BHP Group Regulatory News (BHP)

BHP RESULTS FOR THE YEAR ENDED 30 JUNE 2020

Note: All guidance is subject to further potential impacts from COVID-19 during the 2021 financial year.

Keeping our people and communities safe

- We had no fatalities at our operated sites during the year and improved Total Recordable Injury Frequency.

- Our commitments to safety and social value have enabled us to operate reliably and safely during the COVID-19 pandemic. We had the support of our workforce, Traditional Owners, communities, governments, customers and suppliers.

Maximise cash flow: Robust earnings and free cash flow generation despite COVID-19  

- Attributable profit of US$8.0 billion and Underlying attributable profit(i) of US$9.1 billion broadly in line with the prior year.

- Profit from operations of US$14.4 billion and Underlying EBITDA(i) of US$22.1 billion at a margin(i) of 53%, with unit costs reduced by 9% at our major assets due to foreign exchange, better productivity and improved operating stability.

- Net operating cash flow of US$15.7 billion, above US$15 billion for the fourth consecutive year, and free cash flow(i) of US$8.1 billion.

Capital discipline: Major projects tracking well, early stage options added and balance sheet remains strong

- Capital and exploration expenditure(i) within guidance at US$7.6 billion. We now expect capital and exploration expenditure to be approximately US$7 billion for the 2021 financial year, reflecting the proactive deferral for value of a number of our petroleum projects, and approximately US$8.5 billion for the 2022 financial year.

- Our six major projects under development are progressing well, with first production from Atlantis Phase 3 achieved in July 2020 and the Spence Growth Option and South Flank expected to deliver first production within the next 12 months. Jansen is now expected to be presented to the Board for a Final Investment Decision in the middle of the 2021 calendar year following delays to completion of the shafts. These delays are a result of initial challenges with placement of the shaft lining, since rectified, and due to impacts from our COVID-19 response plan.

- We continue to advance our exploration programs in petroleum, copper and nickel, with results of the third phase of the drilling program completed at our Oak Dam copper discovery in South Australia currently under analysis. We have also added to our early stage optionality in nickel with the acquisition of the Honeymoon Well tenements in Western Australia.

- Net debt at US$12.0 billion, compared to US$9.4 billion at 30 June 2019, which is at the low end of our target range of US$12 to US$17 billion. The application of IFRS 16 Leases has increased net debt(i)(1) by US$1.6 billion since 30 June 2019.

Value and returns: Consistently high cash returns, US$6.1 billion of total announced returns to shareholders

- To further enhance our portfolio for value, risk and returns, we intend to concentrate our coal portfolio on higher-quality coking coals, and are looking at options to exit BMC, New South Wales Energy Coal (NSWEC) and Cerrejón.

- The Board has determined to pay a final dividend of 55 US cents per share or US$2.8 billion, which includes an additional amount of 17 US cents per share (equivalent to US$0.9 billion) above the 50% minimum payout policy. Total dividends announced of US$1.20 per share, equivalent to a 67% payout ratio.

- Underlying return on capital employed(i) remained strong at 17%.

1

(1) The definition of net debt has changed to include the fair value of derivatives used to hedge foreign exchange and interest rate risk related to cash and borrowings. Prior period comparatives have been restated to reflect the change in net debt calculation. Net debt was restated from US$9.2 billion to US$9.4 billion as at 30 June 2019.

IFRS 16 became effective from 1 July 2019. As at 30 June 2020, the impact from the application of IFRS 16 Leases on net debt was US$1.6 billion. Further detail is included in the Alternative Performance Measures section.

Results for the year ended 30 June 2020

BHP Chief Executive Officer, Mike Henry:

"BHP delivered a strong set of results for the 2020 financial year that reflect the strength, resilience and quality of our people and our portfolio. In a year marked by the challenges of the global COVID-19 pandemic, social unrest in Chile and commodity price volatility, we were safer, more reliable and lower cost.

BHP's operations generated robust free cash flow and our balance sheet remained strong, with net debt finishing the year at the low end of our target range. We have announced a final dividend of 55 US cents per share, bringing shareholder returns to US$6.1 billion for the full year.

Our workforce operated with purpose, focus, speed and decisiveness, and I am proud of their achievements. We are grateful for the ongoing support of our communities, Traditional Owners, governments and business partners. In line with our commitment to social value, we have in turn sought to support them through this difficult period by creating 1,500 jobs, making early payments to small, regional and indigenous suppliers and contributing more than US$75 million to community, health and social programs.

We expect most major economies will contract heavily in 2020, China being the exception. Recovery will vary considerably by country. Our diversified portfolio and high-quality assets position us to continue to generate returns in the face of near-term uncertainty, even as we secure and create the options in future-facing commodities that will allow us to sustainably grow value in the long-term.

2

Our development projects and exploration programs are progressing well and in line with our strategy. We have secured, and will continue to grow, options in copper and nickel, where increasing demand and our capability give us competitive opportunities. We are moving to concentrate our coal portfolio on high quality coking coals, with greatest potential upside for quality premiums as steel makers seek to improve blast furnace utilisation and reduce emissions intensity. In oil and gas, we will continue to invest in opportunities that are resilient under a range of price scenarios, and which are aligned to our strengths. We will seek to divest oil and gas assets that are mature or which are likely to realise greater value under different ownership. This approach to actively managing our portfolio for value, risk and returns over multiple time horizons will yield superior returns for our investors and greater value for our partners and communities. Our ability to do so will be underpinned by our distinctive culture and organisational capability, our strong balance sheet and disciplined approach to capital allocation.

I have created two new roles on BHP's Executive Leadership Team, appointing Laura Tyler as Chief Technical Officer and Johan van Jaarsveld as Chief Development Officer. These appointments will accelerate our agenda to become safer, lower cost and more productive, and to develop a portfolio that is fit for the future with opportunities for long-term growth. Ragnar Udd and Caroline Cox will also join the team as President Minerals Americas and Chief External Affairs Officer, respectively, replacing Danny Malchuk and Geoff Healy. Our company is safer and stronger because of Danny and Geoff's outstanding leadership and I thank them for their enormous contribution to BHP.

Our products are essential for the world and the future. I am confident our portfolio and approach will continue to support attractive value and returns for decades to come."

Leading delivery of social value

Our priority is the safety, health and wellbeing of our workforce and the communities in which we operate and we have demonstrated this throughout the COVID-19 pandemic.

Our operated assets have continued to operate safely, with additional protocols in place to protect our workforce and communities from the spread of COVID-19, in line with guidelines from local and national government bodies and expert health advice in the geographies where we operate.

Our support for local communities has been a critical area of focus in BHP's response. We have provided significant support to communities in Australia. We announced the A$50 million Vital Resources Fund in March 2020. It is being used to support regional communities in our areas of operation and includes funding for essential community and health services in the Pilbara, Bowen Basin, Hunter Valley and South Australia. We have implemented protective measures for the local communities and we have ceased all face-to-face contact with Traditional Owners to protect vulnerable members of their communities. We also hired an additional 1,500 people into temporary roles to support our workforce operating across Australia.

In Chile, we established a US$8 million program to support the public health response to COVID-19 at the national and regional level, with a focus on increasing testing capacity and tracing, the provision of medical equipment, and the support the communities where we operate and vulnerable populations through hygiene supplies and water, and public spaces sanitation. An additional US$3 million fund was established for specific local community programs. In North America, a US$2 million fund was established to support local and regional health and wellness programs in communities in close proximity to our operations.

We shortened payment terms globally for our small, local and Indigenous suppliers, to further assist them and local communities to manage through the financial pressures of COVID-19.

