Release Time	IMMEDIATE
Date	15 February 2022
Number	08/22

BHP RESULTS FOR THE HALF YEAR ENDED 31 DECEMBER 2021

Note: All guidance is subject to further potential impacts from COVID-19 during the 2022 financial year.

 

Keeping our people and communities safe

- We achieved our third consecutive year fatality free.

- Our focus on safety and health has helped us to mitigate the impacts of COVID-19 and deliver continued strong operational performance.

Margin of 64%, higher realised prices, disciplined cost performance and near record production at Western Australia Iron Ore (WAIO)

·    Profit from operations of US$14.8 billion, up 50%. Underlying EBITDA⁽ⁱ⁾ of US$18.5 billion at a margin⁽ⁱ⁾ of 64% for continuing operations. Disciplined cost performance, with unit cost guidance reiterated (at guidance exchange rates⁽ⁱⁱ⁾) with the exception of Queensland Coal which has increased, reflecting lower expected volumes for the full year as a result of significant wet weather and labour constraints.

·    Attributable profit of US$9.4 billion and Underlying attributable profit⁽ⁱ⁾ of US$10.7 billion up 77% from the prior period for total operations.

- Net operating cash flow of US$11.5 billion and free cash flow⁽ⁱ⁾ of US$8.5 billion for continuing operations reflects higher realised prices across our major commodities and reliable operational performance.

Disciplined capital allocation and a revised net debt target to between US$5 and US$15 billion

- Capital and exploration expenditure⁽ⁱ⁾ of US$2.9 billion for continuing operations. Guidance for minerals capital and exploration expenditure for the full year has decreased by US$0.2 billion to US$6.5 billion as a result of favourable exchange rate movements.

- Our potash developments are tracking to plan. The Jansen shaft project is 98% complete and the Jansen Stage 1 project has commenced contract awards.

- We have added to our early stage growth options in future facing commodities by executing agreements for interests in additional Australian copper projects in October 2021, including the Elliott project in the Northern Territory, and investing in the Kabanga Nickel Project in Tanzania in December 2021.

- Our commitment to a strong balance sheet remains. We have revised our net debt target range to between US$5 and US$15 billion. The revised range will support a resilient balance sheet and retain the flexibility to allocate capital towards shareholder returns and future organic and inorganic investment opportunities. Net debt⁽ⁱ⁾ at 31 December 2021 was US$6.1 billion.

Value and returns: Record interim dividend of US$1.50 per share and Underlying ROCE up to 39.5%

- We will pay a record interim dividend of US$1.50 per share or US$7.6 billion, equivalent to a 78% payout ratio⁽ⁱⁱⁱ⁾.

- Underlying return on capital employed⁽ⁱ⁾ strengthened further to 39.5% for total operations.

Strategic actions progressing to plan

- In January 2022, BHP completed the unification of BHP's dual listed corporate structure.

- The Cerrejón divestment to Glencore completed in January 2022 and the announced share sale agreement to divest BHP Mitsui Coal (BMC) is expected to complete in the middle of the 2022 calendar year. The review process for New South Wales Energy Coal (NSWEC) is progressing, in line with the two-year timeframe we set last year.

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- Completion of the proposed merger of our Petroleum business with Woodside is expected in the June 2022 quarter subject to satisfaction of conditions precedent including approval by Woodside shareholders.

The December 2021 half year financial results have been prepared on the basis that the BHP Petroleum business is a discontinued operation. The financial contribution of Petroleum entities impacted has been disclosed as separate line items, "Discontinued operations", in the BHP Group's Consolidated Income statement and Consolidated Cash flow statement, and has not been included when calculating the minimum dividend payout. BMC will continue to be consolidated with Queensland Coal as a continuing operation until the expected completion in the middle of the 2022 calendar year. On the Consolidated Balance Sheet, both BMC and BHP Petroleum have been reclassified as assets held for sale and excluded from net operating assets.

Half year ended 31 December	2021 US$M	2020 US$M	Change %
Total operations
Attributable profit	9,443	3,876	144%
Basic earnings per share (cents)	186.6	76.6	144%
Interim dividend per share (cents)	150.0	101.0	49%
Net operating cash flow	13,277	9,369	42%
Capital and exploration expenditure	3,677	3,614	2%
Net debt	6,090	11,839	(49%)
Underlying attributable profit	10,687	6,036	77%
Underlying basic earnings per ordinary share (cents)(i)	211.2	119.4	77%
Continuing operations
Profit from operations	14,845	9,889	50%
Underlying EBITDA	18,463	13,887	33%
Underlying attributable profit	9,715	6,200	57%
Net operating cash flow	11,529	9,148	26%
Capital and exploration expenditure	2,878	2,921	(1%)
Underlying basic earnings per ordinary share (cents)	192.0	122.6	57%
Underlying EBITDA including the contribution from Petroleum assets classified as discontinued operations	21,381	14,680	46%

BHP Chief Executive Officer, Mike Henry:

"BHP had a strong first half. We achieved our third consecutive fatality free calendar year. We mitigated the impacts of COVID-19 and significant adverse weather events to turn in a solid operational performance, particularly from our flagship Western Australian Iron Ore business.

We have announced an interim dividend of US$1.50 per share, bringing total shareholder returns to more than US$22 billion over the past 18 months.

Our record interim dividend was supported by our reliable operating performance and continued strong markets for a number of our products.

We have made strong progress on the execution of our strategy. We unified the BHP corporate structure with strong support from shareholders, we announced and advanced the proposed merger of our petroleum business with Woodside, we progressed our divestments of certain coal assets and we announced the final investment decision for our Jansen Stage 1 potash project.  We have also secured further growth options in future facing commodities.

BHP is well positioned for the future. We are building on our strong foundations and capital discipline to reshape our business and grow long-term value for shareholders and other stakeholders." 

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Health and safety

The safety, health and wellbeing of our workforce and the communities in which we operate are fundamental priorities for our business. Our global safety improvement programs are progressing and our safety leading indicators have continued a strong underlying positive trend. We have now achieved our third consecutive year without a fatality and we have seen a sustained improvement in our key safety performance indicators. High Potential Injury frequency has decreased by 10 per cent during the half year, a reduction of 36 per cent since 31 December 2018. Total Recordable Injury Frequency has increased slightly, up three per cent during the half year to 3.8, but is 12 per cent lower over the last three years.

Community transmission of COVID-19 has increased in the jurisdictions in which we operate. We remain vigilant and continue to escalate or deescalate controls taking into account the prevailing risk as well as guidelines from local and national government bodies and expert health advice in the countries where we operate. Many of these measures remain in an elevated state at present. BHP is strongly encouraging workers who have received their first and second doses of COVID-19 vaccines to receive a booster dose as soon as they are eligible to do so. In Western Australia, a public health direction requires, from 5 February 2022, the majority of resource industry workers to receive a booster dose within one month of becoming eligible, and BHP is actively considering whether to make boosters a requirement for entry to BHP workplaces in other locations.

We are firmly committed to eliminating incidents of sexual assault and sexual harassment in our workplaces and accommodation villages, and have strengthened our approach to prevention, reporting and response. We have made significant progress in implementing controls to prevent incidents of sexual assault and sexual harassment and to mitigate the impact of incidents that do occur. Areas of focus include increased clarity and enforcement of respectful and safe workplace behaviours, leadership and education, contractor and third-party engagement, security measures at our accommodation villages and support for impacted persons. We also have ongoing engagement with external experts to learn from best practice.

Social value

We are committed to creating long-term sustainable value for shareholders and all those who benefit from, or are impacted by, BHP's business. Social value and long-term financial value are intrinsically linked. We seek out opportunities that grow both social and financial value. Our focus on social value positions us to maximise our contribution more broadly to society - to our employees and contractors, customers and suppliers, governments,  Indigenous stakeholders and other communities.

We demonstrate social value through multiple dimensions - in our operational and business performance and how we achieve it, in our setting and achieving of high standards of Environmental, Social and Governance (ESG) practices, and in the nature of our relationships with stakeholders. Social value is not merely a concept or an intent; it involves continued planned delivery of tangible outcomes. Over the course of the first half of the 2022 financial year, among other outcomes, we continued to advance social value in a range of areas including in our interactions with small and medium business enterprises, in supporting workforce skills development, in Indigenous partnerships and on decarbonisation.

Empowered communities

We are committed to contributing to the prosperity of the communities where we have a presence. We have continued to support local and Indigenous communities with additional funds to boost COVID-19 vaccine awareness and accessibility. We continue to support local business and training to enhance economic recovery and diversification. From 1 July 2021, we reduced our payment terms for small, local and Indigenous enterprises to 7 days. This came into effect across 31 countries and benefited over 4,000 suppliers.

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We recognise that building capacity and skills is a critical element in the long-term ability of local communities to prosper and thrive. BHP partnered with the Australian Government Department of Education, Skills and Employment to deliver up to 1,000 skills development opportunities in regional Australia, through our voluntary social investment program. Through the Future of Work Program we are working with stakeholders to identify local workforce and business needs in regional areas, and tailoring training opportunities accordingly. The program provides opportunities to unemployed, young and Indigenous Australians across the regions where BHP operates to develop skills and better access employment. It also helps small, medium and Indigenous-run businesses to upskill employees, including skills to work in a digital environment, taking advantage of new opportunities we expect to be created through the economic recovery.

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 address challenges that are directly relevant to the global resources sector and contribute towards many of the United Nations Sustainable Development Goals focusing on the governance of natural resources, environmental resilience and education equity. The BHP Foundation's global partnerships extend across 32 projects and 49 countries, including 'Opening Extractives', led by Extractive Industries Transparency Initiative (EITI) and Open Ownership, supporting governments to transform the availability and use of beneficial ownership data for effective governance in the extractives sector and helping to end the use of anonymous companies; and the 10 Deserts Project which has established the world's largest network of Indigenous-managed conservation areas spanning more than 35 per cent of Australia. Further information can be found at: bhp.com/foundation.

Inclusion

We are progressing a number of improvements to ensure our workplaces are culturally safe, free from any form of harassment, racial discrimination and vilification, or bullying. This includes ensuring that allegations of racial discrimination and vilification are investigated by BHP's Central Investigations Team, which is separate to the functional or operational area of occurrence. A decision was taken in September 2020 that all allegations of racial discrimination and vilification are to be assigned to the most serious investigation category. We are also taking steps to address racial pay disparity. In the US, we have piloted a survey that included information on ethnic background. This supported a pay equity review and resultant adjustments.  We are in the process of rolling the survey out company-wide in the 2022 calendar year. In our Commercial function based in Singapore, we have increased our Asian leadership from 43 per cent in May 2021 to 54 per cent in December 2021. We will continue to work with our people, industry peers and external experts to lift our performance and that of the industry.

