6-K 1 d608836d6k.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

August 21, 2018

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

BHP Billiton Limited |  | BHP Billiton Plc
171 Collins Street |  | Nova South,
Melbourne Victoria 3000 Australia |  | 160 Victoria Street
GPO BOX 86 |  | London SW1E 5LB UK
Melbourne Victoria 3001 Australia |  | Tel +44 20 7802 4000
Tel +61 1300 55 47 57 Fax +61 3 9609 3015 |  | Fax +44 20 7802 4111
bhp.com |  | bhp.com

21 August 2018

To: | Australian Securities Exchange

New York Stock Exchange

BHP RESULTS PRESENTATION YEAR ENDED 30 JUNE 2018

Attached are the presentation slides for a presentation that will be given by the Chief Executive Officer and Chief Financial Officer shortly.

The Webcast for this presentation can be accessed at:

https://edge.media-server.com/m6/p/mjvmq9cq

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

Rachel Agnew
Company Secretary

BHP Billiton Limited ABN 49 004 028 077 |  | BHP Billiton 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 Australia |  | 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 Year ended 30 June 2018 JimblebarFinancial results Year ended 30 June 2018 Jimblebar

Disclaimer 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. Non-IFRS and other financial information BHP results are reported under International Financial Reporting Standards (IFRS). This presentation may also include certain non-IFRS (also referred to as alternate performance measures) and other measures including Underlying attributable profit, Underlying EBITDA (all references to EBITDA refer to Underlying EBITDA), Underlying EBIT, Adjusted effective tax rate, Controllable cash costs, Free cash flow, Gearing ratio, Net debt, Net operating assets, Operating assets free cash flow, Principal factors that affect Underlying EBITDA, Underlying basic earnings/(loss) per share, Underlying EBITDA margin and Underlying return on capital employed (ROCE) (all references to return on capital employed refer to Underlying return on capital employed), Underlying return on invested capital (ROIC). These measures are used internally by management to assess the performance of our business and segments, make decisions on the allocation of our resources and assess operational management. Non-IFRS and other measures have not been subject to audit or review and should not be considered as an indication of or alternative to an IFRS measure of profitability, financial performance or liquidity. Presentation of data Unless specified otherwise: variance analysis relates to the relative performance of BHP and/or its operations during the 2018 financial year compared with the 2017 financial 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 2017 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 Billiton Mitsubishi Alliance (BMA) asset, jointly operated with Mitsubishi, and the BHP Billiton Mitsui Coal (BMC) asset, operated by BHP. Numbers presented may not add up precisely to the totals provided due to rounding. All footnote content contained on slide 43. 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’, ‘BHP Group’, ‘we’, ‘us’, ‘our’ and ‘ourselves’ are used to refer to BHP Billiton Limited, BHP Billiton 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 BHP Group and, as a result, statements regarding our operations, assets and values apply only to our operated assets unless otherwise stated. Financial results 21 August 2018 2Disclaimer 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. Non-IFRS and other financial information BHP results are reported under International Financial Reporting Standards (IFRS). This presentation may also include certain non-IFRS (also referred to as alternate performance measures) and other measures including Underlying attributable profit, Underlying EBITDA (all references to EBITDA refer to Underlying EBITDA), Underlying EBIT, Adjusted effective tax rate, Controllable cash costs, Free cash flow, Gearing ratio, Net debt, Net operating assets, Operating assets free cash flow, Principal factors that affect Underlying EBITDA, Underlying basic earnings/(loss) per share, Underlying EBITDA margin and Underlying return on capital employed (ROCE) (all references to return on capital employed refer to Underlying return on capital employed), Underlying return on invested capital (ROIC). These measures are used internally by management to assess the performance of our business and segments, make decisions on the allocation of our resources and assess operational management. Non-IFRS and other measures have not been subject to audit or review and should not be considered as an indication of or alternative to an IFRS measure of profitability, financial performance or liquidity. Presentation of data Unless specified otherwise: variance analysis relates to the relative performance of BHP and/or its operations during the 2018 financial year compared with the 2017 financial 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 2017 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 Billiton Mitsubishi Alliance (BMA) asset, jointly operated with Mitsubishi, and the BHP Billiton Mitsui Coal (BMC) asset, operated by BHP. Numbers presented may not add up precisely to the totals provided due to rounding. All footnote content contained on slide 43. 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’, ‘BHP Group’, ‘we’, ‘us’, ‘our’ and ‘ourselves’ are used to refer to BHP Billiton Limited, BHP Billiton 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 BHP Group and, as a result, statements regarding our operations, assets and values apply only to our operated assets unless otherwise stated. Financial results 21 August 2018 2

Financial results Year ended 30 June 2018 Following BHP’s sale of the Onshore US assets announced on 27 July 2018, the contribution of these assets have been presented as discontinued operations and related assets and liabilities reclassified to held for sale, unless otherwise noted. Andrew Mackenzie Chief Executive Officer Port HedlandFinancial results Year ended 30 June 2018 Following BHP’s sale of the Onshore US assets announced on 27 July 2018, the contribution of these assets have been presented as discontinued operations and related assets and liabilities reclassified to held for sale, unless otherwise noted. Andrew Mackenzie Chief Executive Officer Port Hedland

BHP’s investment proposition Continued delivery of consistent plans is driving improvement across our business Maximise cash flow Capital discipline Value and returns Lower costs US$10-15 bn net debt ROCE to ~20% productivity, technology, culture range to be maintained by FY22 (at FY17 prices) Volume growth <US$8 bn capex 40% base value upside productivity, project delivery per annum to FY20 potential across our 6 focus areas Constructive outlook Organic opportunities Shareholder returns for our commodities, rich option set across commodities minimum 50% payout ratio dividend, solid demand, disciplined supply and time periods return of Onshore US net proceeds* Note: Disciplined supply: reflects lower levels of investment across the industry. ROCE and base value uplift: based on Global Metals, Mining and Steel Conference presentation on 15 May 2018. * Onshore US: Sale announced for US$10.8 billion (less customary completion adjustments); we expect to return the net proceeds from the transactions to shareholders; we will confirm how and when at the time of completion of the transactions. Financial results 21 August 2018 4BHP’s investment proposition Continued delivery of consistent plans is driving improvement across our business Maximise cash flow Capital discipline Value and returns Lower costs US$10-15 bn net debt ROCE to ~20% productivity, technology, culture range to be maintained by FY22 (at FY17 prices) Volume growth <US$8 bn capex 40% base value upside productivity, project delivery per annum to FY20 potential across our 6 focus areas Constructive outlook Organic opportunities Shareholder returns for our commodities, rich option set across commodities minimum 50% payout ratio dividend, solid demand, disciplined supply and time periods return of Onshore US net proceeds* Note: Disciplined supply: reflects lower levels of investment across the industry. ROCE and base value uplift: based on Global Metals, Mining and Steel Conference presentation on 15 May 2018. * Onshore US: Sale announced for US$10.8 billion (less customary completion adjustments); we expect to return the net proceeds from the transactions to shareholders; we will confirm how and when at the time of completion of the transactions. Financial results 21 August 2018 4

FY18 financial scorecard Strong operating and financial performance supports shareholder returns Volumes Profitability Free cash flow +8% US$24.1 bn US$12.5 bn Cu Eq production growth Underlying EBITDA Free cash flow records at nine operations with strong contributions over US$12 bn for second across all core commodities across the portfolio consecutive year Dividend ROCE Net debt US$10.9 bn 63 US cps 14.4% net debt at low end of target range record H2 dividend ~18% excluding Onshore US greater proportion of future free cash 69% payout ratio up from 10% in FY17 flow expected to be returned full year dividend of 118 US cps Note: Presented on a total operations basis. Financial results 21 August 2018 5FY18 financial scorecard Strong operating and financial performance supports shareholder returns Volumes Profitability Free cash flow +8% US$24.1 bn US$12.5 bn Cu Eq production growth Underlying EBITDA Free cash flow records at nine operations with strong contributions over US$12 bn for second across all core commodities across the portfolio consecutive year Dividend ROCE Net debt US$10.9 bn 63 US cps 14.4% net debt at low end of target range record H2 dividend ~18% excluding Onshore US greater proportion of future free cash 69% payout ratio up from 10% in FY17 flow expected to be returned full year dividend of 118 US cps Note: Presented on a total operations basis. Financial results 21 August 2018 5

Safety and sustainability Health, safety and environment are core values Health Environment Safety • Reducing underground mine diesel • Inaugural Water Report to be released in • Two fatalities emissions exposure August 2018 – Goonyella Riverside (August 2017) • Resilience Program and mental health • Escondida’s desalination plant supports – Permian Basin (November 2017) toolkit roll out 2% reduction in Group freshwater usage • TRIF at operated assets of 4.4 • >1 million field leadership interactions 8%... 31%... 15%... reduction in high potential reduction in potential exposures targeted reduction in five-year 1 3 injuries above Occupational Exposure fresh water withdrawal 2 Limits Note: Presented on a total operations basis. Financial results 21 August 2018 6Safety and sustainability Health, safety and environment are core values Health Environment Safety • Reducing underground mine diesel • Inaugural Water Report to be released in • Two fatalities emissions exposure August 2018 – Goonyella Riverside (August 2017) • Resilience Program and mental health • Escondida’s desalination plant supports – Permian Basin (November 2017) toolkit roll out 2% reduction in Group freshwater usage • TRIF at operated assets of 4.4 • >1 million field leadership interactions 8%... 31%... 15%... reduction in high potential reduction in potential exposures targeted reduction in five-year 1 3 injuries above Occupational Exposure fresh water withdrawal 2 Limits Note: Presented on a total operations basis. Financial results 21 August 2018 6

Samarco and Renova Foundation Committed to social and environmental rehabilitation Rehabilitation Samarco restart Legal developments (Renova Foundation) • Community resettlement underway • Restart important but must be safe and • Governance Agreement ratified economically viable – new Bento Rodrigues construction – Renova structure established commenced • Licences by state and federal authorities – settles the BRL20 bn claim progressing as planned – resettlement complete by mid-2020 – establishes a process to progress • Negotiations with debtholders required prior • Water damage claims being resolved settlement of the BRL155 bn claim to restart • River stabilisation/recovery improving water • Constructive negotiations with prosecutors, quality, ecology, fish species government and communities Rio Gualaxo do Norte turbidity Water damages compensation Renova Foundation's FY18 spending (NTU) 100,000 Water damage 10,000 claims progressing 1,000 (2%) Compensatory BRL1.8 bn Reparatory Water damage (16%) 100 (100% basis) (84%) claims resolved 10 (98%) Jan 2016 Jan 2017 Jan 2018 Turbidity Fresh water quality standard (Brazil) Note: Water damages compensation does not include legal claims in court under dispute. NTU: Nephelometric Turbidity Units. Financial results 21 August 2018 7Samarco and Renova Foundation Committed to social and environmental rehabilitation Rehabilitation Samarco restart Legal developments (Renova Foundation) • Community resettlement underway • Restart important but must be safe and • Governance Agreement ratified economically viable – new Bento Rodrigues construction – Renova structure established commenced • Licences by state and federal authorities – settles the BRL20 bn claim progressing as planned – resettlement complete by mid-2020 – establishes a process to progress • Negotiations with debtholders required prior • Water damage claims being resolved settlement of the BRL155 bn claim to restart • River stabilisation/recovery improving water • Constructive negotiations with prosecutors, quality, ecology, fish species government and communities Rio Gualaxo do Norte turbidity Water damages compensation Renova Foundation's FY18 spending (NTU) 100,000 Water damage 10,000 claims progressing 1,000 (2%) Compensatory BRL1.8 bn Reparatory Water damage (16%) 100 (100% basis) (84%) claims resolved 10 (98%) Jan 2016 Jan 2017 Jan 2018 Turbidity Fresh water quality standard (Brazil) Note: Water damages compensation does not include legal claims in court under dispute. NTU: Nephelometric Turbidity Units. Financial results 21 August 2018 7

Financial results Year ended 30 June 2018 Peter Beaven Chief Financial Officer PyreneesFinancial results Year ended 30 June 2018 Peter Beaven Chief Financial Officer Pyrenees

