6-K 1 d807581d6k.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

November 11, 2019

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

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F: ☒ Form 20-F ☐ Form 40-F

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

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

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

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

NEWS RELEASE

Release Time Date Release Number |  | IMMEDIATE 11 November 2019 21/19 |  |

Petroleum briefing

BHP President Operations Petroleum, Geraldine Slattery, today said Petroleum is set to deliver strong returns and contribute significant value for BHP through the 2020s and beyond, built on a foundation of quality assets, and attractive growth options.

Speaking to investors and analysts at a briefing in Sydney, Ms Slattery said Petroleum is a great business with competitive growth potential and is aligned with BHP’s strategy of being in the best commodities, with the best assets, enabled by the best culture and capabilities. Petroleum has delivered strong financial performance over many years and this is set to continue.

“In a decarbonising world, deepwater oil and advantaged gas close to established infrastructure can offer competitive returns for decades to come.”

Ms Slattery outlined a scenario1 that could potentially:

| • |  | Generate robust EBITDA margins of more than 60 per cent and an average Return on Capital Employed of more than 15 per cent over the next decade;

| • |  | Deliver average Internal Rates of Return of around 25 per cent for major projects, which are resilient through cycles; and

| • |  | Support an average annual volume growth of up to 3 per cent between the 2020 and 2030 financial years.

“Our portfolio of quality assets and pipeline of competitive growth options are expected to generate strong free cash flow and returns through the 2020s and beyond”, Ms Slattery said.

Petroleum’s growth options currently include Scarborough, Wildling Phase I, Trion and Trinidad & Tobago North. While these remain subject to our strict Capital Allocation Framework, they are well placed to compete with other options in the Group’s portfolio.

“Our capabilities in safety, exploration and deepwater operations, coupled with a high-performance culture give us confidence that we can deliver on our plans into the future,” Ms Slattery said.

1 | Represents an unconstrained scenario based on execution of all unsanctioned projects at current equity interests and does not constitute guidance. Based on Wood Mackenzie’s most recent long-term oil and gas price forecasts as follows: Brent oil price assumption (2020-2030 average: US$74.34/bbl, real 2019); Japan LNG DES price assumption (2020-2030 average: US$7.86/MMBtu, real 2019).

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Presentations will be webcast live at https://edge.media-server.com/mmc/p/362g83wf and all materials be available on our website at bhp.com.

A summary of guidance and project details contained in the presentation is included below.

Guidance

Asset |  | FY20e |  | Medium term
|  | Production |  | Unit costs1 |  | Production |  | Unit costs1
Conventional Petroleum |  | 110-116 MMboe |  | US$10.5-11.5/boe |  | ~110 MMboe average |  | <US$13/boe

Future options

Options |  | Operator |  | BHP Ownership |  | Potential execution timing |  | Capex BHP share (US$m) |  | Tollgate |  | Potential first production2 |  | Description
North West Shelf Other Resource Owner |  | Woodside |  | 16.67% |  | <5 years |  | >250 |  | Pre-feasibility |  | FY26 |  | Low risk investment opportunity to maximise Karratha Gas Plant value through processing other resource owner gas; benefits through tolling fees, cost recovery and life extension.
Pyrenees Phase 4 |  | BHP |  | 71.43% |  | <5 years |  | >250 |  | Opportunity Assessment |  | FY22 |  | Combination of well re-entries and new subsea wells which aim to optimise incremental value using the existing infrastructure.
Scarborough3 |  | Woodside |  | 26.5% |  | 1 year |  | 1,400- 1,900 |  | Pre-feasibility |  | FY24 |  | Large resource of 13 subsea wells connected to a semisubmersible floating production unit from which gas is exported via pipeline to Pluto LNG facility for onshore processing.
Atlantis Phase 4 |  | BP |  | 44% |  | <5 years |  | >250 |  | Opportunity Assessment |  | FY24 |  | Additional development opportunities for infill producing wells. Data obtained from Phase 3 project de-risks further development of multiple hydrocarbon bearing zones.
Mad Dog Northwest Water Injection |  | BP |  | 23.9% |  | <5 years |  | >250 |  | Pre-feasibility |  | FY24 |  | Two water injector wells providing water from Mad Dog Phase 2 facility to increase production at existing A Spar facility.
Mad Dog opportunities |  | BP |  | 23.9% |  | <5 years |  | >250 |  | Opportunity Assessment |  | FY25 |  | Additional opportunities to increase the Mad Dog Phase 2 production beyond the initial investment scope with new wells tied back to existing facility, results in highly economic opportunities.
Shenzi Growth opportunities |  | BHP |  | 44% |  | 1 year |  | <250 |  | Pre-feasibility |  | FY23 |  | Shenzi Subsea Multi-Phase Pumping (SSMPP); Subsea pumping opportunities to increase production rates from existing wells.

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Options |  | Operator |  | BHP Ownership |  | Potential execution timing |  | Capex BHP share (US$m) |  | Tollgate |  | Potential first production2 |  | Description
Wildling Phase 1 |  | BHP |  | 44%-72% |  | 1-2 years |  | ~500 |  | Pre- feasibility |  | FY23 |  | Two Shenzi North wells tied-back to the Shenzi platform, provides the opportunity to accelerate production and unlock additional recoverable reserves. Phased development accelerates first oil, minimizes appraisal cost and reduces risk.
Trion |  | BHP |  | 60% |  | 2-3 years |  | >5,000 |  | Conceptual |  | FY25 |  | Large greenfield development in the deepwater Mexico GoM. Resource uncertainty reduced with recent successful appraisal drilling of 2DEL and 3DEL wells.
Trinidad & Tobago North |  | BHP |  | 70% |  | <5 years |  | Under study |  | Opportunity Assessment |  | FY27 |  | Completed successful exploration program on our Northern licenses. Potential material gas play in deepwater Trinidad & Tobago, well positioned to the Atlantic LNG plant onshore Trinidad & Tobago.

Note: This represents an unconstrained scenario based on execution of all unsanctioned projects at current equity interests and does not constitute guidance.

Exploration

Options |  | Location |  | Ownership |  | Maturity |  | Earliest first production |  | Description
Western GoM |  | US – Gulf of Mexico |  | 100% Operator |  | Frontier |  | Early 2030s |  | Acquired a significant acreage position in historically underexplored Western Gulf of Mexico
Mexico |  | Mexico – Gulf of Mexico |  | 60% Operator |  | Exploration |  | Late 2020s |  | Opportunity to tie back prospects to future Trion hub. Included in Trion Minimum Work Program
T&T Southern Gas (Magellan) |  | Trinidad & Tobago |  | 65% Operator |  | Exploration |  | Mid 2020s |  | Discovered gas play in deepwater Trinidad & Tobago
T&T Southern Deep Potential |  | Trinidad & Tobago |  | 65% Operator |  | Frontier |  | Late 2020s |  | Evaluating multiple play types to test deeper potential in deepwater Trinidad & Tobago based on deep oil shows from Le Clerc exploration
Eastern Canada |  | Orphan Basin |  | 100% Operator |  | Frontier |  | Early 2030s |  | Recent bid success for blocks with large liquids resource potential in the offshore Orphan Basin in Eastern Canada

Significant remaining project potential with unrisked NPV of up to US$14 billion4

1. Based on an exchange rate of AUD/USD 0.70. Unit costs are in nominal terms.

2. Potential first production data is an estimate and does not constitute guidance.

3. Based on information provided by operator. Represents BHP’s current equity position as 25% in WA-1-R and 50% in WA-62-R.

4. Exploration unrisked value at BHP prices.

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BHP Group Limited ABN 49 004 028 077 |  | BHP Group plc Registration number 3196209
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Petroleum briefing Positioned for long-term value creation Geraldine Slattery | President Operations Petroleum 11 November 2019Petroleum briefing Positioned for long-term value creation Geraldine Slattery | President Operations Petroleum 11 November 2019

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. Presentation of data Unless specified otherwise: variance analysis relates to the relative performance of BHP and/or its operations during the 2019 financial year compared with the 2018 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 2019 financial year average realised prices; references to Underlying EBITDA margin exclude third party trading activities; data from subsidiaries are shown on a 100 per cent basis and data from equity accounted investments and other operations is presented, with the exception of net operating assets, reflecting BHP’s share; medium term refers to our five year plan. Numbers presented may not add up precisely to the totals provided due to rounding. Production profiles and financial metrics are based on an unconstrained scenario which assumes execution of all unsanctioned projects; current equity interests; and Wood Mackenzie long-term price forecasts. These do not constitute guidance. Advantaged gas refers to gas that is geographically advantaged through infrastructure, customers or both. Alternative performance measures We use various alternative performance measures to reflect our underlying performance. For further information please refer to alternative performance measures set out on pages 45 to 54 of the BHP Results for the year ended 30 June 2019. No offer of securities Nothing in this presentation should be construed as either an offer or a solicitation of an offer to buy or sell BHP securities in any jurisdiction, or be treated or relied upon as a recommendation or advice by BHP. Reliance on third party information The views expressed in this presentation contain information that has been derived from publicly available sources that have not been independently verified. No representation or warranty is made as to the accuracy, completeness or reliability of the information. This presentation should not be relied upon as a recommendation or forecast by BHP. BHP and its subsidiaries In this presentation, the terms ‘BHP’, ‘Group’, ‘BHP Group’, ‘we’, ‘us’, ‘our’ and ‘ourselves’ are used to refer to BHP Group Limited, BHP Group Plc and, except where the context otherwise requires, their respective subsidiaries set out in note 13 ‘Related undertaking of the Group’ in section 5.2 of BHP’s Annual Report on Form 20-F. Notwithstanding that this presentation may include production, financial and other information from non-operated assets, non-operated assets are not included in the BHP Group and, as a result, statements regarding our operations, assets and values apply only to our operated assets unless otherwise stated. Price assumptions For all price point comparisons, unless otherwise indicated, crude oil and natural gas (including LNG) prices are based off Wood Mackenzie’s most recent long-time price forecasts. The Brent oil price assumption is sourced from Wood Mackenzie’s May 2019 Macro Oils Long Term Outlook (H1 2019). Our assumption for LNG gas price is sourced from Wood Mackenzie’s June 2019 Global Gas Service price outlook H1 2019. Brent oil price assumption (2020-2030 average: Wood Mackenzie US$74.34/bbl, real 2019). Japan LNG DES price assumption (2020-2030 average: Wood Mackenzie US$7.86/MMBtu, real 2019). These prices are not intended to reflect management’s forecast for future prices or the prices we use for internal planning purposes. Petroleum briefing 11 November 2019 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. Presentation of data Unless specified otherwise: variance analysis relates to the relative performance of BHP and/or its operations during the 2019 financial year compared with the 2018 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 2019 financial year average realised prices; references to Underlying EBITDA margin exclude third party trading activities; data from subsidiaries are shown on a 100 per cent basis and data from equity accounted investments and other operations is presented, with the exception of net operating assets, reflecting BHP’s share; medium term refers to our five year plan. Numbers presented may not add up precisely to the totals provided due to rounding. Production profiles and financial metrics are based on an unconstrained scenario which assumes execution of all unsanctioned projects; current equity interests; and Wood Mackenzie long-term price forecasts. These do not constitute guidance. Advantaged gas refers to gas that is geographically advantaged through infrastructure, customers or both. Alternative performance measures We use various alternative performance measures to reflect our underlying performance. For further information please refer to alternative performance measures set out on pages 45 to 54 of the BHP Results for the year ended 30 June 2019. No offer of securities Nothing in this presentation should be construed as either an offer or a solicitation of an offer to buy or sell BHP securities in any jurisdiction, or be treated or relied upon as a recommendation or advice by BHP. Reliance on third party information The views expressed in this presentation contain information that has been derived from publicly available sources that have not been independently verified. No representation or warranty is made as to the accuracy, completeness or reliability of the information. This presentation should not be relied upon as a recommendation or forecast by BHP. BHP and its subsidiaries In this presentation, the terms ‘BHP’, ‘Group’, ‘BHP Group’, ‘we’, ‘us’, ‘our’ and ‘ourselves’ are used to refer to BHP Group Limited, BHP Group Plc and, except where the context otherwise requires, their respective subsidiaries set out in note 13 ‘Related undertaking of the Group’ in section 5.2 of BHP’s Annual Report on Form 20-F. Notwithstanding that this presentation may include production, financial and other information from non-operated assets, non-operated assets are not included in the BHP Group and, as a result, statements regarding our operations, assets and values apply only to our operated assets unless otherwise stated. Price assumptions For all price point comparisons, unless otherwise indicated, crude oil and natural gas (including LNG) prices are based off Wood Mackenzie’s most recent long-time price forecasts. The Brent oil price assumption is sourced from Wood Mackenzie’s May 2019 Macro Oils Long Term Outlook (H1 2019). Our assumption for LNG gas price is sourced from Wood Mackenzie’s June 2019 Global Gas Service price outlook H1 2019. Brent oil price assumption (2020-2030 average: Wood Mackenzie US$74.34/bbl, real 2019). Japan LNG DES price assumption (2020-2030 average: Wood Mackenzie US$7.86/MMBtu, real 2019). These prices are not intended to reflect management’s forecast for future prices or the prices we use for internal planning purposes. Petroleum briefing 11 November 2019 2

