6-K 1 d885574d6k.htm FORM 6-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 6-K

REPORT OF FOREIGN PRIVATE ISSUER

PURSUANT TO RULE 13a-16 OR 15d-16

UNDER THE SECURITIES EXCHANGE ACT OF 1934

February 18, 2020

BHP GROUP LIMITED (ABN 49 004 028 077) (Exact name of Registrant as specified in its charter) VICTORIA, AUSTRALIA (Jurisdiction of incorporation or organisation) 171 COLLINS STREET, MELBOURNE, VICTORIA 3000 AUSTRALIA (Address of principal executive offices) |  | BHP GROUP PLC (REG. NO. 3196209) (Exact name of Registrant as specified in its charter) ENGLAND AND WALES (Jurisdiction of incorporation or organisation) NOVA SOUTH, 160 VICTORIA STREET LONDON, SW1E 5LB UNITED KINGDOM (Address of principal executive offices)

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or

Form 40-F: ☒ Form 20-F ☐ Form 40-F

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): ☐

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): ☐

Indicate by check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934: ☐ Yes ☒ No

If “Yes” is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b): n/a

18 February 2020

To: | Australian Securities Exchange

New York Stock Exchange

RESULTS PRESENTATION FOR HALF YEAR ENDED 31 DECEMBER 2019

Attached are the presentation slides for a presentation by the Chief Executive Officer and Chief Financial Officer.

A video of this presentation can be accessed at: https://edge.media-server.com/mmc/p/sy99rvwq

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

Authorised for lodgement by:

Rachel Agnew

Company Secretary

+61 3 9609 3333

BHP Group Limited ABN 49 004 028 077 |  | BHP Group Plc Registration number 3196209
LEI WZE1WSENV6JSZFK0JC28 |  | LEI 549300C116EOWV835768
Registered in Australia |  | Registered in England and Wales
Registered Office: Level 18, 171 Collins Street |  | Registered Office: Nova South, 160 Victoria Street,
Melbourne Victoria 3000 |  | London SW1E 5LB United Kingdom
Tel +61 1300 55 4757 Fax +61 3 9609 3015 |  | Tel +44 20 7802 4000 Fax +44 20 7802 4111

The BHP Group is headquartered in Australia

Financial results Half year ended 31 December 2019 BHP

Disclaimer BHP Forward-looking statements This presentation contains forward-looking statements, including statements regarding: trends in commodity prices and currency exchange rates; demand for commodities; plans, strategies and objectives of management; closure or divestment of certain 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; tax and regulatory developments. Forward-looking statements can be identified by the use of terminology including, but not limited to, ‘intend’, ‘aim’, ‘project’, ‘anticipate’, ‘estimate’, ‘plan’, ‘believe’, ‘expect’, ‘may’, ‘should’, ‘will’, ‘continue’, ‘annualised’ or similar words. These statements discuss future expectations concerning the results of operations or financial condition, or provide other forward-looking statements. These forward-looking statements 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 presentation. Readers are cautioned not to put undue reliance on forward-looking statements. For example, future revenues from our operations, projects or mines described in this presentation 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 operations. Other factors that may affect the actual construction or production commencement dates, costs or production output and anticipated lives of operations, 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 some of the countries where we are exploring or developing these projects, facilities or mines, including increases in taxes, changes in environmental and other regulations and political uncertainty; labour unrest; and other factors identified in the risk factors discussed in BHP’s filings with the US 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, the Group does not undertake any obligation 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. Presentation of data Unless specified otherwise: variance analysis relates to the relative performance of BHP and/or its operations during the December 2019 half year compared with the December 2018 half year; operations includes operated assets and non-operated assets; total operations refers to the combination of continuing and discontinued operations; continuing operations refers to data presented excluding the impacts of South32 from the 2014 financial year onwards, and Onshore US from the 2017 financial year onwards; copper equivalent production based on 2019 financial year average realised prices; references to Underlying EBITDA margin exclude third party trading activities; data from subsidiaries are shown on a 100 per cent basis and data from equity accounted investments and other operations is presented, with the exception of net operating assets, reflecting BHP’s share; medium term refers to our five year plan. Queensland Coal comprises the BHP Mitsubishi Alliance (BMA) asset, jointly operated with Mitsubishi, and the BHP Mitsui Coal (BMC) asset, operated by BHP. Numbers presented may not add up precisely to the totals provided due to rounding. All footnote content (except in the Annexures) is contained on slide 37. Alternative performance measures We use various alternative performance measures to reflect our underlying performance. For further information please refer to alternative performance measures set out on pages 53 to 64 of the BHP Results for the half year ended 31 December 2019. No offer of securities Nothing in this presentation 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 presentation 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 presentation should not be relied upon as a recommendation or forecast by BHP. BHP and its subsidiaries In this presentation, the terms ‘BHP’, ‘Group’, ‘we’, ‘us’ and ‘our’ are used to refer to BHP Group Limited, BHP Group Plc and, except where the context otherwise requires, their respective subsidiaries set out in note 13 ‘Related undertaking of the Group’ in section 5.2 of BHP’s Annual Report on Form 20-F. Notwithstanding that this presentation may include production, financial and other information from non-operated assets, non-operated assets are not included in the Group and, as a result, statements regarding our operations, assets and values apply only to our operated assets unless otherwise stated. Our non-operated assets include Antamina, Cerrejón, Samarco, Atlantis, Mad Dog, Bass Strait and North West Shelf. Financial results 18 February 2020 2

Financial results BHP Half year ended 31 December 2019 Mike Henry Chief Executive Officer