Financial performance Results reflect 8% volume growth and higher commodity prices Summary FY18 Income Statement Strong margins through the cycle 5 (US$ billion) (Underlying EBITDA margin , %) 60 Total operations (including Onshore US) Underlying EBITDA 24.1 Underlying attributable profit 8.9 Net exceptional items (5.2) Attributable profit 3.7 Underlying basic earnings per share 168 US cps“ 33% 35 Dividends per share 118 US cps“ 42% 35 Continuing operations Underlying EBITDA 23.2“ 20% EBITDA margin 55% Underlying EBIT 16.6“ 26% 4 Adjusted effective tax rate 31.4% BHP Peer group range Adjusted effective tax rate incl. royalties 39.9% 10 Underlying attributable profit 9.6“ 33% FY06 FY07 FY08 FY09 FY10 FY11 FY12 FY13 FY14 FY15 FY16 FY17 FY18 Financial results 21 August 2018 9Financial performance Results reflect 8% volume growth and higher commodity prices Summary FY18 Income Statement Strong margins through the cycle 5 (US$ billion) (Underlying EBITDA margin , %) 60 Total operations (including Onshore US) Underlying EBITDA 24.1 Underlying attributable profit 8.9 Net exceptional items (5.2) Attributable profit 3.7 Underlying basic earnings per share 168 US cps“ 33% 35 Dividends per share 118 US cps“ 42% 35 Continuing operations Underlying EBITDA 23.2“ 20% EBITDA margin 55% Underlying EBIT 16.6“ 26% 4 Adjusted effective tax rate 31.4% BHP Peer group range Adjusted effective tax rate incl. royalties 39.9% 10 Underlying attributable profit 9.6“ 33% FY06 FY07 FY08 FY09 FY10 FY11 FY12 FY13 FY14 FY15 FY16 FY17 FY18 Financial results 21 August 2018 9

Segment performance Strong contribution across the portfolio in FY18 Iron Ore Copper 6 6 39% of Group EBITDA 28% of Group EBITDA Record 289 Mtpa run-rate in Q4 Record Spence production and Escondida ore milled 7 8 Cost : US$14.26/t” 2% Cost : US$1.25/lb“ 10% 7 C1 excl 3rd party royalties : US$13.03/t” 2% 7 EBITDA : US$8.9 bn” 1% EBITDA: US$6.5 bn“ 84% 7 EBITDA margin : 61% EBITDA margin: 54% 7 ROCE : 29% ROCE: 15% Coal Petroleum 6 6 19% of Group EBITDA 14% of Group EBITDA Record met coal production despite geotech issues Over 300 MMboe 2P + 2C resources added Cost: Queensland Coal US$68/t “ 14% Conventional cost: US$10.06/boe“ 16% NSWEC US$46/t “ 12% EBITDA: US$4.4 bn“ 16% EBITDA: US$3.3 bn“ 7% EBITDA margin: 49% EBITDA margin: 62% ROCE: 31% ROCE: 12% Note: Presented on a continuing operations basis. Financial results 21 August 2018 10Segment performance Strong contribution across the portfolio in FY18 Iron Ore Copper 6 6 39% of Group EBITDA 28% of Group EBITDA Record 289 Mtpa run-rate in Q4 Record Spence production and Escondida ore milled 7 8 Cost : US$14.26/t” 2% Cost : US$1.25/lb“ 10% 7 C1 excl 3rd party royalties : US$13.03/t” 2% 7 EBITDA : US$8.9 bn” 1% EBITDA: US$6.5 bn“ 84% 7 EBITDA margin : 61% EBITDA margin: 54% 7 ROCE : 29% ROCE: 15% Coal Petroleum 6 6 19% of Group EBITDA 14% of Group EBITDA Record met coal production despite geotech issues Over 300 MMboe 2P + 2C resources added Cost: Queensland Coal US$68/t “ 14% Conventional cost: US$10.06/boe“ 16% NSWEC US$46/t “ 12% EBITDA: US$4.4 bn“ 16% EBITDA: US$3.3 bn“ 7% EBITDA margin: 49% EBITDA margin: 62% ROCE: 31% ROCE: 12% Note: Presented on a continuing operations basis. Financial results 21 August 2018 10

Group EBITDA waterfall Efficient operations capture upside from higher commodity prices Underlying EBITDA variance (US$ billion) 30 External US$3.5 billion Controllable US$0.3 billion 24.1 0.9 4.1 1.0 23.2 22.9 0.6 0.4 (0.2) (0.4) (0.3) (1.2) (0.2) 19.4 20 10 0 11 12 9 10 FY17 Price Foreign Inflation Sub-total Growth Productivity Controllable Fuel & Non-cash Other FY18 Discontinued FY18 Continuing exchange volumes volumes cash costs energy Continuing operations Total operations operations operations Financial results 21 August 2018 11Group EBITDA waterfall Efficient operations capture upside from higher commodity prices Underlying EBITDA variance (US$ billion) 30 External US$3.5 billion Controllable US$0.3 billion 24.1 0.9 4.1 1.0 23.2 22.9 0.6 0.4 (0.2) (0.4) (0.3) (1.2) (0.2) 19.4 20 10 0 11 12 9 10 FY17 Price Foreign Inflation Sub-total Growth Productivity Controllable Fuel & Non-cash Other FY18 Discontinued FY18 Continuing exchange volumes volumes cash costs energy Continuing operations Total operations operations operations Financial results 21 August 2018 11

Productivity Notwithstanding one-off issues in H1, strong productivity momentum in H2 to be carried into FY19 and beyond FY18 productivity performance Cumulative productivity gains (US$ million) (US$ billion) 16 Record production runrates 14 1,000 Geotechnical 12 issues Planned 10 LCE ramp-up maintenance shutdown 500 8 FY18 -US$96m 6 0 4 -470 +374 2 0 (500) Escondida WAIO Olympic BMA Other H1 FY18 H2 FY18 FY12 FY13 FY14 FY15 FY16 FY17 FY18 FY19e Medium Dam term We expect to deliver productivity gains of ~US$1 billion in FY19 Guidance down from US$2 billion due to announced divestments and challenging operating conditions at two BMA mines in FY18 Note: FY18 productivity excludes Onshore US. Financial results 21 August 2018 12Productivity Notwithstanding one-off issues in H1, strong productivity momentum in H2 to be carried into FY19 and beyond FY18 productivity performance Cumulative productivity gains (US$ million) (US$ billion) 16 Record production runrates 14 1,000 Geotechnical 12 issues Planned 10 LCE ramp-up maintenance shutdown 500 8 FY18 -US$96m 6 0 4 -470 +374 2 0 (500) Escondida WAIO Olympic BMA Other H1 FY18 H2 FY18 FY12 FY13 FY14 FY15 FY16 FY17 FY18 FY19e Medium Dam term We expect to deliver productivity gains of ~US$1 billion in FY19 Guidance down from US$2 billion due to announced divestments and challenging operating conditions at two BMA mines in FY18 Note: FY18 productivity excludes Onshore US. Financial results 21 August 2018 12

Cost efficiencies On track to deliver medium-term unit cost guidance Escondida (US$/lb) WAIO (US$/t) 40 1.6 52% 20% 1.07 20 0.8 14.26 0 0.0 FY12 FY13 FY14 FY15 FY16 FY17 FY18 FY19e Medium FY12 FY13 FY14 FY15 FY16 FY17 FY18 FY19e Medium Queensland Coal (US$/t) Conventional Petroleum (US$/boe) 160 20 30% 54% 80 10 10.06 68.04 0 0 FY12 FY13 FY14 FY15 FY16 FY17 FY18 FY19e Medium FY12 FY13 FY14 FY15 FY16 FY17 FY18 FY19e Medium Through productivity, we will continue to lower costs at our bulk operations and partially offset grade decline in copper and natural field decline in oil Financial results 21 August 2018 13Cost efficiencies On track to deliver medium-term unit cost guidance Escondida (US$/lb) WAIO (US$/t) 40 1.6 52% 20% 1.07 20 0.8 14.26 0 0.0 FY12 FY13 FY14 FY15 FY16 FY17 FY18 FY19e Medium FY12 FY13 FY14 FY15 FY16 FY17 FY18 FY19e Medium Queensland Coal (US$/t) Conventional Petroleum (US$/boe) 160 20 30% 54% 80 10 10.06 68.04 0 0 FY12 FY13 FY14 FY15 FY16 FY17 FY18 FY19e Medium FY12 FY13 FY14 FY15 FY16 FY17 FY18 FY19e Medium Through productivity, we will continue to lower costs at our bulk operations and partially offset grade decline in copper and natural field decline in oil Financial results 21 August 2018 13

Cash generation Over US$12 billion free cash flow for second consecutive year Operating cash flow Free cash flow (US$ billion) (Index, FY08=100) (US$ billion) (Index, FY08=100) 15 200 35 200 12.5 200 30 10 25 100 5 18.5 20 100 15 0 0 10 200 (5) 5 0 0 (10) (100) FY08 FY09 FY10 FY11 FY12 FY13 FY14 FY15 FY16 FY17 FY18 FY08 FY09 FY10 FY11 FY12 FY13 FY14 FY15 FY16 FY17 FY18 Operating cash flow (H1) Operating cash flow (H2) Free cash flow (H1) Free cash flow (H2) 13 13 Commodity basket index (RHS) Commodity basket index (RHS) Note: Presented on a total operations basis. Financial results 21 August 2018 14Cash generation Over US$12 billion free cash flow for second consecutive year Operating cash flow Free cash flow (US$ billion) (Index, FY08=100) (US$ billion) (Index, FY08=100) 15 200 35 200 12.5 200 30 10 25 100 5 18.5 20 100 15 0 0 10 200 (5) 5 0 0 (10) (100) FY08 FY09 FY10 FY11 FY12 FY13 FY14 FY15 FY16 FY17 FY18 FY08 FY09 FY10 FY11 FY12 FY13 FY14 FY15 FY16 FY17 FY18 Operating cash flow (H1) Operating cash flow (H2) Free cash flow (H1) Free cash flow (H2) 13 13 Commodity basket index (RHS) Commodity basket index (RHS) Note: Presented on a total operations basis. Financial results 21 August 2018 14

Capital allocation Investment of US$6.8 billion; net debt reduction of >US$5 billion; shareholder returns of >US$5 billion FY18 Operating Capital productivity productivity Net operating cash flow US$18.5 bn Maintenance capital US$1.9 bn Strong balance sheetü 14 Minimum 50% payout ratio dividend US$3.8 bn Excess cash Includes US$1.6 bn of dividends paid to NCIs US$11.8 bn Excludes US$0.6 bn of exploration expensed Additional Organic Acquisitions/ Balance sheet Buy-backs 14 dividends development (Divestments) US$5.6 bn US$1.4 bn US$0.0 bn US$4.9 bn US$(0.1) bn H2 FY17 and • US$1.9 bn improvement • Minor Hawkville sale H1 FY18 • US$0.3 bn latent capacity • US$0.9 bn major projects • US$0.9 bn exploration • US$0.9 bn Onshore US With net debt now at the low end of the target range, a higher proportion of future free cash flow is expected to be returned to shareholders 15 Note: Presented on a total operations basis. Excess cash excludes exploration expense of US$0.6 billion which is classified as organic development in accordance with the Capital Allocation Framework and after dividends paid to NCIs . Financial results 21 August 2018 15Capital allocation Investment of US$6.8 billion; net debt reduction of >US$5 billion; shareholder returns of >US$5 billion FY18 Operating Capital productivity productivity Net operating cash flow US$18.5 bn Maintenance capital US$1.9 bn Strong balance sheetü 14 Minimum 50% payout ratio dividend US$3.8 bn Excess cash Includes US$1.6 bn of dividends paid to NCIs US$11.8 bn Excludes US$0.6 bn of exploration expensed Additional Organic Acquisitions/ Balance sheet Buy-backs 14 dividends development (Divestments) US$5.6 bn US$1.4 bn US$0.0 bn US$4.9 bn US$(0.1) bn H2 FY17 and • US$1.9 bn improvement • Minor Hawkville sale H1 FY18 • US$0.3 bn latent capacity • US$0.9 bn major projects • US$0.9 bn exploration • US$0.9 bn Onshore US With net debt now at the low end of the target range, a higher proportion of future free cash flow is expected to be returned to shareholders 15 Note: Presented on a total operations basis. Excess cash excludes exploration expense of US$0.6 billion which is classified as organic development in accordance with the Capital Allocation Framework and after dividends paid to NCIs . Financial results 21 August 2018 15