Statement of petroleum resources The estimates of Petroleum Reserves and Contingent Resources contained in this presentation are based on, and fairly represent, information and supporting documentation prepared under the supervision of Mr. A. G. Gadgil, who is employed by BHP. Mr. Gadgil is a member of the Society of Petroleum Engineers and has the required qualifications and experience to act as a qualified Petroleum Reserves and Resources evaluator under the ASX Listing Rules. This presentation is issued with the prior written consent of Mr. Gadgil who agrees with the form and context in which the Petroleum Reserves and Contingent Resources are presented. Reserves and Contingent Resources are net of royalties owned by others and have been estimated using deterministic methodology. Aggregates of Reserves and Contingent Resources estimates contained in this presentation have been calculated by arithmetic summation of field/project estimates by category with the exception of the North West Shelf (NWS) Gas Project in Australia. Probabilistic methodology has been utilised to aggregate the NWS Reserves and Contingent Resources for the reservoirs dedicated to the gas project only and represents an incremental 16 MMboe of Proved Reserves. The barrel of oil equivalent conversion is based on 6000 scf of natural gas equals 1 boe. The Reserves and Contingent Resources contained in this presentation are inclusive of fuel required for operations. The respective amounts of fuel for each category are provided by the following table or by footnote for the resource graphics. Production volumes exclude fuel. The custody transfer point(s)/point(s) of sale applicable for each field or project are the reference point for Reserves and Contingent Resources. Reserves and Contingent Resources estimates have not been adjusted for risk. Unless noted otherwise, Reserves and Contingent Resources are as of 30 June 2019. Where used in this presentation, the term Resources represents the sum of 2P reserves and 2C Contingent Resources. BHP estimates Proved Reserve volumes according to SEC disclosure regulations and files these in our annual 20-F report with the SEC. All Unproved volumes are estimated using SPE-PRMS guidelines, which among other things, allow escalations to prices and costs, and as such, would be on a different basis than that prescribed by the SEC, and are therefore excluded from our SEC filings. All Resources and other Unproved volumes may differ from and may not be comparable to the same or similarly-named measures used by other companies. Non-proved estimates are inherently more uncertain than proved. Table 1: Net BHP Petroleum Reserves and Contingent Resources (MMboe) as of 30 June 2019 Offshore US Offshore Australia Rest of World Total BHP Gulf of Mexico Western Australia Bass Strait and MInerva Subtotal Algeria Mexico, Gulf of Mexico Trinidad and Tobago Subtotal Proved 302 268 206 475 16 0 48 64 841 Probable 147 73 64 137 5 0 18 23 307 2P 449 341 271 612 21 0 66 87 1,147 2 1 336 2C 488 633 182 814 63 222 622 1,924 2 1 402 2P+2C 937 974 452 1,426 83 222 708 3,071 Fuel Included Above Proved 10.6 32.4 12.3 44.7 1.1 0.0 1.1 2.3 57.6 Probable 2.8 9.8 4.2 14.0 0.0 0.0 0.4 0.4 17.3 2P 13.5 42.2 16.5 58.7 1.1 0.0 1.6 2.7 74.9 2C 0.0 60.9 6.8 67.7 1.5 0.0 0.0 1.5 69.1 2P+2C 13.5 103.1 23.3 126.4 2.6 0.0 1.6 4.2 144.1 The SEC permits oil and gas companies, in their filings with the SEC, to disclose only Proved, Probable and Possible Reserves, and only when such Reserves have been determined in accordance with SEC guidelines. We use certain terms in this presentation such as “Resources,” “Contingent Resources,” “2C Contingent Resources” and similar terms as well as Probable Reserves not determined in accordance with the SEC’s guidelines, all of which measures we are strictly prohibited from including in filings with the SEC. These measures include Reserves and Resources with substantially less certainty than Proved Reserves. US investors are urged to consider closely the disclosure in our Form 20-F for the fiscal year ended 30 June 2019, File No. 001-09526 and in our other filings with the SEC, available from us at http://www.bhp.com/. These forms can also be obtained from the SEC as described above. 1. The US Gulf of Mexico 2C Contingent Resources includes 19 MMboe for the Samurai field which has been sold for value. The sale closed on 4 November 2019. 2. The Trinidad & Tobago 2C Contingent Resources exclude the FY20 Bélé and Tuk discoveries which represent a combined 180 MMboe (Net) as of 30 September 2019. Petroleum briefing 11 November 2019 3Statement of petroleum resources The estimates of Petroleum Reserves and Contingent Resources contained in this presentation are based on, and fairly represent, information and supporting documentation prepared under the supervision of Mr. A. G. Gadgil, who is employed by BHP. Mr. Gadgil is a member of the Society of Petroleum Engineers and has the required qualifications and experience to act as a qualified Petroleum Reserves and Resources evaluator under the ASX Listing Rules. This presentation is issued with the prior written consent of Mr. Gadgil who agrees with the form and context in which the Petroleum Reserves and Contingent Resources are presented. Reserves and Contingent Resources are net of royalties owned by others and have been estimated using deterministic methodology. Aggregates of Reserves and Contingent Resources estimates contained in this presentation have been calculated by arithmetic summation of field/project estimates by category with the exception of the North West Shelf (NWS) Gas Project in Australia. Probabilistic methodology has been utilised to aggregate the NWS Reserves and Contingent Resources for the reservoirs dedicated to the gas project only and represents an incremental 16 MMboe of Proved Reserves. The barrel of oil equivalent conversion is based on 6000 scf of natural gas equals 1 boe. The Reserves and Contingent Resources contained in this presentation are inclusive of fuel required for operations. The respective amounts of fuel for each category are provided by the following table or by footnote for the resource graphics. Production volumes exclude fuel. The custody transfer point(s)/point(s) of sale applicable for each field or project are the reference point for Reserves and Contingent Resources. Reserves and Contingent Resources estimates have not been adjusted for risk. Unless noted otherwise, Reserves and Contingent Resources are as of 30 June 2019. Where used in this presentation, the term Resources represents the sum of 2P reserves and 2C Contingent Resources. BHP estimates Proved Reserve volumes according to SEC disclosure regulations and files these in our annual 20-F report with the SEC. All Unproved volumes are estimated using SPE-PRMS guidelines, which among other things, allow escalations to prices and costs, and as such, would be on a different basis than that prescribed by the SEC, and are therefore excluded from our SEC filings. All Resources and other Unproved volumes may differ from and may not be comparable to the same or similarly-named measures used by other companies. Non-proved estimates are inherently more uncertain than proved. Table 1: Net BHP Petroleum Reserves and Contingent Resources (MMboe) as of 30 June 2019 Offshore US Offshore Australia Rest of World Total BHP Gulf of Mexico Western Australia Bass Strait and MInerva Subtotal Algeria Mexico, Gulf of Mexico Trinidad and Tobago Subtotal Proved 302 268 206 475 16 0 48 64 841 Probable 147 73 64 137 5 0 18 23 307 2P 449 341 271 612 21 0 66 87 1,147 2 1 336 2C 488 633 182 814 63 222 622 1,924 2 1 402 2P+2C 937 974 452 1,426 83 222 708 3,071 Fuel Included Above Proved 10.6 32.4 12.3 44.7 1.1 0.0 1.1 2.3 57.6 Probable 2.8 9.8 4.2 14.0 0.0 0.0 0.4 0.4 17.3 2P 13.5 42.2 16.5 58.7 1.1 0.0 1.6 2.7 74.9 2C 0.0 60.9 6.8 67.7 1.5 0.0 0.0 1.5 69.1 2P+2C 13.5 103.1 23.3 126.4 2.6 0.0 1.6 4.2 144.1 The SEC permits oil and gas companies, in their filings with the SEC, to disclose only Proved, Probable and Possible Reserves, and only when such Reserves have been determined in accordance with SEC guidelines. We use certain terms in this presentation such as “Resources,” “Contingent Resources,” “2C Contingent Resources” and similar terms as well as Probable Reserves not determined in accordance with the SEC’s guidelines, all of which measures we are strictly prohibited from including in filings with the SEC. These measures include Reserves and Resources with substantially less certainty than Proved Reserves. US investors are urged to consider closely the disclosure in our Form 20-F for the fiscal year ended 30 June 2019, File No. 001-09526 and in our other filings with the SEC, available from us at http://www.bhp.com/. These forms can also be obtained from the SEC as described above. 1. The US Gulf of Mexico 2C Contingent Resources includes 19 MMboe for the Samurai field which has been sold for value. The sale closed on 4 November 2019. 2. The Trinidad & Tobago 2C Contingent Resources exclude the FY20 Bélé and Tuk discoveries which represent a combined 180 MMboe (Net) as of 30 September 2019. Petroleum briefing 11 November 2019 3

We start with our purpose A strong sense of purpose drives better outcomes for all stakeholders Our new purpose To bring people and resources together to build a better world Petroleum briefing 11 November 2019 4We start with our purpose A strong sense of purpose drives better outcomes for all stakeholders Our new purpose To bring people and resources together to build a better world Petroleum briefing 11 November 2019 4

Petroleum is positioned for long-term value creation Our strategy identifies how to position the portfolio to maximise long-term value and deliver high returns for shareholders Best commodities Best assets Best capabilities Oil attractive for decades >60% EBITDA margin Safety and sustainability even with electrification, supported by expected over the next 10 years from top quartile safety supply gap and steep cost curves our high-quality assets performance Advantaged gas Competitive pipeline Exploration success through infrastructure, of options yields ~3% average focused strategy added ~800 MMboe customers, or both production CAGR from FY20 to FY30 in 2C resources since FY17 New supply Optimise legacy assets High-performing culture needs to be continuously induced manage mature assets for value leading to top quartile operational and to balance markets deepwater drilling performance Petroleum ROCE expected to average >15% over the next 10 years; average major project IRRs of ~25% Note: This represents an unconstrained scenario based on execution of all unsanctioned projects at current equity interests and does not constitute guidance. EBITDA margin and ROCE based on Wood Mackenzie prices. ROCE excludes exploration. Petroleum briefing 11 November 2019 5Petroleum is positioned for long-term value creation Our strategy identifies how to position the portfolio to maximise long-term value and deliver high returns for shareholders Best commodities Best assets Best capabilities Oil attractive for decades >60% EBITDA margin Safety and sustainability even with electrification, supported by expected over the next 10 years from top quartile safety supply gap and steep cost curves our high-quality assets performance Advantaged gas Competitive pipeline Exploration success through infrastructure, of options yields ~3% average focused strategy added ~800 MMboe customers, or both production CAGR from FY20 to FY30 in 2C resources since FY17 New supply Optimise legacy assets High-performing culture needs to be continuously induced manage mature assets for value leading to top quartile operational and to balance markets deepwater drilling performance Petroleum ROCE expected to average >15% over the next 10 years; average major project IRRs of ~25% Note: This represents an unconstrained scenario based on execution of all unsanctioned projects at current equity interests and does not constitute guidance. EBITDA margin and ROCE based on Wood Mackenzie prices. ROCE excludes exploration. Petroleum briefing 11 November 2019 5

Quality assets delivering value and returns A strong base combined with high-return projects and exploration growth opportunities significantly increases value Strong returns from our high-quality portfolio 1 (ROCE , %) Over the past five years our portfolio has delivered Strong consistent high margins and strong returns 25 performance • Highest EBITDA margin within BHP at >65% 20 record • Average ROCE of ~15% 15 10 5 High margins and competitive returns are 0 expected to continue over the next 10 years Returns-led FY15-19 average FY20-24e average FY25-30e average 1 pathway to • Potential EBITDA margins >60% to FY30 At US$60-80/bbl oil price ROCE at Wood Mackenzie prices 1 growth • Average ROCE of 12% to FY24, expected to rise to 3 ~20% from FY25-30 Growth options have the potential to grow base value by up to 80% (Risked value uplift) +80% Continued focus on replenishing resource • Added ~800 MMboe in 2C resources since FY17 Exploration 2 drives future • Exploration unrisked value of US$14 billion value • Counter-cyclical investment to develop value accretive exploration FY19 base Sanctioned Unsanctioned T&T North and Total portfolio Note: This represents an unconstrained scenario based on execution of all unsanctioned projects at current equity interests and value projects projects risked does not constitute guidance. exploration 1. EBITDA margins and ROCE at Wood Mackenzie prices. ROCE excludes exploration expenditure. 2. Exploration unrisked value at BHP prices. Value at Wood Mackenzie prices 3. Risked value uplift: represents total potential increase in base value from the addition of upside opportunities. Petroleum briefing 11 November 2019 6Quality assets delivering value and returns A strong base combined with high-return projects and exploration growth opportunities significantly increases value Strong returns from our high-quality portfolio 1 (ROCE , %) Over the past five years our portfolio has delivered Strong consistent high margins and strong returns 25 performance • Highest EBITDA margin within BHP at >65% 20 record • Average ROCE of ~15% 15 10 5 High margins and competitive returns are 0 expected to continue over the next 10 years Returns-led FY15-19 average FY20-24e average FY25-30e average 1 pathway to • Potential EBITDA margins >60% to FY30 At US$60-80/bbl oil price ROCE at Wood Mackenzie prices 1 growth • Average ROCE of 12% to FY24, expected to rise to 3 ~20% from FY25-30 Growth options have the potential to grow base value by up to 80% (Risked value uplift) +80% Continued focus on replenishing resource • Added ~800 MMboe in 2C resources since FY17 Exploration 2 drives future • Exploration unrisked value of US$14 billion value • Counter-cyclical investment to develop value accretive exploration FY19 base Sanctioned Unsanctioned T&T North and Total portfolio Note: This represents an unconstrained scenario based on execution of all unsanctioned projects at current equity interests and value projects projects risked does not constitute guidance. exploration 1. EBITDA margins and ROCE at Wood Mackenzie prices. ROCE excludes exploration expenditure. 2. Exploration unrisked value at BHP prices. Value at Wood Mackenzie prices 3. Risked value uplift: represents total potential increase in base value from the addition of upside opportunities. Petroleum briefing 11 November 2019 6

High-margin barrels drive production growth and returns Current opportunities deliver significant volumes, and more than offset Bass Strait and North West Shelf field declines Value accretive production potential over the next decade • Strong free cash flow and returns through 2020s (Production, MMboe) Base • 10+ years of meaningful production from the base 200 production • High-returning investments limit overall production decline to ~1.5% CAGR over the next five years • Oil-dominated projects delivering strong returns 150 Sanctioned • Atlantis Phase 3, Mad Dog Phase 2, Ruby and projects T&T North West Barracouta to add ~25 MMboe in FY23 2016 Petroleum briefing 100 • Scarborough, Trion and US GoM embedded options Unsanctioned add significant potential growth from mid-2020s projects Unsanctioned projects • Competitive pipeline of high-return and improvement Sanctioned projects projects yield ~3% production CAGR from FY20-30 50 Base production • Material gas discoveries in Trinidad & Tobago North Exploration • Progressing exploration in Western Gulf of Mexico and and future Eastern Canada for tier one oil opportunities 0 options • Targeting further oil exposed growth FY19 FY20e FY21e FY22e FY23e FY24e FY25e FY26e FY27e FY28e FY29e FY30e Note: This represents an unconstrained scenario based on execution of all unsanctioned projects at current equity interests and Unconstrained scenario does not constitute guidance. Petroleum briefing 11 November 2019 7High-margin barrels drive production growth and returns Current opportunities deliver significant volumes, and more than offset Bass Strait and North West Shelf field declines Value accretive production potential over the next decade • Strong free cash flow and returns through 2020s (Production, MMboe) Base • 10+ years of meaningful production from the base 200 production • High-returning investments limit overall production decline to ~1.5% CAGR over the next five years • Oil-dominated projects delivering strong returns 150 Sanctioned • Atlantis Phase 3, Mad Dog Phase 2, Ruby and projects T&T North West Barracouta to add ~25 MMboe in FY23 2016 Petroleum briefing 100 • Scarborough, Trion and US GoM embedded options Unsanctioned add significant potential growth from mid-2020s projects Unsanctioned projects • Competitive pipeline of high-return and improvement Sanctioned projects projects yield ~3% production CAGR from FY20-30 50 Base production • Material gas discoveries in Trinidad & Tobago North Exploration • Progressing exploration in Western Gulf of Mexico and and future Eastern Canada for tier one oil opportunities 0 options • Targeting further oil exposed growth FY19 FY20e FY21e FY22e FY23e FY24e FY25e FY26e FY27e FY28e FY29e FY30e Note: This represents an unconstrained scenario based on execution of all unsanctioned projects at current equity interests and Unconstrained scenario does not constitute guidance. Petroleum briefing 11 November 2019 7

Petroleum investments compete for capital Flexibility to manage investments across the Group • We aim to balance investments, shareholder returns and balance Capital Allocation Framework underpins investment decisions sheet strength to maximise value and returns Operating Capital productivity productivity – promotes discipline in all capital decisions Net operating cash flow – we have a broad suite of attractive opportunities across all Maintenance capital quadrants of our risk and return framework Strong balance sheet – high number of valuable Petroleum options that compete Minimum 50% payout ratio dividend Excess cash flow strongly against other options in the Group portfolio; only the most competitive opportunities will progress Balance Additional Organic Acquisitions/ Buy-backs sheet dividends development (Divestments) – Petroleum major projects with average IRRs ~25%; resilient through the cycle 1 Petroleum unconstrained investments to fund all existing options (US$ billion) • Flexibility to manage investments across the Group 5.0 – optionality through high-equity interests and operatorship – embedded options allow capital phasing and smoothing 2.5 0.0 FY19 FY20-FY22e FY23-FY25e FY26-FY28e Exploration expenditure Capital expenditure 1. This represents an unconstrained scenario based on execution of all unsanctioned projects at current equity interests and does not constitute guidance. Petroleum briefing 11 November 2019 8Petroleum investments compete for capital Flexibility to manage investments across the Group • We aim to balance investments, shareholder returns and balance Capital Allocation Framework underpins investment decisions sheet strength to maximise value and returns Operating Capital productivity productivity – promotes discipline in all capital decisions Net operating cash flow – we have a broad suite of attractive opportunities across all Maintenance capital quadrants of our risk and return framework Strong balance sheet – high number of valuable Petroleum options that compete Minimum 50% payout ratio dividend Excess cash flow strongly against other options in the Group portfolio; only the most competitive opportunities will progress Balance Additional Organic Acquisitions/ Buy-backs sheet dividends development (Divestments) – Petroleum major projects with average IRRs ~25%; resilient through the cycle 1 Petroleum unconstrained investments to fund all existing options (US$ billion) • Flexibility to manage investments across the Group 5.0 – optionality through high-equity interests and operatorship – embedded options allow capital phasing and smoothing 2.5 0.0 FY19 FY20-FY22e FY23-FY25e FY26-FY28e Exploration expenditure Capital expenditure 1. This represents an unconstrained scenario based on execution of all unsanctioned projects at current equity interests and does not constitute guidance. Petroleum briefing 11 November 2019 8

Petroleum creates a stronger and more resilient BHP Petroleum provides portfolio benefits, beyond being an attractive commodity 1 Petroleum reduces cash flow volatility Oil is an attractive commodity (Net operating cash flow volatility, %, nominal) Potential supply- ~10% demand reduction in gap volatility FY20e FY25e FY30e 2018 2050e Group portfolio Group portfolio Base supply Under development Demand range excluding Petroleum Source: BHP internal analysis. Increases competition for our capital Leverages core capabilities • Greater opportunity to invest in large, valuable projects • Shared safety, project execution and operational learnings • Multiple high-quality options, with attractive economics available; • Differentiated and integrated geoscience expertise only the best options selected • Global view of industrial commodities and energy markets • Diversification encourages greater counter-cyclical investment • Strong balance sheet enhances ability to access and develop options 1. Based on historical price and forex volatilities and correlations over the past 20 years. Petroleum briefing 11 November 2019 9Petroleum creates a stronger and more resilient BHP Petroleum provides portfolio benefits, beyond being an attractive commodity 1 Petroleum reduces cash flow volatility Oil is an attractive commodity (Net operating cash flow volatility, %, nominal) Potential supply- ~10% demand reduction in gap volatility FY20e FY25e FY30e 2018 2050e Group portfolio Group portfolio Base supply Under development Demand range excluding Petroleum Source: BHP internal analysis. Increases competition for our capital Leverages core capabilities • Greater opportunity to invest in large, valuable projects • Shared safety, project execution and operational learnings • Multiple high-quality options, with attractive economics available; • Differentiated and integrated geoscience expertise only the best options selected • Global view of industrial commodities and energy markets • Diversification encourages greater counter-cyclical investment • Strong balance sheet enhances ability to access and develop options 1. Based on historical price and forex volatilities and correlations over the past 20 years. Petroleum briefing 11 November 2019 9