3

In parallel with leading through the challenges faced during the year, we are continuing to take action on helping to address the urgent challenge of climate change. In October 2019, we announced four new renewable power contracts for Escondida and Spence that will replace existing electricity supply contracts. The contracts will deliver lower energy prices and will displace approximately 3 Mt CO2-e per year from BHP's Chilean operations from the 2022 financial year. We aim to supply Escondida and Spence's energy requirements fully from 100 per cent renewable energy sources from the mid-2020s. We are also minimising our use of fresh water. Escondida has eliminated water drawdown from aquifers for operational supply 10 years ahead of its 2030 target. This was made possible by the completion of the Escondida Water Supply Expansion project in December 2019, which further increased total desalinated water capacity. We have also realised better water consumption efficiency through a program of continuous improvement.

Work is progressing on the implementation of the climate change initiatives announced in July 2019. We are setting a 2030 science-based target for Scope 1 and 2 emissions, to set the trajectory towards our 2050 goal of net-zero operational emissions, as well as setting Scope 3 emissions goals. We are implementing the US$400 million Climate Investment Program, to develop low carbon technologies and invest in nature-based solutions to support reduction in emissions from our operations as well as those generated from the use of our resources. Furthermore, we are updating our climate portfolio analysis, and clarifying and strengthening the link between performance against emissions targets and BHP's executive pay plans. We will announce these in our Climate Change Report to be published on 10 September 2020.

The BHP Tailings Taskforce, that we established last year, continues to oversee improvement and assurance for our operated tailings storage facilities, including a focus on short term risk reduction, strengthening emergency response, enhancing preventative controls, improving governance processes and leading ongoing participation with the International Council of Mining and Metals and others across the industry on the implementation of the new Global Industry Standard for Tailings Management. The new international standard provides a framework for safer tailings management and an ambition to achieve the goal of zero harm to people and the environment, and we are taking a proactive approach to ensure we meet all of the requirements that have been set out in the standard. We fully support the transparency and independence of the review process, which has brought together multiple stakeholders across a range of disciplines to achieve a global industry standard.

In 2018 we established BHP Operations Services to provide a highly skilled workforce of permanent employees able to work across BHP's Australian operations. We have since created nearly 3,000 permanent jobs, over and above approximately 1,500 other new roles in Australia, with Operations Services now deployed at 20 locations across Western Australia Iron Ore (WAIO), Queensland Coal and NSWEC. Deployments are achieving better safety, productivity and efficiency outcomes.

In May 2020, Operations Services launched the BHP FutureFit Academy, a new national training program, developed to provide a customised training pathway utilising nationally recognised curricula, for trade apprenticeships and maintenance traineeships. The first two FutureFit Academy campuses opened in Mackay in Queensland and Perth in Western Australia, with graduates to be deployed to an Operations Services team from the 2021 calendar year.

The BHP Foundation, which is funded by BHP, continues to work with partner organisations to address some of the world's most critical sustainable development challenges, with a focus on resource governance, environmental resilience, and education equity. Further information can be found at: bhp.com/community/bhp-foundation

4

(1) FY19 presented on a total operations basis, except for operational GHG emissions, fresh water withdrawals and local procurement spend.

(2) HPI frequency: number of injuries from events where there was the potential for a fatality per million hours worked.

(3) Operational GHG emissions have been revised subsequent to the FY19 annual report following an HSE data audit, resulting in an improvement to emissions reporting methodology for our operations in Chile; previously reported as 14.2 Mt CO2-e.

(4) In FY17, our operational GHG emissions were 14.6 Mt CO2-e (excluding Onshore US).

(5) In FY17, our fresh water withdrawals were 156.1 GL (on an adjusted basis, excluding Onshore US).

(6) Work is underway to establish medium term targets for indigenous workforce participation in Australia and Chile.

BHP remains committed to supporting the Renova Foundation and its work to progress the remediation and compensatory programs to restore the environment and re-establish communities affected by the Samarco tragedy.

Resettlement of communities remains one of the Renova Foundation's priority social programs and involves ongoing engagement and consultation with a large number of stakeholders. The implementation of precautionary measures to facilitate physical distancing for COVID-19, including a suspension of works between March and June 2020, as well as increases to the technical scope for resettlement of the communities and licencing delays from authorities have impacted the timeline for completion.

5

Resettlement works resumed in the municipality of Mariana from mid-June 2020 and are continuing with a reduced workforce. Currently, there is no schedule to return to full staff capacity as this depends on the duration of COVID-19 restrictions. At Bento Rodrigues, construction of housing, the public school and healthcare facility is continuing to progress, while infrastructure works are nearing completion. At Paracatu, infrastructure works and the construction of some public buildings and the first houses are underway. At Gesteria, the urban plan design is progressing in consultation with the community.

Under the compensation program, more than 10,000 general damages claims have been resolved, in addition to approximately 260,000 claims for temporary interruption to water supplies resolved shortly after the dam failure. The Renova Foundation continues to assist more than 14,750 families with income support.

Works to stabilise the impacted land areas were successfully concluded by the Renova Foundation in the 2019 calendar year, with the riverbanks and floodplains vegetated, river margins stabilised and, in general, water and sediment qualities returned to historic conditions. Long-term remediation work is continuing with landowners and regulators to re-establish agricultural production.

In October 2019, Samarco obtained the Corrective Operating Licence required to progress towards operational restart of one concentrator. Works related to the construction of a filtration plant have also been slowed as a result of a reduced workforce, as part of the COVID-19 response. Restart can occur when the filtration system is complete and Samarco has met all necessary safety requirements, and will be subject to final approval by Samarco's shareholders.

BHP has reviewed its cost estimates for the Samarco dam failure, including the impact of recent judicial decisions in Brazil regarding financial assistance and compensation of impacted persons. Combined with the benefit of proceeds from insurance settlements, favourable exchange rate movements and net finance costs and other charges, BHP recorded a total income statement charge of US$176 million (after tax) in relation to the Samarco dam failure for the 2020 financial year. This charge is recognised as an exceptional item. Additional commentary, including the breakdown of the income statement charge is included on page 45.

Note: All guidance is subject to further potential impacts from COVID-19 during the 2021 financial year

Earnings and margins

· Attributable profit of US$8.0 billion includes an exceptional loss of US$1.1 billion (2019: US$8.3 billion, which includes a US$818 million exceptional loss). The 2020 financial year exceptional loss is related to the impairment of Cerro Colorado, a provision for cancellation of power contracts as part of a shift towards 100 per cent renewable energy at Escondida and Spence, COVID-19 related costs and the current year impact of the Samarco dam failure.

· Underlying attributable profit of US$9.1 billion (2019: US$9.1 billion).

· Profit from operations of US$14.4 billion (2019: US$16.1 billion) decreased as a result of lower prices, lower volumes (including copper grade and petroleum field declines), increased deferred stripping depletion at Escondida and an increase in the closure and rehabilitation provision for closed mines. This was partially offset by the favourable impacts of exchange rate movements, better productivity, including record production at WAIO, Caval Ridge and Poitrel; record coal mined at Broadmeadow and record average concentrator throughput at Escondida, lower unit costs at our major assets and improved operating stability.

6

· The total impact from COVID-19 on our operations was US$348 million (pre-tax), including an exceptional charge of US$183 million, in the 2020 financial year. This represents the following impacts: lower volumes at our operated assets of US$112 million; temporary shutdowns at our non-operated equity accounted investments (Antamina and Cerrejón) of US$53 million; and additional costs incurred at our operated assets such as temporary relocation costs, screening and hygiene of US$183 million (exceptional item).