Exceptional performance in a dynamic world BHP BHP aims to be the sector’s best operator and reliably deliver leading financial returns and social value Maintain Levers Social value Capital discipline Future Culture fit Safe Simple portfolio Capability Value and Asset-centric focus Strengthen returns Technology Safety High performing Lean Performance Capital allocation Portfolio options Financial results 18 February 2020 4

H1 FY20 financial highlights Solid operational performance and strong earnings Profitability Margin Free cash flow US$12.1 bn 56% US$3.7 bn Underlying EBITDA up 15% Underlying EBITDA margin free cash flow Net debt Shareholder returns ROCE 12.8 bn 65 US cps 19% US$ net debt payout ratio of 63% ROCE dividend determined Note: Net debt up US$3.4 bn since June 2019 (US$1.9 bn relating to IFRS 16). Financial results 18 February 2020 5

H1 FY20 operational highlights We will continue to improve safety and performance at our operations Safety Production Unit costs On track Zero fatalities Volumes stable to full year guidance TRIF â†“2%; On track to full year guidance H1 FY20: WAIO â†“10%; Escondida â†“6% High Potential Injuries1 â†‘5% Petroleum â†“14%; Queensland Coal â†‘1% GHG emissions Exploration Major projects On target Successful First production 7.3 Mt CO -e, equivalent to FY17 target Ongoing drilling program at Oak Dam at SGO and AP3 2 baseline on an annualised basis Exploration program complete at T&T North in the next 12 months Note: TRIF – Total recordable injury frequency; WAIO – Western Australia Iron Ore; T&T – Trinidad and Tobago; SGO – Spence Growth Option; AP3 – Atlantis Phase 3. Financial results 18 February 2020 6

Financial results Half year ended 31 December 2019 Peter Beaven Chief Financial Officer Trinidad and Tobago

Financial performance EBITDA margin 56% and strong earnings growth Summary income statement H1 FY20 % change (US$ billion) Underlying EBITDA Underlying EBITDA margin Underlying EBIT Adjusted effective tax rate2 Adjusted effective tax rate incl. royalties2 Underlying attributable profit Net exceptional items Attributable profit Underlying basic earnings per share (total ops.) Interim dividend per share 12.1 56% 9.0 33.4% 41.4% 5.2 (0.3) 4.9 102.6 US cps 65 US cps ï,“15%ï,“ 21%ï,“ 29% ï,“ 46% ï,“ 18% Strong earnings delivery (US cent per share) (Index, FY16=100) 200 200 150 100 100 50 0 0 FY16 FY17 FY18 FY19 H1 FY20 Underlying basic EPS (H1) Underlying basic EPS (H2) Revenue (RHS) Note: Presented on a total operations basis. Financial results 18 February 2020 8

Group EBITDA waterfall Solid underlying performance across the portfolio Underlying EBITDA variance (US$ billion) 15 External US$2.0 billion Controllable US$(0.4) billion 0.3 0.4 12.5 0.1 0.0 1.5 12.1 (0.1) (0.3) (0.2) (0.1) 10.5 10 H1 FY20 volume variance by business (US$bn) 0.0 0.1 (0.2) 0.3 (0.4) (0.3) 5 (0.2) (0.6) Petroleum Coal Copper Iron ore 0 H1 FY19 Price3 Foreign Inflation IFRS 16 Sub-total Volumes Controllable4 Fuel & Non-cash5 Other 6 H1 FY20 exchange leases cash costs energy Financial results 18 February 2020 9

Segment performance Prices and solid operational performance offset H1 planned maintenance Iron Ore8 Copper Metallurgical Coal Petroleum10 Continued unit cost Record throughput Solid underlying Delivering reduction at Escondida performance strong margins % of Group EBITDA7 60% EBITDA: US$7.1 bn EBITDA margin: 69% ROCE: 49% Unit cost: WAIO (US$/t) 15 Cost 13–14 14 Cost at FX guidance <13 13 Guidance 13.03 12 H1 FY20 FY20e MT H1 FY20 C1 costs US$12.75/t (ex. 3rd party royalties)9 Performance • H1 cost reduction reflects higher drivers: volumes and inventory build during major car dumper maintenance campaign • Volumes weighted to H2 Financial results 18 February 2020 20% US$2.4 bn 47% 9% Escondida (US$/lb) 1.20–1.35 1.40 <1.15 1.00 1.10 0.60 0.20 H1 FY20 FY20e MT • H1 improved concentrator throughput, inventory build, higher deferred stripping, prior period bonus payment • FY20 unit costs to be at lower end of range, including lower by-product credits and higher deferred stripping 10 9% US$1.1 bn 37% 13% Queensland Coal (US$/t) 80 67–74 70.66 54–61 60 40 H1 FY20 FY20e MT • H1 higher maintenance costs from planned major wash plant shutdowns • Volumes weighted to H2 13% US$1.6 bn 65% 15% Petroleum (US$/boe) 15 <13 10.5–11.5 10 9.56 5 H1 FY20 FY20e MT • H1 lower maintenance main driver on costs • FY20 field decline partially offset by strong performance in the Gulf of Mexico

Cash generation Stable operating performance, and solid free cash flow generation Net operating cash flow (US$ billion) (Index, FY10=100) 35 200 H1 FY20 movements in working capital (US$ billion) 30 1.0 0.8 (0.4) 0.0 (0.2) (0.2) (0.1) 25 (0.5) (1.0) Chile Inventory Price WAIO Petroleum Other power build related royalty R&R contracts impacts 20 100 15 10 5 0 0 FY10 FY11 FY12 FY13 FY14 FY15 FY16 FY17 FY18 FY19 HY20 Operating cash flow (H1) Operating cash flow (H2) Onshore US Revenue (RHS) Note: Presented on a total operations basis. Financial results 18 February 2020 11 BHP
Free cash flow (US$ billion) (Index, FY10=100) 25 200 20 200 15 100 10 5 0 0 200 (5) (10) (100) FY10 FY11 FY12 FY13 FY14 FY15 FY16 FY17 FY18 FY19 HY20 Free cash flow (H1) Free cash flow (H2) Onshore US proceeds Revenue (RHS) BHP