Our strategy to maximise value and returns Petroleum aligns directly with BHP’s strategy Highly attractive commodities positioned Culture and capabilities that enable the to meet the world’s growing energy needs execution of our business strategy ü Crude oil ü Unwavering focus on safety Best Best ü Advantaged natural gas and sustainability culture and commodities ü Access, exploration and capabilities appraisal capabilities Value and ü Inclusive, empowered and high-performing culture returns Assets resilient through the cycle with Best embedded growth options assets ü Large, long-life and expandable ü High margin ü Focused on early access Driven by a commitment to transformation, capital discipline and social value Petroleum briefing 11 November 2019 10Our strategy to maximise value and returns Petroleum aligns directly with BHP’s strategy Highly attractive commodities positioned Culture and capabilities that enable the to meet the world’s growing energy needs execution of our business strategy ü Crude oil ü Unwavering focus on safety Best Best ü Advantaged natural gas and sustainability culture and commodities ü Access, exploration and capabilities appraisal capabilities Value and ü Inclusive, empowered and high-performing culture returns Assets resilient through the cycle with Best embedded growth options assets ü Large, long-life and expandable ü High margin ü Focused on early access Driven by a commitment to transformation, capital discipline and social value Petroleum briefing 11 November 2019 10

Oil and gas market outlook underpins our investments Michiel Hovers Group Sales and Marketing Officer AngosturaOil and gas market outlook underpins our investments Michiel Hovers Group Sales and Marketing Officer Angostura

Commodities Assets and opportunities Exploration Capabilities Value and returns We are deliberate about the commodities we choose Focused on holistic long-term value creation potential, informed by supply-demand balance – not just demand outlook Favourable supply and demand gap Large market sizes Favour commodities where inducement economics, rather than operating costs, set the price more often than not Enables future growth options in our assets Differentiated demand drivers Value creation and return potential Reduced portfolio cash flow volatility Enables counter-cyclical investment Steep cost curves Reduced risk of disruption in end-use markets Value in upstream Petroleum briefing 11 November 2019 12Commodities Assets and opportunities Exploration Capabilities Value and returns We are deliberate about the commodities we choose Focused on holistic long-term value creation potential, informed by supply-demand balance – not just demand outlook Favourable supply and demand gap Large market sizes Favour commodities where inducement economics, rather than operating costs, set the price more often than not Enables future growth options in our assets Differentiated demand drivers Value creation and return potential Reduced portfolio cash flow volatility Enables counter-cyclical investment Steep cost curves Reduced risk of disruption in end-use markets Value in upstream Petroleum briefing 11 November 2019 12

Commodities Assets and opportunities Exploration Capabilities Value and returns Supportive fundamentals for oil and advantaged gas New supply needs to be continuously induced to balance markets Why we like oil When we like gas • Conventional oil assets to remain attractive • Gas assets are attractive if: for several decades – geographically advantaged through infrastructure, customers, or both – supply-demand gap exists across all demand cases, even after an eventual peak – competitive on the cost curve – perpetual natural field decline leads supply • Abundance of the underlying resource to decline faster than demand makes asset choice critical – steep cost curve creates margin for assets competitive on the cost curve – even with increasing electrification, a supply-demand gap maintains inducement economics Structural supply-demand gap and a steeper cost curve underpins our more favourable outlook for oil than gas Petroleum briefing 11 November 2019 13Commodities Assets and opportunities Exploration Capabilities Value and returns Supportive fundamentals for oil and advantaged gas New supply needs to be continuously induced to balance markets Why we like oil When we like gas • Conventional oil assets to remain attractive • Gas assets are attractive if: for several decades – geographically advantaged through infrastructure, customers, or both – supply-demand gap exists across all demand cases, even after an eventual peak – competitive on the cost curve – perpetual natural field decline leads supply • Abundance of the underlying resource to decline faster than demand makes asset choice critical – steep cost curve creates margin for assets competitive on the cost curve – even with increasing electrification, a supply-demand gap maintains inducement economics Structural supply-demand gap and a steeper cost curve underpins our more favourable outlook for oil than gas Petroleum briefing 11 November 2019 13

Commodities Assets and opportunities Exploration Capabilities Value and returns Oil demand to peak and then decline modestly Demand tempered by the electrification of transport and fuel efficiency improvements, offset by rising living standards 1 Liquids demand by region Liquids demand by sector (MMbbl/d) (%) 125 100 35% 80 100 44% 47% 47% Road transport 75 60 40 50 20 25 0 0 2005 2020e 2035e 2050e 2000 2005 2010 2015 2020e 2025e 2030e 2035e 2040e 2045e 2050e Light Duty Vehicles (LDV) Medium/Heavy Duty Vehicles (MHDV) OECD China India Other Non-OECD Demand range Aviation Industrial/petrochemicals Other Source: BHP internal analysis. 1. Sectoral breakouts refer to our Central case assumptions. Petroleum briefing 11 November 2019 14Commodities Assets and opportunities Exploration Capabilities Value and returns Oil demand to peak and then decline modestly Demand tempered by the electrification of transport and fuel efficiency improvements, offset by rising living standards 1 Liquids demand by region Liquids demand by sector (MMbbl/d) (%) 125 100 35% 80 100 44% 47% 47% Road transport 75 60 40 50 20 25 0 0 2005 2020e 2035e 2050e 2000 2005 2010 2015 2020e 2025e 2030e 2035e 2040e 2045e 2050e Light Duty Vehicles (LDV) Medium/Heavy Duty Vehicles (MHDV) OECD China India Other Non-OECD Demand range Aviation Industrial/petrochemicals Other Source: BHP internal analysis. 1. Sectoral breakouts refer to our Central case assumptions. Petroleum briefing 11 November 2019 14

Commodities Assets and opportunities Exploration Capabilities Value and returns Electrification of transport: a strategic theme Light duty vehicle and bus fleet electrification is inevitable, however the medium and heavy truck fleet remain resilient Light duty vehicles fleet by segment Bus fleet by segment Medium and heavy truck fleet by segment (%) (%) (%) 100 100 100 50 50 50 0 0 0 2025e 2050e 2025e 2050e 2025e 2050e ICE BEV/PHEV ICE Electricity Natural gas ICE Electricity Natural gas Today: 28 MMbbl/d Æ 2050: 8 – 22 MMbbl/d Today: 14 MMbbl/d Æ 2050: 14 – 20 MMbbl/d Today: 3 MMbbl/d Æ 2050: 2 – 4 MMbbl/d Contribution of oil demand from road transport expected to fall from ~50% today to a range of 30–40% by 2050 Source: BHP internal analysis. Note: All data represented in the charts corresponds to our Central case assumption, while the range in text references our High and Low cases. ICE: Internal Combustion Engine; BEV/PHEV: Battery Electric Vehicles/Plug-in Hybrid Electric Vehicles. Petroleum briefing 11 November 2019 15Commodities Assets and opportunities Exploration Capabilities Value and returns Electrification of transport: a strategic theme Light duty vehicle and bus fleet electrification is inevitable, however the medium and heavy truck fleet remain resilient Light duty vehicles fleet by segment Bus fleet by segment Medium and heavy truck fleet by segment (%) (%) (%) 100 100 100 50 50 50 0 0 0 2025e 2050e 2025e 2050e 2025e 2050e ICE BEV/PHEV ICE Electricity Natural gas ICE Electricity Natural gas Today: 28 MMbbl/d Æ 2050: 8 – 22 MMbbl/d Today: 14 MMbbl/d Æ 2050: 14 – 20 MMbbl/d Today: 3 MMbbl/d Æ 2050: 2 – 4 MMbbl/d Contribution of oil demand from road transport expected to fall from ~50% today to a range of 30–40% by 2050 Source: BHP internal analysis. Note: All data represented in the charts corresponds to our Central case assumption, while the range in text references our High and Low cases. ICE: Internal Combustion Engine; BEV/PHEV: Battery Electric Vehicles/Plug-in Hybrid Electric Vehicles. Petroleum briefing 11 November 2019 15

Commodities Assets and opportunities Exploration Capabilities Value and returns Compelling long run supply-demand fundamentals A supply gap of more than 50 MMbbl/d could emerge by 2035; “yet-to-find” barrels will be an increasingly important contributor Oil demand and onstream supply • Compelling fundamentals (MMbbl/d) – there is a structural supply-demand gap in all our cases that persists beyond the peak in demand – base supply decline will require cumulative new supply equal to 1.5x OPEC by 2035 – we expect oil to be in an inducement pricing regime more often than not; cost curve to remain steep • Upstream investment and project sanctions required 2018 2050e Base supply Under development Demand range – the industry has under-invested in both exploration and 1 deepwater development over the past five years Oil supply by resource theme (MMbbl/d) – conventional oil resources sanctioned for development fell to 7 Bboe from 2016-18 (annual average), 60% lower 1 than previous five years – creates the possibility of a steep price correction in the mid-2020s 2020e 2030e 2035e 2050e Onstream & other OPEC Onshore Offshore US L48 Yet-to-find 1. International Energy Agency (2019), World Energy investment 2019, IEA, Paris. Demand range Source: BHP internal analysis. Petroleum briefing 11 November 2019 16Commodities Assets and opportunities Exploration Capabilities Value and returns Compelling long run supply-demand fundamentals A supply gap of more than 50 MMbbl/d could emerge by 2035; “yet-to-find” barrels will be an increasingly important contributor Oil demand and onstream supply • Compelling fundamentals (MMbbl/d) – there is a structural supply-demand gap in all our cases that persists beyond the peak in demand – base supply decline will require cumulative new supply equal to 1.5x OPEC by 2035 – we expect oil to be in an inducement pricing regime more often than not; cost curve to remain steep • Upstream investment and project sanctions required 2018 2050e Base supply Under development Demand range – the industry has under-invested in both exploration and 1 deepwater development over the past five years Oil supply by resource theme (MMbbl/d) – conventional oil resources sanctioned for development fell to 7 Bboe from 2016-18 (annual average), 60% lower 1 than previous five years – creates the possibility of a steep price correction in the mid-2020s 2020e 2030e 2035e 2050e Onstream & other OPEC Onshore Offshore US L48 Yet-to-find 1. International Energy Agency (2019), World Energy investment 2019, IEA, Paris. Demand range Source: BHP internal analysis. Petroleum briefing 11 November 2019 16

Commodities Assets and opportunities Exploration Capabilities Value and returns Gas demand diversified and resilient; LNG gaining share LNG demand could double by 2035, outpacing global gas demand growth Global gas demand by sector • Global gas demand to rise (Bcf/d) – share of total primary energy demand increases from 500 22% to 26% by 2050 – gas complements renewables in power sector 250 – LNG is the fastest growing fossil fuel segment, with LNG share of global gas demand expected to rise from 12% to ~20% by 2050 0 2015 2020e 2025e 2030e 2035e 2040e • Recent wave of new LNG supply weighs on the market until Power Industrial Residential/commercial Others LNG demand the mid 2020s – new supply from North America, Australia, Russia and Global LNG supply-demand balance (Bcf/d) Mozambique out-stripping demand, with overflow to European storage – strong demand growth from Asia and Europe could allow the market to balance by the mid-2020s 2015 2020e 2025e 2030e 2035e 2040e Operational Under construction Demand range Source: BHP internal analysis. Petroleum briefing 11 November 2019 17Commodities Assets and opportunities Exploration Capabilities Value and returns Gas demand diversified and resilient; LNG gaining share LNG demand could double by 2035, outpacing global gas demand growth Global gas demand by sector • Global gas demand to rise (Bcf/d) – share of total primary energy demand increases from 500 22% to 26% by 2050 – gas complements renewables in power sector 250 – LNG is the fastest growing fossil fuel segment, with LNG share of global gas demand expected to rise from 12% to ~20% by 2050 0 2015 2020e 2025e 2030e 2035e 2040e • Recent wave of new LNG supply weighs on the market until Power Industrial Residential/commercial Others LNG demand the mid 2020s – new supply from North America, Australia, Russia and Global LNG supply-demand balance (Bcf/d) Mozambique out-stripping demand, with overflow to European storage – strong demand growth from Asia and Europe could allow the market to balance by the mid-2020s 2015 2020e 2025e 2030e 2035e 2040e Operational Under construction Demand range Source: BHP internal analysis. Petroleum briefing 11 November 2019 17

Commodities Assets and opportunities Exploration Capabilities Value and returns Price harmonisation increases importance of asset choice Natural gas assets with access to infrastructure will be advantaged as the global LNG market matures • LNG market moving towards a global benchmark – US export capacity is drawing the key consumer regions of Asia and Europe closer together – as the industry expands, single large projects have less impact on the overall market balance Europe 1 Asia North America • Contracting terms continue to evolve 7-12 – contract duration has reduced since the early 9-19 Middle East 31-47 2000s, as buyers demand shorter lengths 12-16 – spot markets are deepening Africa – indexation to oil has dropped in favour of 6-10 Henry Hub indexing and hybrid pricing structures South America 2 Australia 2-3 13-15 Net exporter 2018-2030 (Bcf/d) Net importer Note: Price harmonisation refers to the convergence of LNG pricing around a global benchmark. Source: BHP internal analysis. 1. Includes Mexico. 2. Includes Papua New Guinea. Petroleum briefing 11 November 2019 18Commodities Assets and opportunities Exploration Capabilities Value and returns Price harmonisation increases importance of asset choice Natural gas assets with access to infrastructure will be advantaged as the global LNG market matures • LNG market moving towards a global benchmark – US export capacity is drawing the key consumer regions of Asia and Europe closer together – as the industry expands, single large projects have less impact on the overall market balance Europe 1 Asia North America • Contracting terms continue to evolve 7-12 – contract duration has reduced since the early 9-19 Middle East 31-47 2000s, as buyers demand shorter lengths 12-16 – spot markets are deepening Africa – indexation to oil has dropped in favour of 6-10 Henry Hub indexing and hybrid pricing structures South America 2 Australia 2-3 13-15 Net exporter 2018-2030 (Bcf/d) Net importer Note: Price harmonisation refers to the convergence of LNG pricing around a global benchmark. Source: BHP internal analysis. 1. Includes Mexico. 2. Includes Papua New Guinea. Petroleum briefing 11 November 2019 18

Commodities Assets and opportunities Exploration Capabilities Value and returns Supportive fundamentals for oil and advantaged gas New supply needs to be continuously induced to balance markets Why we like oil When we like gas • Conventional oil assets to remain attractive • Gas assets are attractive if: for several decades – geographically advantaged through infrastructure, customers, or both – supply-demand gap exists across all demand cases, even after an eventual peak – competitive on the cost curve – perpetual natural field decline leads supply • Abundance of the underlying resource to decline faster than demand makes asset choice critical – steep cost curve creates margin for assets competitive on the cost curve – even with increasing electrification, a supply-demand gap maintains inducement economics Structural supply-demand gap and a steeper cost curve underpins our more favourable outlook for oil than gas Petroleum briefing 11 November 2019 19Commodities Assets and opportunities Exploration Capabilities Value and returns Supportive fundamentals for oil and advantaged gas New supply needs to be continuously induced to balance markets Why we like oil When we like gas • Conventional oil assets to remain attractive • Gas assets are attractive if: for several decades – geographically advantaged through infrastructure, customers, or both – supply-demand gap exists across all demand cases, even after an eventual peak – competitive on the cost curve – perpetual natural field decline leads supply • Abundance of the underlying resource to decline faster than demand makes asset choice critical – steep cost curve creates margin for assets competitive on the cost curve – even with increasing electrification, a supply-demand gap maintains inducement economics Structural supply-demand gap and a steeper cost curve underpins our more favourable outlook for oil than gas Petroleum briefing 11 November 2019 19

High-return assets and opportunities Geraldine Slattery President Operations Petroleum ShenziHigh-return assets and opportunities Geraldine Slattery President Operations Petroleum Shenzi

Commodities Assets and opportunities Exploration Capabilities Value and returns Quality assets concentrated in key heartlands Over 3 Bboe in resources provide potential to expand our presence in the Gulf of Mexico, Trinidad & Tobago and Western Australia Western Australia Eastern Canada Western Australia Rest of Proved 2 portfolio Northwest Shelf (NWS) Eastern Canada: 5,434 km Scarborough Pyrenees 974 Macedon 2P MMboe 2P+2C resources ~3.2 Other US US Gulf of Mexico Eastern Canada Bboe GoM 2 Western: 2,180 km 2C Probable 2 Central: 838 km Bass Strait Bass Strait T&T North Scarborough 452 Mexico Mexico Trion Wildling MMboe 2P+2C resources Trion 222 MMboe 2P+2C resources US Gulf of Mexico US Gulf of Mexico 1 Mad Dog Trinidad & Tobago Atlantis Angostura Shenzi 2 Ruby 937 Wildling 582 MMboe T&T North Neptune MMboe 2P+2C resources T&T South 2P+2C resources Note: Algeria resource volumes included in Rest of portfolio wedge. 1. Includes Bélé and Tuk discoveries which represent a combined 180 MMboe (net). 2. Ruby project includes the Ruby and Delaware fields. Petroleum briefing 11 November 2019 21Commodities Assets and opportunities Exploration Capabilities Value and returns Quality assets concentrated in key heartlands Over 3 Bboe in resources provide potential to expand our presence in the Gulf of Mexico, Trinidad & Tobago and Western Australia Western Australia Eastern Canada Western Australia Rest of Proved 2 portfolio Northwest Shelf (NWS) Eastern Canada: 5,434 km Scarborough Pyrenees 974 Macedon 2P MMboe 2P+2C resources ~3.2 Other US US Gulf of Mexico Eastern Canada Bboe GoM 2 Western: 2,180 km 2C Probable 2 Central: 838 km Bass Strait Bass Strait T&T North Scarborough 452 Mexico Mexico Trion Wildling MMboe 2P+2C resources Trion 222 MMboe 2P+2C resources US Gulf of Mexico US Gulf of Mexico 1 Mad Dog Trinidad & Tobago Atlantis Angostura Shenzi 2 Ruby 937 Wildling 582 MMboe T&T North Neptune MMboe 2P+2C resources T&T South 2P+2C resources Note: Algeria resource volumes included in Rest of portfolio wedge. 1. Includes Bélé and Tuk discoveries which represent a combined 180 MMboe (net). 2. Ruby project includes the Ruby and Delaware fields. Petroleum briefing 11 November 2019 21