· Underlying EBITDA of US$22.1 billion (2019: US$23.2 billion), with lower prices, lower volumes (including copper grade and petroleum field declines), inflation, an increase in the closure and rehabilitation provision for closed mines and other net movements, partially offset by record volumes at a number of our assets, improved operating stability, and favourable impacts from exchange rate movements and the application of IFRS 16 Leases.

· Underlying EBITDA margin of 53 per cent (2019: 53 per cent).

· Underlying return on capital employed at 17 per cent (2019: 18 per cent excluding Onshore US).

Costs

· Strong cost performance underpinned by consumption efficiencies at Escondida, improved operating stability across our portfolio and further reductions in overheads, partially offset by increased planned maintenance activities at a number of our assets.

· Unit costs were nine per cent lower across our major assets. Unit costs(i) at Petroleum and Escondida were better than guidance and we achieved unit cost guidance at WAIO and Queensland Coal (based on exchange rate of AUD/USD 0.70 and USD/CLP 683). At WAIO, unit costs on a C1 basis excluding third party royalties, were eight per cent lower than the prior year at US$11.82 per tonne (2019: US$12.86 per tonne), reflecting strong operational performance and continued productivity improvements from our workforce and equipment across the supply chain.

· Costs related to the impact from COVID-19 are reported as an exceptional item and are not included in unit costs for the 2020 financial year. At our major assets these additional costs were: US$0.37 per tonne at Queensland Coal, US$0.30 per tonne at WAIO and US$0.01 per pound at Escondida. The impact on Petroleum unit costs was immaterial.

· Unit cost guidance for the 2021 financial year (based on exchange rates of AUD/USD 0.70 and USD/CLP 769) reflects: natural field decline at Petroleum; lower copper grades and lower deferred stripping costs at Escondida; continued productivity and equipment reliability at WAIO; and higher strip ratios and contractor stripping costs at Queensland Coal.

· We will continue to drive higher performance as we unlock value through the ongoing automation of our supply chain, reduce our reliance on labour hire through the continued roll out in Australia of our Operations Services initiative to leverage best practice in production and maintenance, and continue to set records for equipment utilisation, milling and production across our operations.

7

· Historical costs and guidance are summarised below:

(1) FY21 and medium-term unit cost guidance are based on exchange rates of AUD/USD 0.70 and USD/CLP 769.

(2) Average exchange rates for FY20 of AUD/USD 0.67 and USD/CLP 771.

(3) FY20 unit costs excludes the impact from COVID-19 that was reported as an exceptional item.

(4) FY20 unit costs at guidance exchange rates of AUD/USD 0.70 and USD/CLP 683.

(5) Escondida medium-term unit cost guidance has been revised from less than US$1.15 per pound reflecting updated guidance exchange rates.

(6) WAIO unit costs exclude freight and royalties. The breakdown of C1 unit costs, excluding third party royalties, are detailed on page 26.

(7) Queensland Coal medium-term unit cost guidance has been revised from between US$54 and US$61 per tonne reflecting reduced volumes due to a focus on higher quality coals and a market responsive approach to bringing new tonnes into the market.

· Production and guidance are summarised below:

(1) Petroleum medium-term production guidance has been revised from approximately 110 MMboe following the significant disruptions to oil and gas markets and reflects our lower investment program for the next 12 months. Represents average volumes over the period, with lower volumes now also expected at the end of the five year period as a result of the delay of the Scarborough gas development.

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

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

(4) WAIO's current licenced export capacity is 290 Mtpa.

(5) Queensland Coal medium-term production guidance has been revised from between 49 and 54 Mt reflecting reduced volumes due to a focus on higher quality coals and a market responsive approach to bringing new tonnes into the market.

· Group copper equivalent production(ii) was broadly in line with the prior year, as records set at WAIO, Caval Ridge, Poitrel, Broadmeadow and Escondida, offset the impacts of COVID-19 across our assets, wet weather (particularly at Queensland Coal) and natural field decline in petroleum.

· Group copper equivalent production for the 2021 financial year is expected to be slightly lower than the 2020 financial year, due to impacts from a reduction in operational workforces in copper in response to COVID-19 and petroleum natural field decline.

8

Cash flow and balance sheet

· Net operating cash flows (continuing operations) of US$15.7 billion (2019: US$17.4 billion), above US$15 billion for the fourth consecutive year, reflects weaker commodity prices in coal and petroleum, partially offset by stronger iron ore prices and strong underlying operating and cost performance across the portfolio.

· Free cash flow (continuing operations) of US$8.1 billion, after capital and exploration expenditure of US$7.6 billion.

· Our balance sheet remains strong, with net debt at US$12.0 billion at 30 June 2020 (31 December 2019: US$12.7 billion; 30 June 2019: US$9.4 billion) and at the bottom of our target range. The increase of US$2.6 billion in net debt reflects record ordinary dividends paid to shareholders during the year of US$6.9 billion and a US$1.6 billion impact from the application of IFRS 16 Leases, partially offset by solid free cash flow generation.

· We have reviewed our definition of net debt and have excluded vessel lease contracts that are priced with reference to a freight index as of 1 January 2020 and have restated 31 December 2019 for comparative purposes. These liabilities do not align with how the Group assesses net debt for decision making in relation to the Capital Allocation Framework. These contracts are required to be re-measured at each reporting date at the prevailing freight index. The freight index has historically been volatile which also creates significant short-term fluctuations in these liabilities.

· We remain committed to a strong balance sheet through the commodity price cycle, and expect net debt to remain towards the lower end of the target range of US$12 to US$17 billion in the near term.

· Gearing ratio(i) of 18.7 per cent (31 December 2019: 19.5 per cent; 30 June 2019: 15.4 per cent and 17.8 per cent including 1 July 2019 IFRS 16 impacts).

Dividends

· The dividend policy provides for a minimum 50 per cent payout of Underlying attributable profit at every reporting period. The minimum dividend payment for the June 2020 half year period is 38 US cents per share, or US$1.9 billion.

· The Board has determined to pay an additional amount of 17 US cents per share or US$0.9 billion, taking the final dividend to 55 US cents per share. This is equivalent to a 72 per cent payout ratio (2019: 73 per cent).

· In total, dividends of US$6.1 billion (US$1.20 per share) have been determined for the 2020 financial year, including an additional amount of US$1.5 billion above the minimum payout policy.

Capital and exploration

· Capital and exploration expenditure of US$7.6 billion in the 2020 financial year was within guidance. This included maintenance expenditure(iii) of US$1.9 billion and exploration expenditure of US$740 million.

· Capital and exploration expenditure of approximately US$7 billion is now expected for the 2021 financial year and is approximately US$1 billion lower than previous guidance predominantly due to the deferral of a number of our petroleum projects in order to maximise value. In accordance with our Capital Allocation Framework, we expect capital and exploration expenditure to be approximately US$8.5 billion for the 2022 financial year, partly driven by the deferral of expenditure from the 2021 financial year. Guidance is subject to exchange rate movements.

· This guidance includes a US$0.7 billion exploration program in the 2021 financial year, with approximately US$450 million for petroleum exploration and appraisal expenditure.

9

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

(1) Includes capitalised deferred stripping of US$698 million for FY20 (FY19: US$1.0 billion) and US$0.8 billion for FY21.

(2) Petroleum capital expenditure for FY21 includes US$1.1 billion of development and US$0.1 billion of maintenance.

· Average annual sustaining capital expenditure guidance over the medium term, excluding costs associated with our automation programs, is unchanged for WAIO and forecast to be approximately US$4 per tonne, including the capital cost for South Flank.