Balance sheet 16 Net debt of US$10.9 billion; gearing of 15.3%; average debt maturity of 8.9 years Net debt and gearing Movements in net debt (Net debt, US$ billion) (Gearing, %) (US$ billion) 30 40 20 16.3 25 35 - 15 20 30 0.4 10.9 1.6 - 5.2 10 15 25 (0.1) 10 20 5 5 15 (12.5) 0 0 10 FY17 Free cash Dividends Dividends Other Non-cash FY18 FY12 FY13 FY14 FY15 FY16 FY17 FY18 flow paid paid to movements fair value 15 17 Net debt Net gearing NCIs movement Net debt to remain at lower end of target range while commodity prices are strong Note: Presented on a total operations basis. Financial results 21 August 2018 16Balance sheet 16 Net debt of US$10.9 billion; gearing of 15.3%; average debt maturity of 8.9 years Net debt and gearing Movements in net debt (Net debt, US$ billion) (Gearing, %) (US$ billion) 30 40 20 16.3 25 35 - 15 20 30 0.4 10.9 1.6 - 5.2 10 15 25 (0.1) 10 20 5 5 15 (12.5) 0 0 10 FY17 Free cash Dividends Dividends Other Non-cash FY18 FY12 FY13 FY14 FY15 FY16 FY17 FY18 flow paid paid to movements fair value 15 17 Net debt Net gearing NCIs movement Net debt to remain at lower end of target range while commodity prices are strong Note: Presented on a total operations basis. Financial results 21 August 2018 16

Investing for the future Ongoing improvements in capital productivity are enabling us to thrive on lower levels of capex Capital and exploration expenditure FY18 FY19e US$ billion US$ billion (US$ billion) Maintenance 1.9 2.1 Improvement 1.9 2.2 Latent capacity 0.3 0.6 20 Major projects 0.9 1.9 Exploration 0.9 0.9 18 Onshore US 0.9 0.3 Total 6.8 <8.0 10 <US$8 bn <US$8 bn US$6.8 bn Other* Coal Petroleum H2 Iron Ore Copper H1 0 FY12 FY13 FY14 FY15 FY16 FY17 FY18 FY19e FY20e Capital and exploration expenditure guidance unchanged at below US$8 billion per annum in FY19 and FY20 Note: Presented on a total operations basis. *Other includes discontinued operations (Onshore US assets). Financial results 21 August 2018 17Investing for the future Ongoing improvements in capital productivity are enabling us to thrive on lower levels of capex Capital and exploration expenditure FY18 FY19e US$ billion US$ billion (US$ billion) Maintenance 1.9 2.1 Improvement 1.9 2.2 Latent capacity 0.3 0.6 20 Major projects 0.9 1.9 Exploration 0.9 0.9 18 Onshore US 0.9 0.3 Total 6.8 <8.0 10 <US$8 bn <US$8 bn US$6.8 bn Other* Coal Petroleum H2 Iron Ore Copper H1 0 FY12 FY13 FY14 FY15 FY16 FY17 FY18 FY19e FY20e Capital and exploration expenditure guidance unchanged at below US$8 billion per annum in FY19 and FY20 Note: Presented on a total operations basis. *Other includes discontinued operations (Onshore US assets). Financial results 21 August 2018 17

Return on Capital Employed FY18 ROCE improves to 14% (after tax) or ~18% excluding Onshore US ROCE by asset (%) 19 Antamina NSWEC Productivity, technology, latent capacity to drive 35 further improvement Pampa Norte 19 25 Cerrejón Improving prices and FY17 ROCE record throughput High-return Queensland options to slow WAIO 15 Coal field decline Escondida Conventional SMA, BFX 5 Petroleum 20 Olympic Dam Sale announced for US$10.8 bn Potash Onshore US (5) 0 10 20 30 40 50 60 70 Average capital employed (US$ billion) 21 Exploration We expect our asset-level plans, coupled with the Onshore US exit, to drive continued medium-term ROCE improvement Note: Presented on a total operations basis. Financial results 21 August 2018 18Return on Capital Employed FY18 ROCE improves to 14% (after tax) or ~18% excluding Onshore US ROCE by asset (%) 19 Antamina NSWEC Productivity, technology, latent capacity to drive 35 further improvement Pampa Norte 19 25 Cerrejón Improving prices and FY17 ROCE record throughput High-return Queensland options to slow WAIO 15 Coal field decline Escondida Conventional SMA, BFX 5 Petroleum 20 Olympic Dam Sale announced for US$10.8 bn Potash Onshore US (5) 0 10 20 30 40 50 60 70 Average capital employed (US$ billion) 21 Exploration We expect our asset-level plans, coupled with the Onshore US exit, to drive continued medium-term ROCE improvement Note: Presented on a total operations basis. Financial results 21 August 2018 18

Financial results Year ended 30 June 2018 Andrew Mackenzie Chief Executive Officer YandiFinancial results Year ended 30 June 2018 Andrew Mackenzie Chief Executive Officer Yandi

Market outlook Near-term uncertainty, attractive long-term fundamentals Short term Medium term Long term Growth in New demand Policy Growth Steeper New supply population, centres and uncertainty moderating cost curves wealth themes Decarbonisation Sentiment Prudently Sustainable Emerging and Technology mixed cautious productivity Asia electrification Financial results 21 August 2018 20Market outlook Near-term uncertainty, attractive long-term fundamentals Short term Medium term Long term Growth in New demand Policy Growth Steeper New supply population, centres and uncertainty moderating cost curves wealth themes Decarbonisation Sentiment Prudently Sustainable Emerging and Technology mixed cautious productivity Asia electrification Financial results 21 August 2018 20

Our strategy Value and returns are at the centre of everything we do Simple portfolio Distinctive enablers Shareholder value and Diversified exposure to preferred Charter Values and returns commodities culture of connectivity Safety, productivity and Tier 1 upstream assets operational excellence Technology and systems to Attractive geographies optimise resource and capital Capital discipline, balance sheet Social Valuable options strength and shareholder returns purpose Financial results 21 August 2018 21Our strategy Value and returns are at the centre of everything we do Simple portfolio Distinctive enablers Shareholder value and Diversified exposure to preferred Charter Values and returns commodities culture of connectivity Safety, productivity and Tier 1 upstream assets operational excellence Technology and systems to Attractive geographies optimise resource and capital Capital discipline, balance sheet Social Valuable options strength and shareholder returns purpose Financial results 21 August 2018 21

Simple portfolio 22 We have reshaped our portfolio through the demerger of South32 and US$18 billion of divestments Large assets Long-life Low-cost Upstream ~2x ~70% >30% >80% ~50% 0% 0% 0 FY13 Current FY13 Current FY13 Current FY13 Current Average Cu Eq resource size per minerals Proportion of minerals assets with EBITDA margins at FY18 average realised Cu Eq unit costs of current portfolio asset 'Life of Asset' planning >50 years prices Diversified Simple Expandable Low-risk Non-OECD Petroleum Coal ~$16bn >$15bn 30 13 0 >90% OECD Copper Latent capacity Future options 0 Iron Ore Average >100% IRRs Average ~17% IRRs FY13 Current 23 6 FY18 EBITDA contribution Unrisked NPV (US$) FY18 EBITDA proportion in OECD countries Operated assets Note: Average Cu Eq resource size per minerals asset resource base (equity share basis) is converted to copper equivalent tonnes using FY17 prices; metal resources converted on a contained metal basis; refer to disclaimer on slide 39 and detailed tables for Mineral Resources in the Appendix, slides 40 to 42. Financial results 21 August 2018 22Simple portfolio 22 We have reshaped our portfolio through the demerger of South32 and US$18 billion of divestments Large assets Long-life Low-cost Upstream ~2x ~70% >30% >80% ~50% 0% 0% 0 FY13 Current FY13 Current FY13 Current FY13 Current Average Cu Eq resource size per minerals Proportion of minerals assets with EBITDA margins at FY18 average realised Cu Eq unit costs of current portfolio asset 'Life of Asset' planning >50 years prices Diversified Simple Expandable Low-risk Non-OECD Petroleum Coal ~$16bn >$15bn 30 13 0 >90% OECD Copper Latent capacity Future options 0 Iron Ore Average >100% IRRs Average ~17% IRRs FY13 Current 23 6 FY18 EBITDA contribution Unrisked NPV (US$) FY18 EBITDA proportion in OECD countries Operated assets Note: Average Cu Eq resource size per minerals asset resource base (equity share basis) is converted to copper equivalent tonnes using FY17 prices; metal resources converted on a contained metal basis; refer to disclaimer on slide 39 and detailed tables for Mineral Resources in the Appendix, slides 40 to 42. Financial results 21 August 2018 22

Distinctive enablers Over recent years, we have become simpler and more productive with a stronger culture, but there is more to do Delivered Future plans Culture • From command/control to front line empowerment • Zero fatalities Safety • TRIF down 6%, Field Leadership rolled out • Front line continuous improvement • Employee surveys show strengthening culture • Culture of connectivity, team of teams Connectivity • Even more nimble and less bureaucratic • Improvement in ‘Engage’ and ‘Develop’ metrics Simplification 22 • South32 demerger and ~US$18 bn of divestments • Potential for more copper and oil growth Portfolio • Over US$15 bn net debt reduction • Net debt in target range through commodity price cycle • Fewer management layers Structure • Globalised functions, Centres of Excellence Productivity • BHP Operating System – increased standardised work, • ~US$12 bn annualised productivity gains Assets continuous improvement, leveraging technology • >30% reduction in Cu Eq unit costs • Value Chain Automation – automation, machine learning • World Class Functions – streamlined end-to-end processes • ~50% reduction in annual Group overheads Functions to reflect simpler portfolio Note: ‘Delivered’ refers to FY13 to FY18. Financial results 21 August 2018 23Distinctive enablers Over recent years, we have become simpler and more productive with a stronger culture, but there is more to do Delivered Future plans Culture • From command/control to front line empowerment • Zero fatalities Safety • TRIF down 6%, Field Leadership rolled out • Front line continuous improvement • Employee surveys show strengthening culture • Culture of connectivity, team of teams Connectivity • Even more nimble and less bureaucratic • Improvement in ‘Engage’ and ‘Develop’ metrics Simplification 22 • South32 demerger and ~US$18 bn of divestments • Potential for more copper and oil growth Portfolio • Over US$15 bn net debt reduction • Net debt in target range through commodity price cycle • Fewer management layers Structure • Globalised functions, Centres of Excellence Productivity • BHP Operating System – increased standardised work, • ~US$12 bn annualised productivity gains Assets continuous improvement, leveraging technology • >30% reduction in Cu Eq unit costs • Value Chain Automation – automation, machine learning • World Class Functions – streamlined end-to-end processes • ~50% reduction in annual Group overheads Functions to reflect simpler portfolio Note: ‘Delivered’ refers to FY13 to FY18. Financial results 21 August 2018 23

Our strategy in action Value and returns agenda delivered through continued delivery across our six focus areas Cost efficiencies Technology Latent capacity 12 years 4 4 major initiatives implemented: of continued WAIO unit cost reduction, projects progressing to plan: automation of ship-loader pilot, volumetric C1 costs excluding third party royalties WAIO 290 Mtpa, Olympic Dam SMA, train loading, automated drills, 7 of US$13.03/t Caval Ridge Southern Circuit, EWSE robotic process automation Exploration Onshore US Major projects Exploration 5 4 US$10.8 bn projects progressing to plan: Petroleum exploration wells encountered sale announced: South Flank, SGO, Mad Dog 2, Greater hydrocarbons; results being assessed net proceeds expected to be returned to Western Flank-B, Jansen shafts Wildling, Samurai, Victoria, Bongos shareholders Note: SMA – Southern Mine Area; EWSE – Escondida Water Supply Expansion; SGO – Spence Growth option. Financial results 21 August 2018 24Our strategy in action Value and returns agenda delivered through continued delivery across our six focus areas Cost efficiencies Technology Latent capacity 12 years 4 4 major initiatives implemented: of continued WAIO unit cost reduction, projects progressing to plan: automation of ship-loader pilot, volumetric C1 costs excluding third party royalties WAIO 290 Mtpa, Olympic Dam SMA, train loading, automated drills, 7 of US$13.03/t Caval Ridge Southern Circuit, EWSE robotic process automation Exploration Onshore US Major projects Exploration 5 4 US$10.8 bn projects progressing to plan: Petroleum exploration wells encountered sale announced: South Flank, SGO, Mad Dog 2, Greater hydrocarbons; results being assessed net proceeds expected to be returned to Western Flank-B, Jansen shafts Wildling, Samurai, Victoria, Bongos shareholders Note: SMA – Southern Mine Area; EWSE – Escondida Water Supply Expansion; SGO – Spence Growth option. Financial results 21 August 2018 24