Capital allocation BHP Disciplined adherence to our Capital Allocation Framework H1 FY20 Operating Capital productivity productivity Net operating cash flow US$7.4 bn Maintenance capital US$1.0 bn Strong balance sheetïƒ¼ Minimum 50% payout ratio dividend11 US$2.7 bn Excess cash US$3.0 bn Excludes net cash outflow US$0.7 bn Additional Organic Acquisitions/ Balance sheet Buy-backs dividends11 development (Divestments) US$(1.0) bn US$1.2 bn US$0.0 bn US$2.8 bn US$(0.0) bn H2 FY19 • US$1.5 bn improvement • US$0.2 bn latent capacity • US$0.7 bn major projects • US$0.4 bn exploration Note: Excess cash includes total net cash outflow of US$0.7 billion (H1 FY19: US$0.8 billion) which comprises dividends paid to non-controlling interests of US$0.6 billion12 (H1 FY19: US$0.6 billion); net investment and funding of equity accounted investments of US$0.3 billion (H1 FY19: US$0.4 billion) and an adjustment for exploration expenses of US$(0.2) billion (H1 FY19: US$(0.2) billion) which is classified as organic development in accordance with the Capital Allocation Framework. Financial results 18 February 2020 12 BHP

Maximise value and returns Net debt US$12.8 billion at lower end of the range; since 2016 ~US$31 billion reinvested; ~US$33 billion returned to shareholders13 Net debt at lower end of target range Disciplined investment Returns to shareholders (Net debt, US$ billion) (Capital and exploration expenditure, US$ billion) (Dividends determined and share buy-backs, US$ billion) 30 9 18 ~US$17 bn Onshore US proceeds 20 6 6 Target range $12-17 bn 10 3 3 0 0 0 FY16 FY17 FY18 FY19 H1 FY20 FY16 FY17 FY18 FY19 FY20e FY21e FY16 FY17 FY18 FY19 H1 FY20 Actuals Net debt target IFRS 16 impact Actuals Guidance Minimum dividend Additional amount Note: FY19 net debt restated due to definition change. Net debt target range after IFRS 16 Leases adjustments. Capital and exploration expenditure presented on a total operations basis. Financial results 18 February 2020 13 BHP

Return on Capital Employed H1 FY20 ROCE 19%; plans to improve ROCE at every asset ROCE by asset Returns (%) (ROCE excluding Onshore US, %) 50 Excludes investment in 20 major projects in execution Antamina14 15 20 15 10 WAIO15 10 Escondida Petroleum Ex-Exploration Queensland 5 Coal Pampa 5 Norte Potash Olympic Dam 0 0 Cerrejón14, 15 FY16 FY17 FY18 FY19 HY20 NSWEC15 Actual FY17 average realised prices (5) Exploration15 0 10 20 30 40 50 60 Average capital employed (US$ billion) Note: ROCE represents annualised profit after tax excluding exceptional items and net finance costs (after tax) divided by average capital employed. Average capital employed is net assets less net debt for the last two reporting periods. Financial results 18 February 2020 14 BHP

Financial results
Half year ended 31 December 2019
Mike Henry Chief Executive Officer
BMA BHP

We have a strong foundation World class assets across the best commodities, underpinned by the Capital Allocation Framework Iron Ore Copper Metallurgical Coal Petroleum • Low cost iron ore producer • Top 3 copper producer with • Largest seaborne supplier of • Consistent high margins and high-quality deposits16 premium hard coking coal strong returns • Fe ~62% and higher lump with South Flank • Pipeline of growth options • Strong seaborne cost curve • Strong pipeline of competitive (Spence, Olympic Dam) position growth options • No new hub required for at least a decade, with >100 years of • Increased optionality through • Pipeline of opportunities to • Increased 2P + 2C resources to optionality interests in exploration reduce costs and steadily grow 3.3 Bboe18 volumes Cost performance Escondida Strong cost curve position Unit costs actively managed to offset base (C1 excluding freight and royalties, US$/t) (Production, Mt) (Index, FY15=100) (C1 Seaborne, US$/t)17 decline impacts (US$/boe) (MMboe) 14.00 1,500 200 300 20 140 13.00 750 100 150 10 125 12.00 0 0 0 0 110 FY19 HY20 FY15 FY20e MT 0% 25% 50% 75% 100% FY15 FY16 FY17 FY18 FY19 Peers range Production (LHS) Grade Cost BHP assets Unit costs Production Financial results 18 February 2020 16 BHP

Asset performance Building momentum to further unlock value; South Flank on track to CY21 first production WAIO Queensland Coal Improving supply chain reliability Improving cost performance • Car Dumper 2 major overhaul as part of port stabilisation program • Extensive planned maintenance program completed on time and on budget in H1 • Cost reductions and volume creep enabled through BOS, technology and improved maintenance strategies • Focus on improving truck and shovel productivity over the medium term to enable continuous wash plant feed South Flank progressing well (58% complete) Acceleration of improved safety and performance • All major construction contractors now mobilised to site, first modules for the stacker and reclaimer arrived in Port Hedland • Continued ramp up of Operational Services • Focus on quality: improving grade and consistency • Autonomous truck roll-out at Goonyella Riverside Continued unit cost reduction at WAIO Strip ratio headwinds to unwind over the medium term (Unit costs, US$/t) (Iron ore production, Mtpa) (US$/t) (Queensland Coal, prime to product strip ratio) 30 300 95 12 80 15 250 8 65 10 200 50 4 FY18 H1 FY19 H2 FY19 H1 FY2019 FY20e Medium FY14 FY15 FY16 FY17 FY18 FY19 H1 FY20e Medium term FY20 term Unit costs Production FY run rate Unit costs Strip ratio Financial results 18 February 2020 17 BHP