· Queensland Coal sustaining capital expenditure guidance has increased from approximately US$8 per tonne to approximately US$9 per tonne and reflects increased investment in risk reduction programs across our operations and fleet replacement towards the end of our five year plan.

Projects

· Our latent capacity projects are tracking to plan:

- Escondida Water Supply Expansion project was completed in December 2019, on schedule and budget, further increasing total desalinated water capacity to 3,800 litres per second. Escondida has invested more than US$4 billion in desalinated water since 2006;

- West Barracouta (Bass Strait) project is on schedule and budget, and is still expected to achieve first production in the 2021 calendar year despite delays in component delivery and equipment fabrication due to COVID-19 restrictions; and

- WAIO to sustainably achieve supply chain capacity of 290 Mtpa over the medium-term.

· On 8 August 2019, the BHP Board approved an investment of US$283 million (BHP share) for the development of the Ruby oil and gas project in Trinidad and Tobago.

· At the end of the 2020 financial year, BHP had six major projects under development (in petroleum, copper, iron ore and potash) with a combined budget of US$11.4 billion over the life of the projects. First production from Atlantis Phase 3 was achieved in July 2020, with the Spence Growth Option and South Flank expected to deliver first production within the next 12 months.

· The Spence Growth Option is continuing to progress, however, as a result of measures put in place to reduce the spread of COVID-19, first production is now expected between December 2020 and March 2021. As a result of the reduction of the on-site workforce, the commissioning of the desalination plant and capitalisation of the associated US$600 million lease (approximate) will now occur in the first half of the 2021 financial year.

10

· The Jansen Stage 1 potash project in Canada is now expected to be presented to the BHP Board for Final Investment Decision in the middle of the 2021 calendar year following delays to completion of the shafts. These delays are a result of initial challenges with placement of the shaft lining, since rectified, and due to impacts from our COVID-19 response plan. The forecast capital cost for the execution of Jansen Stage 1 is unchanged at between US$5.3 to US$5.7 billion, however some additional costs are now expected to be incurred on the US$2.7 billion shaft project currently in execution as a result of the delays. This is currently under review.

· In March 2020, Woodside (the operator) announced the delay of the Scarborough gas development to the second half of the 2021 calendar year. A Final Investment Decision by BHP is expected to be aligned with this revised timing.

· Autonomous trucks are being implemented at three additional mine sites across coal and iron ore. We will continue to assess the value case for potential expansion of this technology to our other Australian iron ore and coal mine sites.

- At the Daunia coal mine in Central Queensland, we announced the introduction of 34 autonomous trucks in July 2020. The first trucks will begin operating in February 2021 and the rollout is expected to be completed early in the 2022 calendar year.

- At the Newman East (Eastern Ridge) iron ore mine in Western Australia, the first of 20 autonomous trucks began operating in July 2020, with the rollout expected to be completed by the end of the 2020 calendar year.

- At the Goonyella Riverside mine in Queensland, the first coal site to implement autonomous haul trucks, the deployment of 86 autonomous trucks is expected to be completed early in the 2022 calendar year.

11

· Major projects are summarised below:

(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 reflects BHP's share.

(2) Potash capital expenditure of approximately US$285 million is expected for FY21.

12

Capital Allocation Framework

Adherence to our Capital Allocation Framework aims to balance value creation, cash returns to shareholders and balance sheet strength in a transparent and consistent manner.

(1) Includes total net cash outflow of US$1.1 billion (FY19: US$1.3 billion) which comprises dividends paid to non-controlling interests of US$1.0 billion (FY19: US$1.2 billion); net investment and funding of equity accounted investments of US$0.6 billion (FY19: US$0.6 billion) and an adjustment for exploration expenses of US$(0.5) billion (FY19: US$(0.5) billion) which is classified as organic development in accordance with the Capital Allocation Framework.

With the exception of China, the world's major economies will contract during the 2020 calendar year as a result of the COVID-19 pandemic. While the outlook for 2021 remains uncertain, within the scenarios that we consider, our base case has the world economy rebounding solidly during the year. There will, however, be considerable variation at the country level. Even with this rebound, our base case is for the world economy to be six per cent smaller than it would otherwise have been in the 2021 calendar year. We expect that China and the OECD will return to their pre COVID-19 trend growth rates from around 2023. Developing economies outside East Asia may take longer.

Inflation trends and exchange rates have been volatile. Many of our uncontrollable cost exposures such as diesel, power, explosives and steel products have declined in the last six months. The impact of COVID-19 on national and regional labour markets has also been profound. Looking ahead, we expect that costs for these inputs will remain lower than anticipated pre-COVID for some years, even though inflation period-on-period may be quite variable.

In Chile, the need to continue to combat COVID-19, the background social unrest and the associated commitment to develop a new Constitution together imply ongoing heightened uncertainty when it comes to decision making in both the public and private spheres.

There remains a significant degree of uncertainty in terms of how the COVID-19 pandemic will progress, and its longer term effects. For the time being, we expect that this uncertainty will constrain risk appetite of households and businesses. This will in turn have a dampening effect on the global economy.

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

13

Notwithstanding our view that the primary demand shock associated with COVID-19 is behind us, we believe that for the year ahead there remains a range of risks to prices for our various commodities. The potential for re-emergence of COVID-19 outbreaks in key markets or supply jurisdictions is the main source of uncertainty in our year-ahead outlook.

Global crude steel production will decline in the 2020 calendar year, with solid growth in China offset by a steep fall in the rest of the world. Steel production is expected to decline by six per cent for crude steel and between three per cent and four per cent for pig iron. Our preliminary assessment for the 2021 calendar year is for a percentage increase of similar magnitude to the 2020 contraction, with pig iron lagging somewhat as rising scrap availability and lower scrap cost restore the competitiveness of production from the electric arc furnace fleet. We anticipate that global steel production will expand slightly faster than population growth in coming decades, with a plateau and then slow decline in China offset by growth in the developing world, led by India. Growth in pig iron production will trail behind the growth in steel, principally reflecting higher long term proportion of steel sourced from scrap.

Iron ore prices have been elevated since the Brumadinho tailings dam tragedy in Brazil first disrupted the market in early 2019 but can be expected to ease as Brazilian supply recovers. In the second half of the 2020s, China's demand for iron ore is expected to be lower than today as crude steel production plateaus and the scrap-to-steel ratio rises. At the same time, the likelihood of new supply of iron ore from West Africa has increased. This implies that it will be even more important to create competitive advantage and to grow value through driving exceptional operational performance. In the long-term, prices are expected to be determined by high cost production, on a value-in-use adjusted basis, from Australia or Brazil. Quality differentiation will remain a factor in determining iron ore prices.

Metallurgical coal prices have weakened markedly. A steep, COVID-19 induced decline in ex-China demand, which normally comprises around four-fifths of the seaborne trade, has been the major factor in driving the lower prices. Metallurgical coal faces a difficult and uncertain period as major importing regions manage their re-openings over the first half of the financial year. COVID-19 permitting, a sustained improvement in prices is possible in the second half of the 2021 financial year. We believe that a wholesale shift away from blast furnace steel making, which depends on metallurgical coal, is still decades in the future. This is due to the existing capital stock of blast furnace steel making capacity (70 per cent of global capacity today, average fleet age of around 10 - 12 years in China and around 18 years in India), and the high cost of large scale switching to alternative iron and steel making technologies, which in many cases are still in the early stage of their technological development. Over time, premium quality coking coals are expected to be particularly advantaged given the drive by steel makers to improve blast furnace productivity, partly to reduce emissions intensity. Demand for seaborne Hard Coking Coals (HCC) is expected to grow alongside the growth of the steel industry in HCC importing countries such as India, and increasing market share in China for large, integrated mills situated in the major demand centres on the coast. There is a developing mismatch between the expected evolution of customer demand and the cost-competitive growth options available to the supply side of the industry, which are skewed towards lower quality coals. As a result, we view the medium to long-term fundamentals for higher quality metallurgical coals as attractive.