Gender diversity

We continue to build a more inclusive and diverse workforce that better reflects the communities in which we operate and further enhances performance. This includes our aspirational goal of a gender balanced workforce by the end of the 2025 financial year. In the first half of the 2022 financial year, 46 per cent of our external hires were female, which has resulted in a further increase of female representation in the workforce, up 0.8 percentage points to 30.6 per cent. The Executive Leadership Team established in the 2020 calendar year is gender balanced.

Indigenous partnerships

We recognise the connection of Indigenous peoples to the land and water, and we seek to recognise this by listening, learning and building shared understandings and objectives. Our approach to cultural heritage focuses on building and maintaining genuine and mutually beneficial partnerships with Indigenous peoples and is driven by the commitments made in our Indigenous Peoples Policy Statement, our Indigenous Peoples Strategy and our Regional Indigenous Peoples plans, including the Australian Reconciliation Action Plan. These plans include key targets for increasing Indigenous representation in the workforce and engaging with Indigenous businesses. Indigenous representation has increased across all operating regions and BHP has spent over US$69 million in the December 2021 half year with Indigenous and First Nation's businesses globally.

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During the half year, we continued to work with Indigenous groups and representative organisations to further strengthen our cultural heritage management practices. We recognise our responsibility to respect and sustain the cultural landscapes in which we operate and work in partnership to ensure we respect the rights of the Indigenous peoples who are its custodians. We also continue to support efforts to further strengthen the laws, policies and practices that regulate the management of cultural heritage values. In August 2021, and after a year of negotiations, the Barada Barna Aboriginal Corporation, on behalf of the Barada Barna people, and BMC signed a Native Title Project Agreement for South Walker Creek Mine in Central Queensland.

Our progress on decarbonisation

Climate Transition Action Plan

In September 2021, we released our Climate Transition Action Plan (CTAP), which was strongly supported by shareholders through the non-binding advisory 'Say on Climate' shareholder vote at our Annual General Meetings in 2021. The CTAP outlines BHP's updated approach to reducing greenhouse gas (GHG) emissions and managing climate risks across our global value chain, including the detail of our value chain (Scope 3) net zero goal.

We expect our diversified portfolio to be resilient under a number of different long-term scenarios, and we continue to pursue opportunities to further strengthen our portfolio and our exposure to long-term decarbonisation trends. 

Our progress on operational decarbonisation (Scope 1 and Scope 2)

We have made progress on actions required to meet our medium-term target and long-term goal to reduce operational emissions. In January 2022, Escondida and Spence completed the transition to four renewable power contracts to increase flexibility for our power portfolio, as part of our continued aim to supply Escondida and Spence's energy requirements from 100 per cent renewable energy sources by the mid-2020s.

In Australia, Olympic Dam partnered with Iberdrola at the Port Augusta Renewable Energy Park to reduce Olympic Dam's emissions position to zero from 50 per cent of its electricity consumption by 2025, based on current forecast demand. This follows BHP's entry into renewable energy agreements for our operations in Nickel West in 2021 and Queensland Coal in 2020.

To support our goal to achieve net-zero operational GHG emissions by 2050, BHP has become a founding member of Komatsu's GHG Alliance, which aims to develop commercially viable zero-greenhouse gas emissions haul trucks. We are also working in partnership with Caterpillar Inc. to accelerate their development and deployment of zero-emissions mining trucks at BHP operations.

Our progress on value chain decarbonisation (Scope 3)

We have made progress on actions to support the reduction of value chain emissions through partnerships with our customers. COP26 in Glasgow highlighted the increasing importance on collaboration for 'breakthrough' discoveries, particularly in steelmaking. In October 2021, BHP announced the signing of a Memorandum of Understanding (MoU) with South Korea's POSCO, one of the world's largest steelmakers, to undertake pilot and plant trials to reduce emissions in the steelmaking process. This, combined with other MoUs, means we now have partnerships with major steelmakers with a combined output of approximately 12 per cent of reported global steel production. In November 2021, we officially joined the Global Low-carbon Metallurgical Innovation Alliance, with the aim of boosting the global steel industry's low-carbon transformation. The alliance, initiated by China Baowu Steel Group, is comprised of 62 enterprises, colleges and universities and scientific research institutions from 15 countries.

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In the first half of the 2022 financial year, we also announced a collaboration with Tesla Inc. to make the nickel-based battery supply chain more sustainable, with a focus on end-to-end raw material traceability using blockchain technology. BHP also entered into a MoU with Toyota Tsusho Corporation and Japan's Prime Planet Energy & Solutions to create a Green Electric Vehicle Ecosystem that will seek to enhance sustainability, recyclability and traceability, starting with nickel sulphate supply.

In maritime, BHP signed the Call to Action for Shipping Decarbonisation to urge world leaders to align shipping with the goals of the Paris Agreement. This is one dimension of our commitment to maritime decarbonisation, which includes our new target, announced in September 2021, of net zero by 2050 for greenhouse gas emissions from all shipping of our products by 2050, subject to the widespread availability of carbon neutral solutions, including low/zero-emission technology on board suitable ships and low/zero-emission marine fuels^(iv).

Value chain stewardship

BHP was awarded the Copper Mark for Escondida, Spence and Olympic Dam. The Copper Mark is an assurance framework specific to the copper industry, developed to ensure that value chain participants demonstrate best practice in responsible production and contribute to the United Nations' Sustainable Development Goals. Additionally, BHP and leading US copper cable and wire manufacturer, Southwire, have completed their first 'carbon neutral'^(v) copper transaction involving delivery from BHP's mines in Chile to Southwire's processing activities in Georgia, United States.

Environmental performance

We are on track to achieve our five-year target to reduce FY22 fresh water withdrawal by 15 per cent from FY17 levels.

The importance of the intersection between biodiversity and climate effects was noted at several major intergovernmental meetings in 2021. A new US$3.3 million research program by BHP and CSIRO, Australia's national science agency, will seek to measure and quantify the net emissions reduction potential of Australia's mangroves, seagrasses and tidal marshes, which can absorb carbon faster than land-based forests. They also provide coastal communities with essential benefits for coastal protection, fish production and biodiversity. This project aims to develop metrics to measure these benefits for incorporation into Australian and international standards.

As part of BHP's commitment to contribute to environmental resilience and biodiversity outcomes in a collaborative way, BHP joined the Taskforce on Nature-related Financial Disclosures (TNFD) Forum, a global multi-disciplinary consultative group of institutions seeking to develop and deliver a natured-based risk management and disclosure framework. It aims to support a shift in global financial flows away from nature-negative outcomes and toward nature-positive ones.

 

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Social value: key indicators scorecard⁽¹⁾

	Target	H1 FY22	H2  FY21	H1 FY21	FY21	Comment
Fatalities	Zero work-related fatalities	0	0	0	0	No fatalities at our operated assets over the last 36 months.
High Potential Injury (HPI) frequency(vi) (per million hours worked)	Year-on-year improvement in HPI frequency	0.18	0.20	0.20	0.20	36 per cent reduction since 31 December 2018.
TRIF(vi) (per million hours worked)	Year-on-year improvement in TRIF	3.8	3.7	3.6	3.7	12 per cent reduction over the last three years.
Operational greenhouse gas (GHG) emissions(vi) (Mt CO2-e)	Maintain FY22 operational GHG emissions at or below FY17 levels(2)(3) while we continue to grow our business and reduce emissions by at least 30 per cent from FY20 levels(3) by FY30	6.8	8.0	8.2	16.2	On track to meet our FY22 and FY30 targets with the reductions in emissions from renewable power contracts at Escondida, Spence, Queensland Coal, Nickel West and Olympic Dam.
Value chain emissions(vi)	Steelmaking: 2030 goal to support industry to develop technologies and pathways capable of 30 per cent emissions intensity reduction in integrated steelmaking, with widespread adoption expected post-2030					On track to deliver 2030 goal with MoU with South Korea's POSCO signed in H1 FY22.
	Maritime transportation: 2030 goal to support 40 per cent emissions intensity reduction of BHP-chartered shipping of our products					On track to deliver 2030 goal.
Freshwater withdrawals(vi) (GL)	Reduce FY22 freshwater withdrawals by 15 per cent from FY17 levels(4)	55.3	60.9	52.6	113.5	On track to meet our five-year target.
Community and social investment (US$M)	No less than one per cent of pre-tax profit (three-year rolling average)	46.9	144.3	30.5	174.8	On track to deliver our target.
Local procurement spend (US$M)	Support the growth of local businesses in the regions where we operate	1,172	1,064	1,112	2,176	Over US$1.9 billion directed to local suppliers in each of the past two financial years.
Female workforce participation(vi) (%)	Aspirational goal for gender balance by the end of FY25	30.6	29.8	27.4	29.8	74 per cent increase from FY16(5), with 46 per cent female external hires in H1 FY21.
Indigenous workforce participation(vi) (%)	Australia: aim to achieve 8.0 per cent by the end of FY25	8.0	7.2	6.7	7.2	Assets continue to focus on Indigenous employment.
	Chile: aim to achieve 10.0 per cent by the end of FY26	8.5	7.5	6.8	7.5	Assets continue to focus on Indigenous employment.
	Canada - Potash: aim to achieve 20.0 per cent by the end of FY27	13.7	13.7	12.8	13.7	Assets continue to focus on Indigenous employment.

(1)   All data points are presented on a total operations basis and are subject to non-financial assurance reviews. Some previously reported data points have been re-stated as a result of audit and assurance reviews completed subsequent to release of information or reclassification. Re-stated figures are shown in italics.

(2)   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.

(3)   FY17 and FY20 baselines will be adjusted for any material acquisitions and divestments based on GHG emissions at the completion of the transaction. Carbon offsets will be used as required.

(4)   In FY17, our fresh water withdrawals were 156.1 GL (on an adjusted basis, excluding Onshore US). The FY17 baseline data has been adjusted to account for: the materiality of the strike affecting water withdrawals at Escondida in FY17 and improvements to water balance methodologies at WAIO and Queensland Coal and exclusion of hypersaline, wastewater, entrainment, supplies from desalination and Discontinued operations (Onshore US assets) in FY19 and FY20.

(5)   In FY16, our female representation was 17.6%.

 

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Samarco

BHP Brasil remains committed to Samarco 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 Fundão dam failure, as set out in the Framework Agreement entered into in March 2016 by BHP Brasil, Samarco, Vale and relevant Brazilian authorities.

In total, Renova has spent R$19.6 billion (approximately US$4.2 billion^(vii)) on remediation and compensation programs to 31 December 2021.

Compensation and financial assistance increased to a total of approximately R$8.7 billion (approximately US$1.8 billion^(vii)) in payments to support approximately 370,000 people affected by the Fundão dam failure. This includes approximately 51,200 payments paid through the court-mandated "Novel System". Resettlement of communities continues to progress, with 128 resettlement cases across the region completed, and a further 176 in progress, through construction of houses and public buildings, allocation of plots or cash payments. 

Negotiations are ongoing with State and Federal Prosecutors and other Brazilian public authorities on the review of the Framework Agreement, seeking a definitive and substantive settlement of claims relating to the dam failure.