Asset performance Continuous improvement in maintenance and operating performance; throughput records at Escondida Escondida Pampa Norte Strong operating performance Continuous improvement in maintenance and operating performance • Record concentrator throughput of 367 ktpd at Escondida with further • Successful replication of recovery optimisation technology at Cerro Colorado, performance improvements to be enabled by deployment of BOS after deployment at Spence improved recoveries by 14% in two years • EWSE completed on schedule and budget, increasing Escondida total • Over the last five years, Spence throughput increased by 23% following desalinated water capacity to 3,800 l/s maintenance and operational improvements to partially offset grade decline Leap forward on sustainability Spence growth on track • Ceased water drawdown from aquifers at Escondida, 10 years ahead of target • SGO to produce first copper in H1 FY21 • Escondida and Spence targeting 100% renewable energy from mid-2020s: new • SGO to support ~300 ktpa Spence production for first four years, together with renewable power contracts to ensure security of supply and competitive costs current leaching operations Concentrator performance to offset grade decline impacts (Concentrator head grade, %) (Throughput, ktpd) Olympic Dam 1.50 500 Stabilising operations 1.00 • Multi-year asset integrity program over 50% complete 250 – Refinery crane replacement progressing well; to be completed in H2 0.50 • Continue to progress underground development of Southern Mine Area Growth options 0.00 0 FY15 FY16 FY17 FY18 FY19 FY20e FY21e FY22e FY23e FY24e • BFX continues to be evaluated Throughput Concentrator head grade Note: BOS – BHP Operating System; EWSE – Escondida Water Supply Expansion; SGO – Spence Growth Option; BFX – Brownfield Expansion Option. Financial results 18 February 2020 18 BHP

Asset performance A strong base combined with high-return projects and exploration growth opportunities Petroleum Petroleum exploration High-return options within current portfolio to offset field decline Exploration and appraisal program continues progressing well • Scarborough FID expected from mid-2020 • Deepwater Invictus rig contract extended at competitive rate • Several high-return brownfield opportunities going to FID in the next 12 months • Environmental and Social Impact Assessments approved for two offshore • Pipeline of projects to lift production in the medium term blocks in Barbados, exploration program planning underway – Mad Dog 2, Ruby and West Barracouta tracking to plan • Western GoM OBN seismic under evaluation – Atlantis Phase 3 development drilling commenced in October 2019 • Industry competitive average discovery size at low finding costs over the last – Trion development planning underway after successful 3-DEL drilling five years Substantial increase in 2C20 resources CY2020 2021 2022 2023 2024 2025 2026 2027 2028 (Net 2C resources, MMboe) Atlantis Phase 3 2,200 Mad Dog Phase 2 41 Scarborough 19 Mad Dog – Water Injection 1,800 408 Shenzi SSMPPïƒ‡70% Wildling Phase 1 222 1,400 68 T&T North 112 Trion Western GoM 1,000 Eastern Canada FY17 Production Wildling Trion T&T T&T Other FID range Unit Adds increase North South E&A First production range Explore Appraise Note: FID – Final Investment Decision; OBN – Ocean Bottom Node; Shenzi SSMPP – Shenzi Sub-Sea Multi-Phase Pumping; GoM – Gulf of Mexico. Financial results 18 February 2020 19 BHP

Investment proposition We have the assets, options, capabilities and discipline to sustainably grow long-term shareholder value and returns Maximise cash flow Capital discipline Value and returns Low-cost producer Net debt 18% ROCE targeting lower end efficiency, technology, culture of US$12-17 bn range at spot prices Volume growth <US$8 bn capex Portfolio performance, project delivery in FY20 and ~US$8 bn in FY21 creating and securing options Constructive outlook Organic opportunities Shareholder returns for our commodities, rich option set across commodities US$3.3 bn dividends solid demand, disciplined supply and time periods assessed on risk determined in H1 and return metrics Note: Details on change in net target debt range provided on slide 27. Spot prices as of 4 February 2020. Financial results 18 February 2020 20 BHP

Exceptional performance in a dynamic world BHP aims to be the sector’s best operator and reliably deliver leading financial returns and social value Maintain Social Value Capital discipline Simple portfolio Strengthen Safety Performance Portfolio options Future fit safe high performing safe lean value and returns levers culture capability asset-centric focus technology capital allocation Future Safe fit Value and returns High performing Lean Financial results 18 February 2020 21 BHP