14

Energy coal prices are particularly challenged, with prices recently falling below the levels reached during the 2015/16 downturn. Around two-thirds of seaborne supply is estimated to be earning negative margins at such price levels. An uplift in power demand across developed Asia as re-starts progress might help to stabilise the market. China's policy in respect of energy coal imports remains a key uncertainty. Longer-term, we expect total primary energy derived from coal (power and non-power) to expand at a compound rate slower than that of global population growth. Coal power is expected to progressively lose competitiveness to unsubsidised renewables on a new build basis in the developed world and in China. However, coal power is expected to retain competitiveness in India (where the coal fleet is only around 10 years old on average) and other populous, low income emerging markets, for a much longer time. Large, low cost mines supplying energy coal to seaborne markets will continue to be able to generate decent margins.

Copper prices fell sharply in the early stages of the COVID-19 pandemic but have since rebounded, first on improving sentiment towards pro-growth assets, and more recently on news of COVID-19 related supply-side challenges. In the medium term we believe that the effect of the pandemic will be to delay the timing of the anticipated structural deficit for copper by one or two years to the mid to late 2020s. Longer term, end-use demand is expected to be solid, while broad exposure to the electrification mega-trend offers attractive upside. Our view is that the price setting marginal tonne a decade from now will come from either a lower grade brownfield expansion in a lower risk jurisdiction, or a higher grade greenfield project in a higher risk jurisdiction. Prices will rise on the back of grade decline, resource depletion, increased input costs, water constraints and a scarcity of high quality future development opportunities after a poor decade for industry-wide exploration.

Nickel prices have been driven by the swings in macro-economic sentiment that have also influenced other base metals. Longer term, we believe that nickel will be a substantial beneficiary of the global electrification mega-trend and that nickel sulphides will be particularly attractive given the relatively lower cost of production of battery-suitable class-1 nickel than for laterites, which will set the long-run nickel price. This view is supported by our assessment of the likely rate of growth in electric vehicles and of the likely battery chemistry that will underpin this.

Crude oil prices experienced unprecedented volatility in the second half of the 2020 financial year. We believe that the most significant risks to the physical market have now passed. Prices may well build upon their recent recovery, if mobility continues to improve globally. The pace of gains though could be modest given potential headwinds from supply returning, whether that is re-started primary production or releases from storage. However, if we look beyond this, our bottom-up analysis of demand, allied to systematic field decline rates, points to a structural demand-supply gap through at least the mid-2030s. Considerable investment in conventional oil is going to be required to fill that gap. The medium to long term supply deficit has been amplified by the global retreat from capital spending across the industry in response to the COVID-19 pandemic. Specifically on demand, road transport is subject to clear disruption risk, while non-transport demand looks resilient, especially in the developing world. Behavioural changes post COVID-19 are another factor we consider. The net impact of these trends is likely to be a steady erosion of total demand beyond the plateau we expect in the medium-term. Deepwater assets are the most likely major supply segment to balance the market in the longer term. The price expectation required to trigger investment in deepwater projects will be significantly higher than the prices we face today. We believe oil will be an attractive commodity, even under a plausible low case, for a considerable time to come.

15

The Japan-Korea Marker price for LNG performed poorly in the second half of the 2020 financial year. Demand is expected to be firmer in the new financial year, but storage levels are very high. Longer term, the commodity offers a combination of systematic base decline and an attractive demand trajectory. However, gas resource is abundant and liquefaction infrastructure comes with large upfront costs and extended pay backs. North American exports are expected to provide the marginal supply across multiple longer term scenarios for the LNG industry, with new supply likely to be required to balance the market in the middle of this decade, or slightly later. Within global gas, LNG is expected to gain share. Against this backdrop, LNG assets advantaged by their proximity to existing infrastructure or customers, or both, will be attractive.

Potash stands to benefit from the intersection of a number of global megatrends: rising population, changing diets and the need for the sustainable intensification of agriculture. We anticipate trend demand growth of 1.5 to 2.0 Mt per year (between two and three per cent per annum) through the 2020s. This would progressively absorb the excess capacity currently present in the industry, with the window for new supply expected to be open by the late 2020s or early 2030s.

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

Our strategy is to have the best assets in the best commodities, run with the best capabilities. Our existing portfolio is built upon an industry leading set of large, low cost, expandable resource bases. We have exposure to large, growing commodities, which enable low cost assets to generate attractive and consistent returns.

However, the world is rapidly changing with decarbonisation of energy sources, population growth and the drive for higher living standards in the developing world key drivers in the future. Our diversified portfolio is resilient under different long-term scenarios but we are constantly considering ways to further strengthen it for the near, medium and long term. We must continue to generate excellent and growing returns for shareholders in this changing world. We have successfully undertaken a series of steps to simplify and strengthen our portfolio over the recent past. To ensure that we mitigate the risks that this changing world presents and take advantage of the many opportunities to grow value, it will require us to continue to be active portfolio managers.

Even against the backdrop of the decarbonisation of the global economy, metallurgical coal will remain an essential input into the steel-making process for a long time yet(iv). However, as steel makers seek to reduce their carbon intensity of production, we anticipate that markets will evolve to place an even higher relative value on higher quality HCC that increase blast furnace productivity and reduce emissions intensity of steel production.

BHP has the world's leading portfolio of metallurgical coal assets. The majority of our mines produce HCC coals and are owned via our 50 per cent share of the BHP Mitsubishi Alliance (BMA) joint venture. We also own 80 per cent of the BHP Mitsui Coal (BMC) joint venture which is comprised of low cost mines but which produce lower quality coals. Our energy coal exposure comprises a very small portion of our overall asset portfolio (approximately three per cent of our net asset base). We own two assets, a 100 per cent share of the New South Wales Energy Coal asset and a 33.3 per cent stake in the independently operated Cerrejón mine in Colombia.

We will pursue options to divest our interests in BMC, NSWEC and Cerrejón. These are large-scale and long life assets. They produce good cash flow through-the-cycle and have the potential for value growth, including through productivity driven volume growth, further cost reductions and embedded expansion options. Given our focus on HCC, these assets would better compete for capital outside of BHP. We will look to maximise the value of these assets, including via a demerger of an independent, listed company and trade sale opportunities.

16

We will, across the whole portfolio of our metallurgical coal mines, continue to grow value through a focus on lowering costs and productivity related volume growth from our existing mines, where the market opportunity warrants it. We do not intend to invest significant growth capital in new capacity in this business.

As set out in the outlook section above, we believe oil will be an attractive commodity for a considerable time period to come. We believe gas, where advantaged by infrastructure and proximity to market, also has attractive fundamentals for high quality assets. Gas has the more resilient demand profile while oil has the steeper cost curve, driven by complex and diverse geology. Ongoing field decline (at least three per cent per annum) in existing producing oil and gas assets is an important underpin to each market.

Our producing petroleum assets in Australia, the Gulf of Mexico and in Trinidad and Tobago enjoy low cash break-evens and deliver high EBITDA margins. Beyond our producing assets we continue to progress development of sanctioned and unsanctioned high return growth projects, with competitive break even prices. While our strict capital discipline ensures all investments are resilient to low points in the commodity cycle, we also recognise the potential for price upside over the medium term given the global slowdown in development activity, and we are well positioned to participate in that upside.