In October 2021, the 12th Federal Court delivered a ruling that expanded the scope of eligible individuals of the court mandated compensation process ("Novel System"), extended its geographical scope and increased indemnification amounts for certain categories of damage. While the decision is under appeal and applications have been made to clarify certain aspects of the ruling, the ruling has been considered in determining the cost estimates that form the basis of the Group's dam failure provision as at 31 December 2021. The Group's provisions related to the Samarco dam failure have increased by US$327 million since 30 June 2021, to a total of US$3.1 billion as at 31 December 2021. 

In the December 2021 half year, BHP reported an exceptional loss of US$821 million (after tax) in relation to the Fundão dam failure. This predominantly reflected an increase in cost estimates for the Samarco dam failure provision, primarily as a result of the 12th Federal Court's decision and fair value change on forward exchange derivatives. Additional commentary is included on page 47.

Samarco's Judicial Reorganisation process is continuing in the Commercial Courts of Belo Horizonte, State of Minas Gerais. The Judicial Reorganisation is a process for Samarco to restructure its financial debts in order to establish a sustainable independent financial position that would allow Samarco to continue its operations safely and meet its Renova Foundation obligations. BHP Brasil will continue to support Samarco in this process.

 

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Financial performance

Note: All guidance is subject to further potential impacts from COVID-19 during the 2022 financial year

Earnings and margins

·      Attributable profit of US$9.4 billion includes an exceptional loss of US$1.2 billion (31 December 2020: US$3.9 billion, which included an exceptional loss of US$2.2 billion).

·      The exceptional loss of US$1.2 billion (after tax) relates to the current half year impact of the Samarco dam failure of US$821 million as well as an impairment of US deferred tax assets no longer expected to be recoverable after the Petroleum demerger of US$423 million.

·      Underlying attributable profit of US$10.7 billion for total operations (31 December 2020: US$6.0 billion) was underpinned by disciplined cost performance across our operations.

·      Profit from operations (continuing operations) of US$14.8 billion (31 December 2020: US$9.9 billion) increased as a result of higher sales prices across our major commodities, near record production at WAIO and higher concentrate sales at Spence, and favourable exchange rate movements. This was partially offset by the impacts from planned maintenance across a number of our assets, expected copper grade decline at Escondida, significant wet weather at Queensland Coal and inflationary pressures, including higher fuel, energy and consumable prices.

·      The total impact from COVID-19 on our operations was US$223 million (pre-tax) (31 December 2020: US$405 million). This represents the following impacts: lower volumes at our operated assets of US$69 million (31 December 2020: US$138 million) and direct costs of US$154 million incurred (31 December 2020: US$267 million, reported as an exceptional item), such as social distancing measures including additional charter flights, accommodation, security and health and hygiene services and also temporary relocation costs due to border restrictions, combined with higher demurrage and other standby charges due to delays caused by COVID-19.

·      Underlying EBITDA (continuing operations) of US$18.5 billion (31 December 2020: US$13.9 billion), with an increased EBITDA margin (continuing operations) of 64 per cent (31 December 2020: 60 per cent). Additional commentary is included on page 15. 

·      Underlying return on capital employed strengthened to 39.5 per cent (31 December 2020: 23.6 per cent). Underlying return on capital employed, excluding Petroleum, is approximately 42.9 per cent.

Costs

·      Full year unit cost guidance for WAIO and Escondida remains unchanged (based on exchange rates of AUD/USD 0.78 and USD/CLP 727). Unit cost guidance for Queensland Coal has been increased, reflecting lower expected volumes for the full year as previously announced.

·      Unit costs⁽ⁱ⁾ at WAIO are below guidance at the half year (based on an exchange rate of AUD/USD 0.78) and are tracking towards the lower end of the guidance range on a full year basis. WAIO unit costs, on a C1 basis excluding third party royalties, were 18 per cent higher than the prior period at US$14.74 per tonne (31 December 2020: US$12.46 per tonne) driven by higher diesel prices (US$0.84 per tonne) and costs associated with the South Flank ramp up (US$0.82 per tonne). 

·      Escondida unit costs were at the top end of the guidance range (based on an exchange rate of USD/CLP 727) and reflect the planned lower concentrator feed grade. Concentrator feed grade is expected to improve in the June 2022 half year as the mine sequence moves towards higher grade areas.

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·      Queensland Coal unit costs are tracking above the revised guidance range at the half year (based on an exchange rate of AUD/USD 0.78) primarily due to lower volumes in the first half due to significant wet weather impacts and labour constraints. A stronger second half performance is expected following planned maintenance undertaken in the first half, however COVID-19 related absenteeism impacts remain a risk for the second half of the 2022 financial year.

 

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·      Historical costs and guidance for our major assets are summarised below:

			H1 FY22 at
	Medium-term guidance(1)	FY22 guidance(1)	guidance exchange rates(1)	realised exchange rates(2)	H1 FY21(3)	H1 FY22(2) vs H1 FY21(3)
Escondida unit cost (US$/lb)	<1.10	1.20 - 1.40	1.40	1.29	0.90	43%
WAIO unit cost (US$/t)(4)	<16	17.50 - 18.50	17.38	16.15	14.38	12%
Queensland Coal unit cost (US$/t)(5)	−(6)	85 - 94	98.63	91.39	84.92	8%
Discontinued operations
Petroleum unit cost (US$/boe)	−(7)	−(7)	10.82	10.51	10.30	2%

(1)   FY22 and medium-term unit cost guidance are based on exchange rates of AUD/USD 0.78 and USD/CLP 727.

(2)   Average realised exchange rates for H1 FY22 of AUD/USD 0.73 and USD/CLP 798.

(3)   H1 FY21 unit costs exclude the impact from COVID-19 which was reported as an exceptional item.

(4)   WAIO unit costs exclude freight and government royalties. C1 unit costs, excluding third party royalties, are detailed on page 22.

(5)   We announced the share sale agreement to divest our interest in BMC in November 2021, however we will continue to report BMC as part of Queensland Coal and we maintain economic and operating control of BMC until the sale has completed.

(6)   Coal imports into China remains uncertain and as a result Queensland Coal medium-term unit cost guidance is not able to be provided.

(7)   Given our announcement of a binding share sale agreement for the proposed merger of BHP's oil and gas portfolio with Woodside in November 2021, no further unit cost guidance for Petroleum will be provided.

·      Production and guidance are summarised below:

Production	Medium-term guidance	FY22  guidance		H1 FY22	H1 FY21	H1 FY22 vs H1 FY21
Copper (kt)		1,590 - 1,760	Low end	742	841	(12%)
Escondida (kt)	~1,200(1)	1,020 - 1,080	Narrowed range	488	572	(15%)
Other copper(2) (kt)		520 - 590	Lowered	254	269	(5%)
Iron ore (Mt)		249 - 259	Unchanged	129	128	1%
WAIO (Mt)		246 - 255	Unchanged	127	128	(1)%
WAIO (100% basis) (Mt)	290(3)	278 - 288	Unchanged	144	145	0%
Samarco (Mt)		3 - 4	Unchanged	2	0	>100%
Metallurgical coal (Mt)(4)	−(5)	38 - 41	Lowered	18	19	(8%)
Queensland Coal (100% basis) (Mt)		68 - 72	Lowered	31	34	(10%)
Energy Coal - NSWEC (Mt)		13 - 15	Unchanged	7	7	5%
Energy Coal - Cerrejón (Mt)		−(6)		4	1	>100%
Nickel (kt)		85 - 95	Unchanged	40	46	(15%)
Discontinued operations
Petroleum (MMboe)	−(7)	−(7)		53	50	5%

(1)   Represents annual average copper production over the medium term.

(2)   Other copper comprises Pampa Norte, Olympic Dam and Antamina.

(3)   In September 2021, WAIO received regulatory approval to increase capacity at its Port Hedland operations to 330 Mtpa (100 per cent basis), subject to the outcomes of a standard appeals processes. Our near-term focus remains on sustainable achievement of 290 Mtpa, with plans to creep beyond this through productivity improvements in the medium term.

(4)   We announced the share sale agreement to divest our interest in BMC in November 2021, however we will continue to report BMC as part of Queensland Coal and we maintain economic and operating control of BMC until the sale has completed.

(5)   Coal imports into China remains uncertain and as a result Queensland Coal medium-term production guidance is not able to be provided.

(6)   We have ceased providing Cerrejón production guidance due to the completion of the divestment of our interest. The transaction has an effective economic date of 31 December 2020 and volumes have been reported separately.

(7)   Given our announcement of a binding share sale agreement for the proposed merger of BHP's oil and gas portfolio with Woodside in November 2021, no further annual production guidance for Petroleum will be provided. However, until merger completion, we expect a production run rate broadly consistent with the original FY22 production guidance of between 99 and 106 MMboe.

 

11

 

Cash flow and balance sheet

·      Net operating cash flows (continuing operations) of US$11.5 billion (31 December 2020: 9.1 billion) reflects strong prices across our major commodities and a reliable operating performance during the period. This includes an unfavourable working capital movement of US$2.2 billion largely related to inventory builds, net price impacts on receivables and royalties, and other movements. Income tax and royalty-related taxation payments of US$5.0 billion include approximately US$2.0 billion of tax instalments and final tax payments relating to the 2021 financial year.

·      Free cash flow (continuing operations) of US$8.5 billion for the half year (31 December 2020: US$5.9 billion), and free cash flow of US$9.7 billion (total operations), inclusive of capital and exploration expenditure of US$3.7 billion.

·      Our balance sheet remains strong with net debt at US$6.1 billion at 31 December 2021 (30 June 2021: US$4.1 billion; 31 December 2020: US$11.8 billion). The increase of US$2.0 billion in net debt in the half year (or a decrease of US$5.7 billion from 31 December 2020) reflects strong free cash flow generation by the operations more than offset by the record final dividend paid to shareholders in September 2021 of US$10.0 billion, dividends paid to non-controlling interests of US$1.3 billion and US$0.5 billion of lease additions.

	H1 FY22 US$M	H1 FY21 US$M
Net debt at the beginning of the period	4,121	12,044
Lease additions	497	909
Free cash flow	(9,688)	(5,160)
Dividends paid	10,029	2,767
Dividends paid to NCI	1,273	762
Transfer to liability directly associated with assets held for sale	(528)	−
Other movements	386	517
Net debt at the end of the period	6,090	11,839

·      Following a review of the net debt target, we have revised the range to between US$5 and US$15 billion from the previous target range of between US$12 and US$17 billion. The revised net debt target range will enable BHP to maintain a resilient balance sheet during periods of change and external uncertainties and retain flexibility to allocate capital within our Capital Allocation Framework towards shareholder returns and future organic and inorganic investment opportunities.

·      Gearing ratio⁽ⁱ⁾ of 10.0 per cent (30 June 2021: 6.9 per cent; 31 December 2020: 18.1 per cent).