Bhp

Appendix Bhp

Safety and sustainability We transparently track our performance on our social value commitments and we are making good progress Category Key indicators H1 FY20 H2 FY19 H1 FY19 FY19 Target Fatalities1 0 0 1 1 Zero work-related fatalities High Potential Injury (HPI) rate Safety & Health 0.32 0.33 0.28 0.31 Year-on-year improvement of our HPI rate (per million hours worked)1 Total Recordable Injury Frequency (TRIF) 4.6 5.0 4.3 4.7 Year-on-year improvement of our TRIF (per million hours worked)1 Operational greenhouse gas (GHG) emissions 7.3 7.1 7.2 14.32 Maintain FY22 operational GHG emissions (Mt CO2-e) at or below FY17 levels3 Environment Fresh water withdrawals (GL) 75.0 78.5 77.0 155.5 Reduce FY22 fresh water withdrawal by 15 per cent from FY17 levels4 No less than one per cent of pre-tax profit Community Social investment (US$m)1 29.8 78.4 15.1 93.5 (three-year rolling average) Aspirational goal for gender balance by Inclusion & Diversity Female workforce participation (%)1 24.8 24.5 23.3 24.5 CY2025 Work is progressing on the implementation of the climate change initiatives announced in July 2019, including the setting of Scope 3 emissions goals, a science-based target for Scope 1 and 2 emissions to set the trajectory towards our longer term goal of net-zero operational emissions, the US$400 million Climate Investment Program, updating our climate portfolio analysis, and clarifying and strengthening the link between performance against emissions targets and BHP’s executive pay plans. We will provide an update later in the 2020 calendar year. Notes: 1. Presented on a total operations basis. 2. FY19 operational GHG emissions has been adjusted; previously reported as 14.2 Mt. 3. In FY17, our operational GHG emissions were 14.6 Mt CO2-e (excluding Onshore US). 4. In FY17, our fresh water withdrawals were 157.3 GL (on an adjusted basis, excluding Onshore US). Financial results 18 February 2020 24 BHP

Samarco and Renova Foundation Resettlement remains a priority social program Rehabilitation Compensation Samarco restart (Renova Foundation) (Renova Foundation) Communities • BRL$2.3 billion indemnification and • Received LOC (Corrective Operating financial aid paid to December 2019 Licence)—key licence required to progress • Paracatu: 60 of 116 house designs to restart with one concentrator • More than 9,500 general damages claims completed in collaboration with families, resolved some construction permits for them issued • Works for construction of filtration plant • 14,400 families continue to receive income underway, with plant foundation completed • Bento Rodrigues: Construction of support through emergency financial aid in December 2019 healthcare centre, public school and houses underway • Plan to restart after the filtration plant completion, all safety requirements are met • Gesteira: urban plan being discussed with and final Samarco shareholders’ approval community is received River recovery • Decommissioning plan for the two upstream dams in the Germano complex • Removal of Linhares barrier in the ongoing; expected start during Q2 CY20 Pequeno River, allowing free flow of water between the river and the Juparanã lake Note: Germano decommissioning start date subject to shareholder approval. Financial results 18 February 2020 25 BHP

Market outlook Near-term uncertainty, attractive medium-term fundamentals, long run strategic themes Short term Medium term Long term Growth in Policy Demand Steeper Electrification New supply population, uncertainty uncertainty cost curves of transport wealth Sentiment Prudently Sustainable Emerging Decarbonisation Biosphere mixed cautious productivity Asia of power stewardship Note: Further information on BHP’s economic and commodity outlook can be found at www.bhp.com/prospects. Financial results 18 February 2020 26 BHP

Working capital and balance sheet Net debt of US$12.8 billion and gearing of 19.7% Movements in working capital Debt maturity profile3 (US$ billion) (US$ billion) Price impact on 1.0 0.8 Includes employee provision 8 receivables and movements, timing of operational royalties payables payments and embedded (0.4) derivative movements 0.0 (0.2) (0.2) 6 (0.1) Split broadly between increasing operational stability and maintenance (0.5) (1.0) Chile Inventory Price WAIO Petroleum Other 4 power build related royalty R&R contracts impacts Movements in net debt (US$ billion) 20 2 Application of IFRS 16 15 0.6 0.7 12.8 2.3 3.9 0.2 9.4 0 10 9.2 (0.3) (0.1) FY20 FY21 FY22 FY23 FY24 FY25 FY26 FY27 FY28 Post (3.7) FY29 5 US$ Euro Sterling A$ C$ Bonds4 Bonds4 Bonds4 Bonds Bonds Subsidiaries 0 38% 31% 14% 3% 3% 11% FY19 Derivatives FY19 IFRS16 CVC Other Free cash Dividends Dividends Other HY20 restated remeasure IFRS16 flow paid paid movements2 % of portfolio Capital markets 89% Asset financing 11% -ment impacts to NCI1 Notes: 1. NCIs: dividends paid to non-controlling interests of US$0.6 billion predominantly relate to Escondida. 2. Other: Non-cash fair value movement: relates to foreign exchange variance due to the revaluation of local currency denominated cash and debt to USD and movements in interest rates. 3. Debt maturity profile: all debt balances are represented in notional USD values and based on financial years; as at 31 December 2019; subsidiary debt is presented in accordance with IFRS 10 and IFRS 11. 4. Debt maturity profile: includes hybrid bonds (27% of portfolio: 14% in USD, 9% in Euro, 4% in Sterling) with maturity shown at first call date. Financial results 18 February 2020 27 BHP

Net debt: definition and IFRS 16 Operating lease commitments brought onto balance sheet from 1 July 2019 • Net debt target range US$12-17 bn – change in net debt definition to include fair value of debt-related derivatives at 30 June 2019 (US$0.2 bn increase), unrelated to IFRS 16 Net debt – initial impact of IFRS 16 on 1 July 2019 (~US$2.3 bn increase) definition – new leases commencing in FY20 (including SGO desalination plant) and renewals of existing lease arrangements (~US$1.3 bn increase, the majority will be incurred in H2 FY20) • Removes distinction between operating and finance leases; introduces new identification criteria • Results in operating leases being recognised on balance sheet; no change to treatment of existing finance leases • No change to underlying cash flows IFRS16 • Short term, variable payment and low-value leases will remain off-balance sheet and continue to be recorded as operating expenses Implementation approach • Applied on a modified retrospective basis (i.e. additional lease assets equal additional lease liabilities; no restatement of historical financials) • Applied to all existing contracts on 1 July 2019 (i.e. grandfathering rules not applied) No material impact on NPAT; calculation of minimum dividend unaffected • Lease Liability H1 FY20 – US$1.9 bn increase • Lease Liability H2 FY20 – Initial recognition of ~US$2.3 bn on 1 July 2019 – additional new leases commencing in H2 FY20 (including SGO Key impacts – additional new leases commencing in H1 FY20 ~US$0.2 bn desalination plant) and renewals of existing lease arrangements increase (~US$1.1 bn increase) – revaluations (inc CVC1) ~US$0.3 bn decrease – impacts of revaluations1 and lease payments – lease payments ~US$0.4 bn decrease Note: 1. CVCs (Continuous Voyage Charter contracts) are priced with reference to the volatile freight index (C5 Dry Baltic) and the lease liability must be remeasured at each period end. Financial results 18 February 2020 28 BHP