We continue to optimise our petroleum portfolio through the exit of later life assets, including an intended exit from Bass Strait, and farm-downs of the longer dated options. In addition, we will explore potential targeted counter-cyclical acquisitions in producing or near producing high quality assets, with each opportunity tested against our strict Capital Allocation Framework. Our exploration and appraisal work program will test prospective acreage in basins we understand well in the Gulf of Mexico and Trinidad and Tobago South, as well as progress the appraisal and development studies of the Trinidad and Tobago Northern gas discovery.

Creating and securing more options in future-facing commodities remains a priority. Copper, nickel and potash demand is expected to expand faster than for many other commodities, given their exposure to mega-trends of decarbonisation, electrification, diet, land use and population. We intend to increase our options in these through a focus on technical innovation, to help unlock further options within our existing resources, as well as through exploration and early-stage entry.

We have made good progress. In copper, we have added to our options through partnering with junior companies in Canada, Mexico and Ecuador. The third phase of drilling at the Oak Dam copper discovery was completed in June 2020, taking the total area drilled to over 21 thousand metres, and we are currently analysing the results. In nickel, we have expanded our footprint, with the acquisition of the Honeymoon Well nickel tenements. In potash, we have progressed the Jansen project, further de-risking the option, as we focus on getting it ready to present to the Board for a Final Investment Decision in the middle of the 2021 calendar year.

Through the combination of continuing to drive exceptional operational performance, creating and securing more options in future facing commodities and applying our disciplined approach to capital allocation, we will continue to reliably grow value and returns for decades to come.

17

Underlying attributable profit and Underlying EBITDA are presented below.

(1) Refer to page 17 and to note 2 Exceptional items and note 8 Significant events - Samarco dam failure of the Financial Information for further information.

(1) Exceptional items loss of US$1,453 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 8 Significant events - Samarco dam failure of the Financial Information for further information.

(2) Relates to an impairment charge in relation to Cerro Colorado. Refer to page 17 and to note 2 Exceptional items.

18

The following table and commentary describes the impact of the principal factors(i) that affected Underlying EBITDA for the 2020 financial year compared with the 2019 financial year:

(1) Closure and rehabilitation provision for closed mines adjustment charge to the income statement of US$612 million (FY19: US$250 million).

19

The average realised prices achieved for our major commodities are summarised in the following table and are presented on a continuing operations basis:

(1) Based on provisional, unaudited estimates. Prices exclude sales from equity accounted investments, third party product and internal sales, and represent the weighted average of various sales terms (for example: FOB, CIF and CFR), unless otherwise noted. Includes the impact of provisional pricing and finalisation adjustments.

(2) Includes internal sales.

(3) Hard coking coal (HCC) refers generally to those metallurgical coals with a Coke Strength after Reaction (CSR) of 35 and above, which includes coals across the spectrum from Premium Coking to Semi Hard Coking coals, while weak coking coal (WCC) refers generally to those metallurgical coals with a CSR below 35.

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

In Copper, the provisional pricing and finalisation adjustments increased Underlying EBITDA by US$125 million in the 2020 financial year and is 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:

(1) Displayed as US$ to A$1 based on common convention.

Depreciation, amortisation and impairments increased by US$513 million to US$6.6 billion. This increase reflected depreciation of right-of-use assets from the application of IFRS 16 Leases of US$656 million and higher impairment charges mainly in relation to the Cerro Colorado exceptional impairment charge, offset by lower depreciation and amortisation at Petroleum in line with lower production volumes and lower depreciation at Escondida and WAIO.

Net finance costs decreased by US$153 million to US$911 million largely reflecting the benefit from lower interest rates on a lower average debt balance (following the repayment on maturity of Group debt). This was partially offset by an additional interest expense recognised on the application of IFRS 16 Leases of US$44 million.

20

(1) Refer exceptional items below for further details.

The Group's adjusted effective tax rate, which excludes the impact of exchange rate movements and exceptional items, was 33.2 per cent (2019: 36.0 per cent). The adjusted effective tax rate is above 30 per cent primarily due to profits being subject to rates of tax higher than 30 per cent (for example, petroleum projects in Australia, Algeria and Trinidad and Tobago and withholding tax on dividends from Escondida, Pampa Norte, Antamina and Cerrejón). The adjusted effective tax rate is lower than at 30 June 2019 primarily as the prior year was impacted by provisions for tax disputes and a higher net reduction in US tax credits related to Chilean taxes, combined with lower Australian Petroleum Resource Rent Tax in the current year. The adjusted effective tax rate is expected to be in the range of 32 to 37 per cent for the 2021 financial year.

Other royalty and excise arrangements which are not profit based are recognised as operating costs within Profit before taxation. These amounted to US$2.4 billion during the period (2019: US$2.5 billion).

On 11 March 2020, the Australian High Court ruled that BHP Group Limited and BHP Group Plc are 'associates' under the Controlled Foreign Companies rules and therefore profits earned globally by BHP's Sales and Marketing organisation from the sale of commodities acquired from Australian subsidiaries of BHP Group Plc are subject to 'top‑up tax' in Australia at the corporate tax rate of 30 per cent. As a result of this ruling, BHP paid approximately US$115 million in additional taxes for the prior years, being 2006 to 2019, with US$32 million paid in prior periods and US$83 million paid in the 2020 financial year.

The following table sets out the exceptional items for the 2020 financial year. Additional commentary is included on page 41.

(1) Refer to note 2 Exceptional items and note 8 Significant events - Samarco dam failure of the Financial Information for further information.

21

Net debt increased by US$2.6 billion during the 2020 financial year:

(1) Vessel lease contracts are included in total interest bearing liabilities, however as of 1 January 2020 these contracts have been excluded from net debt as they do not align with how the Group assesses net debt for decision making in relation to the Capital Allocation Framework.

During the 2020 financial year, total interest bearing liabilities increased from US$24.8 billion at 30 June 2019 to US$27.0 billion at 30 June 2020. This reflects a US$1.6 billion impact from new leases and a US$1.2 billion impact from vessel lease contracts that are priced with reference to a freight index (totalling US$2.8 billion) from the application of IFRS 16 Leases, and a fair value adjustment of US$0.4 billion related to interest rate and exchange movements, partially offset by the redemption of US$0.9 billion of bonds (consisting of an A$1 billion bond and the remaining amount of the €600 million bond that matured).

At the subsidiary level, Escondida refinanced US$0.5 billion of maturing long-term debt.

The Group has a US$5.5 billion commercial paper program backed by a US$5.5 billion revolving credit facility, which expires in October 2024. As at 30 June 2020, the Group had no outstanding US commercial paper, no drawn amount under the revolving credit facility and US$13.4 billion in cash and cash equivalents.

Our Board today determined to pay a final dividend of 55 US cents per share. The final 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 final dividend. Full terms and conditions of the DRP and details about how to participate can be found at: bhp.com

22

BHP Group Plc shareholders registered on the South African section of the register will not be able to dematerialise or rematerialise their shareholdings between the dates of 2 and 4 September 2020 (inclusive), and transfers between the UK register and the South African register will not be permitted between the dates of 28 August and 4 September 2020 (inclusive). American Depositary Shares (ADSs) each represent two fully paid ordinary shares and receive dividends accordingly. Details of the currency exchange rates applicable for the dividend will be announced to the relevant stock exchanges following conversion and will appear on the Group's website.