Commodities Assets and opportunities Exploration Capabilities Value and returns Replenishing the portfolio with high-value resources Balanced portfolio provides strong foundation for growth through the next decade 1,2 Heartlands Value accretive production potential over the next decade (Production, MMboe) Advantaged gas position with modest investable 200 Bass Strait opportunities Western North West Shelf provides strong free cash flows; 150 Australia Scarborough offers growth potential T&T North US Gulf of T&T shallow water Mexico Large, long-life and expandable oil position 100 Mexico US Gulf of Mexico First deepwater oil asset in Mexico with equity Mexico and exploration potential 50 Western Australia Trinidad & Advantaged gas position with significant volumes Bass Strait Tobago and equity, providing flexibility on development 2 Other 0 FY19 FY20e FY21e FY22e FY23e FY24e FY25e FY26e FY27e FY28e FY29e FY30e Unconstrained scenario 1. This represents an unconstrained scenario based on execution of all unsanctioned projects at current equity interests and does not constitute guidance. Volumes include base, sanctioned and unsanctioned projects, and exploration. 2. Other production includes volumes from Algeria. Petroleum briefing 11 November 2019 22Commodities Assets and opportunities Exploration Capabilities Value and returns Replenishing the portfolio with high-value resources Balanced portfolio provides strong foundation for growth through the next decade 1,2 Heartlands Value accretive production potential over the next decade (Production, MMboe) Advantaged gas position with modest investable 200 Bass Strait opportunities Western North West Shelf provides strong free cash flows; 150 Australia Scarborough offers growth potential T&T North US Gulf of T&T shallow water Mexico Large, long-life and expandable oil position 100 Mexico US Gulf of Mexico First deepwater oil asset in Mexico with equity Mexico and exploration potential 50 Western Australia Trinidad & Advantaged gas position with significant volumes Bass Strait Tobago and equity, providing flexibility on development 2 Other 0 FY19 FY20e FY21e FY22e FY23e FY24e FY25e FY26e FY27e FY28e FY29e FY30e Unconstrained scenario 1. This represents an unconstrained scenario based on execution of all unsanctioned projects at current equity interests and does not constitute guidance. Volumes include base, sanctioned and unsanctioned projects, and exploration. 2. Other production includes volumes from Algeria. Petroleum briefing 11 November 2019 22

Commodities Assets and opportunities Exploration Capabilities Value and returns Australia: strong free cash flow generation Bass Strait and North West Shelf demonstrate the strength of our base assets 1,2 Australian assets: production by lifecycle • Bass Strait: high returns with upside through the 2020s (Production, MMboe) – highly cash generative, advantaged gas play 80 – West Barracouta sanctioned in FY19 with a ~20% IRR – multiple improvement projects with expected average IRRs >30% 40 • North West Shelf: consistently delivers high returns – strong free cash flow generation from equity gas 0 – followed by revenue generation from other resource owners FY19 FY20e FY21e FY22e FY23e FY24e FY25e FY26e FY27e FY28e FY29e FY30e Base production Sanctioned projects • Manage the portfolio for value Unsanctioned projects Scarborough – advance Scarborough to final investment decision Australian assets: free cash flow and capex profile (US$ billion) – commercialise remaining resources 3 Free cash flow Capex – recognise optimal exit windows 2 1 0 (1) FY19 FY20-24e FY25-30e 1. This represents an unconstrained scenario based on execution of all unsanctioned projects at current equity interests and average average does not constitute guidance. Volumes include base, sanctioned and unsanctioned projects, and exploration. 2. Scarborough production at BHP effective working interest of 26.5% across WA-1-R and WA-62-R; excludes the 10% option. Free cash flow and capex at Wood Mackenzie prices At US$60-80/bbl oil price Petroleum briefing 11 November 2019 23Commodities Assets and opportunities Exploration Capabilities Value and returns Australia: strong free cash flow generation Bass Strait and North West Shelf demonstrate the strength of our base assets 1,2 Australian assets: production by lifecycle • Bass Strait: high returns with upside through the 2020s (Production, MMboe) – highly cash generative, advantaged gas play 80 – West Barracouta sanctioned in FY19 with a ~20% IRR – multiple improvement projects with expected average IRRs >30% 40 • North West Shelf: consistently delivers high returns – strong free cash flow generation from equity gas 0 – followed by revenue generation from other resource owners FY19 FY20e FY21e FY22e FY23e FY24e FY25e FY26e FY27e FY28e FY29e FY30e Base production Sanctioned projects • Manage the portfolio for value Unsanctioned projects Scarborough – advance Scarborough to final investment decision Australian assets: free cash flow and capex profile (US$ billion) – commercialise remaining resources 3 Free cash flow Capex – recognise optimal exit windows 2 1 0 (1) FY19 FY20-24e FY25-30e 1. This represents an unconstrained scenario based on execution of all unsanctioned projects at current equity interests and average average does not constitute guidance. Volumes include base, sanctioned and unsanctioned projects, and exploration. 2. Scarborough production at BHP effective working interest of 26.5% across WA-1-R and WA-62-R; excludes the 10% option. Free cash flow and capex at Wood Mackenzie prices At US$60-80/bbl oil price Petroleum briefing 11 November 2019 23

Commodities Assets and opportunities Exploration Capabilities Value and returns Scarborough: working to advance development Material growth potential through development of Scarborough and unlocking additional contingent resources BHP’s Western Australia heartland • Large, long-life resource 1 – 2C resources: 11.1 Tcf (gross) Thebe – proposed development concept of 13 subsea wells tied North West Shelf Jupiter back to a semi-submersible floating production unit – opportunity for further expansion through Thebe/Jupiter Scarborough tieback LNG Plant • Advantaged gas opportunity Dampier Karratha – close to attractive LNG markets – enabled by leveraging regional infrastructure Pyrenees Stybarrow Macedon • Working with operator to advance development Onslow Macedon – negotiations for gas processing ongoing BHP Gas Plant 1 Liquid Fields – capex of US$1.4–1.9 billion (net), with a final investment Gas Fields decision expected in CY20 Timeline CY2020 2021 2022 2023 2024 2025 2026 2027 1. Based on information provided by operator. Represents BHP’s current equity position as 25% in WA-1-R and 50% in WA-62-R. FID range First production range Petroleum briefing 11 November 2019 24Commodities Assets and opportunities Exploration Capabilities Value and returns Scarborough: working to advance development Material growth potential through development of Scarborough and unlocking additional contingent resources BHP’s Western Australia heartland • Large, long-life resource 1 – 2C resources: 11.1 Tcf (gross) Thebe – proposed development concept of 13 subsea wells tied North West Shelf Jupiter back to a semi-submersible floating production unit – opportunity for further expansion through Thebe/Jupiter Scarborough tieback LNG Plant • Advantaged gas opportunity Dampier Karratha – close to attractive LNG markets – enabled by leveraging regional infrastructure Pyrenees Stybarrow Macedon • Working with operator to advance development Onslow Macedon – negotiations for gas processing ongoing BHP Gas Plant 1 Liquid Fields – capex of US$1.4–1.9 billion (net), with a final investment Gas Fields decision expected in CY20 Timeline CY2020 2021 2022 2023 2024 2025 2026 2027 1. Based on information provided by operator. Represents BHP’s current equity position as 25% in WA-1-R and 50% in WA-62-R. FID range First production range Petroleum briefing 11 November 2019 24

Commodities Assets and opportunities Exploration Capabilities Value and returns US Gulf of Mexico: big fields get bigger Growing pipeline of high-return projects across all three assets 1 US Gulf of Mexico delivers value-accretive production • Atlantis: additional targets unlocked with advanced seismic (Production, MMboe) – Phase 3: 8 well tieback; 32 Mbbl/d incremental liquids peak 40 rate (gross); >40% IRR with first oil expected in CY20 – multiple future development projects in planning phase 20 • Mad Dog: tier one asset in the US Gulf of Mexico – Phase 2: 140 Mbbl/d liquids peak rate (gross); >15% IRR with first oil expected in CY22 0 – future unsanctioned projects include Northwest Water Injection FY19 FY20e FY21e FY22e FY23e FY24e FY25e FY26e FY27e FY28e FY29e FY30e (NWI) and tieback opportunities Mad Dog Atlantis Shenzi / Wildling Other US Gulf of Mexico drives strong returns over the next 10 years • Shenzi: operated infield and nearfield opportunity sets (ROCE, %) – Wildling Phase 1: two well development tieback to Shenzi 30 derisks future development phase concept – future unsanctioned projects include Shenzi Subsea Multi-Phase Pumping and further infill targets 15 • Pipeline of unsanctioned growth opportunities enabled by Ocean Bottom Node (OBN) seismic and advanced processing 0 FY19 FY20-24e FY25-30e 1. This represents an unconstrained scenario based on execution of all unsanctioned projects at current equity interests and does not constitute guidance. ROCE at Wood Mackenzie prices At US$60-80/bbl oil price Petroleum briefing 11 November 2019 25Commodities Assets and opportunities Exploration Capabilities Value and returns US Gulf of Mexico: big fields get bigger Growing pipeline of high-return projects across all three assets 1 US Gulf of Mexico delivers value-accretive production • Atlantis: additional targets unlocked with advanced seismic (Production, MMboe) – Phase 3: 8 well tieback; 32 Mbbl/d incremental liquids peak 40 rate (gross); >40% IRR with first oil expected in CY20 – multiple future development projects in planning phase 20 • Mad Dog: tier one asset in the US Gulf of Mexico – Phase 2: 140 Mbbl/d liquids peak rate (gross); >15% IRR with first oil expected in CY22 0 – future unsanctioned projects include Northwest Water Injection FY19 FY20e FY21e FY22e FY23e FY24e FY25e FY26e FY27e FY28e FY29e FY30e (NWI) and tieback opportunities Mad Dog Atlantis Shenzi / Wildling Other US Gulf of Mexico drives strong returns over the next 10 years • Shenzi: operated infield and nearfield opportunity sets (ROCE, %) – Wildling Phase 1: two well development tieback to Shenzi 30 derisks future development phase concept – future unsanctioned projects include Shenzi Subsea Multi-Phase Pumping and further infill targets 15 • Pipeline of unsanctioned growth opportunities enabled by Ocean Bottom Node (OBN) seismic and advanced processing 0 FY19 FY20-24e FY25-30e 1. This represents an unconstrained scenario based on execution of all unsanctioned projects at current equity interests and does not constitute guidance. ROCE at Wood Mackenzie prices At US$60-80/bbl oil price Petroleum briefing 11 November 2019 25

Commodities Assets and opportunities Exploration Capabilities Value and returns Trion: Mexico’s first deepwater development Material oil resource advancing towards an early 2020s final investment decision BHP’s Trion position in relation to US Gulf of Mexico blocks • Large oil resource: 222 MMboe net 2C resources • Successful appraisal program has reduced uncertainty – first deepwater well drilled by an international operator – top-tier drilling performance – reduced downside uncertainty associated with potential gas cap • Deploying our deepwater capabilities in Mexico 1 Gas fields 1 – top-five deepest offshore oil development Oil fields BHP leases Mexico leases – focus on building strong relationships, safety performance and US current leases social value • Unlocking further opportunities – additional exploration drilling in the Trion block in FY21 – continue to look for attractive investment opportunities to expand our position in Mexico Timeline CY2020 2021 2022 2023 2024 2025 2026 2027 Schedule range excludes non-project risks Exploration drilling FID range First production range 1. Source: Wood Mackenzie. Petroleum briefing 11 November 2019 26Commodities Assets and opportunities Exploration Capabilities Value and returns Trion: Mexico’s first deepwater development Material oil resource advancing towards an early 2020s final investment decision BHP’s Trion position in relation to US Gulf of Mexico blocks • Large oil resource: 222 MMboe net 2C resources • Successful appraisal program has reduced uncertainty – first deepwater well drilled by an international operator – top-tier drilling performance – reduced downside uncertainty associated with potential gas cap • Deploying our deepwater capabilities in Mexico 1 Gas fields 1 – top-five deepest offshore oil development Oil fields BHP leases Mexico leases – focus on building strong relationships, safety performance and US current leases social value • Unlocking further opportunities – additional exploration drilling in the Trion block in FY21 – continue to look for attractive investment opportunities to expand our position in Mexico Timeline CY2020 2021 2022 2023 2024 2025 2026 2027 Schedule range excludes non-project risks Exploration drilling FID range First production range 1. Source: Wood Mackenzie. Petroleum briefing 11 November 2019 26

Commodities Assets and opportunities Exploration Capabilities Value and returns Trinidad & Tobago: a material, deepwater gas discovery Building on our existing position in the region and successfully unlocking a frontier basin Trinidad & Tobago North licenses and discoveries • T&T North deepwater gas exploration program successful Block 23(a) – discovered 3.5 Tcf gross contingent resources, with additional Burrokeet 2 unpenetrated potential (net interest 70%) Carnival-1 – evaluation ongoing for upside potential from recent drilling 2C Contingent Resources Penetrated, evaluation ongoing Bele-1 – multiple gas discoveries suited to a hub development Prospective Volumes Boom-1 BHP Dry Hole BHP Gas Discovery • Development planning and commerciality assessment – targeting LNG and gas-short domestic markets – currently evaluating multiple development concepts – final investment decision expected by CY24 Bongos-2 Hi-Hat 1 • Ruby to offset declines from Angostura in mid-2020s – Ruby project sanctioned August 2019; IRR ~30% Tuk-1 – further oil development upside unlocked from recent OBN Block 14 • Additional exploration and appraisal opportunities Timeline – evaluating a deep test in the southern deepwater licenses CY2020 2021 2022 2023 2024 2025 2026 2027 2028 – assessing commerciality potential of gas discovery in the south T&T North FID range First production range Petroleum briefing 11 November 2019 27Commodities Assets and opportunities Exploration Capabilities Value and returns Trinidad & Tobago: a material, deepwater gas discovery Building on our existing position in the region and successfully unlocking a frontier basin Trinidad & Tobago North licenses and discoveries • T&T North deepwater gas exploration program successful Block 23(a) – discovered 3.5 Tcf gross contingent resources, with additional Burrokeet 2 unpenetrated potential (net interest 70%) Carnival-1 – evaluation ongoing for upside potential from recent drilling 2C Contingent Resources Penetrated, evaluation ongoing Bele-1 – multiple gas discoveries suited to a hub development Prospective Volumes Boom-1 BHP Dry Hole BHP Gas Discovery • Development planning and commerciality assessment – targeting LNG and gas-short domestic markets – currently evaluating multiple development concepts – final investment decision expected by CY24 Bongos-2 Hi-Hat 1 • Ruby to offset declines from Angostura in mid-2020s – Ruby project sanctioned August 2019; IRR ~30% Tuk-1 – further oil development upside unlocked from recent OBN Block 14 • Additional exploration and appraisal opportunities Timeline – evaluating a deep test in the southern deepwater licenses CY2020 2021 2022 2023 2024 2025 2026 2027 2028 – assessing commerciality potential of gas discovery in the south T&T North FID range First production range Petroleum briefing 11 November 2019 27