IFRS 16 leases: H1 impacts Accounting change only; no impact to net cash flows Balance sheet1 Income statement Cash flow statement Disclosures Financial metrics Right of use assets Operating lease Operating costs Operating cash outflow Net debt (PP&E) commitments (IAS 17) US$0.4 bn US$0.4 bn US$1.9 bn US$1.7 bn1 ~US$1.9 bn Lease liabilities EBITDA Investing cash flow Short term, variable, low Gearing (Interest bearing liabilities) US$1.9 bn US$0.4 bn no impact value leases 2%2 Depreciation Financing cash outflow EBITDA margin US$0.3 bn US$0.4 bn 2% Unit cash costs Interest No impact on 1-4% US$0.05 bn net cash flows (no change to guidance) No material impact on ROCE income statement negligible impact Notes: 1. As at 31 December 2019. PP&E: Excludes small decrease for change in classification of onerous lease provisions on implementation of IFRS 16. 2. Gearing as at 30 June 2019 was 15.4% (pre IFRS 16). Gearing at 31 December 2019 adjusted to exclude IFRS 16 is 17.2%. Financial results 18 February 2020 29 BHP

IFRS 16 leases: H1 impacts Accounting changes only, no impact to net cash flows Balance sheet Income statement Unit cost Group Lease liabilities Depreciation1 EBITDA1 No change to unit US$1.9 bn US$0.3 bn US$0.4 bn cost guidance WAIO2 US$0.17 bn US$0.02 bn US$0.03 bn 2% Queensland Coal2 US$0.18 bn US$0.06 bn US$0.05 bn 4% Escondida2 US$0.03 bn US$0.01 bn US$0.01 bn 1% Petroleum2 US$0.42 bn US$0.02 bn US$0.01 bn 2% Other18 US$0.31 bn US$0.03 bn US$0.06 bn Marketing/G&U3 US$0.77 bn US$0.20 bn US$0.24 bn Notes: 1. Difference between depreciation impact and EBITDA reflects interest impact. 2. Impact primarily relates to other leases (including mining and other equipment, rigs and accommodation). There is no change to the treatment of intercompany freight expenses that are allocated from G&U. 3. Impact primarily relates to freight contracts and office buildings. Freight costs are no longer included in underlying EBITDA for G&U, as operating leases are now recognised on the balance sheet with associated depreciation and interest charges expensed over the term of the lease. There is no change to how the expense is allocated to and recorded within assets. Financial results 18 February 2020 30 BHP

Projects in feasibility Autonomous truck hauling Jansen Stage 1 Scarborough Australia Saskatchewan, Canada Australia Automating up to ~500 haul trucks across Western Australia Iron Ore and Queensland Coal sites Shaft equipping, mine development, processing facility, site 13 subsea wells tied back to a semisubmersible FPU2; dry gas pipeline ~435 km in length transports dry gas from the (150 currently under feasibility or execution and 350 infrastructure and outbound logistics FPU to the onshore LNG plant at Pluto included in medium term plans) Operator BHP BHP Woodside (75%) 26.5% BHP ownership Various 100% (25% in WA-1-R and 50% in WA-62-R) <800 5,300 – 5,700 (includes US$250 m capex for sites in feasibility and Capex (US$m) Sustaining capital ~US$15/t (real) long term average; 1,400 – 1,900 (BHP share) execution and up to US$550 m included in medium-term +/- 20% in any given year. plans) Combination of feasibility study phase and execution phase First investment decision taken in CY19, site by site Feasibility study phase Phase / timing Feasibility study phase decision on roll out Final investment decision expected from mid CY20 (capex represents full amount) First production / ~5 years from sanction to commissioning Staged site rollout from CY20 onwards CY24 onwards Project delivery ~2 years from first production to ramp up 6.5 Mtpa (100% basis, LNG); and Volumes n/a 4.3 – 4.5 Mtpa (Potassium chloride, KCL) 160MMscf/d (100% basis at peak, domestic gas) 6% royalty Non-binding Heads of Agreement signed in November Gooneylla Riverside in Queensland first site approved in Federal and Provincial Corporate income tax and Potash 2019, which, amongst other terms, includes agreement on a Other considerations November 2019 Eastern Ridge and Daunia in feasibility study phase Production Tax1 competitive tariff for gas processing through the Pluto LNG Jansen Stage 1 expected mine life of 100 years facility. Notes: 1. Tax consideration for Jansen Stage 1 project includes Royalties, Federal and Provincial Corporate Income taxes, and Potash Production Tax (PPT). Withholding tax on dividend payments under the current corporate structure is 5%. 2. FPU: Floating production unit. Financial results 18 February 2020 31 BHP