Any eligible shareholder who wishes to participate in the DRP, or to vary a participation election should do so in accordance with the timetable above, or, in the case of shareholdings on the South African branch register of BHP Group Plc, in accordance with the instructions of your CSDP. The DRP Allocation Price will be calculated in each jurisdiction as an average of the price paid for all shares actually purchased to satisfy DRP elections. The Allocation Price applicable to each exchange will made available at: bhp.com/DRP

CEO Mike Henry has today announced new roles and appointments on the Executive Leadership Team (ELT). Ragnar Udd will become President Minerals Americas, effective 1 November 2020, replacing Daniel Malchuk. Mr Malchuk will continue in the role until that time, and leave BHP at the end of the 2020 calendar year. Laura Tyler will commence in the new role of Chief Technical Officer on 1 September 2020. This role will be an expansion of her current position on the ELT as Chief Geoscientist. She will relinquish her concurrent role as Asset President Olympic Dam. Caroline Cox will become Chief External Affairs Officer, effective 1 November 2020, replacing Geoff Healy. Mr Healy will continue in the role until that time, and leave BHP at the end of the 2020 calendar year. Johan van Jaarsveld will commence in the new role of Chief Development Officer on 1 September 2020.

On 17 June 2020, we announced that Peter Beaven would step down as the CFO with effect from 30 November 2020, and the appointment of David Lamont as the CFO from 1 December 2020.

Rachel Agnew will resign as Company Secretary of BHP Group Limited and BHP Group Plc, effective 1 September 2020.

Gary Goldberg and Dion Weisler, who joined the Board in recent months, and Xiaoqun Clever, who joins the Board effective 1 October 2020, will stand for election for the first time at the 2020 BHP Annual General Meetings (AGMs).

As previously announced in January this year, Lindsay Maxsted will not stand for re-election at the AGMs. Mr Maxsted has informed the Board of his intention to retire as a Director with effect from 4 September 2020, having completed the handover of the Risk and Audit Committee Chairman position to Terry Bowen, and seen through the Group's FY20 financial reporting schedule.

Shriti Vadera, who as previously announced will not stand for re-election at the 2020 AGMs, intends to remain a Director until the conclusion of the BHP Group Plc AGM on 15 October 2020.

23

The current members of the Board's committees are:

(1) Senior Independent Director (SID).

Segment summary(1)

A summary of performance for the 2020 and 2019 financial years is presented below.

(1) Group and segment level information is reported on a statutory basis which reflects the application of the equity accounting method in preparing the Group financial statements - in accordance with IFRS. Underlying EBITDA of the Group and the reportable segments, includes depreciation, amortisation and impairments (D&A), net finance costs and taxation expense of US$446 million (2019: US$505 million) related to equity accounted investments. It excludes exceptional items loss of US$508 million (2019: US$945 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$7,650 million (2019: US$7,045 million) and net finance costs of US$911 million (2019: US$1,064 million).

(2) Revenue is based on Group realised prices and includes third party products. Sale of third party products by the Group contributed revenue of US$1,171 million and Underlying EBITDA of US$32 million (2019: US$1,198 million and US$129 million).

(3) For more information on the reconciliation of certain alternative performance measures to our statutory measures, reasons for usefulness and calculation methodology, please refer to alternative performance measures set on pages 51 and 62.

(4) Exceptional items loss of US$1,453 million excludes net finance costs of US$93 million included in the total loss before taxation of US$176 million related to the Samarco dam failure. Refer to note 2 Exceptional items and note 8 Significant events - Samarco dam failure of the Financial Information for further information.

(5) Includes US$223 million capitalised exploration (2019: US$357 million).

(6) Includes US$ nil of exploration expenditure previously capitalised, written off as impaired (included in depreciation and amortisation) (2019: US$21 million).

(7) Group and unallocated items includes functions, other unallocated operations including Potash, Nickel West and legacy assets (previously disclosed as closed mines in the Petroleum reportable segment), and consolidation adjustments. Comparative information for the year ended 30 June 2019 have been restated to reflect the inclusion of legacy assets in Group and unallocated items. 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.

24

(8) Comprises revenue of US$62 million generated by Petroleum (2019: US$77 million), US$1 million generated by Coal (2019: US$ nil) and US$ nil generated by Iron Ore (2019: US$4 million).

Underlying EBITDA for Petroleum decreased by US$1.9 billion to US$2.2 billion in the 2020 financial year.

Petroleum unit costs decreased by eight per cent to US$9.74 per barrel of oil equivalent due to a reduction in price- linked costs, cost efficiencies and lower maintenance activities at our Australian operations due to COVID-19, partially offset by lower volumes. Unit costs in the 2021 financial year are expected to be between US$11 and US$12 per barrel (based on an exchange rate of AUD/USD 0.70) reflecting the impact of lower volumes and forecast lower price-linked costs. In the medium term, we expect an increase in unit costs to less than US$13 per barrel (based on an exchange rate of AUD/USD 0.70) primarily as a result of natural field decline.

25

(1) Other includes non-cash profit on sales of assets, inventory movements, foreign exchange, provision for onerous lease contracts and the impact from revaluation of embedded derivatives in the Trinidad and Tobago gas contract.

(2) FY20 based on an exchange rate of AUD/USD 0.67.

Given the significant petroleum price volatility in the 2020 financial year and the potential impact of climate change on long term petroleum prices, the Group considered a range of long term price assumptions, including oil prices (Brent) at US$55 a barrel, when determining that no indicators of impairment of accounting carrying values existed at 30 June 2020.

As previously announced, in light of the significant disruption to oil and gas markets we have reviewed our investment program for the next 12 months. Petroleum capital and exploration expenditure of approximately US$1.6 billion is now planned in the 2021 financial year as a result of a delay of the Scarborough gas development and several small and medium sized projects, and an approximately US$250 million reduction in our exploration and appraisal program. These delays will maximise the value of the projects by ensuring that production will commence at a time when we expect prices to be higher. Reflecting these changes in our plans as well as natural field decline, production is expected to average approximately 104 MMboe over the next five years, with lower volumes now also expected at the end of the five year period as a result of the delay of the Scarborough gas development.

Petroleum exploration

Petroleum exploration expenditure for the 2020 financial year was US$564 million, of which US$394 million was expensed. An approximately US$450 million exploration and appraisal program is planned for the 2021 financial year. This is a reduction of approximately US$250 million to our medium-term program, and as a result, our focus will be on delivering the highest priority opportunities in the portfolio and our licence commitments. The 2021 financial year exploration and appraisal program includes the Broadside exploration well in our Trinidad and Tobago Southern licences, preparation for exploration drilling in our Green Canyon blocks in the US Gulf of Mexico and appraisal planning in our Trinidad and Tobago Northern licences. Our planned activities are subject to any further COVID-19 delays.

In Trinidad and Tobago, we drilled two exploration wells in our Northern licences and completed Phase 4 of our deepwater drilling campaign in the first half of the 2020 financial year. The campaign included two wells; Boom-1(v) encountered hydrocarbons and Carnival-1(v) was a dry hole. Technical work is ongoing to evaluate an appraisal program, development planning and commercial options for the discoveries in the Northern Gas play.

In Barbados, the offshore exploration licences for the Carlisle Bay and Bimshire blocks were declared effective as of 27 January 2020. The first exploration phase is a three-year program with commitment of seismic data.