Commodities Assets and opportunities Exploration Capabilities Value and returns A healthy pipeline of options supports our future Constantly identifying and derisking new opportunities while progressing only the best options 2 Significant growth potential over the next decade Value accretive production potential over the next decade 1 (Value , BHP share) (Production, MMboe) 200 Unsanctioned Sanctioned Base Exploration projects projects production Eastern 150 T&T Western Canada NWS North Australia T&T North APU Atlantis Scarborough Bass Strait Ph3 Eastern Mad Dog Western 100 Australia Ph2 GoM Atlantis Trion (EB Hub) Unsanctioned projects Ruby Shenzi Wildling Mad Angostura Dog Sanctioned projects West Barracouta 50 Gulf of Western Base Mexico GoM production (GB Hub) 0 Reduced risk, increasing value FY19 FY20e FY21e FY22e FY23e FY24e FY25e FY26e FY27e FY28e FY29e FY30e 1. Unrisked values at BHP long-term price forecasts. 2. This represents an unconstrained scenario based on execution of all unsanctioned projects at current equity interests and does not Unconstrained scenario constitute guidance; Eastern Canada and Western GoM volumes not shown as they begin producing outside the forecast period. Petroleum briefing 11 November 2019 28Commodities Assets and opportunities Exploration Capabilities Value and returns A healthy pipeline of options supports our future Constantly identifying and derisking new opportunities while progressing only the best options 2 Significant growth potential over the next decade Value accretive production potential over the next decade 1 (Value , BHP share) (Production, MMboe) 200 Unsanctioned Sanctioned Base Exploration projects projects production Eastern 150 T&T Western Canada NWS North Australia T&T North APU Atlantis Scarborough Bass Strait Ph3 Eastern Mad Dog Western 100 Australia Ph2 GoM Atlantis Trion (EB Hub) Unsanctioned projects Ruby Shenzi Wildling Mad Angostura Dog Sanctioned projects West Barracouta 50 Gulf of Western Base Mexico GoM production (GB Hub) 0 Reduced risk, increasing value FY19 FY20e FY21e FY22e FY23e FY24e FY25e FY26e FY27e FY28e FY29e FY30e 1. Unrisked values at BHP long-term price forecasts. 2. This represents an unconstrained scenario based on execution of all unsanctioned projects at current equity interests and does not Unconstrained scenario constitute guidance; Eastern Canada and Western GoM volumes not shown as they begin producing outside the forecast period. Petroleum briefing 11 November 2019 28

Delivering the future through exploration Sonia Scarselli VP Exploration and Appraisal Deepwater InvictusDelivering the future through exploration Sonia Scarselli VP Exploration and Appraisal Deepwater Invictus

Commodities Assets and opportunities Exploration Capabilities Value and returns Our exploration strategy is delivering Exploration has added ~800 MMboe of 2C resources since FY17 1,2 Substantial increase in 2C resources, back to FY12 levels Access Explore Appraise (Net 2C resources, MMboe) 2,200 • Tier one potential, geographically focused – bias for oil 41 19 – big reservoir systems, world class source rock Ç70% – large scale; >100 Mboe/d net; multiple pools >250 MMboe 408 1,800 • Value focused – competitive fiscal terms – early access at high equity 222 • BHP way 1,400 68 – acquire the right data 112 – rigorous “bottom-up” systems based technical evaluation 1,000 FY17 Production Wildling Trion T&T T&T Other Unit Adds increase North South E&A 1. T&T North 408 MMboe includes FY19 Bongos 2C of 228 MMboe and FY20 Bélé and Tuk discoveries which represent combined 2C of 180 MMboe as of 30 September 2019 (net, no fuel). 2. Samurai 19 MMboe (net, no fuel) exited for value. The sale closed on 4 November 2019. Petroleum briefing 11 November 2019 30Commodities Assets and opportunities Exploration Capabilities Value and returns Our exploration strategy is delivering Exploration has added ~800 MMboe of 2C resources since FY17 1,2 Substantial increase in 2C resources, back to FY12 levels Access Explore Appraise (Net 2C resources, MMboe) 2,200 • Tier one potential, geographically focused – bias for oil 41 19 – big reservoir systems, world class source rock Ç70% – large scale; >100 Mboe/d net; multiple pools >250 MMboe 408 1,800 • Value focused – competitive fiscal terms – early access at high equity 222 • BHP way 1,400 68 – acquire the right data 112 – rigorous “bottom-up” systems based technical evaluation 1,000 FY17 Production Wildling Trion T&T T&T Other Unit Adds increase North South E&A 1. T&T North 408 MMboe includes FY19 Bongos 2C of 228 MMboe and FY20 Bélé and Tuk discoveries which represent combined 2C of 180 MMboe as of 30 September 2019 (net, no fuel). 2. Samurai 19 MMboe (net, no fuel) exited for value. The sale closed on 4 November 2019. Petroleum briefing 11 November 2019 30

Commodities Assets and opportunities Exploration Capabilities Value and returns Investing in the BHP way underpins our success Getting the right data, at the right time, and capturing the play is crucial to creating value in exploration Technical success translating to likely commercial success • Invest in the right data to describe the volume, risk and value (%) of an opportunity to maximise chance of success 100 • Focused strategy has resulted in strong technical and likely commercial success 50 – Trion – Wilding 0 – Trinidad & Tobago North FY17 FY18 FY19 FY20 (YTD) • We have the right people and processes Technical success rate Likely commercial success – regionally based exploration teams supported by globally Acquiring the right data ahead of drilling 1 integrated geoscience expertise (FY20 – FY24 spend categories ) Seismic – right data and fit-for-purpose systems reprocessing Seismic acquisition • Added new tier one opportunities Exploration Seismic drilling licensing Studies & data 1. Excludes lease access and rental costs. Appraisal Petroleum briefing drilling 11 November 2019 31Commodities Assets and opportunities Exploration Capabilities Value and returns Investing in the BHP way underpins our success Getting the right data, at the right time, and capturing the play is crucial to creating value in exploration Technical success translating to likely commercial success • Invest in the right data to describe the volume, risk and value (%) of an opportunity to maximise chance of success 100 • Focused strategy has resulted in strong technical and likely commercial success 50 – Trion – Wilding 0 – Trinidad & Tobago North FY17 FY18 FY19 FY20 (YTD) • We have the right people and processes Technical success rate Likely commercial success – regionally based exploration teams supported by globally Acquiring the right data ahead of drilling 1 integrated geoscience expertise (FY20 – FY24 spend categories ) Seismic – right data and fit-for-purpose systems reprocessing Seismic acquisition • Added new tier one opportunities Exploration Seismic drilling licensing Studies & data 1. Excludes lease access and rental costs. Appraisal Petroleum briefing drilling 11 November 2019 31

Commodities Assets and opportunities Exploration Capabilities Value and returns Early access to capture value and enable optionality We have added tier one potential opportunities to the portfolio at high equity • Early access with high equity to manage risk through lifecycle • Large material positions in major potential petroleum systems • Continue to look for oil focused opportunities that improve value of the portfolio Eastern Canada US GoM Exploration and appraisal acreage Mexico 2 (km ) (Average working interest, %) Barbados 6,000 100 Western Australia Trinidad & Tobago 3,000 50 Bass Strait 0 0 T&T T&T Mexico US GoM Barbados Eastern North South Canada Net acreage (LHS) Working interest (RHS) Petroleum briefing 11 November 2019 32Commodities Assets and opportunities Exploration Capabilities Value and returns Early access to capture value and enable optionality We have added tier one potential opportunities to the portfolio at high equity • Early access with high equity to manage risk through lifecycle • Large material positions in major potential petroleum systems • Continue to look for oil focused opportunities that improve value of the portfolio Eastern Canada US GoM Exploration and appraisal acreage Mexico 2 (km ) (Average working interest, %) Barbados 6,000 100 Western Australia Trinidad & Tobago 3,000 50 Bass Strait 0 0 T&T T&T Mexico US GoM Barbados Eastern North South Canada Net acreage (LHS) Working interest (RHS) Petroleum briefing 11 November 2019 32

Commodities Assets and opportunities Exploration Capabilities Value and returns Eastern Canada: major potential tier one oil opportunity Orphan Basin bringing options for the 2030s • Opportunity details Orphan Basin – BHP (100% WI, operator) 1 – Orphan Basin contains significant prospective potential BHP 2 – large leases (2,700 km ) with multiple play types BP Flemish Pass Basin 2 CNOOC (one GoM lease is 23 km ) Chevron 2 – giant structures with 100-500 km with potential for Equinor multiple closures at reservoir level Exxon Husky 2 Fields • Next steps Imperial Jeanne d’Arc Basin Prospects Suncor – reprocessing seismic – targeting first exploration well in FY22 Orphan Basin BHP Prospect BHP Prospect BHP Prospect kilometres Timeline CY2020 2021 2022 2023 2024 2025 2026 2027 2028 Economic Basement Explore Appraise Tithonian Reservoir Targets 1. Offshore Newfoundland & Labrador Resource Assessment – Orphan Basin Area NL18-CFB01 (BeicipFranlab September 2018). 2. Source: Wood Mackenzie. Petroleum briefing 11 November 2019 33Commodities Assets and opportunities Exploration Capabilities Value and returns Eastern Canada: major potential tier one oil opportunity Orphan Basin bringing options for the 2030s • Opportunity details Orphan Basin – BHP (100% WI, operator) 1 – Orphan Basin contains significant prospective potential BHP 2 – large leases (2,700 km ) with multiple play types BP Flemish Pass Basin 2 CNOOC (one GoM lease is 23 km ) Chevron 2 – giant structures with 100-500 km with potential for Equinor multiple closures at reservoir level Exxon Husky 2 Fields • Next steps Imperial Jeanne d’Arc Basin Prospects Suncor – reprocessing seismic – targeting first exploration well in FY22 Orphan Basin BHP Prospect BHP Prospect BHP Prospect kilometres Timeline CY2020 2021 2022 2023 2024 2025 2026 2027 2028 Economic Basement Explore Appraise Tithonian Reservoir Targets 1. Offshore Newfoundland & Labrador Resource Assessment – Orphan Basin Area NL18-CFB01 (BeicipFranlab September 2018). 2. Source: Wood Mackenzie. Petroleum briefing 11 November 2019 33

Commodities Assets and opportunities Exploration Capabilities Value and returns Western GoM: extending prolific Perdido play sub-salt Using innovative technology to image the play • Opportunity details – BHP (100% WI, operator); secured key position as early mover GB Hub – historically underexplored area due to sub-salt imaging challenges EB Hub 1 – acquired world’s first exploration OBN seismic survey to improve sub-salt imaging; currently finalising processing – added new Garden Banks (GB) Hub in August 2019 lease sales BHP Equinor AC Hub • Next steps Shell Trion – targeting first East Breaks (EB) Hub exploration well in FY21/FY22 Perdido Foldbelt – planning OBN for GB Hub in FY21 BHP Prospect BHP Prospect Great White SALT Timeline CY2020 2021 2022 2023 2024 2025 2026 2027 2028 Oceanic Basement Continental Explore Appraise Paleogene Reservoir Targets Basement 1. Western GoM OBN 2018 Seismic, OCS Permit T18-010. Petroleum briefing 11 November 2019 34Commodities Assets and opportunities Exploration Capabilities Value and returns Western GoM: extending prolific Perdido play sub-salt Using innovative technology to image the play • Opportunity details – BHP (100% WI, operator); secured key position as early mover GB Hub – historically underexplored area due to sub-salt imaging challenges EB Hub 1 – acquired world’s first exploration OBN seismic survey to improve sub-salt imaging; currently finalising processing – added new Garden Banks (GB) Hub in August 2019 lease sales BHP Equinor AC Hub • Next steps Shell Trion – targeting first East Breaks (EB) Hub exploration well in FY21/FY22 Perdido Foldbelt – planning OBN for GB Hub in FY21 BHP Prospect BHP Prospect Great White SALT Timeline CY2020 2021 2022 2023 2024 2025 2026 2027 2028 Oceanic Basement Continental Explore Appraise Paleogene Reservoir Targets Basement 1. Western GoM OBN 2018 Seismic, OCS Permit T18-010. Petroleum briefing 11 November 2019 34

Commodities Assets and opportunities Exploration Capabilities Value and returns Finding new hydrocarbons – executing our program Testing five petroleum systems over the next three years Stage FY20 FY21 FY22 Moving to appraisal T&T North Appraisal T&T South Exploration Testing deeper potential Tieback opportunity Mexico Exploration for Trion Adding to a heartland Central GoM Exploration Western GoM Early exploration Derisking with technology Preparing for Eastern Canada Early exploration play test Access Identifying the highest ranked potential tier one opportunities to feed the pipeline Exploration Appraisal Seismic reprocessing Seismic acquisition / purchase Petroleum briefing 11 November 2019 35Commodities Assets and opportunities Exploration Capabilities Value and returns Finding new hydrocarbons – executing our program Testing five petroleum systems over the next three years Stage FY20 FY21 FY22 Moving to appraisal T&T North Appraisal T&T South Exploration Testing deeper potential Tieback opportunity Mexico Exploration for Trion Adding to a heartland Central GoM Exploration Western GoM Early exploration Derisking with technology Preparing for Eastern Canada Early exploration play test Access Identifying the highest ranked potential tier one opportunities to feed the pipeline Exploration Appraisal Seismic reprocessing Seismic acquisition / purchase Petroleum briefing 11 November 2019 35

Capabilities to deliver on our strategy Geraldine Slattery President Operations Petroleum HoustonCapabilities to deliver on our strategy Geraldine Slattery President Operations Petroleum Houston

Commodities Assets and opportunities Exploration Capabilities Value and returns Social value is an integral part of our business The health and safety of our people, environment and wellbeing of our communities are essential preconditions to shareholder value Our people Environment Communities Safety Climate Mexico 44% 15% 10% high potential injury events from greenhouse gas emissions from FY18 to national content, up to double the licence FY15 to FY19, only eight injury incidents FY19 driven by efficiency gains and agreement requirements since FY15 production decline Inclusion and diversity Conservation Trinidad & Tobago 3 programs Road safety 87% across US Gulf Coast, Trinidad & Tobago reduction in road fatalities since BHP favourable inclusion index score, and Australia to preserve wetlands, limit began working with the Government and 14% higher than oil and gas industry coastal erosion, and preserve marine life NGOs on road safety peers in FY19 Petroleum briefing 11 November 2019 37Commodities Assets and opportunities Exploration Capabilities Value and returns Social value is an integral part of our business The health and safety of our people, environment and wellbeing of our communities are essential preconditions to shareholder value Our people Environment Communities Safety Climate Mexico 44% 15% 10% high potential injury events from greenhouse gas emissions from FY18 to national content, up to double the licence FY15 to FY19, only eight injury incidents FY19 driven by efficiency gains and agreement requirements since FY15 production decline Inclusion and diversity Conservation Trinidad & Tobago 3 programs Road safety 87% across US Gulf Coast, Trinidad & Tobago reduction in road fatalities since BHP favourable inclusion index score, and Australia to preserve wetlands, limit began working with the Government and 14% higher than oil and gas industry coastal erosion, and preserve marine life NGOs on road safety peers in FY19 Petroleum briefing 11 November 2019 37

Commodities Assets and opportunities Exploration Capabilities Value and returns Exploration strategy reset is delivering success Larger discoveries and higher success rate drives improvement in finding cost 1 2015-2019 average discovery size • Building on recent exploration success (MMboe per well) – success in Mexico, Trinidad & Tobago and the US Gulf of 200 Mexico increased 2C resources by ~800 MMboe since FY17 – strong technical and likely commercial success 100 • Leading explorer in maximising resource per well BHP – 80 MMboe per well in average resource size 1 – top third within peer group 0 • Focused exploration has led to competitive finding costs 1,2 2015-2019 exploration finding cost – potential heartland established in Trinidad & Tobago (US$/boe, real 2019) – during 2015-2019, BHP ranked in the top third for average 10 1,2 exploration finding costs at US$2.6/boe • Leading approach to exploration 5 – acquire the right data to reduce risks ahead of drilling BHP – only drill prospects with a high probability of working 0 Source: Wood Mackenzie, including BHP commissioned 2019 Exploration Benchmarking report. 1. Peer group includes oil majors and upstream independents. 2. Finding costs are calculated based on total exploration spent divided by net discovered resources from 2015-2019 YTD. Petroleum briefing 11 November 2019 38Commodities Assets and opportunities Exploration Capabilities Value and returns Exploration strategy reset is delivering success Larger discoveries and higher success rate drives improvement in finding cost 1 2015-2019 average discovery size • Building on recent exploration success (MMboe per well) – success in Mexico, Trinidad & Tobago and the US Gulf of 200 Mexico increased 2C resources by ~800 MMboe since FY17 – strong technical and likely commercial success 100 • Leading explorer in maximising resource per well BHP – 80 MMboe per well in average resource size 1 – top third within peer group 0 • Focused exploration has led to competitive finding costs 1,2 2015-2019 exploration finding cost – potential heartland established in Trinidad & Tobago (US$/boe, real 2019) – during 2015-2019, BHP ranked in the top third for average 10 1,2 exploration finding costs at US$2.6/boe • Leading approach to exploration 5 – acquire the right data to reduce risks ahead of drilling BHP – only drill prospects with a high probability of working 0 Source: Wood Mackenzie, including BHP commissioned 2019 Exploration Benchmarking report. 1. Peer group includes oil majors and upstream independents. 2. Finding costs are calculated based on total exploration spent divided by net discovered resources from 2015-2019 YTD. Petroleum briefing 11 November 2019 38