BHP guidance Group FY20e FY21e Capital and exploration expenditure (US$bn) <8.0 ~8.0 Cash basis. Including: Maintenance 2.1 Includes non-discretionary capital expenditure to maintain asset integrity, reduce risks and meet compliance requirements. Also includes capitalised deferred development and production stripping (FY20e: US$0.8 billion). Improvement 2.9 Includes Petroleum infill drilling and South Flank. Latent capacity 0.4 Includes EWSE, WAIO to 290 Mtpa and West Barracouta. Major growth 1.7 Includes Spence Growth Option, Mad Dog Phase 2, Jansen, Atlantis Phase 3 and Ruby Exploration 0.9 Includes US$0.7 billion Petroleum and ~US$60 million Copper exploration programs planned for FY20. Petroleum FY20e Medium term Petroleum production (MMboe) 110 – 116 ~110 FY20 volumes now expected to be at the bottom of the guidance range as a result of the impact from Tropical Cyclone Damien on North West Shelf operations in early February 2020. Decline of ~1.5% p.a. over medium term includes projects yet to be sanctioned. ~110 MMboe represents average over medium term. Capital expenditure (US$bn) 1.2 Sanctioned Capex First production Production (BHP share) (100% basis at peak) Mad Dog Phase 2 February 2017 US$2.2 bn CY22 140,000 boe/d West Barracouta December 2018 ~US$140 m CY21 104 MMscf/d Atlantis Phase 3 February 2019 ~US$700 m CY20 38,000 boe/d Ruby August 2019 ~US$340 m CY21 16,000 bopd (oil) and (~US$280 m excl. pre-commitment) 80 MMscf/d (gas) Exploration expenditure (US$bn) 0.7 Focused on Mexico, the Gulf of Mexico, Canada and the Caribbean. Unit cost (US$/boe) 10.5 – 11.5 <13 Excludes inventory movements, embedded derivatives movements, freight, third party product purchases and exploration expense. Based on exchange rate of AUD/USD 0.70. Financial results 18 February 2020 32 BHP

BHP guidance (continued) Copper FY20e Medium term Copper production (kt) 1,705 – 1,820 Escondida: 1.16 – 1.23 Mt; Olympic Dam: 180 – 205 kt; Pampa Norte 230 – 250 kt; Antamina: 135 kt (zinc 110kt). Capital and exploration expenditure (US$bn) 2.6 Includes ~US$60 million exploration expenditure. Sanctioned Capex First production Production (BHP share) (100% basis) Spence Growth Option August 2017 US$2.46 bn H1 FY21 ~185 ktpa of incremental copper (over first 10 years) Escondida Copper production (kt, 100% basis) 1,160 – 1,230 ~1,200 ~1,200 kt represents average over medium term. Unit cash costs (US$/lb) 1.20 – 1.35 <1.15 Excludes freight; net of by-product credits; based on an exchange rate of USD/CLP 683. Unit costs expected to be impacted by lower byproduct credits (compared to FY19) in the short term. FY20e unit costs tracking to lower end of the guidance range. Iron Ore FY20e Medium term Iron ore production (Mt) 242 – 253 Excludes production from Samarco. Major car dumper maintenance in September 2019 quarter. Capital and exploration expenditure (US$bn) 2.3 Sanctioned Capex First production Production (BHP share) (100% basis) South Flank June 2018 US$3.1 bn CY21 80 Mtpa sustaining mine Western Australia Iron Ore Iron ore production (Mt, 100% basis) 273 – 286 290 Unit cash costs (US$/t) 13 – 14 <13 Excludes freight and royalties; based on an exchange rate of AUD/USD 0.70. Sustaining capital expenditure (US$/t) 4 Medium term average; +/- 50% in any given year. Includes South Flank; excludes costs associated with Value Chain Automation. Financial results 18 February 2020 33 BHP

BHP guidance (continued) Coal FY20e Medium term Metallurgical coal production (Mt) 41 – 45 49 – 54 Planned wash plant shutdowns in Sept Q19 at Goonyella, Peak Downs and Caval Ridge Energy coal production (Mt) 24 – 26 NSWEC: 15 – 17 Mt; Cerrejón: ~9 Mt. Capital and exploration expenditure (US$bn) 0.7 Queensland Coal Production (Mt, 100% basis) 73 – 79 Unit cash costs (US$/t) 67 – 74 54 – 61 Excludes freight and royalties; based on an exchange rate of AUD/USD 0.70. Sustaining capital expenditure (US$/t) 8 Medium term average; +/- 50% in any given year. Excludes costs associated with Value Chain Automation. Other FY20e Other capex (US$bn) 0.6 Includes Nickel West and Jansen. Including: Jansen current scope (US$bn) ~0.25 US$2.7 billion. Financial results 18 February 2020 34 BHP

Key Underlying EBITDA sensitivities Approximate impact1 on FY20 Underlying EBITDA of changes of: US$ million US$1/t on iron ore price2 233 US$1/bbl on oil price3 38 US$1/t on metallurgical coal price 39 US¢1/lb on copper price2 36 US$1/t on energy coal price2 16 US¢1/lb on nickel price 1.5 AUD (US¢1/A$) operations4 120 CLP (US¢1/CLP) operations4 23 Notes: 1. EBITDA sensitivities: assumes total volume exposed to price; determined on the basis of BHP’s existing portfolio. 2. EBITDA sensitivities: excludes impact of equity accounted investments. 3. EBITDA sensitivities: excludes impact of change in input costs across the Group. 4. EBITDA sensitivities: based on average exchange rate for the period Financial results 18 February 2020 35 BHP