Minerals Australia Productivity to drive cost reductions across our operations Queensland Coal strip ratio Record production at 7 mines, WAIO costs down 2% (Prime to product strip ratio) (Unit costs, US$/t) • WAIO costs flat in FY19 at <US$14/t 12 80 Cost – medium term <US$13/t efficiencies • Queensland Coal costs at US$68-72/t in FY19 due to strip ratio US$68-72/t 10 – medium term US$57/t 70 US$68/t Equipment productivity MCoE strategies 8 60 Production creep Minerals Australia volumes up ~5% in FY19 Technology US$57/t • WAIO: 290 Mtpa exit run rate in FY19 Strip ratio Unit cost Latent 6 50 • Queensland Coal: Caval Ridge Southern Circuit start-up FY15 FY16 FY17 FY18 FY19e FY20e FY21e Medium term capacity • Olympic Dam: increased ore from SMA • Nickel West: first production from sulphate plant in CY19 Olympic Dam mine development and jumbo productivity (Development kilometres) (Metres per jumbo per day) 50 8 Timed to maximise value and returns • WAIO: South Flank first ore targeted in CY21; will increase Major average grade and lump proportion 25 6 projects • Olympic Dam: increasing underground development kilometres in preparation for BFX 0% 42% 46% 58% 68% 75% 0 4 FY16 FY17 FY18 FY19e FY20e FY21e SMA % of development Total development Jumbo productivity Note: BFX – Brownfield Expansion; NMA – Northern Mine Area; SMA – Southern Mine Area; MCoE – Maintenance Centre of Excellence. Financial results 21 August 2018 25Minerals Australia Productivity to drive cost reductions across our operations Queensland Coal strip ratio Record production at 7 mines, WAIO costs down 2% (Prime to product strip ratio) (Unit costs, US$/t) • WAIO costs flat in FY19 at <US$14/t 12 80 Cost – medium term <US$13/t efficiencies • Queensland Coal costs at US$68-72/t in FY19 due to strip ratio US$68-72/t 10 – medium term US$57/t 70 US$68/t Equipment productivity MCoE strategies 8 60 Production creep Minerals Australia volumes up ~5% in FY19 Technology US$57/t • WAIO: 290 Mtpa exit run rate in FY19 Strip ratio Unit cost Latent 6 50 • Queensland Coal: Caval Ridge Southern Circuit start-up FY15 FY16 FY17 FY18 FY19e FY20e FY21e Medium term capacity • Olympic Dam: increased ore from SMA • Nickel West: first production from sulphate plant in CY19 Olympic Dam mine development and jumbo productivity (Development kilometres) (Metres per jumbo per day) 50 8 Timed to maximise value and returns • WAIO: South Flank first ore targeted in CY21; will increase Major average grade and lump proportion 25 6 projects • Olympic Dam: increasing underground development kilometres in preparation for BFX 0% 42% 46% 58% 68% 75% 0 4 FY16 FY17 FY18 FY19e FY20e FY21e SMA % of development Total development Jumbo productivity Note: BFX – Brownfield Expansion; NMA – Northern Mine Area; SMA – Southern Mine Area; MCoE – Maintenance Centre of Excellence. Financial results 21 August 2018 25

Minerals Americas Driving productivity, releasing latent capacity and investing in major projects Strong Escondida production despite grade decline Escondida mining cost down 15%, record throughput (Production, kt) (Concentrator head grade, %) • Signed new collective agreement Cost • Volumes to average ~1.2 Mtpa to 2025 1.4 1,200 efficiencies 24 • FY19 unit costs at <US$1.15/lb Average production 1.2Mtpa – up 7% despite >15% grade decline 1.1 800 0.8 400 Escondida – LCE delivered, EWSE underway Concentrator head grade Production • Continued runtime improvement for all three concentrators 0 0.5 Latent FY14 FY15 FY16 FY17 FY18 FY19eFY20eFY21eFY22eFY23e Spence record production in FY18 to 200 kt capacity • Throughput up >16% and recoveries up ~10% since FY15 Spence production record despite grade decline (Production, kt) (Head grade, %) 400 1.4 Desalination projects secure future for Chilean assets • Desalinated water use at Escondida to ~40% in FY18 1.1 Major SGO on schedule and budget 200 projects • 14% complete, on track for first production in FY21 0.8 Jansen a valuable option Head grade Production • Expected lowest FOB costs in world’s best potash basin 0 0.5 FY14 FY15 FY16 FY17 FY18 FY19eFY20eFY21eFY22eFY23e Note: LCE – Los Colorados Extension; EWSE – Escondida Water Supply Expansion; SGO – Spence Growth Option. Financial results 21 August 2018 26Minerals Americas Driving productivity, releasing latent capacity and investing in major projects Strong Escondida production despite grade decline Escondida mining cost down 15%, record throughput (Production, kt) (Concentrator head grade, %) • Signed new collective agreement Cost • Volumes to average ~1.2 Mtpa to 2025 1.4 1,200 efficiencies 24 • FY19 unit costs at <US$1.15/lb Average production 1.2Mtpa – up 7% despite >15% grade decline 1.1 800 0.8 400 Escondida – LCE delivered, EWSE underway Concentrator head grade Production • Continued runtime improvement for all three concentrators 0 0.5 Latent FY14 FY15 FY16 FY17 FY18 FY19eFY20eFY21eFY22eFY23e Spence record production in FY18 to 200 kt capacity • Throughput up >16% and recoveries up ~10% since FY15 Spence production record despite grade decline (Production, kt) (Head grade, %) 400 1.4 Desalination projects secure future for Chilean assets • Desalinated water use at Escondida to ~40% in FY18 1.1 Major SGO on schedule and budget 200 projects • 14% complete, on track for first production in FY21 0.8 Jansen a valuable option Head grade Production • Expected lowest FOB costs in world’s best potash basin 0 0.5 FY14 FY15 FY16 FY17 FY18 FY19eFY20eFY21eFY22eFY23e Note: LCE – Los Colorados Extension; EWSE – Escondida Water Supply Expansion; SGO – Spence Growth Option. Financial results 21 August 2018 26

Conventional Petroleum Extending production runway and securing next wave of growth 25,26 Leading Finding and Development costs ~1 Bboe 1P reserves replaced over the last decade (10-year average, US$/boe) • F&D costs >20% lower than peers and >30% lower than sector 40 Latent • ~30 brownfield projects with average returns of ~40% capacity • West Barracouta investment decision expected in FY19 • Brownfield options help offset base decline over next 5 years 20 Current investments profitable below US$50/bbl • Greater Western Flank-B first production in FY19 0 • Mad Dog 2 on plan for first oil in FY22, 23% complete Major BHP Peers Sector Pipeline of 8 projects with average returns of >25% projects 27 Exploration wells and success rate • Atlantis 3, Ruby investment decisions in next 12 months (Net exploration wells) (Productive wells/wells drilled, %) • Scarborough LNG processing options being progressed 6 100 Trion and LeClerc increase 2C resources by ~16% • GoM: Samurai-2 discovery adjacent to Wildling 3 50 • Trinidad: Victoria-1 encountered gas in Q4 FY18 Exploration • Trinidad: Bongos-2 encountered hydrocarbons in Q1 FY19 • Mexico: Trion appraisal drilling planned in Q2 FY19 0 0 FY17 FY18 FY19 (YTD) Net exploration wells Technical success rate (RHS) Note: GoM – Gulf of Mexico; F&D – Finding and Development; reported additions for 2008 through 2017. Financial results 21 August 2018 27Conventional Petroleum Extending production runway and securing next wave of growth 25,26 Leading Finding and Development costs ~1 Bboe 1P reserves replaced over the last decade (10-year average, US$/boe) • F&D costs >20% lower than peers and >30% lower than sector 40 Latent • ~30 brownfield projects with average returns of ~40% capacity • West Barracouta investment decision expected in FY19 • Brownfield options help offset base decline over next 5 years 20 Current investments profitable below US$50/bbl • Greater Western Flank-B first production in FY19 0 • Mad Dog 2 on plan for first oil in FY22, 23% complete Major BHP Peers Sector Pipeline of 8 projects with average returns of >25% projects 27 Exploration wells and success rate • Atlantis 3, Ruby investment decisions in next 12 months (Net exploration wells) (Productive wells/wells drilled, %) • Scarborough LNG processing options being progressed 6 100 Trion and LeClerc increase 2C resources by ~16% • GoM: Samurai-2 discovery adjacent to Wildling 3 50 • Trinidad: Victoria-1 encountered gas in Q4 FY18 Exploration • Trinidad: Bongos-2 encountered hydrocarbons in Q1 FY19 • Mexico: Trion appraisal drilling planned in Q2 FY19 0 0 FY17 FY18 FY19 (YTD) Net exploration wells Technical success rate (RHS) Note: GoM – Gulf of Mexico; F&D – Finding and Development; reported additions for 2008 through 2017. Financial results 21 August 2018 27

Delivered our plans in FY18… Maximise cash flow Capital discipline Value and returns +8% >US$5 bn 14.4% ROCE Cu Eq volume growth net debt reduction to US$10.9 bn ~18% excluding Onshore US >US$12 bn US$6.8 bn 63 US cps free cash flow for second year capex within guidance record H2 dividend Unit costs Organic opportunities Onshore US in line with guidance, sanctioned SGO, South Flank; clean exit for value, quality H2 productivity momentum carried completed 2 latent capacity projects counterparties, cash consideration into FY19 Note: SGO – Spence Growth Option. Financial results 21 August 2018 28Delivered our plans in FY18… Maximise cash flow Capital discipline Value and returns +8% >US$5 bn 14.4% ROCE Cu Eq volume growth net debt reduction to US$10.9 bn ~18% excluding Onshore US >US$12 bn US$6.8 bn 63 US cps free cash flow for second year capex within guidance record H2 dividend Unit costs Organic opportunities Onshore US in line with guidance, sanctioned SGO, South Flank; clean exit for value, quality H2 productivity momentum carried completed 2 latent capacity projects counterparties, cash consideration into FY19 Note: SGO – Spence Growth Option. Financial results 21 August 2018 28

…expect to further deliver in FY19… Maximise cash flow Capital discipline Value and returns Cu Eq volumes Net debt ~18% ROCE broadly flat in FY19 to remain at lower end of target range at spot prices ~US$9 bn <US$8.0 bn Minimum 50% free cash flow at spot prices capex guidance of underlying earnings as dividends ~US$1 bn productivity Organic opportunities Net shale proceeds gains targeted continued development of 4 latent expected to be returned following capacity and 5 major projects completion of Onshore US sale Note: Spot prices as of 3 August 2018; 4 latent capacity projects include WAIO 290 Mtpa, Caval Ridge Southern Circuit, Olympic Dam Southern Mine Area and Escondida Water Supply Expansion; 5 major projects include Greater Western Flank-B, Mad Dog 2, Spence Growth Option, South Flank and completion of the Jansen shafts. Financial results 21 August 2018 29…expect to further deliver in FY19… Maximise cash flow Capital discipline Value and returns Cu Eq volumes Net debt ~18% ROCE broadly flat in FY19 to remain at lower end of target range at spot prices ~US$9 bn <US$8.0 bn Minimum 50% free cash flow at spot prices capex guidance of underlying earnings as dividends ~US$1 bn productivity Organic opportunities Net shale proceeds gains targeted continued development of 4 latent expected to be returned following capacity and 5 major projects completion of Onshore US sale Note: Spot prices as of 3 August 2018; 4 latent capacity projects include WAIO 290 Mtpa, Caval Ridge Southern Circuit, Olympic Dam Southern Mine Area and Escondida Water Supply Expansion; 5 major projects include Greater Western Flank-B, Mad Dog 2, Spence Growth Option, South Flank and completion of the Jansen shafts. Financial results 21 August 2018 29

…and have a clear path forward over the medium term Maximise cash flow Capital discipline Value and returns Lower costs US$10-15 bn net debt ROCE to ~20% productivity, technology, culture range to be maintained by FY22 (at FY17 prices) Volume growth <US$8 bn capex 40% base value upside productivity, project delivery per annum to FY20 potential across our 6 focus areas Constructive outlook Organic opportunities Shareholder returns for our commodities, rich option set across commodities minimum 50% payout ratio dividend, solid demand, disciplined supply and time periods return of Onshore US net proceeds* Note: Disciplined supply: reflects lower levels of investment across the industry. ROCE and base value uplift: based on Global Metals, Mining and Steel Conference presentation on 15 May 2018. * Onshore US: Sale announced for US$10.8 billion (less customary completion adjustments); we expect to return the net proceeds from the transactions to shareholders; we will confirm how and when at the time of completion of the transactions. . Financial results 21 August 2018 30…and have a clear path forward over the medium term Maximise cash flow Capital discipline Value and returns Lower costs US$10-15 bn net debt ROCE to ~20% productivity, technology, culture range to be maintained by FY22 (at FY17 prices) Volume growth <US$8 bn capex 40% base value upside productivity, project delivery per annum to FY20 potential across our 6 focus areas Constructive outlook Organic opportunities Shareholder returns for our commodities, rich option set across commodities minimum 50% payout ratio dividend, solid demand, disciplined supply and time periods return of Onshore US net proceeds* Note: Disciplined supply: reflects lower levels of investment across the industry. ROCE and base value uplift: based on Global Metals, Mining and Steel Conference presentation on 15 May 2018. * Onshore US: Sale announced for US$10.8 billion (less customary completion adjustments); we expect to return the net proceeds from the transactions to shareholders; we will confirm how and when at the time of completion of the transactions. . Financial results 21 August 2018 30

