attacks on our enterprise or incidents relating to human error, online and web-based operations and infrastructure.
- Geopolitics and stakeholder relations (including access to markets): Risks associated with geopolitical changes and government actions that affect the macroeconomic outlook, commodity demand 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.		- Third party performance: Risks associated with non-operated joint ventures and the delivery of products and services by third parties engaged by BHP, including contractors.
- Capital allocation, and assets and growth options: Risks associated with the allocation of capital through annual planning and other processes, to make investment decisions and to discover, maintain and grow assets suited to our capabilities and strategy.		- Legal, regulatory, ethics and compliance: Risks associated with legal, regulatory, ethics and compliance obligations.
- Commodity prices: Risks associated with the prices of commodities, including sustained price shifts relative to the price of extraction.		- Balance sheet and liquidity: Risks associated with our ability to maintain a robust and effective 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.

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

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

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

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.

· 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.

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

16 February 2021

In respect of BHP Group Limited

London

16 February 2021

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.

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BHP

Alternative performance measures

Half year ended
31 December 2020

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.

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.

Half year ended 31 December	2020 US$M	2019 US$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

APMs derived from Consolidated Income Statement

Underlying attributable profit

Half year ended 31 December	2020 US$M	2019 US$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

Half year ended 31 December	2020 US cents	2019 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

Half year ended 31 December	2020 US$M	2019 US$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.

Underlying EBITDA margin

Half year ended 31 December 2020 US$M	Petroleum	Copper	Iron Ore	Coal	Group and unallocated items/ 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%


Half year ended 31 December 2019 US$M	Petroleum	Copper	Iron Ore	Coal	Group and unallocated items/ 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

Half year ended 31 December	2020 US$M	2019 US$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

Half year ended 31 December	2020 US$M	2019 US$M

Net operating cash flows	9,369	7,442
Net investing cash flows	(4,209)	(3,732)

Free cash flow	5,160	3,710

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

	31 Dec 2020 US$M	30 June 2020 US$M Restated	31 Dec 2019 US$M 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 reflect 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 2020 US$M	31 Dec 2019 US$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)

Net operating assets

	31 Dec 2020 US$M	31 Dec 2019 US$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 reflect 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.

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.

	Revenue US$M	Total expenses, Other income and (Loss)/profit from equity accounted investments US$M	Profit from operations US$M	Depreciation, amortisation and impairments and Exceptional Items US$M	Underlying EBITDA 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

Underlying return on capital employed (ROCE)

	31 Dec 2020 US$M	31 Dec 2019 US$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 US$M	Petroleum	Copper	Iron Ore	Coal	Group and unallocated items/ 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 Restated⁽²⁾	Petroleum	Copper	Iron Ore	Coal	Group and unallocated items/ 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.

Underlying return on capital employed (ROCE) by asset

Half year ended 31 December 2020 US$M	Western Australia Iron Ore	Antamina	Escondida	Pampa Norte	Petroleum⁽¹⁾	Potash	Olympic Dam	Queensland Coal	Cerrejon	New South Wales Energy Coal	Other	Total 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 December 2019 US$M Restated⁽²⁾	Western Australia Iron Ore	Antamina	Escondida	Pampa Norte	Petroleum⁽¹⁾	Potash	Olympic Dam	Queensland Coal	Cerrejon	New South Wales Energy Coal	Other	Total 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.

Definition and calculation of alternative performance measures

Alternative Performance Measures (APMs)	Reasons why we believe the APMs are useful	Calculation methodology

Underlying attributable profit	Allows the comparability of underlying financial performance by excluding the impacts of exceptional items and is also the basis on which our dividend payout ratio policy is applied.	Profit after taxation attributable to BHP shareholders excluding any exceptional items attributable to BHP shareholders.
Underlying basic earnings per share	On a per share basis, allows the comparability of underlying financial performance by excluding the impacts of exceptional items.	Underlying attributable profit divided by the weighted basic average number of shares.
Underlying EBITDA	Used to help assess current operational profitability excluding the impacts of sunk costs (i.e. depreciation from initial investment). Each is a measure that management uses internally to assess the performance of the Group's segments and make decisions on the allocation of resources.	Earnings before net finance costs, depreciation, amortisation and impairments, taxation expense, discontinued operations and exceptional items. Underlying EBITDA includes BHP's share of profit/(loss) from investments accounted for using the equity method including net finance costs, depreciation, 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 operational profitability excluding net finance costs and taxation expense (each of which are managed at the Group level) as well as discontinued operations and any exceptional items.	Earnings before net finance costs, taxation expense, discontinued operations and any exceptional items. Underlying EBIT includes BHP's share of profit/(loss) from investments accounted for 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 Framework to assess efficient deployment of capital. Represents the total outflows of our operational investing expenditure.	Purchases of property, plant and equipment and exploration expenditure.
Free cash flow	It is a key measure used as part of our Capital Allocation Framework. 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.	Net operating cash flows less net investing cash flows.