Dividends

·      We will pay a record interim dividend of US$1.50 per share or US$7.6 billion, including an additional amount of US$2.7 billion above the minimum payout policy. This is equivalent to a 78 per cent payout ratio⁽ⁱⁱⁱ⁾ (31 December 2020: 85 per cent).

·      We have consistently delivered high cash returns, with more than US$22 billion of total announced returns to shareholders over the last 18 months. 

Capital and exploration

·      Capital and exploration expenditure of US$3.7 billion (total operations) in the December 2021 half year included maintenance expenditure^(viii) of US$1.1 billion, minerals exploration of US$0.1 billion and Petroleum expenditure of US$0.8 billion.

·      Capital and exploration expenditure of approximately US$6.5 billion (continuing operations) is now expected for the 2022 financial year. This is US$0.2 billion lower than previous guidance predominantly due to favourable exchange rate movements. Guidance is subject to exchange rate movements.

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·      Historical capital and exploration expenditure and guidance are summarised below:

	FY22e US$M	H1 FY22 US$M	H1 FY21 US$M	FY21 US$M
Maintenance(1)	2,800	1,090	1,034	2,259
Development - Minerals	3,500	1,678	1,801	3,353
Capital expenditure (purchases of property, plant and equipment)	6,300	2,768	2,835	5,612
Add: exploration expenditure	200	110	86	192
Capital expenditure - Continuing operations	6,500	2,878	2,921	5,804
Capital expenditure - Discontinued operations	−(2)	799	693	1,316
Capital and exploration expenditure - Total operations	−	3,677	3,614	7,120

(1)   Includes capitalised deferred stripping of approximately US$800 million for FY22 and US$409 million for H1 FY22 (H1 FY21: US$396 million; FY21: $810 million).

(2)   Given our announcement of a binding share sale agreement for the proposed merger of BHP's oil and gas portfolio with Woodside in November 2021, no further capital and exploration guidance for Petroleum will be provided.

 

·      Average annual sustaining capital expenditure guidance over the medium term, excluding costs associated with carbon abatement and our automation programs, is unchanged and forecast to be approximately:

‒    US$4.50 per tonne for WAIO; and

‒    US$10 per tonne for Queensland Coal.

·      Capital expenditure on decarbonisation is expected to be at the upper end of the guidance range of between US$2 to US$4 billion until the 2030 calendar year.

Projects

·      At the end of December 2021, BHP had two major projects under development, the US$2.97 billion Jansen mine shafts project and the US$5.7 billion Jansen Stage 1 project.  

 

 

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·      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 in execution at 31 December 2021 - continuing operations
Potash	Jansen Potash(2) (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	CY27	The project is 98% complete. Target project completion in CY22
Potash	Jansen Stage 1 (Canada) 100%	Design, engineering and construction of an underground potash mine and surface infrastructure, with capacity to produce 4.35 Mtpa.	5,723	CY27	Approved in August 2021, the project is 3% complete.
Projects in execution at 31 December 2021 - discontinued operations
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 97% complete.
Petroleum	Shenzi North development (US Gulf of Mexico) 72% (operator)	A two-well subsea tie-in to the Shenzi platform, with the capacity to produce up to 30,000 gross barrels of oil equivalent per day.	392	CY24	On schedule and budget. The overall project is 5% complete.
Petroleum	Scarborough (Western Australia) 26.5% (non-operator)	New upstream facilities designed to deliver daily gas quantities to manufacture 8 Mtpa LNG and 180 TJ/day of domestic gas.	1,500	CY26	Sanctioned in November 2021.  On schedule and budget. The overall project is 10% 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)    Capital expenditure of approximately US$120 million is expected for FY22.

 

·      On 7 September 2021, BHP received regulatory approval to increase capacity at our Port Hedland operations up to 330 Mtpa (100 per cent basis), subject to the outcomes of standard appeals processes. Our near-term focus remains on sustainable achievement of 290 Mtpa of iron ore, with plans to creep beyond this through productivity improvements in the medium term. 

·      We continue to progress with the implementation of autonomous trucks across our Australian iron ore and coal mine sites.

‒    In December 2021, we approved the South Flank Autonomous Haulage Project to automate the current fleet of 41 Komatsu haul trucks. The project is scheduled to commence in the June 2022 quarter and is expected to be completed within 18 months.

‒    At the Daunia coal mine in Central Queensland, the second coal operation to implement autonomous haul trucks, all trucks are now commissioned and operational, on schedule and budget.

‒    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 in the middle of the 2022 calendar year, on schedule and budget.

 

14

 

Operations Services

Operations Services performs business critical services across our minerals operations in Australia, including maintaining a significant portion of ultra-class trucks and moving significant volumes of material as part of production services. At 31 December 2021, Operations Services was responsible across Minerals Australia for maintaining 38 per cent of BHP's haul trucks, including 92 per cent of ultra-class trucks at BMA, and the 308 km of conveyors in our WAIO operations.

The BHP FutureFit Academy, launched in May 2020, has welcomed over 520 students and graduated over 200 maintenance associates during this period. The FutureFit Academy extended its curriculum to Production in 2021 and is now able to deliver a nationally accredited qualification in Surface Extraction Operations.

 

Outlook

Economic outlook

We remain positive in our outlook for long-term global economic growth and commodity demand. Population growth, the infrastructure of decarbonisation and rising living standards are all expected to drive demand for energy, metals and fertilisers for decades to come.

In the near term, volatility in the operating environment is expected to continue. Momentum towards recovery remains intact across most key regions, although China slowed over the second half of the 2021 calendar year, and vigilance around COVID-19 risks is still a constant for all. We anticipate that the headwinds that buffeted China will diminish as the 2022 calendar proceeds. A desynchronised exit from emergency policy settings around the globe is a source of uncertainty. 

Industry wide inflationary pressure has been pronounced, lifting and steepening operating cost curves and challenging timely project delivery. Many commodity-linked uncontrollable costs have moved noticeably higher, in some cases to record highs. Labour costs have increased materially due to localised shortages of both general and skilled workers. This partly reflects regulatory constraints on movement across international and state borders. We expect cost headwinds due to supply bottlenecks to remain challenging in the 2022 calendar year, with only tentative signs of easing by the end of the period. As the actual recognition of costs tends to lag developments in prompt pricing, these pressures are expected to continue to impact on our cost base in the following calendar year. Demand-led inflation in the broader economy, reflecting a healthy tension between rising demand and the ability to meet it, is expected to endure for some time. That is fundamentally positive for the resources industry. After more than half a decade of industry wide capital discipline, positive developments in demand are broadly expected to manifest in tighter market balances. That can potentially prolong the period of attractive pricing that we currently observe across the portfolio. Low cost operators stand to capture increased margins in certain commodities.

 

 

15

 

Commodities outlook

In the half year ended 31 December 2021, the key theme in steel was a policy induced production crunch in China. The starting point for Chinese output expectations in the 2022 calendar year is zero growth from the 1.033 Bt produced in 2021. End-use demand in China is expected to firm over the course of the 2022 calendar year, as easier policy gradually takes hold. As is common at the start of a new five-year plan, infrastructure is expected to be supportive of steel demand.

Iron ore prices declined in the first half of the 2022 financial year as China's steel production curbs took hold, while seaborne supply improved. Prices have since stabilised and recovered, albeit not to the previous highs. In the medium term, China's demand for iron ore is expected to be lower than it is 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. It is imperative that we continue to compete on both quality and operational effectiveness. 

Metallurgical coal prices surged to record highs in the first half of the 2022 financial year on multi-regional supply constraints amidst challenging operating conditions. Even so, the industry faces a difficult and uncertain period ahead while natural trade flows are impaired. Longer term, high quality metallurgical coals will continue to provide value-in-use benefits to integrated steelmakers as they seek to optimise the energy and emissions intensity of their operations. This will particularly be the case in emerging Asia, where the blast furnace fleet is still young, and transitional technologies are expected to dominate decarbonisation efforts in the next 20-30 years.

Energy coal prices reached all-time highs in the first half of the 2022 financial year as constrained supply coincided with very strong demand from both Asia and Europe. China's policy in respect of energy coal imports remains a key medium-term uncertainty.   

Copper prices have receded slightly from the record highs established in the second half of the 2021 financial year, but they remain very high in absolute terms. Longer term, both demand and supply factors indicate that copper is an attractive avenue for future growth.

Nickel prices performed well over the first half of the 2022 financial year and the positive momentum continues. Depleting stocks was a recurrent theme over the half, with strong demand from both traditional uses and batteries coupled with supply uncertainty. Longer term, we believe nickel will be a core beneficiary of the electrification mega-trend and that nickel sulphides will be particularly attractive.

Potash prices have increased sharply over the last 18 months, despite latent excess production capacity. Longer term, 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. The compelling demand picture, and the maturity of the existing asset base, offers an attractive entry opportunity for a world class operation later this decade. 

Crude oil prices traded in an approximate range of US$65-85 per bbl (Brent) over the last half year, with prices moving above US$90 per bbl early in the current half. Beyond the current phase, considerable investment is going to be required to fill the medium and longer term supply-demand gap we expect to emerge. If that investment is not forthcoming in a timely way, the possibility of oil prices moving up aggressively cannot be ruled out.

The Japan-Korea Marker price for LNG has been extremely elevated, with all-time high spot pricing achieved in the lead-up to the northern hemisphere winter. Longer term, assets advantaged by their proximity to existing infrastructure or customers, or both, in addition to competitive emissions intensities, are expected to be attractive. 

Further information on BHP's economic and commodity outlook can be found at: bhp.com/prospects

 

16

 

Income statement

Underlying attributable profit and Underlying EBITDA are presented below.

Underlying attributable profit

Half year ended 31 December	2021 US$M	2020 US$M Restated
Profit after taxation attributable to BHP shareholders	9,443	3,876
Total exceptional items attributable to BHP shareholders(1)	1,244	2,160
Underlying attributable profit	10,687	6,036
(Profit)/loss after taxation attributable to members of BHP for Discontinued operations	(972)	192
Total exceptional items attributable to BHP shareholders for Discontinued operations	−	(28)
Underlying attributable profit - Continuing operations	9,715	6,200
Weighted basic average number of shares (Million)	5,061	5,057
Underlying basic earnings per ordinary share - Continuing operations	192.0	122.6

(1)   Refer to page 17 and to note 2 'Exceptional items' and note 10 'Significant events - Samarco dam failure' of the Financial Report for further information.

Underlying EBITDA

Half year ended 31 December	2021 US$M	2020 US$M Restated
Profit from operations	14,845	9,889
Exceptional items included in profit from operations(1)	729	1,511
Underlying EBIT	15,574	11,400
Depreciation and amortisation expense	2,851	2,405
Net impairments	38	629
Exceptional item included in Depreciation, amortisation and impairments(2)	−	(547)
Underlying EBITDA	18,463	13,887

(1)   Exceptional items loss of US$729 million excludes net finance costs of US$93 million related to the Samarco dam failure. Refer to page 17 and to note 2 '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. Refer to note 2 'Exceptional items'.