AppendixAppendix

Technology Integration and automation of our value chains to unlock resources and drive a step change in safety, volume and cost MARKETING GEOSCIENCE & PLANNING MINING PROCESSING TRANSPORT • Optimised planning • Improved train • Meet specific customer • Autonomous systems • Advanced process scheduling demand while control • Real time resource • Automated drill and maximising realised • Real time monitoring characterisation blast • Improved tracking of price WAIO ore quality and optimisation of • Dynamic Live4D model • Extraction and track conditions and • Increased direct movement automation • Processing automation • Real time work plans port shipping and integration • Optimised planning • High productivity • Advanced process • Replicating successes from other minerals assets for extraction systems control optimised logistics and improved customer satisfaction • Real time resource • Optimised shovel truck characterisation • Precision mining Escondida system • Dynamic Live4D model • Next-generation • Material movement concentrator • Real time work plans optimised for value Enable further cost efficiencies Unlock margin uplift potentials Financial results 21 August 2018 33Technology Integration and automation of our value chains to unlock resources and drive a step change in safety, volume and cost MARKETING GEOSCIENCE & PLANNING MINING PROCESSING TRANSPORT • Optimised planning • Improved train • Meet specific customer • Autonomous systems • Advanced process scheduling demand while control • Real time resource • Automated drill and maximising realised • Real time monitoring characterisation blast • Improved tracking of price WAIO ore quality and optimisation of • Dynamic Live4D model • Extraction and track conditions and • Increased direct movement automation • Processing automation • Real time work plans port shipping and integration • Optimised planning • High productivity • Advanced process • Replicating successes from other minerals assets for extraction systems control optimised logistics and improved customer satisfaction • Real time resource • Optimised shovel truck characterisation • Precision mining Escondida system • Dynamic Live4D model • Next-generation • Material movement concentrator • Real time work plans optimised for value Enable further cost efficiencies Unlock margin uplift potentials Financial results 21 August 2018 33

BHP guidance Group FY19e Capital and exploration expenditure (US$ bn) <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 stripping of US$1.0 billion for FY19. Improvement 2.2 Includes North West Shelf Greater Western Flank-B, Conventional Petroleum infill drilling and South Flank. Includes Escondida Water Supply Extension, Caval Ridge Southern Circuit, Olympic Dam Southern Mine Area, Western Australia Iron Latent capacity 0.6 Ore to 290 Mtpa. Major growth 1.9 Includes Spence Growth Option, Mad Dog Phase 2, Jansen. Exploration 0.9 Includes US$750 million Petroleum and ~US$70 million Copper exploration program planned for FY19. Until completion of divestment, expected by the end of October 2018, we intend to operate five rigs in Onshore US and incur capital Onshore US 0.3 expenditure at an annualised rate broadly consistent with the 2018 financial year. Petroleum FY19e Total Conventional petroleum production (MMboe) 113 – 118 Given our intention to exit Onshore US, no annual guidance for the 2019 financial year for these assets will be provided; however, until completion, we expect a production run rate broadly consistent with the second half of the 2018 financial year. Infill drilling projects are more than offset by planned dry dock maintenance at Pyrenees and natural field decline across the portfolio. Conventional Petroleum Capital expenditure (US$m) 730 Primarily focused on progressing the Mad Dog Phase 2 project and completing the North West Shelf Greater Western Flank-B project. Unit cost (US$/boe) <11 Excludes inventory movements, embedded derivatives movements, freight, third party product purchases and exploration expense. Based on exchange rates of AUD/USD 0.75. Exploration (US$m) 750 Focused on Mexico, the Gulf of Mexico and the Caribbean. Financial results 21 August 2018 34BHP guidance Group FY19e Capital and exploration expenditure (US$ bn) <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 stripping of US$1.0 billion for FY19. Improvement 2.2 Includes North West Shelf Greater Western Flank-B, Conventional Petroleum infill drilling and South Flank. Includes Escondida Water Supply Extension, Caval Ridge Southern Circuit, Olympic Dam Southern Mine Area, Western Australia Iron Latent capacity 0.6 Ore to 290 Mtpa. Major growth 1.9 Includes Spence Growth Option, Mad Dog Phase 2, Jansen. Exploration 0.9 Includes US$750 million Petroleum and ~US$70 million Copper exploration program planned for FY19. Until completion of divestment, expected by the end of October 2018, we intend to operate five rigs in Onshore US and incur capital Onshore US 0.3 expenditure at an annualised rate broadly consistent with the 2018 financial year. Petroleum FY19e Total Conventional petroleum production (MMboe) 113 – 118 Given our intention to exit Onshore US, no annual guidance for the 2019 financial year for these assets will be provided; however, until completion, we expect a production run rate broadly consistent with the second half of the 2018 financial year. Infill drilling projects are more than offset by planned dry dock maintenance at Pyrenees and natural field decline across the portfolio. Conventional Petroleum Capital expenditure (US$m) 730 Primarily focused on progressing the Mad Dog Phase 2 project and completing the North West Shelf Greater Western Flank-B project. Unit cost (US$/boe) <11 Excludes inventory movements, embedded derivatives movements, freight, third party product purchases and exploration expense. Based on exchange rates of AUD/USD 0.75. Exploration (US$m) 750 Focused on Mexico, the Gulf of Mexico and the Caribbean. Financial results 21 August 2018 34

BHP guidance (continued) Copper FY19e Total copper production (Mt) 1.68 – 1.77 Includes Escondida at 1.12 - 1.18 Mt. Escondida Production (Mt, 100% basis) 1.12 – 1.18 Reflects significant decrease in average concentrator head grade consistent with the mine plan. Unit cash costs (US$/lb) <1.15 Excludes freight and treatment and refining charges; net of by-product credits; includes costs to settle labour negotiations; based on an exchange rate of USD/CLP 663. Iron Ore FY19e Total iron ore production (Mt) 241 – 250 A program of work to optimise maintenance schedules across our supply chain and improve port reliability and performance is planned for the first half of the 2019 financial year, with a corresponding impact expected on production and unit costs. Excludes production from Samarco. Western Australia Iron Ore Production (Mt, 100% basis) 273 – 283 Unit cash costs (US$/t) <14 Excludes freight and royalties; based on an exchange rate of AUD/USD 0.75. Sustaining capital expenditure (US$/t) 4 Medium term average; +/- 50% in any given year. Includes South Flank of US$45 per tonne. Coal FY19e Total metallurgical coal production (Mt) 43 – 46 An extensive maintenance program is planned for the first half of the 2019 financial year, with a corresponding impact also expected on unit costs. Total energy coal production (Mt) 28 – 29 Queensland Coal Production (Mt) 43 – 46 Unit cash costs (US$/t) 68 – 72 Excludes freight and royalties; based on an exchange rate of AUD/USD 0.75. Sustaining capital expenditure (US$/t) 8 Medium term average; +/- 50% in any given year. NSW Energy Coal Unit cash costs (US$/t) 43 – 48 Excludes freight and royalties; based on an exchange rate of AUD/USD 0.75. Sustaining capital expenditure (US$/t) 5 Medium term average; +/- 50% in any given year. Financial results 21 August 2018 35BHP guidance (continued) Copper FY19e Total copper production (Mt) 1.68 – 1.77 Includes Escondida at 1.12 - 1.18 Mt. Escondida Production (Mt, 100% basis) 1.12 – 1.18 Reflects significant decrease in average concentrator head grade consistent with the mine plan. Unit cash costs (US$/lb) <1.15 Excludes freight and treatment and refining charges; net of by-product credits; includes costs to settle labour negotiations; based on an exchange rate of USD/CLP 663. Iron Ore FY19e Total iron ore production (Mt) 241 – 250 A program of work to optimise maintenance schedules across our supply chain and improve port reliability and performance is planned for the first half of the 2019 financial year, with a corresponding impact expected on production and unit costs. Excludes production from Samarco. Western Australia Iron Ore Production (Mt, 100% basis) 273 – 283 Unit cash costs (US$/t) <14 Excludes freight and royalties; based on an exchange rate of AUD/USD 0.75. Sustaining capital expenditure (US$/t) 4 Medium term average; +/- 50% in any given year. Includes South Flank of US$45 per tonne. Coal FY19e Total metallurgical coal production (Mt) 43 – 46 An extensive maintenance program is planned for the first half of the 2019 financial year, with a corresponding impact also expected on unit costs. Total energy coal production (Mt) 28 – 29 Queensland Coal Production (Mt) 43 – 46 Unit cash costs (US$/t) 68 – 72 Excludes freight and royalties; based on an exchange rate of AUD/USD 0.75. Sustaining capital expenditure (US$/t) 8 Medium term average; +/- 50% in any given year. NSW Energy Coal Unit cash costs (US$/t) 43 – 48 Excludes freight and royalties; based on an exchange rate of AUD/USD 0.75. Sustaining capital expenditure (US$/t) 5 Medium term average; +/- 50% in any given year. Financial results 21 August 2018 35

Key Underlying EBITDA sensitivities 28 Approximate impact on FY19 Underlying EBITDA of changes of: US$ million 29 US$1/t on iron ore price 227 30 US$1/bbl on oil price 43 US$1/t on metallurgical coal price 41 29 US¢1/lb on copper price 35 29 US$1/t on energy coal price 17 US¢1/lb on nickel price 1 31 AUD (US¢1/A$) operations 116 Note: Oil price impact presented on a continuing operations basis. Financial results 21 August 2018 36Key Underlying EBITDA sensitivities 28 Approximate impact on FY19 Underlying EBITDA of changes of: US$ million 29 US$1/t on iron ore price 227 30 US$1/bbl on oil price 43 US$1/t on metallurgical coal price 41 29 US¢1/lb on copper price 35 29 US$1/t on energy coal price 17 US¢1/lb on nickel price 1 31 AUD (US¢1/A$) operations 116 Note: Oil price impact presented on a continuing operations basis. Financial results 21 August 2018 36

Debt maturity profile 32,33 Debt balances (US$ billion) 8 6 4 2 0 FY19 FY20 FY21 FY22 FY23 FY24 FY25 FY26 FY27 FY28 FY29 Post FY29 US$ Euro Sterling A$ C$ 34 34 34 Bonds Bonds Bonds Bonds Bonds Subsidiaries % of portfolio 10% 38% 34% 12% 3% 3% Capital markets 90% Asset financing 10% Financial results 21 August 2018 37Debt maturity profile 32,33 Debt balances (US$ billion) 8 6 4 2 0 FY19 FY20 FY21 FY22 FY23 FY24 FY25 FY26 FY27 FY28 FY29 Post FY29 US$ Euro Sterling A$ C$ 34 34 34 Bonds Bonds Bonds Bonds Bonds Subsidiaries % of portfolio 10% 38% 34% 12% 3% 3% Capital markets 90% Asset financing 10% Financial results 21 August 2018 37