26

In the US Gulf of Mexico, we expanded our acreage positions through lease sale participation. In the 2020 financial year, the Regulator awarded two blocks (vi) in Green Canyon, central Gulf of Mexico and 19 blocks(vii) in the western Gulf of Mexico. In July 2020, the Regulator awarded two blocks(viii) in Green Canyon, central Gulf of Mexico and three blocks(ix) in the western Gulf of Mexico. In the western US Gulf of Mexico, the final processed data from the Ocean Bottom Node(x) seismic acquisition was received in April 2020 and technical work is ongoing to inform the exploration program. We continue to advance evaluation of options to optimise value at Wildling through progressive development of the discovery. Different options for the development concept are under review, including a tieback to the Shenzi facility.

In Mexico, we drilled the Trion 3DEL appraisal well(v) in the first half of the 2020 financial year where we encountered oil in the reservoirs up dip from all previous well intersections. The results provided greater confidence around the scale, and quality, of the resource and we now have sufficient information to underpin development planning.

In Eastern Canada, technical evaluation is ongoing on our two licences in the Orphan Basin to support exploration well planning.

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

27

(1) Total Petroleum statutory result revenue includes: crude oil US$2,033 million (2019: US$3,171 million), natural gas US$980 million (2019: US$1,259 million), LNG US$774 million (2019: US$1,179 million), NGL US$198 million (2019: US$263 million) and other US$85 million (2019: US$58 million) which includes third party products.

(2) Includes US$170 million of capitalised exploration (2019: US$297 million).

(3) Includes US$ nil of exploration expenditure previously capitalised, written off as impaired (included in depreciation and amortisation) (2019: US$21 million).

(4) Australia Production Unit includes Macedon, Pyrenees and Minerva.

(5) Predominantly divisional activities, business development, UK (divested in November 2018), Neptune and Genesis. Also includes the Caesar oil pipeline and the Cleopatra gas pipeline, which are equity accounted investments. The financial information for the Caesar oil pipeline and the Cleopatra gas pipeline presented above, with the exception of net operating assets, reflects BHP's share.

(6) Total Petroleum statutory result revenue excludes US$16 million (2019: US$17 million) revenue related to the Caesar oil pipeline and the Cleopatra gas pipeline. Total Petroleum statutory result Underlying EBITDA includes US$3 million (2019: US$2 million) D&A related to the Caesar oil pipeline and the Cleopatra gas pipeline.

Underlying EBITDA for the 2020 financial year decreased by US$203 million to US$4.3 billion.

Escondida unit costs decreased by 11 per cent to US$1.01 per pound, reflecting record concentrator throughput, strong cost management and favourable inventory and exchange rate movements. This decrease was achieved despite the impact of a three per cent decline in copper grade, lower by-product credits, higher desalinated water costs and higher deferred stripping costs.

28

Unit costs in the 2021 financial year are expected to be between US$1.00 and US$1.25 per pound (based on an exchange rate of USD/CLP 769), reflecting lower volumes as a result of a reduced operational workforce due to COVID-19 and a further decline in concentrator feed grade of approximately four per cent. This will be partially offset by lower stripping costs. In the medium term, unit costs have been revised to less than US$1.10 per pound reflecting updated guidance exchange rates (based on an exchange rate of USD/CLP 769), with expected higher power consumption and water costs offset by further operational efficiency improvements and optimised maintenance strategies.

(1) FY20 based on an average exchange rate USD/CLP 711.

(2) FY20 excludes COVID-19 related costs of US$0.01 per pound that are reported as exceptional items.

Escondida eliminated water drawdown from aquifers for operational supply, 10 years ahead of its 2030 target, with the completion of the Escondida Water Supply Expansion project in December 2019 (which increased total desalinated water capacity to 3,800 litres per second) and an increase of approximately five per cent in water consumption efficiency achieved on the prior year through increased concentrator stability. Escondida has invested more than US$4 billion in desalinated water since 2006.

In October 2019, we announced four new renewable power contracts for Escondida and Spence that will replace existing contracts. The new contracts will commence in the 2022 financial year and will increase flexibility for our power portfolio and ensure security of supply for our operations. We aim to supply Escondida and Spence's energy requirements from 100 per cent renewable energy sources from the mid-2020s. These contracts will deliver an estimated 20 per cent reduction in energy prices at both operations and will be value accretive even including a provision of US$778 million (pre-tax) related to the cancellation of the existing contracts.

Financial information for Copper for the 2020 and 2019 financial years is presented below.

29

(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 (acquired in October 2018).

(5) Total Copper statutory result revenue excludes US$832 million (2019: US$1,144 million) revenue related to Antamina. Total Copper statutory result Underlying EBITDA includes US$165 million (2019: US$110 million) D&A and US$141 million (2019: US$222 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$205 million (2019: US$229 million) related to Antamina and US$ nil (2019: US$1 million) related to SolGold. Exploration gross excludes US$8 million (2019: US$4 million) related to SolGold of which US$3 million (2019: US$3 million) was expensed.

Underlying EBITDA for the 2020 financial year increased by US$3.4 billion to US$14.6 billion.

30

WAIO unit costs declined by 11 per cent to US$12.63 per tonne (or US$11.82 per tonne on a C1 basis excluding third party royalties(3)), reflecting record volumes following strong performance and continued productivity improvements across the supply chain, and favourable exchange movements. Costs related to the impact from COVID-19 are reported as an exceptional item and are not included in unit costs. These additional costs were approximately US$0.30 per tonne, bringing WAIO unit costs to a total of US$12.93 per tonne (or US$12.08 per tonne on a C1 basis excluding third party royalties(3)). A record annualised production run rate of above 300 Mt (100 per cent basis) was achieved during the June 2020 quarter and supported unit costs on a C1 basis of US$10.96 per tonne in the second half of the 2020 financial year.

Unit costs in the 2021 financial year are expected to be between US$13 and US$14 per tonne (based on an exchange rate of AUD/USD 0.70). In the medium term, we expect to lower our unit costs to less than US$13 per tonne (based on an exchange rate of AUD/USD 0.70).

(1) FY20 based on an average exchange rate of AUD/USD 0.67.

(2) FY20 excludes COVID-19 related costs of US$0.30 per tonne (including US$0.04 per tonne of demurrage) that are reported as exceptional items.

(3) Excludes third party royalties of US$1.17 per tonne (2019: US$1.00 per tonne), depletion of production stripping US$0.63 (2019: US$0.75), net inventory movements US$ (0.61) per tonne (2019: US$(0.30) per tonne), exploration expenses, demurrage, exchange rate gains/losses, and other income US$(0.38) per tonne (2019: US$(0.15) per tonne).

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

31

(1) Includes US$40 million of capitalised exploration (2019: US$52 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.

Underlying EBITDA for the 2020 financial year decreased by US$2.4 billion to US$1.6 billion.

Queensland Coal unit costs decreased by three per cent to US$68 per tonne due to a build in inventory, as a result of solid dragline performance across the majority of operations, and favourable impacts from exchange rate movements and the application of IFRS 16 Leases. This was partially offset by lower volumes due to significant wet weather during the March 2020 quarter and planned maintenance.

32

Unit costs in the 2021 financial year are expected to be between US$69 and US$75 per tonne (based on an exchange rate of AUD/USD 0.70) as a result of higher strip ratios, increased contractor stripping costs and tailings and risk spend, partially offset by higher volumes and improved productivity. In the medium term, we now expect our unit costs to between US$58 and US$66 per tonne (based on an exchange rate of AUD/USD 0.70), up from between US$54 and US$61 per tonne, as this reflects reduced volumes due to a focus on higher quality coals and a market responsive approach to bringing new tonnes into the markets. Reflecting these changes to our plans, we now expect production of between 46 and 52 Mt over the medium-term.