Commodities Assets and opportunities Exploration Capabilities Value and returns High performance culture delivering results Relentless focus on costs and continuous improvement demonstrated in our operational and drilling performance Unit costs actively managed • Continuous focus on productivity and high-margin investments (US$/boe) supports unit costs below US$13/boe 20 – US$3.5/boe reduction over five years, with 12% lower volumes È~25% <13 – medium-term unit cash costs expected to remain below FY14 10.5-11.5 10 levels • Demonstrated deepwater drilling capability 0 – proven capability in the deepwater FY14 FY15 FY16 FY17 FY18 FY19 FY20e Medium – continuous learning cycle through transformation AUD/USD: 0.92 0.84 0.73 0.75 0.78 0.72 0.70 0.70 – Trion 3DEL the fastest well drilled in Mexico deepwater 1 Recent deepwater drilling performance in Trinidad & Tobago 2016-2019 (days per 1,000 ft) • Investing in our project capabilities and capital discipline 10 – working with joint venture partners Most recent BHP wells – Project Centre of Excellence – mature governance framework 5 0 1. All 2019 wells are named above. Trinidad & Tobago BHP wells exclude coring and logging time. Two Suriname wells are also included in the Trinidad & Tobago data. Source: IHS Rushmore and CNH (Mexico wells). Petroleum briefing 11 November 2019 39 Carnival Boom Tuk Bélé Hi Hat Concepcion Le Clerc Bongos Victoria BurrokeetCommodities Assets and opportunities Exploration Capabilities Value and returns High performance culture delivering results Relentless focus on costs and continuous improvement demonstrated in our operational and drilling performance Unit costs actively managed • Continuous focus on productivity and high-margin investments (US$/boe) supports unit costs below US$13/boe 20 – US$3.5/boe reduction over five years, with 12% lower volumes È~25% <13 – medium-term unit cash costs expected to remain below FY14 10.5-11.5 10 levels • Demonstrated deepwater drilling capability 0 – proven capability in the deepwater FY14 FY15 FY16 FY17 FY18 FY19 FY20e Medium – continuous learning cycle through transformation AUD/USD: 0.92 0.84 0.73 0.75 0.78 0.72 0.70 0.70 – Trion 3DEL the fastest well drilled in Mexico deepwater 1 Recent deepwater drilling performance in Trinidad & Tobago 2016-2019 (days per 1,000 ft) • Investing in our project capabilities and capital discipline 10 – working with joint venture partners Most recent BHP wells – Project Centre of Excellence – mature governance framework 5 0 1. All 2019 wells are named above. Trinidad & Tobago BHP wells exclude coring and logging time. Two Suriname wells are also included in the Trinidad & Tobago data. Source: IHS Rushmore and CNH (Mexico wells). Petroleum briefing 11 November 2019 39 Carnival Boom Tuk Bélé Hi Hat Concepcion Le Clerc Bongos Victoria Burrokeet

Commodities Assets and opportunities Exploration Capabilities Value and returns Transformation unlocking new opportunities Focused on key value drivers for BHP Transparent Earth • OBN acquisition for deepwater exploration Explore • Low frequency seismic sources for breakthrough image accuracy • Machine Learning & Data Analytics powering Petroleum and Minerals Global Endowment OBN early seismic image from the Western Gulf of Mexico Facilities of the future • Leveraging digital technologies for Trion design, construct and operate Develop • Integrating emerging technology optionality • Multi-phase pumping applied to GOM deep-water operated development and production Multi-phase subsea pump Integrated reservoir imaging and characterisation • OBN to unlock contingent resources and new opportunities Produce • Integrating 4D seismic and well imaging tools will unlock further Pyrenees potential • Proprietary production optimisation tools Integrating seismic, reservoir simulation and real-time logging to best place wells for maximum recovery Petroleum briefing 11 November 2019 40Commodities Assets and opportunities Exploration Capabilities Value and returns Transformation unlocking new opportunities Focused on key value drivers for BHP Transparent Earth • OBN acquisition for deepwater exploration Explore • Low frequency seismic sources for breakthrough image accuracy • Machine Learning & Data Analytics powering Petroleum and Minerals Global Endowment OBN early seismic image from the Western Gulf of Mexico Facilities of the future • Leveraging digital technologies for Trion design, construct and operate Develop • Integrating emerging technology optionality • Multi-phase pumping applied to GOM deep-water operated development and production Multi-phase subsea pump Integrated reservoir imaging and characterisation • OBN to unlock contingent resources and new opportunities Produce • Integrating 4D seismic and well imaging tools will unlock further Pyrenees potential • Proprietary production optimisation tools Integrating seismic, reservoir simulation and real-time logging to best place wells for maximum recovery Petroleum briefing 11 November 2019 40

Petroleum delivers value and strong returns Geraldine Slattery President Operations Petroleum ShenziPetroleum delivers value and strong returns Geraldine Slattery President Operations Petroleum Shenzi

Commodities Assets and opportunities Exploration Capabilities Value and returns High-margin barrels drive production growth and returns Current opportunities deliver significant volumes, and more than offset Bass Strait and North West Shelf field declines Value accretive production potential over the next decade • Strong free cash flow and returns through 2020s (Production, MMboe) Base • 10+ years of meaningful production from the base 200 production • High-returning investments limit overall production decline to ~1.5% CAGR over the next five years • Oil-dominated projects delivering strong returns 150 Sanctioned • Atlantis Phase 3, Mad Dog Phase 2, Ruby and projects T&T North West Barracouta to add ~25 MMboe in FY23 2016 Petroleum briefing 100 • Scarborough, Trion and US GoM embedded options Unsanctioned add significant potential growth from mid-2020s projects Unsanctioned projects • Competitive pipeline of high-return and improvement Sanctioned projects projects yield ~3% production CAGR from FY20-30 50 Base production • Material gas discoveries in Trinidad & Tobago North Exploration • Progressing exploration in Western Gulf of Mexico and and future Eastern Canada for tier one oil opportunities 0 options • Targeting further oil exposed growth FY19 FY20e FY21e FY22e FY23e FY24e FY25e FY26e FY27e FY28e FY29e FY30e Unconstrained scenario Note: This represents an unconstrained scenario based on execution of all unsanctioned projects at current equity interests and does not constitute guidance. Petroleum briefing 11 November 2019 42Commodities Assets and opportunities Exploration Capabilities Value and returns High-margin barrels drive production growth and returns Current opportunities deliver significant volumes, and more than offset Bass Strait and North West Shelf field declines Value accretive production potential over the next decade • Strong free cash flow and returns through 2020s (Production, MMboe) Base • 10+ years of meaningful production from the base 200 production • High-returning investments limit overall production decline to ~1.5% CAGR over the next five years • Oil-dominated projects delivering strong returns 150 Sanctioned • Atlantis Phase 3, Mad Dog Phase 2, Ruby and projects T&T North West Barracouta to add ~25 MMboe in FY23 2016 Petroleum briefing 100 • Scarborough, Trion and US GoM embedded options Unsanctioned add significant potential growth from mid-2020s projects Unsanctioned projects • Competitive pipeline of high-return and improvement Sanctioned projects projects yield ~3% production CAGR from FY20-30 50 Base production • Material gas discoveries in Trinidad & Tobago North Exploration • Progressing exploration in Western Gulf of Mexico and and future Eastern Canada for tier one oil opportunities 0 options • Targeting further oil exposed growth FY19 FY20e FY21e FY22e FY23e FY24e FY25e FY26e FY27e FY28e FY29e FY30e Unconstrained scenario Note: This represents an unconstrained scenario based on execution of all unsanctioned projects at current equity interests and does not constitute guidance. Petroleum briefing 11 November 2019 42

Commodities Assets and opportunities Exploration Capabilities Value and returns Petroleum investments compete for capital Flexibility to manage investments across the Group 1 Petroleum unconstrained investments to fund all existing options • We aim to balance investments, shareholder returns and (US$ billion) balance sheet strength to maximise value and returns 5.0 – promotes discipline in all capital decisions – we have a broad suite of attractive opportunities, across all quadrants of our risk and return framework 2.5 – high number of valuable Petroleum options that compete strongly against other options in the Group portfolio; only the most competitive opportunities will progress 0.0 FY19 FY20-FY22e FY23-FY25e FY26-FY28e • Flexibility to manage investments across the Group Exploration expenditure Capital expenditure – optionality through high equity interests and operatorship 2 Flexibility in average annual capital expenditure – embedded options allow capital phasing and smoothing (FY20-28e, % of total expenditure) Other Maintenance Australia Improvement Mexico Major sanctioned projects US GoM 1. This represents an unconstrained scenario based on execution of all unsanctioned projects at current equity interests and Major does not constitute guidance. unsanctioned T&T 2. Excludes annual exploration expenditure. projects Petroleum briefing 11 November 2019 43Commodities Assets and opportunities Exploration Capabilities Value and returns Petroleum investments compete for capital Flexibility to manage investments across the Group 1 Petroleum unconstrained investments to fund all existing options • We aim to balance investments, shareholder returns and (US$ billion) balance sheet strength to maximise value and returns 5.0 – promotes discipline in all capital decisions – we have a broad suite of attractive opportunities, across all quadrants of our risk and return framework 2.5 – high number of valuable Petroleum options that compete strongly against other options in the Group portfolio; only the most competitive opportunities will progress 0.0 FY19 FY20-FY22e FY23-FY25e FY26-FY28e • Flexibility to manage investments across the Group Exploration expenditure Capital expenditure – optionality through high equity interests and operatorship 2 Flexibility in average annual capital expenditure – embedded options allow capital phasing and smoothing (FY20-28e, % of total expenditure) Other Maintenance Australia Improvement Mexico Major sanctioned projects US GoM 1. This represents an unconstrained scenario based on execution of all unsanctioned projects at current equity interests and Major does not constitute guidance. unsanctioned T&T 2. Excludes annual exploration expenditure. projects Petroleum briefing 11 November 2019 43

Commodities Assets and opportunities Exploration Capabilities Value and returns Delivering strong margins, high returns and value A strong base combined with high-return major projects and exploration growth opportunities significantly increases value 2 EBITDA EBITDA margin Growth options have the potential to grow base value by up to 80% (US$ billion) (%) (Risked value uplift) 8 70 4 0 50 FY15-19 average FY20-24e average FY25-30e average At US$60-80/bbl oil price EBITDA at Wood Mackenzie prices EBITDA margin range Returns 1 (ROCE , %) 25 20 15 10 5 0 FY15-19 average FY20-24e average FY25-30e average FY19 base value Sanctioned Unsanctioned T&T North and Total portfolio projects projects risked ROCE at Wood Mackenzie prices At US$60-80/bbl oil prices exploration Note: This represents an unconstrained scenario based on execution of all unsanctioned projects at current equity interests and does not constitute guidance. Value at Wood Mackenzie prices 1. Excludes exploration expenditure. 2. Risked value uplift: represents total potential increase in base value from the addition of upside opportunities. Petroleum briefing 11 November 2019 44Commodities Assets and opportunities Exploration Capabilities Value and returns Delivering strong margins, high returns and value A strong base combined with high-return major projects and exploration growth opportunities significantly increases value 2 EBITDA EBITDA margin Growth options have the potential to grow base value by up to 80% (US$ billion) (%) (Risked value uplift) 8 70 4 0 50 FY15-19 average FY20-24e average FY25-30e average At US$60-80/bbl oil price EBITDA at Wood Mackenzie prices EBITDA margin range Returns 1 (ROCE , %) 25 20 15 10 5 0 FY15-19 average FY20-24e average FY25-30e average FY19 base value Sanctioned Unsanctioned T&T North and Total portfolio projects projects risked ROCE at Wood Mackenzie prices At US$60-80/bbl oil prices exploration Note: This represents an unconstrained scenario based on execution of all unsanctioned projects at current equity interests and does not constitute guidance. Value at Wood Mackenzie prices 1. Excludes exploration expenditure. 2. Risked value uplift: represents total potential increase in base value from the addition of upside opportunities. Petroleum briefing 11 November 2019 44

Commodities Assets and opportunities Exploration Capabilities Value and returns Petroleum is positioned for long-term value creation Our strategy identifies how to position the portfolio to maximise long-term value and deliver high returns for shareholders Best commodities Best assets Best capabilities Oil attractive for decades >60% EBITDA margin Safety and sustainability even with electrification, supported by expected over the next 10 years from top quartile safety supply gap and steep cost curves our high-quality assets performance Advantaged gas Competitive pipeline Exploration success through infrastructure, of options yields ~3% average focused strategy added ~800 MMboe customers, or both production CAGR from FY20 to FY30 in 2C resources since FY17 New supply Optimise legacy assets High-performing culture needs to be continuously induced manage mature assets for value leading to top quartile operational and to balance markets deepwater drilling performance Petroleum ROCE expected to average >15% over the next 10 years; average major project IRRs of ~25% Note: This represents an unconstrained scenario based on execution of all unsanctioned projects at current equity interests and does not constitute guidance. EBITDA margin and ROCE based on Wood Mackenzie prices. ROCE excludes exploration. Petroleum briefing 11 November 2019 45Commodities Assets and opportunities Exploration Capabilities Value and returns Petroleum is positioned for long-term value creation Our strategy identifies how to position the portfolio to maximise long-term value and deliver high returns for shareholders Best commodities Best assets Best capabilities Oil attractive for decades >60% EBITDA margin Safety and sustainability even with electrification, supported by expected over the next 10 years from top quartile safety supply gap and steep cost curves our high-quality assets performance Advantaged gas Competitive pipeline Exploration success through infrastructure, of options yields ~3% average focused strategy added ~800 MMboe customers, or both production CAGR from FY20 to FY30 in 2C resources since FY17 New supply Optimise legacy assets High-performing culture needs to be continuously induced manage mature assets for value leading to top quartile operational and to balance markets deepwater drilling performance Petroleum ROCE expected to average >15% over the next 10 years; average major project IRRs of ~25% Note: This represents an unconstrained scenario based on execution of all unsanctioned projects at current equity interests and does not constitute guidance. EBITDA margin and ROCE based on Wood Mackenzie prices. ROCE excludes exploration. Petroleum briefing 11 November 2019 45

AppendixAppendix

Petroleum guidance Conventional Petroleum FY20e Medium term Petroleum production (MMboe) 110 -116 ~110 FY20 volumes expected to decrease due to planned maintenance at Atlantis and natural field decline across the portfolio. Decline of ~1.5% p.a. over medium term includes projects yet to be sanctioned. Capital expenditure (US$bn) 1.2 Sanctioned Capex First production Production (BHP share) (100% basis at peak) Mad Dog Phase 2 February 2017 US$2.2 billion CY22 140,000 bbl/d West Barracouta December 2018 ~US$140 million CY21 104 MMscf/d Atlantis Phase 3 February 2019 ~US$700 million CY20 32,000 bbl/d (oil) Ruby August 2019 ~US$280 million CY21 16,000 bbl/d (oil) and 80 MMscf/d (gas) Exploration expenditure (US$bn) 0.7 Focused on Mexico, the Gulf of Mexico, Canada, the Caribbean and identifying growth opportunities. Unit cost (US$/boe) 10.5-11.5 <13 Excludes inventory movements, embedded derivatives movements, freight, third party product purchases and exploration expense. Based on exchange rate of AUD/USD 0.70. Note: All guidance is in nominal terms. Petroleum briefing 11 November 2019 48Petroleum guidance Conventional Petroleum FY20e Medium term Petroleum production (MMboe) 110 -116 ~110 FY20 volumes expected to decrease due to planned maintenance at Atlantis and natural field decline across the portfolio. Decline of ~1.5% p.a. over medium term includes projects yet to be sanctioned. Capital expenditure (US$bn) 1.2 Sanctioned Capex First production Production (BHP share) (100% basis at peak) Mad Dog Phase 2 February 2017 US$2.2 billion CY22 140,000 bbl/d West Barracouta December 2018 ~US$140 million CY21 104 MMscf/d Atlantis Phase 3 February 2019 ~US$700 million CY20 32,000 bbl/d (oil) Ruby August 2019 ~US$280 million CY21 16,000 bbl/d (oil) and 80 MMscf/d (gas) Exploration expenditure (US$bn) 0.7 Focused on Mexico, the Gulf of Mexico, Canada, the Caribbean and identifying growth opportunities. Unit cost (US$/boe) 10.5-11.5 <13 Excludes inventory movements, embedded derivatives movements, freight, third party product purchases and exploration expense. Based on exchange rate of AUD/USD 0.70. Note: All guidance is in nominal terms. Petroleum briefing 11 November 2019 48