Statement of Petroleum resources Petroleum resources The estimates of Conventional Petroleum reserves and contingent resources contained in this presentation are on a Net interest basis and 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. Aggregates of reserves and contingent resources estimates contained in this presentation have been calculated by arithmetic summation of field/project estimates by category. The aggregate 1P reserves may be conservative due to the portfolio effects of arithmetic summation. Reserves and contingent resources estimates contained in this presentation have been estimated using deterministic methodology with the exception of the North West Shelf gas asset in Australia where probabilistic methodology has been utilised to estimate and aggregate reserves and contingent resources for the reservoirs dedicated to the gas project only. The probabilistic based portion of these reserves totals 23 MMboe (total boe conversion is based on the following: 6,000 scf of natural gas equals 1 boe) and represents approximately three per cent of our total reported conventional proved reserves. The reserves and contingent resources contained in this presentation are inclusive of fuel required for operations. The respective amounts of fuel for each category at 30 June 2018 are: 1P reserves: 910 MMboe (62 MMboe fuel), 2P reserves: 1,213 MMboe (81 MMboe fuel), 2C contingent resources: 1,512 MMboe (69 MMboe fuel), annual production 125 MMboe (5 MMboe fuel). At 30 June 2017 the respective amounts were 2P reserves 1,306 MMboe (74 MMboe fuel), 2C contingent resources: 1,235 MMboe (fuel 68 MMboe). 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 contained in this presentation have not been adjusted for risk. Unless noted otherwise, reserves and contingent resources are as at 30 June 2018. In this presentation millions of barrels of oil equivalent are abbreviated as MMboe and billions of barrels of oil equivalent are abbreviated as Bboe. BHP estimates proved reserve volumes according to SEC disclosure regulations and files these in our annual Form 20-F with the SEC. All unproved volumes are estimated using SPE-PRMS guidelines which 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. Non-proved estimates are inherently more uncertain than proved. Petroleum exploration well information Well Location Target Formation age BHP equity Spud date Water depth Total well depth Status (as of July 2018) LeClerc-1 Trinidad & Tobago Block TTDAA 5 Oil Pliocene 65% Operator 21 May 2016 1,800 metres 5,771 metres Hydrocarbons encountered; plugged and abandoned LeClerc-ST1 Trinidad & Tobago Block TTDAA 5 Oil Pliocene 100% Operator 6 July 2016 1,800 metres 6,973 metres Hydrocarbons encountered; plugged and abandoned Samurai-2 US Gulf of Mexico GC432 Oil Miocene 50% (Murphy Operator) 16 April 2018 1,088 metres 9,574 metres Hydrocarbons encountered; drilling ahead Victoria-1 Trinidad & Tobago Block TTDAA 5 Gas Pleistocene/Pliocene 65% Operator 12 June 2018 1,828 metres 3,174 metres Hydrocarbons encountered; plugged and abandoned Bongo-1 Trinidad & Tobago Block TTDAA 14 Gas 70% Operator 20 July 2018 1,940 meters 2,190 metres Abandoned due to mechanical failure Pliocene/Miocene Bongos-2 Trinidad & Tobago Block TTDAA 14 Gas Pliocene/Miocene 70% Operator 22 July 2018 1,940 meters 2,991 metres Hydrocarbons encountered; drilling ahead LeClerc – 2C contingent resources 26 Net MMboe estimated as of 30 June 2018. Trion – 2C contingent resources of 166 Net MMboe estimated as of 29 August 2017 submitted to Comisión Nacional de Hidrocarburos (Mexico). Financial results 21 August 2018 38Statement of Petroleum resources Petroleum resources The estimates of Conventional Petroleum reserves and contingent resources contained in this presentation are on a Net interest basis and 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. Aggregates of reserves and contingent resources estimates contained in this presentation have been calculated by arithmetic summation of field/project estimates by category. The aggregate 1P reserves may be conservative due to the portfolio effects of arithmetic summation. Reserves and contingent resources estimates contained in this presentation have been estimated using deterministic methodology with the exception of the North West Shelf gas asset in Australia where probabilistic methodology has been utilised to estimate and aggregate reserves and contingent resources for the reservoirs dedicated to the gas project only. The probabilistic based portion of these reserves totals 23 MMboe (total boe conversion is based on the following: 6,000 scf of natural gas equals 1 boe) and represents approximately three per cent of our total reported conventional proved reserves. The reserves and contingent resources contained in this presentation are inclusive of fuel required for operations. The respective amounts of fuel for each category at 30 June 2018 are: 1P reserves: 910 MMboe (62 MMboe fuel), 2P reserves: 1,213 MMboe (81 MMboe fuel), 2C contingent resources: 1,512 MMboe (69 MMboe fuel), annual production 125 MMboe (5 MMboe fuel). At 30 June 2017 the respective amounts were 2P reserves 1,306 MMboe (74 MMboe fuel), 2C contingent resources: 1,235 MMboe (fuel 68 MMboe). 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 contained in this presentation have not been adjusted for risk. Unless noted otherwise, reserves and contingent resources are as at 30 June 2018. In this presentation millions of barrels of oil equivalent are abbreviated as MMboe and billions of barrels of oil equivalent are abbreviated as Bboe. BHP estimates proved reserve volumes according to SEC disclosure regulations and files these in our annual Form 20-F with the SEC. All unproved volumes are estimated using SPE-PRMS guidelines which 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. Non-proved estimates are inherently more uncertain than proved. Petroleum exploration well information Well Location Target Formation age BHP equity Spud date Water depth Total well depth Status (as of July 2018) LeClerc-1 Trinidad & Tobago Block TTDAA 5 Oil Pliocene 65% Operator 21 May 2016 1,800 metres 5,771 metres Hydrocarbons encountered; plugged and abandoned LeClerc-ST1 Trinidad & Tobago Block TTDAA 5 Oil Pliocene 100% Operator 6 July 2016 1,800 metres 6,973 metres Hydrocarbons encountered; plugged and abandoned Samurai-2 US Gulf of Mexico GC432 Oil Miocene 50% (Murphy Operator) 16 April 2018 1,088 metres 9,574 metres Hydrocarbons encountered; drilling ahead Victoria-1 Trinidad & Tobago Block TTDAA 5 Gas Pleistocene/Pliocene 65% Operator 12 June 2018 1,828 metres 3,174 metres Hydrocarbons encountered; plugged and abandoned Bongo-1 Trinidad & Tobago Block TTDAA 14 Gas 70% Operator 20 July 2018 1,940 meters 2,190 metres Abandoned due to mechanical failure Pliocene/Miocene Bongos-2 Trinidad & Tobago Block TTDAA 14 Gas Pliocene/Miocene 70% Operator 22 July 2018 1,940 meters 2,991 metres Hydrocarbons encountered; drilling ahead LeClerc – 2C contingent resources 26 Net MMboe estimated as of 30 June 2018. Trion – 2C contingent resources of 166 Net MMboe estimated as of 29 August 2017 submitted to Comisión Nacional de Hidrocarburos (Mexico). Financial results 21 August 2018 38

Mineral Resources and Competent Persons statement Competent Person Statement The information in this presentation that relates to the FY2017 and FY2013 Mineral Resources (inclusive of Ore Reserves) were first reported by the Company in compliance with the ‘Australasian Code for Reporting of Exploration Results, Mineral Resources and Ore Reserves, 2012’ (‘The JORC Code 2012 Edition’) in the 2017 BHP Annual Report and the 2013 BHP Billiton Annual Report respectively. Both reports are available to view on www.bhp.com. The detailed breakdown of Mineral Resources for all assets are shown in the Annual Reports on 100% basis, with corresponding BHP interest. Compilation of Mineral Resources information from 2013 is included in this presentation to provide a portfolio comparison between these two dates. Divested assets are no longer owned or operated by BHP and the majority of these were demerged into South32 in May 2015. Other divestments are noted in the corresponding BHP Annual Reports. In relation to the 2017 Mineral Resources, the company confirms that it is not aware of any new information or data that materially affects the Mineral Resources information included in the original 2017 market announcement and, in the case of estimates of Mineral Resources, that all material assumptions and technical parameters underpinning the estimates in the relevant market announcement continue to apply and have not materially changed. The company confirms that the form and context in which the Competent Persons’ findings are presented have not been materially modified from the original market announcement. The information in this presentation that relates to Mineral or Coal Resources is based on information compiled by: L Moharana (MAusIMM) for Western Australia Iron Ore (WAIO) and Divested assets (Alumar including MRN, Worsley, GEMCO, Hotazel); R Macpherson (MAIG) for Minerals Australia Energy Coal, Metallurgical Coal - Operations and Projects including Queensland CQCA-JV, Gregory JV and BHP Mitsui Coal and Projects and Divested assets (Illawarra Coal and BECSA); M Menicheli (MAusIMM) for Nickel West Operations and Nickel Colombia (Cerro Matoso); C Badenhorst (MAusIMM) for Olympic Dam; M Williams (MAusIMM) for Escondida District, Pampa Norte, Antamina, Pinto Valley, Cerrejón, New Mexico Coal, Samarco; J McElroy (MAusIMM) for Minerals Americas Jansen Project and M Furness (MAusIMM) for Cannington. All of the people listed above are full-time employees of BHP and have sufficient experience that is relevant to the style of mineralisation and type of deposit under consideration and to the activity which they are undertaking to qualify as Competent Persons as defined in the 2012 Edition of the ‘Australasian Code for Reporting of Exploration Results, Mineral Resources and Ore Reserves’ and consent to the inclusion in the presentation of the matters based on this information in the form and context in which it appears. Resources and metal equivalent calculations Please refer to detailed tables in the Appendix, slides 40 to 42, for Mineral Resource classifications (100% basis) for each asset / deposit included in the average copper equivalent resource size per minerals asset calculations on slide 22 of this presentation. Resource base (equity share basis) is converted to copper equivalent tonnes using FY2017 average realised prices as reported in the BHP results for the year ended 30 June 2017 for Metallurgical Coal, Energy Coal, Iron Ore, Copper and Nickel. The conversion of U3O8, Au, Ag, Zn and Pb use prices as reported in the BHP 2017 US Securities and Exchange Commission Form 20-F. Potash price used is US$216.55/t, Molybdenum US$7.41/lb, Aluminium US$1,771.26/t and Manganese Ore US$151.20/t. The reporting of Mineral Resources for polymetallic deposits in terms of metal equivalents (a single equivalent grade of one major metal) is based on FY2017 average realised prices as reported in the BHP results for the year ended 30 June 2017 for Cu and for other metals the BHP 2013 and 2017 Form 20-F submissions (unless otherwise stated). The metallurgical recoveries applied are those footnoted for the respective operations as footnoted in the corresponding Annual Reports from 2013 and 2017. It is the company’s opinion that all elements included in the metal equivalent calculation have a reasonable potential to be recovered and sold. No mining or metallurgical modifying factors were applied to the results. The following copper equivalent grade calculations are listed below. 2013 calculations Olympic Dam: CuEq = Cu % + (U3O8 kg/t x 1.064) + (Au g/t x 0.459) + (Ag g/t x 0.0089); Spence: CuEq = Cu % + (Mo % x 3.039); Antamina Sulphide Cu-only: CuEq = Cu % + (Mo % x 2.048) + (Ag g/t x 0.0097); Antamina Sulphide Cu-Zn: CuEq = Cu % + (Zn % x 0.45) + (Ag g/t x 0.0096); Cannington: PbEq = Pb % + (Ag g/t x 0.043) + (Zn % x 0.95), Molybdenum price used is US$11.18/lb. 2017 calculations Olympic Dam: CuEq = Cu % + (U3O8 kg/t x 0.978) + (Au g/t x 0.547) + (Ag g/t x 0.0077); Escondida: CuEq = Cu % + (Au g/t x 0.703); Spence: CuEq = Cu % + (Mo % x 2.917); Antamina Sulphide Cu-only: CuEq = Cu % + (Mo % x 1.966) + (Ag g/t x 0.0084); Antamina Sulphide Cu- Zn: CuEq = Cu % + (Zn % x 0.36) + (Ag g/t x 0.0083). Financial results 21 August 2018 39Mineral Resources and Competent Persons statement Competent Person Statement The information in this presentation that relates to the FY2017 and FY2013 Mineral Resources (inclusive of Ore Reserves) were first reported by the Company in compliance with the ‘Australasian Code for Reporting of Exploration Results, Mineral Resources and Ore Reserves, 2012’ (‘The JORC Code 2012 Edition’) in the 2017 BHP Annual Report and the 2013 BHP Billiton Annual Report respectively. Both reports are available to view on www.bhp.com. The detailed breakdown of Mineral Resources for all assets are shown in the Annual Reports on 100% basis, with corresponding BHP interest. Compilation of Mineral Resources information from 2013 is included in this presentation to provide a portfolio comparison between these two dates. Divested assets are no longer owned or operated by BHP and the majority of these were demerged into South32 in May 2015. Other divestments are noted in the corresponding BHP Annual Reports. In relation to the 2017 Mineral Resources, the company confirms that it is not aware of any new information or data that materially affects the Mineral Resources information included in the original 2017 market announcement and, in the case of estimates of Mineral Resources, that all material assumptions and technical parameters underpinning the estimates in the relevant market announcement continue to apply and have not materially changed. The company confirms that the form and context in which the Competent Persons’ findings are presented have not been materially modified from the original market announcement. The information in this presentation that relates to Mineral or Coal Resources is based on information compiled by: L Moharana (MAusIMM) for Western Australia Iron Ore (WAIO) and Divested assets (Alumar including MRN, Worsley, GEMCO, Hotazel); R Macpherson (MAIG) for Minerals Australia Energy Coal, Metallurgical Coal - Operations and Projects including Queensland CQCA-JV, Gregory JV and BHP Mitsui Coal and Projects and Divested assets (Illawarra Coal and BECSA); M Menicheli (MAusIMM) for Nickel West Operations and Nickel Colombia (Cerro Matoso); C Badenhorst (MAusIMM) for Olympic Dam; M Williams (MAusIMM) for Escondida District, Pampa Norte, Antamina, Pinto Valley, Cerrejón, New Mexico Coal, Samarco; J McElroy (MAusIMM) for Minerals Americas Jansen Project and M Furness (MAusIMM) for Cannington. All of the people listed above are full-time employees of BHP and have sufficient experience that is relevant to the style of mineralisation and type of deposit under consideration and to the activity which they are undertaking to qualify as Competent Persons as defined in the 2012 Edition of the ‘Australasian Code for Reporting of Exploration Results, Mineral Resources and Ore Reserves’ and consent to the inclusion in the presentation of the matters based on this information in the form and context in which it appears. Resources and metal equivalent calculations Please refer to detailed tables in the Appendix, slides 40 to 42, for Mineral Resource classifications (100% basis) for each asset / deposit included in the average copper equivalent resource size per minerals asset calculations on slide 22 of this presentation. Resource base (equity share basis) is converted to copper equivalent tonnes using FY2017 average realised prices as reported in the BHP results for the year ended 30 June 2017 for Metallurgical Coal, Energy Coal, Iron Ore, Copper and Nickel. The conversion of U3O8, Au, Ag, Zn and Pb use prices as reported in the BHP 2017 US Securities and Exchange Commission Form 20-F. Potash price used is US$216.55/t, Molybdenum US$7.41/lb, Aluminium US$1,771.26/t and Manganese Ore US$151.20/t. The reporting of Mineral Resources for polymetallic deposits in terms of metal equivalents (a single equivalent grade of one major metal) is based on FY2017 average realised prices as reported in the BHP results for the year ended 30 June 2017 for Cu and for other metals the BHP 2013 and 2017 Form 20-F submissions (unless otherwise stated). The metallurgical recoveries applied are those footnoted for the respective operations as footnoted in the corresponding Annual Reports from 2013 and 2017. It is the company’s opinion that all elements included in the metal equivalent calculation have a reasonable potential to be recovered and sold. No mining or metallurgical modifying factors were applied to the results. The following copper equivalent grade calculations are listed below. 2013 calculations Olympic Dam: CuEq = Cu % + (U3O8 kg/t x 1.064) + (Au g/t x 0.459) + (Ag g/t x 0.0089); Spence: CuEq = Cu % + (Mo % x 3.039); Antamina Sulphide Cu-only: CuEq = Cu % + (Mo % x 2.048) + (Ag g/t x 0.0097); Antamina Sulphide Cu-Zn: CuEq = Cu % + (Zn % x 0.45) + (Ag g/t x 0.0096); Cannington: PbEq = Pb % + (Ag g/t x 0.043) + (Zn % x 0.95), Molybdenum price used is US$11.18/lb. 2017 calculations Olympic Dam: CuEq = Cu % + (U3O8 kg/t x 0.978) + (Au g/t x 0.547) + (Ag g/t x 0.0077); Escondida: CuEq = Cu % + (Au g/t x 0.703); Spence: CuEq = Cu % + (Mo % x 2.917); Antamina Sulphide Cu-only: CuEq = Cu % + (Mo % x 1.966) + (Ag g/t x 0.0084); Antamina Sulphide Cu- Zn: CuEq = Cu % + (Zn % x 0.36) + (Ag g/t x 0.0083). Financial results 21 August 2018 39