Net debt	Net debt shows the position of gross debt less index-linked freight contracts offset by cash immediately available to pay debt if required and any associated derivative financial instruments. Liability associated with index-linked freight contracts are excluded from 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.	Interest bearing liabilities less liability associated with index-linked freight contracts less cash and cash equivalents less net cross currency and interest rate swaps less net cash management related instruments for the Group at the reporting date.
Gearing ratio		Ratio of Net debt to Net debt plus Net assets.
Net operating assets	Enables a clearer view of the assets deployed to generate earnings by highlighting the net operating assets of the business separate from the financing and tax balances. This measure helps provide an indicator of the underlying performance of our assets and enhances comparability between them.	Operating assets net of operating liabilities, including the carrying value of equity accounted investments and predominantly excludes cash balances, loans to associates, interest bearing liabilities, derivatives hedging our net debt and tax balances.
Underlying return on capital employed (ROCE)	Indicator of the Group's capital efficiency and is provided on an underlying basis to allow comparability of underlying financial performance by excluding the impacts of exceptional items.	Profit after taxation excluding exceptional items and net finance costs (after taxation) divided by average capital employed. Profit after taxation excluding exceptional items and net finance 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 allow comparability of underlying financial performance by excluding the impacts of exceptional items.	Total taxation expense/(benefit) excluding exceptional items and exchange rate movements included in taxation expense/(benefit) divided by Profit before taxation and exceptional items.

Unit cost

Used to assess the controllable financial performance of the Group's assets for each unit of production. Unit costs are adjusted for site specific non controllable factors to enhance comparability between the Group's assets.

Ratio of net costs of the assets to the equity share of sales tonnage. Net costs is defined as revenue less Underlying EBITDA and excludes freight and other costs, depending on the nature of each asset. Freight is excluded as the Group believes it provides a similar basis of comparison 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.

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.

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.

Key Indicator

Calculation methodology

Operational greenhouse gas emissions

Definition

Scope 1 greenhouse gas emissions are direct emissions from operations that are owned or controlled by BHP, primarily emissions from fuel consumed by haul trucks at our operated assets, as well 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 Energy Coal, Olympic Dam, Nickel West, WA Iron ore, Petroleum - Australia	Australia	National Greenhouse and Energy Reporting Scheme
Escondida, Pampa Norte	Chile	Green Tax legislation (referencing IPCC factors)
Petroleum - Gulf of Mexico	USA	US EPA GHG reporting program
Potash - Canada	Canada	Canadian Greenhouse Gas Reporting Program (referencing IPCC factors)
Petroleum - Trinidad	Trinidad	None

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 emissions

Scope 3 emissions have been calculated on a carbon dioxide equivalent basis using methodologies 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.

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.

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.

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.

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END

IR UVVRRANUUAUR

Results for the half year ended 31 December 2020

BHP RESULTS FOR THE HALF YEAR ENDED 31 DECEMBER 2020

Results for the half year ended 31 December 2020

Social value underpins everything we do

Safety and sustainability

Climate change

Key indicators scorecard

Financial performance

Earnings and margins

Costs

Cash flow and balance sheet

Dividends

Capital and exploration

Projects

Capital Allocation Framework

Outlook

Economic outlook

Commodities outlook

Portfolio

Income statement

Underlying attributable profit

Underlying EBITDA

Underlying EBITDA

Prices and exchange rates

Depreciation, amortisation and impairments

Net finance costs

Taxation expense

Exceptional items

Debt management and liquidity

Dividend

Corporate governance

Segment summary(1)

Petroleum

Petroleum exploration

Copper

Iron Ore

Coal

Greenfield minerals exploration

Group and unallocated items

Contents

Notes to the Financial Statements

Impact of COVID-19 pandemic

COVID-19 related costs

Impairment of Energy coal assets and associated tax losses

Review of Operations

Principal Risks and Uncertainties

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

Conclusion of EY Australia

Conclusion of EY UK

Directors' Responsibility for the half year Financial Report

Auditor's Responsibility

Scope of Review

Independence

Use of EY UK's review report

Health and safety-related metrics

Climate change-related metrics

Fresh water withdrawals

People-related metrics

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