World class portfolio of producing assets Country Asset Operator BHP ownership First production FY19 production Future Development Options Australia Bass Strait Esso Gippsland Basin Joint Venture (GBJV): 50.0% 1969 Liquids: 10.6 MMboe West Barracouta (sanctioned) Kipper Unit Joint Venture (KUJV): 32.5% Gas: 18.6 MMboe Kipper Phase 2 Additional infill opportunities Australia North West Shelf Woodside 12.5 – 16.67% across 9 separate joint venture 1984 Liquids: 6.7 MMboe South Goodwyn (NWS) agreements Gas: 24.2 MMboe North West Shelf Other Resource Owner Additional infill opportunities Australia Pyrenees BHP WA-42-L permit: 71.43% 2010 Liquids: 3.3 MMboe Pyrenees Phase 4 WA-43-L permit: 39.999% Australia Macedon BHP 71.43% 2013 Gas: 7.3 MMboe Wet Gas Compression Additional infill opportunities United States Atlantis BP 44.0% 2007 Liquids: 15.5 MMboe Atlantis Phase 3 (sanctioned) Gas: 1.3 MMboe Atlantis Phase 4 Atlantis opportunities United States Mad Dog BP 23.9% 2005 Liquids: 5.1 MMboe Mad Dog Phase 2 (sanctioned) Gas: 0.1 MMboe Mad Dog Northwest Water Injection Mad Dog opportunities United States Shenzi BHP 44.0% 2009 Liquids: 8.0 MMboe Subsea Multi-Phase Pumping Gas: 0.3 MMboe Wildling Phase 1 Additional infill opportunities United States Neptune BHP 35% 2008 Liquids: 0.6 MMboe Gas: 0.0 MMboe Trinidad & Tobago Greater Angostura BHP 45.0% Block 2(c) 2005 Liquids: 1.2 MMboe Ruby (sanctioned) 68.46% effective interest in Block 3(a) Project Gas: 12.5 MMboe Ruby Algeria ROD Integrated Joint Sonatrach / ENI 29.3% effective interest in the ROD Integrated 2004 Liquids: 3.6 MMboe Phase 2 Infill Drilling Development Development Note: FY19 production from Minerva and UK assets not included in the above table. Amounts in the above Ownership column represent working interest. Petroleum briefing 11 November 2019 49World class portfolio of producing assets Country Asset Operator BHP ownership First production FY19 production Future Development Options Australia Bass Strait Esso Gippsland Basin Joint Venture (GBJV): 50.0% 1969 Liquids: 10.6 MMboe West Barracouta (sanctioned) Kipper Unit Joint Venture (KUJV): 32.5% Gas: 18.6 MMboe Kipper Phase 2 Additional infill opportunities Australia North West Shelf Woodside 12.5 – 16.67% across 9 separate joint venture 1984 Liquids: 6.7 MMboe South Goodwyn (NWS) agreements Gas: 24.2 MMboe North West Shelf Other Resource Owner Additional infill opportunities Australia Pyrenees BHP WA-42-L permit: 71.43% 2010 Liquids: 3.3 MMboe Pyrenees Phase 4 WA-43-L permit: 39.999% Australia Macedon BHP 71.43% 2013 Gas: 7.3 MMboe Wet Gas Compression Additional infill opportunities United States Atlantis BP 44.0% 2007 Liquids: 15.5 MMboe Atlantis Phase 3 (sanctioned) Gas: 1.3 MMboe Atlantis Phase 4 Atlantis opportunities United States Mad Dog BP 23.9% 2005 Liquids: 5.1 MMboe Mad Dog Phase 2 (sanctioned) Gas: 0.1 MMboe Mad Dog Northwest Water Injection Mad Dog opportunities United States Shenzi BHP 44.0% 2009 Liquids: 8.0 MMboe Subsea Multi-Phase Pumping Gas: 0.3 MMboe Wildling Phase 1 Additional infill opportunities United States Neptune BHP 35% 2008 Liquids: 0.6 MMboe Gas: 0.0 MMboe Trinidad & Tobago Greater Angostura BHP 45.0% Block 2(c) 2005 Liquids: 1.2 MMboe Ruby (sanctioned) 68.46% effective interest in Block 3(a) Project Gas: 12.5 MMboe Ruby Algeria ROD Integrated Joint Sonatrach / ENI 29.3% effective interest in the ROD Integrated 2004 Liquids: 3.6 MMboe Phase 2 Infill Drilling Development Development Note: FY19 production from Minerva and UK assets not included in the above table. Amounts in the above Ownership column represent working interest. Petroleum briefing 11 November 2019 49

Bass Strait: high returns with upside through the 2020s Strong market demand supports continued investments Net production Bass Strait detail Investment opportunities Sanctioned projects (MMboe) 40 • West Barracouta sanctioned in FY19, ~20% IRR, with first production expected in CY21 Unsanctioned projects • Multiple unsanctioned improvement projects with 20 average IRRs >30% – Kipper Phase 2 expected to FID in FY20, proposed as a 2 well tieback – Longford gas plant debottlenecking to sustain 0 throughput in FY25 BHP • Seismic planned for CY20 to unlock resource Liquid fields development Base Sanctioned projects Unsanctioned projects Gas fields Bass Strait Key highlights FY19 production FY25e production Key metrics Bass 1 Bass • Advantaged gas play 1P Reserves: 206 MMboe Strait Strait 1 • Highly cash generative 2P Reserves: 270 MMboe • Strong acreage and infrastructure position 1 29 23 2P+2C Resources: 451 MMboe MMboe MMboe 2 FY20-25 average ROCE: ~15% Note: This represents an unconstrained scenario based on execution of all unsanctioned projects at current equity interests and does not constitute guidance. 1. Excludes Minerva field. 2. At Wood Mackenzie prices. Liquids production Gas production Petroleum briefing 11 November 2019 50 FY19 FY20e FY21e FY22e FY23e FY24e FY25e FY26e FY27e FY28e FY29e FY30eBass Strait: high returns with upside through the 2020s Strong market demand supports continued investments Net production Bass Strait detail Investment opportunities Sanctioned projects (MMboe) 40 • West Barracouta sanctioned in FY19, ~20% IRR, with first production expected in CY21 Unsanctioned projects • Multiple unsanctioned improvement projects with 20 average IRRs >30% – Kipper Phase 2 expected to FID in FY20, proposed as a 2 well tieback – Longford gas plant debottlenecking to sustain 0 throughput in FY25 BHP • Seismic planned for CY20 to unlock resource Liquid fields development Base Sanctioned projects Unsanctioned projects Gas fields Bass Strait Key highlights FY19 production FY25e production Key metrics Bass 1 Bass • Advantaged gas play 1P Reserves: 206 MMboe Strait Strait 1 • Highly cash generative 2P Reserves: 270 MMboe • Strong acreage and infrastructure position 1 29 23 2P+2C Resources: 451 MMboe MMboe MMboe 2 FY20-25 average ROCE: ~15% Note: This represents an unconstrained scenario based on execution of all unsanctioned projects at current equity interests and does not constitute guidance. 1. Excludes Minerva field. 2. At Wood Mackenzie prices. Liquids production Gas production Petroleum briefing 11 November 2019 50 FY19 FY20e FY21e FY22e FY23e FY24e FY25e FY26e FY27e FY28e FY29e FY30e

Western Australia: strong base with optionality Material growth potential through development of Scarborough and unlocking additional contingent resources Net production West Australia assets Investment opportunities Unsanctioned projects (MMboe) Thebe North West Shelf 50 • Scarborough offers material growth Jupiter • Multiple unsanctioned improvement projects with Scarborough average IRRs >35% LNG – South Goodwyn: 3 well subsea tieback Plant 25 Dampier – Lambert Deep standalone subsea tieback Karratha – Macedon and NWS compression projects Pyrenees Stybarrow • North West Shelf tolling opportunity for third 0 Macedon party gas Onslow Macedon • Pyrenees Phase 4: robust opportunities targeting BHP Gas Plant developed and undeveloped reservoirs being Liquid fields Base Unsanctioned projects Scarborough matured Gas fields Key highlights FY19 production FY25e production Key metrics Pyrenees • Scarborough FID expected in CY20, with increased 1P Reserves: 268 MMboe Scarborough resource base Macedon NWS 2P Reserves: 341 MMboe NWS • Greater Western Flank 2 achieved first gas in FY19, ahead of schedule 42 42 2P+2C Resources: 974 MMboe MMboe MMboe • Strong free cash flow generation and returns on 1 FY20-25 average ROCE: ~20% brownfield projects Note: This represents an unconstrained scenario based on execution of all Pyrenees Macedon unsanctioned projects at current equity interests and does not constitute guidance. 1. At Wood Mackenzie prices. Liquids production Gas production Petroleum briefing 11 November 2019 51 FY19 FY20e FY21e FY22e FY23e FY24e FY25e FY26e FY27e FY28e FY29e FY30eWestern Australia: strong base with optionality Material growth potential through development of Scarborough and unlocking additional contingent resources Net production West Australia assets Investment opportunities Unsanctioned projects (MMboe) Thebe North West Shelf 50 • Scarborough offers material growth Jupiter • Multiple unsanctioned improvement projects with Scarborough average IRRs >35% LNG – South Goodwyn: 3 well subsea tieback Plant 25 Dampier – Lambert Deep standalone subsea tieback Karratha – Macedon and NWS compression projects Pyrenees Stybarrow • North West Shelf tolling opportunity for third 0 Macedon party gas Onslow Macedon • Pyrenees Phase 4: robust opportunities targeting BHP Gas Plant developed and undeveloped reservoirs being Liquid fields Base Unsanctioned projects Scarborough matured Gas fields Key highlights FY19 production FY25e production Key metrics Pyrenees • Scarborough FID expected in CY20, with increased 1P Reserves: 268 MMboe Scarborough resource base Macedon NWS 2P Reserves: 341 MMboe NWS • Greater Western Flank 2 achieved first gas in FY19, ahead of schedule 42 42 2P+2C Resources: 974 MMboe MMboe MMboe • Strong free cash flow generation and returns on 1 FY20-25 average ROCE: ~20% brownfield projects Note: This represents an unconstrained scenario based on execution of all Pyrenees Macedon unsanctioned projects at current equity interests and does not constitute guidance. 1. At Wood Mackenzie prices. Liquids production Gas production Petroleum briefing 11 November 2019 51 FY19 FY20e FY21e FY22e FY23e FY24e FY25e FY26e FY27e FY28e FY29e FY30e

US Gulf of Mexico: large, long-life and expandable Near-term projects deliver attractive returns, while major growth options increase production volumes Net production Building on a solid foundation Investment opportunities Sanctioned projects (MMboe) 40 • Atlantis Phase 3 (19% complete) first oil CY20 • Mad Dog Phase 2 (60% complete) first oil CY22 Neptune Unsanctioned projects 20 • Wildling: 2C resource 104 MMboe Shenzi – Phase 1: two well development – Phase 2 and 3 on success of Phase 1 Atlantis Mad Dog • Multiple unsanctioned projects with IRRs >20% 0 unlocked through technology and latent capacity • Shenzi OBN acquisition planned in FY20 to 1 identify/derisk additional future growth projects Fields BHP leases Base Sanctioned projects Unsanctioned projects Key highlights FY19 production FY25e production Key metrics Neptune Neptune Wildling • Largest fields in the Gulf of Mexico with a long 1P Reserves: 302 MMboe Mad Dog history of delivering value and consistent growth Shenzi 2P Reserves: 449 MMboe • Continue to advance future opportunities by Atlantis 31 36 2P+2C Resources: 937 MMboe leveraging infrastructure, technology and MMboe MMboe Atlantis remaining resource 1 FY20-25 average ROCE: ~20% Shenzi Note: This represents an unconstrained scenario based on execution of all Mad Dog unsanctioned projects at current equity interests and does not constitute guidance. 1. Source: Wood Mackenzie. 2. At Wood Mackenzie prices. Liquids production Gas production Petroleum briefing 11 November 2019 52 FY19 FY20e FY21e FY22e FY23e FY24e FY25e FY26e FY27e FY28e FY29e FY30eUS Gulf of Mexico: large, long-life and expandable Near-term projects deliver attractive returns, while major growth options increase production volumes Net production Building on a solid foundation Investment opportunities Sanctioned projects (MMboe) 40 • Atlantis Phase 3 (19% complete) first oil CY20 • Mad Dog Phase 2 (60% complete) first oil CY22 Neptune Unsanctioned projects 20 • Wildling: 2C resource 104 MMboe Shenzi – Phase 1: two well development – Phase 2 and 3 on success of Phase 1 Atlantis Mad Dog • Multiple unsanctioned projects with IRRs >20% 0 unlocked through technology and latent capacity • Shenzi OBN acquisition planned in FY20 to 1 identify/derisk additional future growth projects Fields BHP leases Base Sanctioned projects Unsanctioned projects Key highlights FY19 production FY25e production Key metrics Neptune Neptune Wildling • Largest fields in the Gulf of Mexico with a long 1P Reserves: 302 MMboe Mad Dog history of delivering value and consistent growth Shenzi 2P Reserves: 449 MMboe • Continue to advance future opportunities by Atlantis 31 36 2P+2C Resources: 937 MMboe leveraging infrastructure, technology and MMboe MMboe Atlantis remaining resource 1 FY20-25 average ROCE: ~20% Shenzi Note: This represents an unconstrained scenario based on execution of all Mad Dog unsanctioned projects at current equity interests and does not constitute guidance. 1. Source: Wood Mackenzie. 2. At Wood Mackenzie prices. Liquids production Gas production Petroleum briefing 11 November 2019 52 FY19 FY20e FY21e FY22e FY23e FY24e FY25e FY26e FY27e FY28e FY29e FY30e

Future options: worked for value, timed for returns Investment decisions made in accordance with our Capital Allocation Framework and fully consider the broader market impact Option Description Operator BHP Potential Capex Tollgate Potential first 1 Ownership execution BHP share production timing (US$m) North West Shelf Other Low risk investment opportunity to maximise Karratha Gas Plant value through processing Woodside 16.67% <5 years >250 Pre-feasibility FY26 Resource Owner other resource owner gas; benefits through tolling fees, cost recovery and life extension. Pyrenees Phase 4 Combination of well re-entries and new subsea wells which aim to optimise incremental BHP 71.43% <5 years >250 Opportunity FY22 value using the existing infrastructure. Assessment 2 Scarborough Large resource of 13 subsea wells connected to a semisubmersible floating production Woodside 25% WA-1-R 1 year 1,400 - Pre-feasibility FY24 unit from which gas is exported via pipeline to Pluto LNG facility for onshore processing. (50% WA-62-R) 1,900 Atlantis Phase 4 Additional development opportunities for infill producing wells. Data obtained from Phase 3 BP 44% <5 years >250 Opportunity FY24 project de-risks further development of multiple hydrocarbon bearing zones. Assessment Mad Dog Northwest Two water injector wells providing water from Mad Dog Phase 2 facility to increase BP 23.9% <5 years >250 Pre-feasibility FY24 Water Injection production at existing A Spar facility. Mad Dog opportunities Additional opportunities to increase the Mad Dog Phase 2 production beyond the initial BP 23.9% <5 years >250 Opportunity FY25 investment scope with new wells tied back to existing facility, results in highly economic Assessment opportunities. Shenzi Growth Shenzi Subsea Multi-Phase Pumping (SSMPP); Subsea pumping opportunities to BHP 44% 1 year <250 Pre-feasibility FY23 opportunities increase production rates from existing wells. Wildling Phase 1 Two Shenzi North wells tied-back to the Shenzi platform, provides the opportunity to BHP 44%-72% 1-2 years ~500 Pre-feasibility FY23 accelerate production and unlock additional recoverable reserves. Phased development accelerates first oil, minimizes appraisal cost and reduces risk. Trion Large greenfield development in the deepwater Mexico GoM. Resource uncertainty BHP 60% 2-3 years >5,000 Conceptual FY25 reduced with recent successful appraisal drilling of 2DEL and 3DEL wells. Trinidad & Tobago Completed successful exploration program on our Northern licenses. Potential material BHP 70% <5 years Under study Opportunity FY27 North gas play in deepwater Trinidad & Tobago, well positioned to the Atlantic LNG plant Assessment onshore Trinidad & Tobago. Note: This represents an unconstrained scenario based on execution of all unsanctioned projects at current equity interests and does not constitute guidance. 1. Potential first production data is an estimate and does not constitute guidance. 2. Based on information provided by operator. Represents BHP’s current equity position as 25% in WA-1-R and 50% in WA-62-R. Petroleum briefing 11 November 2019 53Future options: worked for value, timed for returns Investment decisions made in accordance with our Capital Allocation Framework and fully consider the broader market impact Option Description Operator BHP Potential Capex Tollgate Potential first 1 Ownership execution BHP share production timing (US$m) North West Shelf Other Low risk investment opportunity to maximise Karratha Gas Plant value through processing Woodside 16.67% <5 years >250 Pre-feasibility FY26 Resource Owner other resource owner gas; benefits through tolling fees, cost recovery and life extension. Pyrenees Phase 4 Combination of well re-entries and new subsea wells which aim to optimise incremental BHP 71.43% <5 years >250 Opportunity FY22 value using the existing infrastructure. Assessment 2 Scarborough Large resource of 13 subsea wells connected to a semisubmersible floating production Woodside 25% WA-1-R 1 year 1,400 - Pre-feasibility FY24 unit from which gas is exported via pipeline to Pluto LNG facility for onshore processing. (50% WA-62-R) 1,900 Atlantis Phase 4 Additional development opportunities for infill producing wells. Data obtained from Phase 3 BP 44% <5 years >250 Opportunity FY24 project de-risks further development of multiple hydrocarbon bearing zones. Assessment Mad Dog Northwest Two water injector wells providing water from Mad Dog Phase 2 facility to increase BP 23.9% <5 years >250 Pre-feasibility FY24 Water Injection production at existing A Spar facility. Mad Dog opportunities Additional opportunities to increase the Mad Dog Phase 2 production beyond the initial BP 23.9% <5 years >250 Opportunity FY25 investment scope with new wells tied back to existing facility, results in highly economic Assessment opportunities. Shenzi Growth Shenzi Subsea Multi-Phase Pumping (SSMPP); Subsea pumping opportunities to BHP 44% 1 year <250 Pre-feasibility FY23 opportunities increase production rates from existing wells. Wildling Phase 1 Two Shenzi North wells tied-back to the Shenzi platform, provides the opportunity to BHP 44%-72% 1-2 years ~500 Pre-feasibility FY23 accelerate production and unlock additional recoverable reserves. Phased development accelerates first oil, minimizes appraisal cost and reduces risk. Trion Large greenfield development in the deepwater Mexico GoM. Resource uncertainty BHP 60% 2-3 years >5,000 Conceptual FY25 reduced with recent successful appraisal drilling of 2DEL and 3DEL wells. Trinidad & Tobago Completed successful exploration program on our Northern licenses. Potential material BHP 70% <5 years Under study Opportunity FY27 North gas play in deepwater Trinidad & Tobago, well positioned to the Atlantic LNG plant Assessment onshore Trinidad & Tobago. Note: This represents an unconstrained scenario based on execution of all unsanctioned projects at current equity interests and does not constitute guidance. 1. Potential first production data is an estimate and does not constitute guidance. 2. Based on information provided by operator. Represents BHP’s current equity position as 25% in WA-1-R and 50% in WA-62-R. Petroleum briefing 11 November 2019 53