 

 

17

 

Underlying EBITDA

The following table and commentary describe the impact of the principal factors⁽ⁱ⁾ that affected Underlying EBITDA for the December 2021 half year compared with the December 2020 half year:

	US$M
Half year ended 31 December 2020 (Restated)	13,887
Net price impact:
Change in sales prices	6,248	Higher average realised prices for all of our major commodities.
Price-linked costs	(570)	Increased royalties reflecting higher realised prices, mainly for metallurgical and thermal coal products.
	5,678
Change in volumes	(969)	Near record volumes at WAIO and higher concentrate sales at Spence reflecting the continued ramp up of the Spence Growth Option despite lower than expected recoveries, were more than offset by lower planned copper concentrator feed grade at Escondida, lower volumes at Olympic Dam as a result of the planned major smelter maintenance campaign, lower Queensland Coal volumes due to significant wet weather impacts from La Niña and labour constraints, and lower volumes at Nickel West due to planned maintenance during the period.
Change in controllable cash costs	(465)	Higher costs across the Group associated with COVID-19 (US$154 million), which was reported as an exceptional item last year, and higher costs at WAIO due to the South Flank operational ramp-up expenditure. Incremental costs associated with end-of-negotiation workforce bonus payments at Escondida, and a prior period one-off gain from the cancelled power contracts at Escondida and Spence. This was partially offset by favourable inventory movements at Olympic Dam. Coal costs were broadly flat.
Change in other costs:
Exchange rates	591	Impact of movements in the Australian dollar and Chilean peso against the US dollar.
Inflation	(294)	Impact of inflation on the Group's cost base.
Fuel, energy, and consumable price movements	(305)	Predominantly higher diesel and acid prices.
Non-Cash	35	Mainly higher capitalisation due to increased waste movement at Escondida.
	27
Asset sales	5
Ceased and sold operations	(7)
Other items	307	Other includes higher recovery of freight costs caused by movements in the freight index on consecutive voyage charter (CVC) voyages and higher average realised sales prices received by Antamina, partially offset by the write-off of iron ore dormant stockpiles.
Half year ended 31 December 2021	18,463

 

 

18

 

 

 

Prices and exchange rates

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

Average realised prices(1)	H1 FY22	H1 FY21	H2 FY21	FY21	H1 FY22 vs H1 FY21	H1 FY22 vs H2 FY21	H1 FY22 vs FY21
Copper (US$/lb)	4.31	3.32	4.34	3.81	30%	(1%)	13%
Iron ore (US$/wmt, FOB)	113.54	103.78	158.17	130.56	9%	(28%)	(13%)
Metallurgical coal (US$/t)	259.71	97.61	114.81	106.64	166%	126%	144%
Hard coking coal (HCC) (US$/t)(2)	278.60	106.30	118.54	112.72	162%	135%	147%
Weak coking coal (WCC) (US$/t)(2)	218.65	73.17	104.40	89.62	199%	109%	144%
Thermal coal (US$/t)(3)	137.68	44.35	70.83	58.42	210%	94%	136%
Nickel metal (US$/t)	19,651	15,140	17,537	16,250	30%	12%	21%
Discontinued operations
Oil (crude and condensate) (US$/bbl)	73.62(4)	41.24(4)	63.05	52.56	79%	17%	40%
Natural gas (US$/Mscf)(5)	5.78(4)	3.83	4.86	4.34	51%	19%	33%
LNG (US$/Mscf)	15.10	4.45	7.04	5.63	239%	114%	168%

(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)   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.

(3)   Export sales only; excludes Cerrejón. Includes thermal coal sales from metallurgical coal mines

(4)   The average realised prices for oil (crude and condensate) and natural gas have been adjusted after the release of the Operational Review for the half year ended 31 December 2021 to reflect tax barrels and ceased and sold assets adjustments.

(5)   Includes internal sales.

In copper, the provisional pricing and finalisation adjustments increased Underlying EBITDA by US$11 million in the December 2021 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 2021	Average Half year ended 31 December 2020	As at 31 December 2021	As at 31 December 2020	As at 30 June 2021
Australian dollar(1)	0.73	0.72	0.73	0.77	0.75
Chilean peso	798	771	845	711	735

(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$402 million to US$2.9 billion, reflecting higher depreciation and amortisation at WAIO from the commissioning of South Flank and updates to the closure provision at Yandi at the end of the 2021 financial year. Additional charges at Pampa Norte reflects the Spence Growth Option (SGO) commissioning in the prior year.

Net finance costs

Net finance costs decreased by US$524 million to US$352 million mainly due to lower interest rates on a lower average debt balance for the period and premiums of US$395 million paid as part of the value accretive multi-currency hybrid repurchase programs completed during the prior period.

19

 

Taxation expense

	2021				2020 (Restated)
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	14,493	(4,959)	34.2		9,013	(3,993)	44.3
Adjusted for:
Exchange rate movements	−	(91)			−	(48)
Exceptional items(1)	822	422			1,552	590
Adjusted effective tax rate	15,315	(4,628)	30.2		10,565	(3,451)	32.7

(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, is 30.2 per cent (31 December 2020: 32.7 per cent) and is above 30 per cent primarily due to the impact of withholding taxes on current and future dividends from Chilean operations partially offset by a reversal of previously derecognised tax losses relating to NSWEC. The adjusted effective tax rate is lower than at 31 December 2020 predominantly due to the reversal of NSWEC tax losses derecognised in the prior period. The adjusted effective tax rate for the 2022 financial year is expected to be in the range of 30 to 35 per cent, revised from 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$1.7 billion during the period (31 December 2020: US$1.3 billion).

Exceptional items

The following table sets out the exceptional items for the December 2021 half year. Additional commentary is included on page 39.

Half year ended 31 December 2021	Gross US$M	Tax US$M	Net US$M
Exceptional items by category
Samarco dam failure	(822)	1	(821)
Impairment of US deferred tax assets	−	(423)	(423)
Total	(822)	(422)	(1,244)
Attributable to non-controlling interests	−	−	−
Attributable to BHP shareholders	(822)	(422)	(1,244)

Debt management and liquidity

BHP continues to optimise its balance sheet and debt position.

During the December 2021 half year, gross debt decreased by US$2.0 billion to US$19.0 billion at 31 December 2021. This decrease includes a US$0.5 billion repayment of 3.250 per cent USD senior notes that matured on 21 November 2021, US$0.5 billion of coal and petroleum leases transferred to liabilities directly associated with assets held for sale and US$0.5 billion of favourable foreign exchange and interest rate adjustments.

At the subsidiary level, Escondida refinanced US$0.3 billion of long-term debt that was due to mature in the period.

BHP continues to hold a robust liquidity position with US$12.4 billion in cash and cash equivalents. The Group also has a US$5.5 billion commercial paper program backed by a US$5.5 billion revolving credit facility. During the period the Group completed a one-year extension of the revolving credit facility which is now due to mature in October 2026. Furthermore, the Group also updated the facility for the cessation of various interbank offered rates ('IBORs') and the facility now refers to risk-free rates for all IBORs that are being or have been discontinued. As at 31 December 2021, the Group had no outstanding commercial paper and no drawn amount under the revolving credit facility.

20

 

Dividend

The BHP Board today determined to pay an interim dividend of US$1.50 per share (US$7.6 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	18 February 2022
Last day to trade cum dividend on Johannesburg Stock Exchange Limited (JSE)	22 February 2022
Ex-dividend Date JSE	23 February 2022
Last day to trade cum dividend on Australian Securities Exchange (ASX), London Stock Exchange (LSE) and New York Stock Exchange (NYSE)	23 February 2022
Ex-dividend Date ASX, LSE and NYSE	24 February 2022
Record Date	25 February 2022
Announcement of currency conversion into AUD, GBP and NZD	28 February 2022
DRP and Currency Election date	28 February 2022
Payment Date	28 March 2022
DRP Allocation Date	5 April 2022

BHP Group Limited shareholders registered on the South African section of the register will not be able to dematerialise or rematerialise their shareholdings between the dates of 23 February 2022 and 25 February 2022 (inclusive), nor will transfers between the Australian register and the South African register be permitted between the dates of 18 February 2022 and 25 February 2022 (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 Limited, in accordance with the instructions of your CSDP or broker. Any former BHP Group Plc shareholder who previously made an election to participate in the BHP Group Plc dividend reinvestment plan will need to make a new election if they wish to participate in the DRP. The DRP Allocation Price will be calculated in each jurisdiction as an average of the price paid for all shares or equivalent interests actually purchased to satisfy DRP elections. The Allocation Price applicable to each exchange will made available at: bhp.com/DRP

Corporate governance

Susan Kilsby and Anita Frew retired from the Board following the 2021 Annual General Meetings on 11 November 2021.

On 2 September 2021 and 10 February 2022, we announced the appointment of two independent non-executive directors. Michelle Hinchliffe will commence on 1 March 2022 and Catherine Tanna will commence on 4 April 2022.

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 Christine O'Reilly	Ken MacKenzie (Chair) Terry Bowen Gary Goldberg (SID)(1) John Mogford Christine O'Reilly	Christine O'Reilly (Chair) Gary Goldberg (SID)(1) Dion Weisler	John Mogford (Chair) Ian Cockerill Gary Goldberg (SID)(1) Dion Weisler

(1)   Senior Independent Director (SID)

21

A summary of performance for the December 2021 and December 2020 half years is presented below. Unless otherwise noted, information in this section has been presented on a continuing operation basis to exclude the contribution from Petroleum.

Half year ended 31 December 2021 US$M	Revenue(3)	Underlying EBITDA(4)	Underlying EBIT(4)	Exceptional items(5)	Net operating assets(4)	Capital expenditure	Exploration gross(6)	Exploration to profit(7)
Copper	8,494	4,272	3,377	(212)	27,647	1,275	34	34
Iron Ore	15,818	11,153	9,991	(512)	17,997	814	51	30
Coal	5,368	2,642	2,235	−	7,856	313	8	2
Group and unallocated items(8)	847	396	(29)	(5)	3,123	366	17	14
Inter-segment adjustment	−	−	−	−	−	−	−	−
Total Group	30,527	18,463	15,574	(729)	56,623	2,768	110	80

 

Half year ended 31 December 2020 (Restated) US$M	Revenue(3)	Underlying EBITDA(4)	Underlying EBIT(4)	Exceptional items	Net operating assets(4)	Capital expenditure	Exploration gross(6)	Exploration to profit(7)
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(8)	749	106	(218)	(14)	3,892	306	8	8
Inter-segment adjustment	−	−	−	−	−	−	−	−
Total Group	24,044	13,887	11,400	(1,511)	58,333	2,835	86	56

(1)   On 22 November 2021, the Group signed a binding share sale agreement (SSA) for the merger of the Group's oil and gas portfolio with Woodside ('proposed merger'). The Petroleum business remains part of the Group until completion of the proposed merger which is expected in the June 2022 quarter. In the meantime, following that announcement, the Group's Petroleum business no longer meets the reporting segment recognition criteria as outlined in IFRS 8 'Operating segments' and therefore does not form part of the reportable segments summarised above. A detailed summary of performance of the Petroleum assets presented as a single amount in the line item entitled 'Profit/(loss) after taxation from discontinued operations' is outlined below. Refer to note 11 'Discontinued operations and Assets and liabilities held for sale' of the Financial Report for further information.