Mineral Resources (100% basis) Commodity BHP interest Financial Year Measured Resources (Mt) Indicated Resources (Mt) Inferred Resources (Mt) Deposit % Minerals Australia Iron Ore WAIO 2017 2,740 5,930 20,390 88 2013 2,550 4,210 14,560 88 Energy Coal Operations - Mt Arthur Coal 2017 897 1,299 1,019 100 2013 887 2,169 670 100 Projects - Togara South 2017 719 177 1,051 100 2013 719 177 1,051 100 Metallurgical Coal - Operations Queensland CQCA-JV 2017 3,748 2,169 1,882 50 2013 2,561 2,882 2,353 50 Gregory JV 2017 7.9 112.7 0.3 50 2013 7.9 130.7 0.3 50 BHP Mitsui Coal 2017 265 390 238 80 2013 258 347 233 80 Metallurgical Coal - Projects Queensland CQCA-JV 2017 701 2,184 1,405 50 2013 273 1,476 1,398 50 Gregory JV 2017 5.6 - - 50 2013 5.6 - - 50 BHP Mitsui Coal 2017 - 1,457 154.1 80 2013 - 1,457 154.1 80 Copper Olympic Dam 2017 1,460@0.96%Cu, 0.30kg/tonne U O , 0.41g/t Au, 2g/t Ag 4,680@0.79%Cu, 0.25kg/tonne U O , 0.34g/t Au,1g/t Ag 3,920@0.71% Cu,0.24kg/tonne U O ,0.28g/t Au,1g/t Ag 100 3 8 3 8 3 8 2013 1,543@0.97%Cu, 0.29kg/tonne U O , 0.37g/t Au, 2g/t Ag 5,095@0.80% Cu,0.26kg/tonne U O ,0.36g/t Au, 1g/t Ag 3,296@0.69% Cu,0.23kg/tonne U O ,0.25g/t Au,1g/t Ag 100 3 8 3 8 3 8 Nickel Nickel West Operations 2017 160@0.74%Ni 189@0.61%Ni 135@0.65% Ni 100 2013 214@0.61%Ni 186@0.61%Ni 150@0.59% Ni 100 Nickel West Projects 2017 156@0.59%Ni 114@0.63%Ni 206@0.67% Ni 100* 2013 156@0.60%Ni 203@0.66% Ni 100* 114@0.60%Ni * Projects comprise Venus, Yakabindie with 100% BHP interest and Jericho 50% BHP interest. Financial results 21 August 2018 40Mineral Resources (100% basis) Commodity BHP interest Financial Year Measured Resources (Mt) Indicated Resources (Mt) Inferred Resources (Mt) Deposit % Minerals Australia Iron Ore WAIO 2017 2,740 5,930 20,390 88 2013 2,550 4,210 14,560 88 Energy Coal Operations - Mt Arthur Coal 2017 897 1,299 1,019 100 2013 887 2,169 670 100 Projects - Togara South 2017 719 177 1,051 100 2013 719 177 1,051 100 Metallurgical Coal - Operations Queensland CQCA-JV 2017 3,748 2,169 1,882 50 2013 2,561 2,882 2,353 50 Gregory JV 2017 7.9 112.7 0.3 50 2013 7.9 130.7 0.3 50 BHP Mitsui Coal 2017 265 390 238 80 2013 258 347 233 80 Metallurgical Coal - Projects Queensland CQCA-JV 2017 701 2,184 1,405 50 2013 273 1,476 1,398 50 Gregory JV 2017 5.6 - - 50 2013 5.6 - - 50 BHP Mitsui Coal 2017 - 1,457 154.1 80 2013 - 1,457 154.1 80 Copper Olympic Dam 2017 1,460@0.96%Cu, 0.30kg/tonne U O , 0.41g/t Au, 2g/t Ag 4,680@0.79%Cu, 0.25kg/tonne U O , 0.34g/t Au,1g/t Ag 3,920@0.71% Cu,0.24kg/tonne U O ,0.28g/t Au,1g/t Ag 100 3 8 3 8 3 8 2013 1,543@0.97%Cu, 0.29kg/tonne U O , 0.37g/t Au, 2g/t Ag 5,095@0.80% Cu,0.26kg/tonne U O ,0.36g/t Au, 1g/t Ag 3,296@0.69% Cu,0.23kg/tonne U O ,0.25g/t Au,1g/t Ag 100 3 8 3 8 3 8 Nickel Nickel West Operations 2017 160@0.74%Ni 189@0.61%Ni 135@0.65% Ni 100 2013 214@0.61%Ni 186@0.61%Ni 150@0.59% Ni 100 Nickel West Projects 2017 156@0.59%Ni 114@0.63%Ni 206@0.67% Ni 100* 2013 156@0.60%Ni 203@0.66% Ni 100* 114@0.60%Ni * Projects comprise Venus, Yakabindie with 100% BHP interest and Jericho 50% BHP interest. Financial results 21 August 2018 40

Mineral Resources (100% basis) Commodity BHP interest Financial Year Measured Resources (Mt) Indicated Resources (Mt) Inferred Resources (Mt) Deposit % Mineral Americas Copper Escondida District 2017 5,927@0.63% TCu 5,051@0.56% TCu 15,785@0.48% TCu 57.5 2013 5,785@0.67% TCu 3,542@0.54% TCu 12,930@0.47% TCu 57.5 Pampa Norte 2017 825@0.54% TCu 1,119@0.48% TCu 3,158@0.37% TCu 100 2013 593@0.63% TCu 1,386@0.49% TCu 1,275@0.40% TCu 100 Pinto Valley 2017 174@0.31% TCu 40@0.32% TCu 100 2013 350@0.32% TCu 617@0.31% TCu 191@0.26% TCu 100 Antamina 2017 230@0.91% Cu,0.72% Zn,10g/t Ag,255 ppm Mo 839@0.88% Cu,0.78% Zn,11g/t Ag,191 ppm Mo 1,246@0.88% Cu,0.62% Zn,10g/t Ag,185 ppm Mo 33.75 2013 183@0.77% Cu,0.60% Zn,10g/t Ag,238 ppm Mo 943@0.92% Cu,0.66% Zn,11g/t Ag,208ppm Mo 860@0.82% Cu,0.39% Zn,11g/t Ag,173 ppm Mo 33.75 Potash Jansen Project 2017 5,170@25.7% K O 1,270@25.7% K O 100 2 2 2013 5,328@25.7% K O 1,288@25.7% K O 100 2 2 Energy Coal Cerrejon 2017 2,711 1,196 631 33.33 2013 2,924 989 695 33.33 Iron Ore Samarco 2017 2,800 2,800 1,300 50 2013 3,000 3,000 2,000 50 Financial results 21 August 2018 41Mineral Resources (100% basis) Commodity BHP interest Financial Year Measured Resources (Mt) Indicated Resources (Mt) Inferred Resources (Mt) Deposit % Mineral Americas Copper Escondida District 2017 5,927@0.63% TCu 5,051@0.56% TCu 15,785@0.48% TCu 57.5 2013 5,785@0.67% TCu 3,542@0.54% TCu 12,930@0.47% TCu 57.5 Pampa Norte 2017 825@0.54% TCu 1,119@0.48% TCu 3,158@0.37% TCu 100 2013 593@0.63% TCu 1,386@0.49% TCu 1,275@0.40% TCu 100 Pinto Valley 2017 174@0.31% TCu 40@0.32% TCu 100 2013 350@0.32% TCu 617@0.31% TCu 191@0.26% TCu 100 Antamina 2017 230@0.91% Cu,0.72% Zn,10g/t Ag,255 ppm Mo 839@0.88% Cu,0.78% Zn,11g/t Ag,191 ppm Mo 1,246@0.88% Cu,0.62% Zn,10g/t Ag,185 ppm Mo 33.75 2013 183@0.77% Cu,0.60% Zn,10g/t Ag,238 ppm Mo 943@0.92% Cu,0.66% Zn,11g/t Ag,208ppm Mo 860@0.82% Cu,0.39% Zn,11g/t Ag,173 ppm Mo 33.75 Potash Jansen Project 2017 5,170@25.7% K O 1,270@25.7% K O 100 2 2 2013 5,328@25.7% K O 1,288@25.7% K O 100 2 2 Energy Coal Cerrejon 2017 2,711 1,196 631 33.33 2013 2,924 989 695 33.33 Iron Ore Samarco 2017 2,800 2,800 1,300 50 2013 3,000 3,000 2,000 50 Financial results 21 August 2018 41