Statement of petroleum resources The estimates of Petroleum Reserves and Contingent Resources contained in this presentation are based on, and fairly represent, information and supporting documentation prepared under the supervision of Mr. A. G. Gadgil, who is employed by BHP. Mr. Gadgil is a member of the Society of Petroleum Engineers and has the required qualifications and experience to act as a qualified Petroleum Reserves and Resources evaluator under the ASX Listing Rules. This presentation is issued with the prior written consent of Mr. Gadgil who agrees with the form and context in which the Petroleum Reserves and Contingent Resources are presented. Reserves and Contingent Resources are net of royalties owned by others and have been estimated using deterministic methodology. Aggregates of Reserves and Contingent Resources estimates contained in this presentation have been calculated by arithmetic summation of field/project estimates by category with the exception of the North West Shelf (NWS) Gas Project in Australia. Probabilistic methodology has been utilised to aggregate the NWS Reserves and Contingent Resources for the reservoirs dedicated to the gas project only and represents an incremental 16 MMboe of Proved Reserves. The barrel of oil equivalent conversion is based on 6000 scf of natural gas equals 1 boe. The Reserves and Contingent Resources contained in this presentation are inclusive of fuel required for operations. The respective amounts of fuel for each category are provided by footnote for the resource graphics in this presentation. Production volumes exclude fuel. The custody transfer point(s)/point(s) of sale applicable for each field or project are the reference point for Reserves and Contingent Resources. Reserves and Contingent Resources estimates have not been adjusted for risk. Unless noted otherwise, Reserves and Contingent Resources are as of 30 June 2019. Where used in this presentation, the term Resources represents the sum of 2P reserves and 2C Contingent Resources. BHP estimates Proved Reserve volumes according to SEC disclosure regulations and files these in our annual 20-F report with the SEC. All Unproved volumes are estimated using SPE-PRMS guidelines, which among other things, allow escalations to prices and costs, and as such, would be on a different basis than that prescribed by the SEC, and are therefore excluded from our SEC filings. All Resources and other Unproved volumes may differ from and may not be comparable to the same or similarly-named measures used by other companies. Non-proved estimates are inherently more uncertain than proved. The SEC permits oil and gas companies, in their filings with the SEC, to disclose only Proved, Probable and Possible Reserves, and only when such Reserves have been determined in accordance with SEC guidelines. We use certain terms in this presentation such as “Resources,” “Contingent Resources,” “2C Contingent Resources” and similar terms as well as Probable Reserves not determined in accordance with the SEC’s guidelines, all of which measures we are strictly prohibited from including in filings with the SEC. These measures include Reserves and Resources with substantially less certainty than Proved Reserves. US investors are urged to consider closely the disclosure in our Form 20-F for the fiscal year ended 30 June 2019, File No. 001-09526 and in our other filings with the SEC, available from us at http://www.bhp.com/. These forms can also be obtained from the SEC as described above. Financial results 18 February 2020 36 BHP

Footnotes 1. Slide 6: High Potential Injury frequency: number of injuries from events where there was the potential for a fatality per million hours worked, presented on a total operations basis. 2. Slide 8: Adjusted effective tax rate and Adjusted effective tax rate incl. royalties: excludes the influence of exchange rate movements and exceptional items. 3. Slide 9: Price: net of price-linked costs. 4. Slide 9: Controllable cash costs: Operational stability underpinned net favourable inventory movements across our assets. Lower labour costs at Escondida due to the prior period end-of negotiation bonus payments. This was partially offset by increased maintenance activities during the period. 5. Slide 9: Non-cash: includes net deferred stripping costs. 6. Slide 9: Other: includes other items (including profit/loss from equity accounted investments). 7. Slide 10: Segment EBITDA: percentage contribution to Group Underlying EBITDA, excluding Group and unallocated items. Energy coal and Nickel have not been presented. 8. Slide 10: Iron ore: unit cost, C1 unit cost excluding third party royalties, EBITDA margin and ROCE refer to Western Australia Iron Ore. 9. Slide 10: WAIO C1 cost: excludes third party royalties, exploration expenses, depletion of production stripping, demurrage, exchange rate gains/losses, net inventory movements and other income. 10. Slide 10: Petroleum: excludes closed mines, which is now reported within Group and unallocated items. 11. Slide 12: Dividend: represents final dividend determined by the Board for FY19 and paid in September 2019. 12. Slide 12: NCIs: dividends paid to non-controlling interests of US$0.6 billion predominantly relate to Escondida. 13. Slide 13: Shareholder returns: dividends determined since FY16. 14. Slide 14: Antamina and Cerrejón: equity accounted investments; average capital employed represents BHP’s equity interest. 15. Slide 14: WAIO, Cerrejón, NSWEC & Petroleum Exploration: ROCE truncated for illustrative purposes. 16. Slide 16: Wood Mackenzie data, Q4 2019 report. Production reported in equity share of paid metal. 17. Slide 16: Coal cost curve data for all companies including BHP have been sourced from Wood Mackenzie and are shown on a VIU adjusted basis. BHP assets relates to the average cost for Queensland Coal operations. 18. Slide 16: Results as at 30 June 2019 plus Bele and Tuk discoveries as at 30 September 2019, 1P: 841 MMboe (58 MMboe fuel); 2P: 1,147 MMboe (75 MMboe fuel); 2C: 2,104 MMboe (69 MMboe fuel). 19. Slide 17: H1 FY20 unit cost at FX of AUD/USD 0.70. 20. Slide 19: T&T North 408 MMboe includes FY19 BHP Bongos 2C of 228 MMboe and FY20 Bele and Tuk discoveries which represent combined 2C of 180 MMboe as of 30 September 2019 (net, no fuel). Samurai 19 MMboe (net, no fuel) exited for value. The sale closed on 4 Nov 2019. Financial results 18 February 2020 37

BHP

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

|  |  |  |  |  | BHP Group Limited and BHP Group Plc
Date: February 18, 2020 |  |  |  | By: |  | /s/ Rachel Agnew
|  |  |  | Name: |  | Rachel Agnew
|  |  |  | Title: |  | Company Secretary