Petroleum - Discontinued operations US$M	Revenue	Underlying EBITDA	Underlying EBIT	Exceptional items	Net operating assets	Capital expenditure	Exploration gross	Exploration to profit
Half year ended 31 December 2021	3,257	2,918	2,037	−	8,245	556	243	112
Half year ended 31 December 2020	1,595	793	(108)	(31)	8,548	498	195	242

(2)   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$300 million (H1 FY21: US$259 million) related to equity accounted investments. It excludes exceptional items loss of US$702 million (H1 FY21: US$678 million loss) 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$3,618 million (H1 FY21: US$3,998 million) and net finance costs of US$352 million (H1 FY21: US$876 million).

(3)   Revenue is based on Group realised prices and includes third party products. Sale of third party products by the Group contributed revenue of US$1,674 million and Underlying EBITDA of US$10 million (H1 FY21: US$958 million and US$58 million).

(4)   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 62 to 74.

(5)   Exceptional items loss of US$729 million excludes net finance costs of US$93 million included in the total loss before taxation of US$822 million related to the Samarco dam failure. Refer to note 2 'Exceptional items' and note 10 'Significant events - Samarco dam failure' of the Financial Report for further information.

(6)   Includes US$30 million capitalised exploration (H1 FY21: US$30 million).

(7)   Includes US$ nil of exploration expenditure previously capitalised, written off as impaired (included in depreciation and amortisation) (H1 FY21: US$ nil).

 

22

 

 

(8)   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.              

Half year ended 31 December 2021 US$M	Revenue	Underlying EBITDA(4)	D&A	Underlying EBIT(4)	Net operating assets(4)	Capital expenditure	Exploration gross	Exploration to profit
Potash	−	(63)	1	(64)	3,283	158	−	−
Nickel West	838	118	39	79	498	169	14	12

     

Half year ended 31 December 2020 US$M	Revenue	Underlying EBITDA(4)	D&A	Underlying EBIT(4)	Net operating assets(4)	Capital expenditure	Exploration gross	Exploration to profit
Potash	−	(80)	1	(81)	4,203	105	−	−
Nickel West	737	121	52	69	175	130	8	8

Copper

Underlying EBITDA for the December 2021 half year increased by US$534 million to US$4.3 billion.

	US$M
Underlying EBITDA for the half year ended 31 December 2020	3,738
Net price impact:
Change in sales prices	1,325	Higher average realised price: Copper US$4.31/lb (H1 FY21: US$3.32/lb).
Price-linked costs	4
Change in volumes	(649)	Lower planned concentrator feed grade at Escondida and stacking feed grade at Spence, partially offset by higher concentrate sales at Spence, reflecting the continued ramp up of the Spence Growth Option despite lower than expected recoveries. Lower copper volumes at Olympic Dam as a result of the planned major smelter maintenance campaign in the period.
Change in controllable cash costs	(185)	End-of-negotiation workforce bonus payments at Escondida and incremental costs of US$65 million associated with mitigating the impacts of COVID-19 (reported as an exceptional item in the prior period). In the prior period, costs benefited from a one-off gain from the cancelled power contracts at Escondida and Spence. This was partially offset by lower costs at Olympic Dam reflecting favourable inventory movements as a result of reduced operational activity during the major smelter maintenance campaign.
Change in other costs:
Exchange rates	242
Inflation	(116)
Fuel, energy, and consumable price movements	(176)	Predominantly higher diesel and acid prices.
Non-cash	19	Higher capitalisation due to increased waste movement at Escondida.
Other	70	Other includes increased profit at Antamina driven by higher realised prices for both copper and zinc.
Underlying EBITDA for the half year ended 31 December 2021	4,272

Escondida unit costs increased by 43 per cent to US$1.29 per pound, as expected, reflecting higher prices for consumables, lower by-product credits and incremental costs associated with mitigating the impacts of COVID-19. Whilst inflationary pressures persist, the unit cost increase for the half year largely relates to one-off impacts, including end-of-negotiation workforce bonus payments, and a gain recorded in the prior period as a result of cancelled power contracts as the mine shifts towards 100 per cent renewable energy.

 

23

 

Full year unit cost guidance for the 2022 financial year remains unchanged at between US$1.20 and US$1.40 per pound (based on an exchange rate of USD/CLP 727). 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 727), 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$M)				H1 FY22	H2 FY21	H1 FY21	FY21
Revenue				4,829	4,954	4,516	9,470
Underlying EBITDA				3,124	3,464	3,019	6,483
Gross costs				1,705	1,490	1,497	2,987
Less: by-product credits				214	206	272	478
Less: freight				103	83	79	162
Net costs				1,388	1,201	1,146	2,347
Sales (kt)				487	490	576	1,066
Sales (Mlb)				1,074	1,080	1,270	2,350
Cost per pound (US$)(1)(2)(3)				1.29	1.11	0.90	1.00

(1)   H1 FY22 based on average exchange rates of USD/CLP 798.

(2)   H1 FY22 includes COVID-19 related costs of US$0.03 per pound, which was reported as an exceptional item in FY21 (H1 FY21: US$0.02 per pound; FY21: US$0.03 per pound).

(3)   H1 FY21 and FY21 included a gain from the optimised outcome from renegotiation of cancelled power contracts of US$0.07 per pound and US$0.04 per pound respectively. 

SGO demonstrated full concentrator throughput of 95 ktpd in the December 2021 quarter. However, plant design modifications, including modifications to the rougher flotation circuit will be required to increase SGO recoveries and achieve planned copper production levels. The Spence guidance to average 300 ktpa (including cathodes) in the first four years of production will be subject to the timing of these modifications being completed. 

In January 2022, Escondida and Spence completed the 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 continue to 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 2021 and December 2020 half years is presented below.

Half year ended 31 December 2021 US$M	Revenue	Underlying EBITDA	D&A	Underlying EBIT	Net operating assets	Capital expenditure	Exploration gross	Exploration to profit
Escondida(1)	4,829	3,124	461	2,663	11,826	419
Pampa Norte(2)	1,375	760	234	526	4,779	321
Antamina(3)	932	679	72	607	1,366	176
Olympic Dam	652	90	193	(103)	9,638	520
Other(3)(4)	1	(91)	8	(99)	38	15
Total Copper from Group production	7,789	4,562	968	3,594	27,647	1,451
Third party products	1,637	10	−	10	−	−
Total Copper	9,426	4,572	968	3,604	27,647	1,451	39	39
Adjustment for equity accounted investments(5)	(932)	(300)	(73)	(227)	−	(176)	(5)	(5)
Total Copper statutory result	8,494	4,272	895	3,377	27,647	1,275	34	34

 

 

24

 

 

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

(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$932 million (H1 FY21: US$751 million) revenue related to Antamina. Total Copper statutory result Underlying EBITDA includes US$73 million (H1 FY21: US$73 million) D&A and US$227 million (H1 FY21: US$169 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$176 million (H1 FY21: US$117 million) related to Antamina. Exploration gross excludes US$5 million (H1 FY21: US$3 million) related to SolGold of which US$5 million (H1 FY21: US$1 million) was expensed.

 

25

 

Iron Ore

Underlying EBITDA for the December 2021 half year increased by US$909 million to US$11.2 billion.

	US$M
Underlying EBITDA for the half year ended 31 December 2020	10,244
Net price impact:
Change in sales prices	1,257	Higher average realised price: Iron ore US$113.54 wmt, FOB (H1 FY21: US$103.78/wmt, FOB).
Price-linked costs	(66)	Higher royalties in line with higher prices.
Change in volumes	(27)	Sales volumes were broadly flat reflecting continued strong operational performance, despite impacts of temporary labour constraints relating to COVID-19 border restrictions and planned maintenance activities.
Change in controllable cash costs	(240)	Increased South Flank operational ramp up spend, incremental costs associated with COVID-19 (mainly higher demurrage costs, reported as an exceptional item in the prior period) and inventory movements to support the supply chain.
Change in other costs:
Exchange rates	190
Inflation	(89)
Fuel, energy, and consumable price movements	(57)	Higher diesel prices.
Other	(59)	Other includes the write-off of dormant stockpiles, partially offset by other items.
Underlying EBITDA for the half year ended 31 December 2021	11,153

WAIO unit costs increased by 12 per cent to US$16.15 per tonne (or US$14.74 per tonne on a C1 basis excluding third party royalties⁽⁴⁾). The increase in unit cost was mostly due to higher diesel prices reflecting inflationary headwinds, price-linked third party royalties, costs associated with the ramp up of South Flank, and costs associated with COVID-19 of approximately US$0.56 per tonne, which has been taken to unit costs in this period and reported as an exceptional item in the prior period. Sales volumes were slightly lower due to the impact of temporary labour constraints relating to COVID-19 border restrictions. The cost increase was partially offset by the impact of favourable exchange rate movements.

Full year unit cost guidance for the 2022 financial year remains unchanged and is trending towards the lower end at between US$17.50 and US$18.50 per tonne (based on an exchange rate of AUD/USD 0.78). In the medium term, we expect to lower our unit costs to less than US$16 per tonne (based on an exchange rate of AUD/USD 0.78) reflecting ongoing improvements across the supply chain.

WAIO unit costs (US$M)				H1 FY22	H2 FY21	H1 FY21	FY21
Revenue				15,750	20,345	13,992	34,337
Underlying EBITDA				11,227	16,050	10,220	26,270
Gross costs				4,523	4,295	3,772	8,067
Less: freight(1)				1,399	929	826	1,755
Less: royalties				1,069	1,476	1,101	2,577
Net costs				2,055	1,890	1,845	3,735
Sales (kt, equity share)				127,221	123,779	128,273	252,052
Cost per tonne (US$)(2)(3)				16.15	15.27	14.38	14.82
Cost per tonne on a C1 basis excluding third party royalties (US$)(3)(4)				14.74	13.52	12.46	12.98

(1)   H1 FY22 freight costs and vessel demand increased significantly as a result of global supply chain pressures relating to COVID-19.

(2)   H1 FY22 based on an average exchange rate of AUD/USD 0.73.

(3)   H1 FY22 includes COVID-19 related costs of US$0.56 per tonne, which was reported as an exceptional item in FY21 (H1 FY21: US$0.56 per tonne; FY21: US$0.51 per tonne).    

(4)   Excludes third party royalties of US$1.84 per tonne (H1 FY21: US$1.68 per tonne), net inventory movements US$(0.76) per tonne (H1 FY21: US$(1.30) per tonne), depletion of production stripping US$0.61 per tonne (H1 FY21: US$0.72 per tonne), exploration expenses, marketing purchases, demurrage, exchange rate gains/losses, and other income US$(0.28) per tonne (H1FY21: US$0.63 per tonne) and operational readiness costs relating to South Flank US$ nil (H1 FY21: US$0.19 per tonne).