Mineral Resources (100% basis) Commodity BHP interest Financial year Measured Resources (Mt) Indicated Resources (Mt) Inferred Resources (Mt) Deposit % Divested assets Metallurgical Coal Illawarra Coal 2013 278 455 586 100 Nickel Nickel Colombia 2013 115@1.04% Ni 186@0.9% Ni 90@0.8% Ni 99.94 Energy Coal New Mexico Coal 2013 779 265 10 100 BECSA 2013 2,572 838 2,023 90 Silver Lead Zinc Cannington 2013 68@186g/t Ag,5.35% Pb,3.26% Zn 18@122g/t Ag,3.94% Pb,2.56% Zn 10@86g/t Ag,3.25% Pb,1.80% Zn 100 Aluminium Worsley 2013 339 584 50 86 Alumar (MRN) 2013 328 81 999 14.8 GAC Project 2013 87 113 327 33.3 Manganese GEMCO 2013 85@46.5% Mn 68@40.0% Mn 37.3@41.8% Mn 60 Hotazel 2013 74.4@37.2% Mn 181.9@39.9% Mn 4.3@34.5% Mn 44.4 Financial results 21 August 2018 42Mineral Resources (100% basis) Commodity BHP interest Financial year Measured Resources (Mt) Indicated Resources (Mt) Inferred Resources (Mt) Deposit % Divested assets Metallurgical Coal Illawarra Coal 2013 278 455 586 100 Nickel Nickel Colombia 2013 115@1.04% Ni 186@0.9% Ni 90@0.8% Ni 99.94 Energy Coal New Mexico Coal 2013 779 265 10 100 BECSA 2013 2,572 838 2,023 90 Silver Lead Zinc Cannington 2013 68@186g/t Ag,5.35% Pb,3.26% Zn 18@122g/t Ag,3.94% Pb,2.56% Zn 10@86g/t Ag,3.25% Pb,1.80% Zn 100 Aluminium Worsley 2013 339 584 50 86 Alumar (MRN) 2013 328 81 999 14.8 GAC Project 2013 87 113 327 33.3 Manganese GEMCO 2013 85@46.5% Mn 68@40.0% Mn 37.3@41.8% Mn 60 Hotazel 2013 74.4@37.2% Mn 181.9@39.9% Mn 4.3@34.5% Mn 44.4 Financial results 21 August 2018 42

Footnotes 1. High potential injuries: injury events where there was the potential for a fatality. 2. Occupational Exposure Limits (OELs): in FY18, a new five-year target was established to achieve a 50% reduction in the number of workers potentially exposed to respirable silica, diesel particulate matter and coal mine dust, as compared with our FY17 baseline (discounting protection by personal protective equipment). 3. Withdrawal: defined as water withdrawn and intended for use (in accordance with ‘A Practical Guide to Consistent Water Reporting’, ICMM (2017)) consistent with WAF inputs; fresh water is defined as ‘waters other than sea water’, irrespective of quality. The FY17 baseline for the purposes of this target has been adjusted to account for the materiality of the strike affecting water withdrawals at Escondida in FY17. The revised baseline is 173,000 megalitres. 4. Adjusted effective tax: excludes the influence of exchange rate movements and exceptional items. 5. Underlying EBITDA margin: BHP data presented on a total operations basis up to FY14 and on a continuing operations basis from FY15 onwards: peer group comprises Anglo American, Rio Tinto and Vale. 6. Segment EBITDA: percentage contribution to Group Underlying EBITDA, excluding Group and unallocated items. 7. Iron ore: unit cost, C1 unit cost excluding third party royalties, EBITDA margin and ROCE refer to Western Australia Iron Ore. 8. Copper: operated copper assets (Escondida, Pampa Norte and Olympic Dam). 9. Price: net of price-linked costs. 10. Controllable cash costs: includes unfavourable fixed cost dilution at Olympic Dam (smelter maintenance campaign) and Conventional Petroleum (natural field decline), challenging operating conditions at two Queensland Coal mines (Broadmeadow and Blackwater); and a favourable change in estimated recoverable copper in the Escondida sulphide leach pad in the prior period, partially offset by lower labour and contractor costs at WAIO. 11. Non-cash: includes net deferred stripping costs. 12. Other: includes one-off items and other items (including profit/loss from equity accounted investments). 13. Commodity basket index: represents an EBITDA weighted average of key commodity prices, reweighted each financial year. 14. Dividends: related to final dividend determined by the Board for FY17 and paid in September 2017, and dividend determined by the Board for H1 FY18 and paid in March 2018. 15. NCIs: dividends paid to non-controlling interests of US$1,604 million predominantly relate to Escondida. 16. Average debt maturity: calculated based on first call date of Hybrid issuances, and includes subsidiary debt. 17. Non-cash fair value movement: relates to foreign exchange variance due to the revaluation of local currency denominated debt to USD and movements in interest rates. 18. Onshore US FY19 guidance: until divestment completion, expected by the end of October 2018, we intend to operate five rigs in Onshore US and incur capital expenditure at an annualised rate broadly consistent with the 2018 financial year. 19. Antamina and Cerrejón: equity accounted investments; average capital employed represents BHP’s equity interest. Antamina ROCE truncated for illustrative purposes. 20. Onshore US sale: less customary completion adjustments; subject to customary regulatory approvals and conditions precedent. 21. Conventional Petroleum exploration; ROCE truncated for illustrative purposes. 22. Divestments: announced or completed from FY13 onwards. 23. Unrisked NPV and average IRRs: based on Global Metals, Mining and Steel Conference presentation on 15 May 2018. 24. Escondida FY19 unit cost: guidance includes end of negotiation bonus at USD/CLP 663. 25. Finding and Development costs: includes reported exploration plus Conventional Petroleum capital expenditure, divided by proven reserves added (extensions and discoveries plus improved recovery plus revision). BHP F&D costs calculated on a financial year basis (FY08-FY17). Peers calculated on calendar year basis (CY08-CY17). 26. Finding and Development costs: source: BHP: own analysis. Peers and Sector: WoodMackenzie. Peers include: BP, Chevron, ENI, ExxonMobil, OMV, Petrobras, PetroChina, Repsol, RD Shell, Sinopec, TOTAL, Anadarko, Apache, CNOOC, ConocoPhillips, Encana, Hess, Lundin, Murphy, Noble, Occidental, PTTEP. Sector include all companies (excluding BHP) reported by WoodMackenzie. 27. Exploration wells and success rate: refers to the number of wells completed at any time during the respective year, regardless of when drilling was initiated. A productive well is an exploratory or extension well that is not a dry well. Productive wells include wells in which hydrocarbons were encountered and the drilling or completion of which, has been suspended pending further drilling. Excludes wells that had mechanical issues (Burrokeet-1 and Wildling-1 in FY17 and Bongos-1 in FY19) where the opportunities were tested by a subsequent well. 28. EBITDA sensitives: assumes total volume exposed to price; determined on the basis of the BHP’s existing portfolio. 29. EBITDA sensitives: excludes impact of equity accounted investments. 30. EBITDA sensitives: excludes impact of change in input costs across the Group. 31. EBITDA sensitives: based on average exchange rate for the period. 32. Debt maturity profile: all debt balances are represented in notional USD values and based on financial years; as at 30 June 2018. 33. Debt maturity profile: subsidiary debt is presented in accordance with IFRS 10 and IFRS 11. 34. Debt maturity profile: includes hybrid bonds (24% of portfolio: 12% in USD, 9% in Euro, 3% in Sterling) with maturity shown at first call date. Financial results 21 August 2018 43Footnotes 1. High potential injuries: injury events where there was the potential for a fatality. 2. Occupational Exposure Limits (OELs): in FY18, a new five-year target was established to achieve a 50% reduction in the number of workers potentially exposed to respirable silica, diesel particulate matter and coal mine dust, as compared with our FY17 baseline (discounting protection by personal protective equipment). 3. Withdrawal: defined as water withdrawn and intended for use (in accordance with ‘A Practical Guide to Consistent Water Reporting’, ICMM (2017)) consistent with WAF inputs; fresh water is defined as ‘waters other than sea water’, irrespective of quality. The FY17 baseline for the purposes of this target has been adjusted to account for the materiality of the strike affecting water withdrawals at Escondida in FY17. The revised baseline is 173,000 megalitres. 4. Adjusted effective tax: excludes the influence of exchange rate movements and exceptional items. 5. Underlying EBITDA margin: BHP data presented on a total operations basis up to FY14 and on a continuing operations basis from FY15 onwards: peer group comprises Anglo American, Rio Tinto and Vale. 6. Segment EBITDA: percentage contribution to Group Underlying EBITDA, excluding Group and unallocated items. 7. Iron ore: unit cost, C1 unit cost excluding third party royalties, EBITDA margin and ROCE refer to Western Australia Iron Ore. 8. Copper: operated copper assets (Escondida, Pampa Norte and Olympic Dam). 9. Price: net of price-linked costs. 10. Controllable cash costs: includes unfavourable fixed cost dilution at Olympic Dam (smelter maintenance campaign) and Conventional Petroleum (natural field decline), challenging operating conditions at two Queensland Coal mines (Broadmeadow and Blackwater); and a favourable change in estimated recoverable copper in the Escondida sulphide leach pad in the prior period, partially offset by lower labour and contractor costs at WAIO. 11. Non-cash: includes net deferred stripping costs. 12. Other: includes one-off items and other items (including profit/loss from equity accounted investments). 13. Commodity basket index: represents an EBITDA weighted average of key commodity prices, reweighted each financial year. 14. Dividends: related to final dividend determined by the Board for FY17 and paid in September 2017, and dividend determined by the Board for H1 FY18 and paid in March 2018. 15. NCIs: dividends paid to non-controlling interests of US$1,604 million predominantly relate to Escondida. 16. Average debt maturity: calculated based on first call date of Hybrid issuances, and includes subsidiary debt. 17. Non-cash fair value movement: relates to foreign exchange variance due to the revaluation of local currency denominated debt to USD and movements in interest rates. 18. Onshore US FY19 guidance: until divestment completion, expected by the end of October 2018, we intend to operate five rigs in Onshore US and incur capital expenditure at an annualised rate broadly consistent with the 2018 financial year. 19. Antamina and Cerrejón: equity accounted investments; average capital employed represents BHP’s equity interest. Antamina ROCE truncated for illustrative purposes. 20. Onshore US sale: less customary completion adjustments; subject to customary regulatory approvals and conditions precedent. 21. Conventional Petroleum exploration; ROCE truncated for illustrative purposes. 22. Divestments: announced or completed from FY13 onwards. 23. Unrisked NPV and average IRRs: based on Global Metals, Mining and Steel Conference presentation on 15 May 2018. 24. Escondida FY19 unit cost: guidance includes end of negotiation bonus at USD/CLP 663. 25. Finding and Development costs: includes reported exploration plus Conventional Petroleum capital expenditure, divided by proven reserves added (extensions and discoveries plus improved recovery plus revision). BHP F&D costs calculated on a financial year basis (FY08-FY17). Peers calculated on calendar year basis (CY08-CY17). 26. Finding and Development costs: source: BHP: own analysis. Peers and Sector: WoodMackenzie. Peers include: BP, Chevron, ENI, ExxonMobil, OMV, Petrobras, PetroChina, Repsol, RD Shell, Sinopec, TOTAL, Anadarko, Apache, CNOOC, ConocoPhillips, Encana, Hess, Lundin, Murphy, Noble, Occidental, PTTEP. Sector include all companies (excluding BHP) reported by WoodMackenzie. 27. Exploration wells and success rate: refers to the number of wells completed at any time during the respective year, regardless of when drilling was initiated. A productive well is an exploratory or extension well that is not a dry well. Productive wells include wells in which hydrocarbons were encountered and the drilling or completion of which, has been suspended pending further drilling. Excludes wells that had mechanical issues (Burrokeet-1 and Wildling-1 in FY17 and Bongos-1 in FY19) where the opportunities were tested by a subsequent well. 28. EBITDA sensitives: assumes total volume exposed to price; determined on the basis of the BHP’s existing portfolio. 29. EBITDA sensitives: excludes impact of equity accounted investments. 30. EBITDA sensitives: excludes impact of change in input costs across the Group. 31. EBITDA sensitives: based on average exchange rate for the period. 32. Debt maturity profile: all debt balances are represented in notional USD values and based on financial years; as at 30 June 2018. 33. Debt maturity profile: subsidiary debt is presented in accordance with IFRS 10 and IFRS 11. 34. Debt maturity profile: includes hybrid bonds (24% of portfolio: 12% in USD, 9% in Euro, 3% in Sterling) with maturity shown at first call date. Financial results 21 August 2018 43

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 Billiton Limited and BHP Billiton Plc
Date: August 21, 2018 |  |  |  | By: |  | /s/ Rachel Agnew
|  |  |  | Name: |  | Rachel Agnew
|  |  |  | Title: |  | Company Secretary