 

26

 

Financial information for Iron Ore for the December 2021 and December 2020 half years is presented below.

Half year ended 31 December 2021 US$M	Revenue	Underlying EBITDA	D&A	Underlying EBIT	Net operating assets	Capital expenditure	Exploration gross(1)	Exploration to profit
Western Australia Iron Ore	15,750	11,227	1,058	10,169	21,087	814
Samarco(2)	−	−	−	−	(3,119)	−
Other(3)	59	(74)	104	(178)	29	−
Total Iron Ore from Group production	15,809	11,153	1,162	9,991	17,997	814
Third party products(4)	9	−	−	−	−	−
Total Iron Ore	15,818	11,153	1,162	9,991	17,997	814	51	30
Adjustment for equity accounted investments	−	−	−	−	−	−	−	−
Total Iron Ore statutory result	15,818	11,153	1,162	9,991	17,997	814	51	30

 

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

(1)   Includes US$21 million of capitalised exploration (H1 FY21: US$23 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.

 

27

 

Coal

Underlying EBITDA for the December 2021 half year increased by US$2.8 billion to US$2.6 billion.

	US$M
Underlying EBITDA for the half year ended 31 December 2020	(201)
Net price impact:
Change in sales prices	3,417	Higher average prices: Hard coking coal US$278.60/t (H1 FY21: US$106.30); Weak coking coal US$218.65/t (H1 FY21: US$73.17/t); Thermal coal US$137.68/t (H1 FY21: US$44.35/t).
Price-linked costs	(446)	Higher royalties in line with higher prices.
Change in volumes	(172)	Lower volumes at Queensland Coal due to significant wet weather impacts from La Niña coupled with additional maintenance and labour constraints. Increased volumes at NSWEC as a result of increased stripping volumes in lower strip ratio areas as well as a ship loader outage in the prior period.
Change in controllable cash costs	26	Cost reduction initiatives and favourable inventory movements partially offset by inventory revaluations at BMC as a result of the asset held for sale classification, additional costs to support the focus on higher quality products at NSWEC and incremental COVID-19 related costs.
Change in other costs:
Exchange rates	106
Inflation	(59)
Fuel, energy, and consumable price movements	(56)	Predominantly higher diesel prices.
Other	27	Other items.
Underlying EBITDA for the half year ended 31 December 2021	2,642

Queensland Coal unit costs increased by eight per cent to US$91 per tonne for the half year, primarily due to lower volumes following significant La Niña wet weather impacts, additional maintenance and labour constraints. This was partially offset by cost reduction initiatives and favourable inventory and exchange rate movements.

Unit cost guidance for the 2022 financial year has been increased to between US$85 and US$94 per tonne (based on an exchange rate of AUD/USD 0.78) from between US$80 and US$90 per tonne, reflecting lower expected volumes for the full year. Workforce absenteeism arising from COVID-19 remains a risk for the remainder of the financial year.

Queensland Coal unit costs (US$M)				H1 FY22	H2 FY21	H1 FY21	FY21
Revenue				4,342	2,459	1,856	4,315
Underlying EBITDA				2,236	534	59	593
Gross costs				2,106	1,925	1,797	3,722
Less: freight				25	24	45	69
Less: royalties				511	194	136	330
Net costs				1,570	1,707	1,616	3,323
Sales (kt, equity share)				17,180	21,589	19,030	40,619
Cost per tonne (US$)(1)(2)				91.39	79.07	84.92	81.81

(1)   H1 FY22 based on an average exchange rate of AUD/USD 0.73.

(2)   H1 FY22 includes COVID-19 related costs of US$0.26 per tonne, which was reported as an exceptional item in FY21 (H1 FY21: US$1.42 per tonne; FY21: US$0.91 per tonne).    

NSWEC unit costs increased by two per cent to US$68 per tonne due to increased maintenance, fleet and processing costs enabling the increased production of higher quality products which now make up approximately 80 per cent of sales volumes, unfavourable inventory movements and some inflationary pressures. This was partially offset by increased volumes as a result of continued truck productivity and mining in lower strip ratio areas, despite increased rainfall as well as cost reduction initiatives and favourable exchange rate movements.

28

 

Unit cost guidance for the 2022 financial year remains unchanged at between US$62 and US$70 per tonne (based on an exchange rate of AUD/USD 0.78).

NSWEC unit costs (US$M)				H1 FY22	H2 FY21	H1 FY21	FY21
Revenue				1,026	525	314	839
Underlying EBITDA				435	11	(180)	(169)
Gross costs				591	514	494	1,008
Less: royalties				84	41	25	66
Net costs				507	473	469	942
Sales (kt, equity share)				7,498	7,518	7,108	14,626
Cost per tonne (US$)(1)(2)				67.62	62.92	65.98	64.41

(1)   H1 FY22 based on an average exchange rate of AUD/USD 0.73.

(2)   H1 FY22 includes COVID-19 related costs of US$0.84 per tonne, which was reported as an exceptional item in FY21 (H1 FY21: US$0.56 per tonne; FY21: US$0.40 per tonne).         

Financial information for Coal for the December 2021 and December 2020 half years is presented below.

Half year ended 31 December 2021 US$M	Revenue	Underlying EBITDA	D&A	Underlying EBIT	Net operating assets	Capital expenditure	Exploration gross	Exploration to profit
Queensland Coal(1)	4,342	2,236	357	1,879	8,066	283
New South Wales Energy Coal(2)	1,070	458	54	404	(212)	23
Colombia(3)	−	−	−	−	−	−
Other(4)	−	(29)	9	(38)	2	7
Total Coal from Group production	5,412	2,665	420	2,245	7,856	313
Third party products	−	−	−	−	−	−
Total Coal	5,412	2,665	420	2,245	7,856	313	8	2
Adjustment for equity accounted investments(5)(6)	(44)	(23)	(13)	(10)	−	−	−	−
Total Coal statutory result	5,368	2,642	407	2,235	7,856	313	8	2

 

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)	1,856	59	329	(270)	8,137	278
New South Wales Energy Coal (2)	358	(130)	78	(208)	288	31
Colombia	63	(13)	39	(52)	355	8
Other(4)	−	(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(5)(6)	(107)	(67)	(53)	(14)	−	(8)	−	−
Total Coal statutory result	2,170	(201)	400	(601)	8,792	320	11	4

(1)   On 8th November 2021, BHP announced it has signed a Share Sale and Purchase Agreement to divest its 80 per cent interest in BHP Mitsui Coal (BMC). While BHP continues to report its share of profit and loss within the Coal Segment and asset tables, BMC's assets and liabilities have been classified as 'Held For Sale' and therefore excluded from Net Operating Assets (US$623 million).

(2)   Newcastle Coal Infrastructure Group is an equity accounted investments and its financial information presented above with the exception of net operating assets reflects BHP Group's share.

(3)   On 11 January 2022, BHP completed the sale to Glencore of its 33.3 per cent interest in Cerrejón. The transaction was first announced on 28 June 2021 for a total cash consideration of US$294 million with an effective economic date of 31 December 2020. The Group's investment in Cerrejón has subsequently been classified as 'Assets held for sale' and therefore excluded from net operating assets. At 31 December 2021, the Group's investment in Cerrejón continued to be classified as 'Assets held for sale' and measured at fair value in line with the divestment consideration. During the half year ended 31 December 2021, the Group received dividends of US$238 million from Cerrejón, reducing completion proceeds, net of expected transaction costs, and the value of the Group's investment in Cerrejón to US$46 million as at 31 December 2021.

(4)   Predominantly comprises divisional activities and ceased operations.

(5)   Total Coal statutory result revenue excludes US$ nil (H1 FY21: US$63 million) revenue related to Cerrejón. Total Coal statutory result Underlying EBITDA includes US$ nil (H1 FY21: US$39 million) D&A and US$ nil (H1 FY21: US$22 million) net finance costs and taxation benefits related to Cerrejón, that are also included in Underlying EBIT. Total Coal statutory result Capital expenditure excludes US$ nil (H1 FY21: US$8 million) related to Cerrejón.

(6)   Total Coal statutory result revenue excludes US$44 million (H1 FY21: US$44 million) revenue related to Newcastle Coal Infrastructure Group. Total Coal statutory result excludes US$23 million (H1 FY21: US$50 million) Underlying EBITDA, US$13 million (H1 FY21: US$14 million) D&A and US$10 million (H1 FY21: US$36 million) Underlying EBIT related to Newcastle Coal Infrastructure Group until future profits exceed accumulated losses.

 

29

 

Greenfield minerals exploration

BHP continues to strengthen its portfolio of options in future facing commodities including through an increased focus on exploration. A new office has been opened in Toronto for exploration and business development, and expenditure on minerals exploration in the December 2021 half year increased 28 per cent to US$110 million. Work continues on existing projects, joint ventures and farm-ins as well as leveraging technology to both look deeper in mature exploration jurisdictions and delineate new high potential search spaces globally. We have continued to add to our early stage options in future facing commodities. Greenfield minerals exploration is being undertaken on advancing copper targets in Chile, Ecuador, Mexico, Peru, Canada, Australia and the south-west United States. Nickel targets are also being advanced in Canada and Australia. Specifically in copper, we are testing targets with drilling in Chile, Ecuador, the United States and Australia.

In October 2021, BHP executed its farm-in agreement for the early-stage prospective Elliott copper project covering 7,200 km2 in the Northern Territory, Australia. Under the terms of the agreement, BHP can earn up to 75 per cent interest in Elliott by spending up to A$25 million over 10 years.

BHP is continuing resource definition drilling at Oak Dam, after commencing the program in May 2021.

In December 2021, BHP announced it would not increase or extend its offer to acquire Noront Resources. BHP is committed to its strict capital allocation framework and while the Eagle's Nest deposit is a promising resource, we do not see adequate long-term value for BHP shareholders.

In December 2021, BHP advanced its early-stage nickel interests by investing in the Kabanga Nickel Project (Kabanga), a high-quality nickel sulphide deposit in Tanzania. Kabanga is a joint venture between Kabanga Nickel Limited (84 per cent interest) and the Government of Tanzania (16 per cent interest).

 

Group and unallocated items

Underlying EBITDA for Group and unallocated items increased by US$290 million to US$396 million in the December 2021 half year primarily due to recovery of higher freight costs caused by movements in the freight index on consecutive voyage charter (CVC) voyages of US$172 million and lower demurrage costs related to China's coal import restrictions.

Nickel West's Underlying EBITDA decreased by US$3 million to US$118 million in the December 2021 half year. This reflects lower volumes and higher maintenance costs following planned maintenance at the Kalgoorlie Smelter, Kwinana Refinery and the Leinster and Kambalda concentrators in the September 2021 quarter, and planned asset integrity work to support operational stability completed in the December 2021 quarter. This was largely offset by higher prices and favourable exchange rate movements.

 

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Discontinued Operations - Petroleum

In November 2021, BHP signed a binding Share Sale Agreement for the proposed merger of BHP's oil and gas portfolio with Woodside to create a global top 10 independent energy company by production. On completion of the merger, Woodside will acquire BHP Petroleum in exchange for new Woodside shares. Completion is subject to satisfaction of conditions precedent including regulatory and competition authority approvals and approval by Woodside's shareholders. The process remains on track and the Australian Competition and Consumer Commission confirmed in December 2021 that it will not oppose the transaction. The Woodside shareholder meeting to vote on the merger as well as completion of the merger remains targeted for the June 2022 quarter. In addition to its primary listing on the Australian Securities Exchange, Woodside is pursuing a standard listing on the London Stock Exchange and a listing of American Depositary Receipts on the New York Stock Exchange. The effective date of the merger is 1 July 2021. The half-year financial results have been prepared on the basis that BHP Petroleum is a discontinued operation.

Underlying EBITDA for the December 2021 half year increased by US$2.1 billion to US$ 2.9 billion.

	US$M
Underlying EBITDA for the half year ended 31 December 2020	793
Net price impact	1,767	Higher average realised prices: Crude and condensate oil US$73.62/bbl (H1 FY21: US$41.24/bbl); Natural gas US$5.78/Mscf (H1 FY21: US$3.83/Mscf); LNG US$15.10/Mscf (H1 FY21: US$4.45/Mscf).
Change in volumes	170	Higher seasonal gas demand at Bass Strait, increased volumes from Ruby following first production in May 2021 and lower impact from weather events in the Gulf of Mexico partially offset by natural field decline across the portfolio.
Change in controllable cash costs	52	Increased maintenance and integrity activity in Trinidad and Tobago and the impact of expensing the Wasabi-1 well, were more than offset by the impact from expensing the Broadside-1 well and seismic costs in the Gulf of Mexico and Trinidad and Tobago in the prior period.
Ceased and sold operations	3
Change in other costs:
Exchange rates	40
Inflation	(15)
Other	108	Other includes the contingent consideration proceeds from the Scarborough divestment in 2016 (payable upon FID which was announced in November 2021) and tax barrel adjustments at Trinidad and Tobago, partially offset by the revaluation loss of embedded derivatives in the Trinidad and Tobago gas contract of US$32 million (H1 FY21: US$1 million loss) and other items.
Underlying EBITDA for the half year ended 31 December 2021	2,918

Petroleum unit costs increased by two per cent to US$10.51 per barrel of oil equivalent primarily driven by an increase in price-linked costs and increased maintenance and integrity activity in Trinidad and Tobago. No further guidance for the 2022 financial year will be provided given the Petroleum business has been presented as a discontinued operation. The Petroleum business continues to actively manage costs across the portfolio and improve competitiveness.

Petroleum unit costs (US$M)				H1 FY22	H2 FY21	H1 FY21	FY21
Revenue				3,288	2,327	1,619	3,946
Underlying EBITDA				2,918	1,513	793	2,306
Gross costs				370	814	826	1,640
Less: exploration expense				112	115	181	296
Less: freight				65	78	29	107
Less: development and evaluation				79	90	106	196
Less: other(1)				(443)	(69)	(5)	(74)
Net costs				557	600	515	1,115
Production (MMboe, equity share)				53	53	50	103
Cost per Boe (US$)(2)(3)				10.51	11.32	10.30	10.83

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(1)   Other includes over/under lift and inventory movements, non-cash profit on sales of assets, Scarborough FID consideration, foreign exchange, discontinued operations adjustments and the impact from revaluation of embedded derivatives in the Trinidad and Tobago gas contract. 

(2)   H1 FY22 based on an average exchange rate of AUD/USD 0.73.

(3)   H1 FY22 includes nil COVID-19 related costs, which was reported as an exceptional item in FY21 (H1 FY21: US$0.25 per barrel of oil; FY21: US$0.27 per barrel of oil).    

On 22 November 2021, we announced the approval of US$1.5 billion in capital expenditure for development of the Scarborough upstream project located in the North Carnarvon Basin, Western Australia. The approved capital expenditure represents BHP's 26.5 per cent participating interest in Phase 1 of the upstream development. Final investment decisions have also been made by Woodside and the Scarborough Joint Venture.

In the December 2021 quarter, we completed the Ruby project in Trinidad and Tobago. The project was completed on schedule and within budget, and the Ruby field is currently producing both oil and gas.

The Mad Dog Phase 2 project's semi-submersible platform, Argos, was towed to final location in the US Gulf of Mexico and moored. Offshore execution of construction and commissioning is in progress. First production from Mad Dog Phase 2 is expected from the middle of the 2022 calendar year.

In December 2021, we reached a commercial milestone for the Trion project in Mexico with the filing of a Declaration of Commerciality with the National Hydrocarbons Commission. As announced in August 2021, we have moved Trion into the Front End Engineering Design (FEED) phase and work is progressing to plan. Studies are underway, focused on completion of the engineering, commercial arrangements and execution planning required to progress readiness for a Final Investment Decision from the middle of the 2022 calendar year.

Petroleum exploration

Petroleum exploration expenditure for the December 2021 half year was US$243 million, of which US$112 million was expensed. An approximately US$540 million exploration and appraisal program is being executed for the 2022 financial year.

In Trinidad and Tobago, the Calypso appraisal drilling programme concluded on 20 December 2021. All wells encountered hydrocarbons. Bongos-3 confirmed volumes downdip of prior penetrations and Bongos-4 established volumes in a new segment. The well results are currently under evaluation and will be incorporated into the development plan.

In the central Gulf of Mexico, the Wasabi-1 well encountered a mechanical difficulty and was plugged and abandoned on 13 November 2021. Wasabi-2 (GC124-002) was spud on 17 November 2021 and drilling operations continue.

In Barbados, a 3D seismic survey was acquired in November 2021 over a portion of the Bimshire and Carlisle Bay blocks^(ix). Processed data is expected to be delivered in the middle of the 2022 calendar year.

BHP has acquired interests in offshore exploration blocks in the Red Sea in Egypt. In December 2021, the Minister of Energy in Egypt signed the Deed of Assignment for Red Sea Block 1, finalising the assignment of a 45 per cent participating interest from Chevron to BHP. The effective date of the transfer is 12 September 2021. This follows a separate agreement with Shell in March 2021 for BHP to acquire a 30 and 25 per cent non-operated working interest in Egypt's Red Sea Blocks 3 and 4, respectively. The effective date of BHP's participation in Blocks 3 and 4 is pending final government approvals.

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Financial information for Petroleum for the December 2021 and December 2020 half years is presented below.

Half year ended 31 December 2021 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)	225	181	68	113	8	7
Bass Strait	775	621	421	200	706	14
North West Shelf	865	1,141	101	1,040	1,636	114
Atlantis	517	454	106	348	998	11
Shenzi	326	260	76	184	1,079	140
Mad Dog	157	129	23	106	1,950	109
Trinidad/Tobago	206	156	48	108	442	111
Algeria	108	94	−	94	119	6
Exploration	−	(112)	12	(124)	1,194	−
Other(5)	111	(4)	28	(32)	113	44
Total Petroleum from Group production	3,290	2,920	883	2,037	8,245	556
Third party products	6	−	−	−	−	−
Total Petroleum	3,296	2,920	883	2,037	8,245	556	243	112
Adjustment for equity accounted investments(6)	(8)	(2)	(2)	−	−	−	−	−
Total Petroleum statutory result	3,288	2,918	881	2,037	8,245	556	243	112
Inter-segment adjustment	(31)	−	−	−	−	−	−	−
Total Discontinued Operations - Petroleum	3,257	2,918	881	2,037	8,245	556	243	112

 

Half year ended 31 December 2020 US$M (Restated)	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	(105)	37	(142)	175	33
Total Petroleum from Group production	1,622	795	903	(108)	8,548	498
Third party products	3	−	−	−	−	−
Total Petroleum	1,625	795	903	(108)	8,548	498	195	242
Adjustment for equity accounted investments(6)	(6)	(2)	(2)	−	−	−	−	−
Total Petroleum statutory result	1,619	793	901	(108)	8,548	498	195	242
Inter-segment adjustment	(24)	−	−	−	−	−	−	−
Total Discontinued Operations - Petroleum	1,595	793	901	(108)	8,548	498	195	242

(1)   Total Petroleum revenue includes: crude oil US$1,654 million (H1 FY21: US$769 million), natural gas US$669 million (H1 FY21: US$434 million), LNG US$743 million (H1 FY21: US$292 million), NGL US$190 million (H1 FY21: US$96 million) and other (including inter-segment adjustments) US$1 million (H1 FY21: US$4 million).

(2)   Includes US$131 million of capitalised exploration (H1 FY21: US$14 million).

(3)   Includes US$ nil of exploration expenditure previously capitalised, written off as impaired (included in depreciation and amortisation) (H1 FY21: US$61 million).

(4)   Australia Production Unit includes Macedon and Pyrenees.

(5)   Predominantly divisional activities, business development and Neptune (sale finalised in May 2021). 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.

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(6)   Total Petroleum revenue excludes US$8 million (H1 FY21: US$6 million) revenue related to the Caesar oil pipeline and the Cleopatra gas pipeline. Total Petroleum statutory result Underlying EBITDA includes US$2 million (H1 FY21: US$2 million) D&A related to the Caesar oil pipeline and the Cleopatra gas pipeline.

 

The Financial Report set out on pages 33 to 55 for the half year ended 31 December 2021 has been prepared on the basis of accounting policies and methods of computation consistent with those applied in the 30 June 2021 financial statements contained within the Annual Report of the Group. 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 2021 half year compared with the December 2020 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 62 to 74. 

(ii)    FY22 and medium-term unit cost guidance are based on exchange rates of AUD/USD 0.78 and USD/CLP 727.

(iii)   Based on Underlying attributable profit from continuing operations.

(iv)   Refer to page 8 of BHP's Climate Transition Action Plan 2021 for the definitions applicable to this target.

(v)    Carbon neutral is not intended to imply certification under any standard or application of a particular methodology and includes all those greenhouse gas emissions as defined for BHP reporting purposes.

(vi)   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 76.

(vii)  US dollar amounts are calculated based on weighted average actual transactional (historical) exchange rates related to Renova funding.

(viii) Maintenance capital includes non-discretionary spend for the following purposes: deferred development and production stripping; risk reduction, compliance, asset integrity, decarbonisation and social value investments.

(ix)   Permission for survey granted by the Barbados Ministry of Energy.

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; operational performance, 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, 'guidance', outlook', 'prospect', 'target', '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.

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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.

 

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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, the respective subsidiaries as defined in note 30 'Subsidiaries' in section 3.1 of BHP's 30 June 2021 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 2021 to 31 December 2021. 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, 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. 

 

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

 

Authorised for lodgement by:

The Board of BHP Group Limited

 

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