Atlantis & Mad Dog: 10+ years of future delivery Long history of consistent growth and delivery through the next decade Mad Dog and Atlantis production Atlantis Phase 3: BHP (44% WI); BP (operator) - sanctioned (BHP production, MMboe) 8 well subsea tieback; first production FY21 30 Project IRR: >40% Project capex (BHP share): US$700 million Volumes (100% basis at peak): 32 Mbbl/d Field life: 18 years 15 Project Status 19% complete (tracking to plan) Future options: Atlantis Phase 4 infill program enabled by OBN and subsurface evaluation 0 FY19 FY20e FY21e FY22e FY23e FY24e FY25e FY26e FY27e FY28e FY29e FY30e Mad Dog Phase 2: BHP (23.9% WI); BP (operator) - sanctioned Base production Sanctioned projects Unsanctioned projects FPSO with 22 subsea wells (14 producing wells, 8 water injection wells); first production FY22 Timeline Project IRR: >15% CY2020 2021 2022 2023 2024 2025 2026 2027 2028 Project capex (BHP share): US$2.2 billion Volumes (100% basis at peak): 140 Mbbl/d Atlantis Phase 3 Field life: 35 years Mad Dog Phase 2 Project Status 60% complete (tracking to plan) Mad Dog – Water injection Future options: Mad Dog northwest water injection, southwest extension, infill wells and cc sands enabled by ullage at Mad Dog Phase 2 FID range First production range Note: This represents an unconstrained scenario based on execution of all unsanctioned projects at current equity interests and does not constitute guidance. Petroleum briefing 11 November 2019 54Atlantis & Mad Dog: 10+ years of future delivery Long history of consistent growth and delivery through the next decade Mad Dog and Atlantis production Atlantis Phase 3: BHP (44% WI); BP (operator) - sanctioned (BHP production, MMboe) 8 well subsea tieback; first production FY21 30 Project IRR: >40% Project capex (BHP share): US$700 million Volumes (100% basis at peak): 32 Mbbl/d Field life: 18 years 15 Project Status 19% complete (tracking to plan) Future options: Atlantis Phase 4 infill program enabled by OBN and subsurface evaluation 0 FY19 FY20e FY21e FY22e FY23e FY24e FY25e FY26e FY27e FY28e FY29e FY30e Mad Dog Phase 2: BHP (23.9% WI); BP (operator) - sanctioned Base production Sanctioned projects Unsanctioned projects FPSO with 22 subsea wells (14 producing wells, 8 water injection wells); first production FY22 Timeline Project IRR: >15% CY2020 2021 2022 2023 2024 2025 2026 2027 2028 Project capex (BHP share): US$2.2 billion Volumes (100% basis at peak): 140 Mbbl/d Atlantis Phase 3 Field life: 35 years Mad Dog Phase 2 Project Status 60% complete (tracking to plan) Mad Dog – Water injection Future options: Mad Dog northwest water injection, southwest extension, infill wells and cc sands enabled by ullage at Mad Dog Phase 2 FID range First production range Note: This represents an unconstrained scenario based on execution of all unsanctioned projects at current equity interests and does not constitute guidance. Petroleum briefing 11 November 2019 54

Greater Shenzi and Wildling: continuing to deliver value Applying technology to unlock more resource and value Shenzi and Wildling production Shenzi growth projects: BHP (44% WI, operator) - unsanctioned (BHP production, MMboe) Subsea pumping opportunities to increase production rates from existing wells. 10 Anticipated FID: Q4 FY20; first production: Q1 FY22 Project capex range (BHP share): <US$250 million Production (100% basis at peak): 4 Mbbl/d 5 Field life: 15 years Future options: Multiple infill assessments underway benefitting from OBN seismic and dynamic appraisal 0 FY19 FY20e FY21e FY22e FY23e FY24e FY25e FY26e FY27e FY28e FY29e FY30e Base production Unsanctioned projects Wildling Phase 1: BHP (44% - 72% WI, operator) - unsanctioned Future volumes from unsanctioned projects are risked. Phase 1: Two producer development tied back to nearby facilities Phase 1 anticipated FID: Q3 FY21; first production: Q2 FY23 Timeline Project capex (BHP share): ~US$500 million CY2020 2021 2022 2023 2024 2025 2026 2027 2028 Production (100% basis at peak): 15 Mbbl/d Shenzi SSMPP Field life: 15 years Wildling Phase 1 Future options: Additional phases with potential for water injection in BHP 100% blocks FID range First production range Note: This represents an unconstrained scenario based on execution of all unsanctioned projects at current equity interests and does not constitute guidance. Petroleum briefing 11 November 2019 55Greater Shenzi and Wildling: continuing to deliver value Applying technology to unlock more resource and value Shenzi and Wildling production Shenzi growth projects: BHP (44% WI, operator) - unsanctioned (BHP production, MMboe) Subsea pumping opportunities to increase production rates from existing wells. 10 Anticipated FID: Q4 FY20; first production: Q1 FY22 Project capex range (BHP share): <US$250 million Production (100% basis at peak): 4 Mbbl/d 5 Field life: 15 years Future options: Multiple infill assessments underway benefitting from OBN seismic and dynamic appraisal 0 FY19 FY20e FY21e FY22e FY23e FY24e FY25e FY26e FY27e FY28e FY29e FY30e Base production Unsanctioned projects Wildling Phase 1: BHP (44% - 72% WI, operator) - unsanctioned Future volumes from unsanctioned projects are risked. Phase 1: Two producer development tied back to nearby facilities Phase 1 anticipated FID: Q3 FY21; first production: Q2 FY23 Timeline Project capex (BHP share): ~US$500 million CY2020 2021 2022 2023 2024 2025 2026 2027 2028 Production (100% basis at peak): 15 Mbbl/d Shenzi SSMPP Field life: 15 years Wildling Phase 1 Future options: Additional phases with potential for water injection in BHP 100% blocks FID range First production range Note: This represents an unconstrained scenario based on execution of all unsanctioned projects at current equity interests and does not constitute guidance. Petroleum briefing 11 November 2019 55

Mexico: Trion project advancing Building on our early-mover, high-equity positions in key areas to grow our portfolio Net production Drilling our future Investment opportunities Unsanctioned projects (MMboe) 40 • Gross 2C resource of 436 MMboe (net 222 MMboe) • Unlocking opportunities by being first foreign operator in Mexican deepwater in partnership 20 with PEMEX US • Additional exploration drilling planned for FY21 Mexico Further access opportunities 0 • Continue to look for attractive investment Trion opportunities to expand our position in Mexico 1 Fields BHP leases Unsanctioned projects Key highlights FY30e production Key metrics • First well drilled by an international operator in the Net 2C Resources: 222 MMboe Mexican deepwater (acquired Trion FY17) 2 FY26-30 average ROCE: ~25% • Trion 2 DEL appraisal well encountered oil in line with expectations 17 MMboe • Trion 3 DEL found oil above prior well intersections • Performing further studies in FY20 Note: This represents an unconstrained scenario based on execution of all Trion unsanctioned projects at current equity interests and does not constitute guidance. 1. Source: Wood Mackenzie. 2. At Wood Mackenzie prices. Liquids production Gas production Petroleum briefing 11 November 2019 56 FY19 FY20e FY21e FY22e FY23e FY24e FY25e FY26e FY27e FY28e FY29e FY30eMexico: Trion project advancing Building on our early-mover, high-equity positions in key areas to grow our portfolio Net production Drilling our future Investment opportunities Unsanctioned projects (MMboe) 40 • Gross 2C resource of 436 MMboe (net 222 MMboe) • Unlocking opportunities by being first foreign operator in Mexican deepwater in partnership 20 with PEMEX US • Additional exploration drilling planned for FY21 Mexico Further access opportunities 0 • Continue to look for attractive investment Trion opportunities to expand our position in Mexico 1 Fields BHP leases Unsanctioned projects Key highlights FY30e production Key metrics • First well drilled by an international operator in the Net 2C Resources: 222 MMboe Mexican deepwater (acquired Trion FY17) 2 FY26-30 average ROCE: ~25% • Trion 2 DEL appraisal well encountered oil in line with expectations 17 MMboe • Trion 3 DEL found oil above prior well intersections • Performing further studies in FY20 Note: This represents an unconstrained scenario based on execution of all Trion unsanctioned projects at current equity interests and does not constitute guidance. 1. Source: Wood Mackenzie. 2. At Wood Mackenzie prices. Liquids production Gas production Petroleum briefing 11 November 2019 56 FY19 FY20e FY21e FY22e FY23e FY24e FY25e FY26e FY27e FY28e FY29e FY30e

Trinidad & Tobago: deepwater development potential Building on our existing position in the region Net production Drilling our future Investment opportunities Exploration discovery International Offshore Boundaries (MMboe) Barbados BHP Current Leasehold • Trinidad & Tobago North: Gross 2C Resources 75 3.5 Tcf (BHP net interest 70%) Carlisle Bay • Incorporating results from Boom and Carnival 50 Bimshire wells into planning and development studies Sanctioned projects 29 Grenada 1 • Ruby gross 2C resource of 13.2 MMbbl (oil); and 25 23(a) 14 274 Bcf natural gas; IRR ~30% (BHP net interest 65.87%) Trinidad 0 and Tobago Exploration and appraisal opportunities 3(a) 6 • Potential for two oil prospects to be added to the 2(c) Ruby development drilling campaign in FY21 5 3 Base Sanctioned projects Unsanctioned projects • Southern potential for oil and gas Key highlights FY19 production FY30e production Key metrics 1 TTPU • Ruby sanctioned August 2019; will offset declining Ruby 1P Reserves: 48 MMboe production from Angostura in mid-2020s 2P Reserves: 66 MMboe • T&T North deepwater gas exploration program successful 2 • Assessing commercial potential of Southern deepwater 14 66 2P+2C Resources: 582 MMboe MMboe MMboe licenses 3 FY26-30 average ROCE: ~20% Note: This represents an unconstrained scenario based on execution of all T&T unsanctioned projects at current equity interests and does not constitute guidance. TTPU North 1. The Ruby project includes the Ruby and Delaware fields. 2. Includes 2C Resources from Bele and Tuk as at 30 September 2019. 3. At Wood Mackenzie prices. Liquids production Gas production Petroleum briefing 11 November 2019 57 FY19 FY20e FY21e FY22e FY23e FY24e FY25e FY26e FY27e FY28e FY29e FY30eTrinidad & Tobago: deepwater development potential Building on our existing position in the region Net production Drilling our future Investment opportunities Exploration discovery International Offshore Boundaries (MMboe) Barbados BHP Current Leasehold • Trinidad & Tobago North: Gross 2C Resources 75 3.5 Tcf (BHP net interest 70%) Carlisle Bay • Incorporating results from Boom and Carnival 50 Bimshire wells into planning and development studies Sanctioned projects 29 Grenada 1 • Ruby gross 2C resource of 13.2 MMbbl (oil); and 25 23(a) 14 274 Bcf natural gas; IRR ~30% (BHP net interest 65.87%) Trinidad 0 and Tobago Exploration and appraisal opportunities 3(a) 6 • Potential for two oil prospects to be added to the 2(c) Ruby development drilling campaign in FY21 5 3 Base Sanctioned projects Unsanctioned projects • Southern potential for oil and gas Key highlights FY19 production FY30e production Key metrics 1 TTPU • Ruby sanctioned August 2019; will offset declining Ruby 1P Reserves: 48 MMboe production from Angostura in mid-2020s 2P Reserves: 66 MMboe • T&T North deepwater gas exploration program successful 2 • Assessing commercial potential of Southern deepwater 14 66 2P+2C Resources: 582 MMboe MMboe MMboe licenses 3 FY26-30 average ROCE: ~20% Note: This represents an unconstrained scenario based on execution of all T&T unsanctioned projects at current equity interests and does not constitute guidance. TTPU North 1. The Ruby project includes the Ruby and Delaware fields. 2. Includes 2C Resources from Bele and Tuk as at 30 September 2019. 3. At Wood Mackenzie prices. Liquids production Gas production Petroleum briefing 11 November 2019 57 FY19 FY20e FY21e FY22e FY23e FY24e FY25e FY26e FY27e FY28e FY29e FY30e

Exploration: extending our conventional reserve life Investment decisions made in accordance with our Capital Allocation Framework and fully consider the broader market impact Option Location Ownership Maturity Earliest first Description Planned future activity production Finalising processing of Ocean Bottom Node (OBN) seismic Acquired a significant acreage position in historically 1 100% Western GoM US – Gulf of Mexico Frontier Early 2030s survey . Planning OBN survey for GB hub in FY21; underexplored Western Gulf of Mexico Operator targeting first exploration well in FY21/22 Mexico – Gulf of 60% Opportunity to tie back prospects to future Trion hub. Included in Mexico Exploration Late 2020s Targeting first exploration well in FY21 Mexico Operator Trion Minimum Work Program T&T Southern Gas 65% Trinidad & Tobago Exploration Mid 2020s Discovered gas play in deepwater Trinidad & Tobago Evaluating commerciality (Magellan) Operator Evaluating multiple play types to test deeper potential in T&T Southern 65% Trinidad & Tobago Frontier Late 2020s deepwater Trinidad & Tobago based on deep oil shows from Le Targeting first exploration well in FY20 Deep Potential Operator Clerc exploration 100% Recent bid success for blocks with large liquids resource potential Eastern Canada Orphan Basin Frontier Early 2030s Targeting first exploration well in FY22 Operator in the offshore Orphan Basin in Eastern Canada 2 Significant remaining project potential with unrisked NPV of up to US$14 billion 1. Western GoM OBN 2018 Seismic, OCS Permit T18-010. 2. Exploration unrisked value at BHP prices. Petroleum briefing 11 November 2019 58Exploration: extending our conventional reserve life Investment decisions made in accordance with our Capital Allocation Framework and fully consider the broader market impact Option Location Ownership Maturity Earliest first Description Planned future activity production Finalising processing of Ocean Bottom Node (OBN) seismic Acquired a significant acreage position in historically 1 100% Western GoM US – Gulf of Mexico Frontier Early 2030s survey . Planning OBN survey for GB hub in FY21; underexplored Western Gulf of Mexico Operator targeting first exploration well in FY21/22 Mexico – Gulf of 60% Opportunity to tie back prospects to future Trion hub. Included in Mexico Exploration Late 2020s Targeting first exploration well in FY21 Mexico Operator Trion Minimum Work Program T&T Southern Gas 65% Trinidad & Tobago Exploration Mid 2020s Discovered gas play in deepwater Trinidad & Tobago Evaluating commerciality (Magellan) Operator Evaluating multiple play types to test deeper potential in T&T Southern 65% Trinidad & Tobago Frontier Late 2020s deepwater Trinidad & Tobago based on deep oil shows from Le Targeting first exploration well in FY20 Deep Potential Operator Clerc exploration 100% Recent bid success for blocks with large liquids resource potential Eastern Canada Orphan Basin Frontier Early 2030s Targeting first exploration well in FY22 Operator in the offshore Orphan Basin in Eastern Canada 2 Significant remaining project potential with unrisked NPV of up to US$14 billion 1. Western GoM OBN 2018 Seismic, OCS Permit T18-010. 2. Exploration unrisked value at BHP prices. Petroleum briefing 11 November 2019 58

Mexico Evaluating opportunities in offshore Mexico • Opportunity details – targeting first exploration well in FY21 – included in Trion Minimum Work Program – established strong relationship with PEMEX • Next steps BHP Chevron – maturing drill ready prospects near Trion CNOOC – evaluating multiple play types Pemex 1 Fields Shell – opportunity to tieback to a Trion hub Prospects Total – potential to expand early mover position Perdido Foldbelt BHP Prospects Timeline SALT SALT CY2020 2021 2022 2023 2024 2025 2026 2027 2028 Oceanic Basement Continental Basement Explore Appraise Paleogene Reservoir Targets 1. Source: Wood Mackenzie. Petroleum briefing 11 November 2019 59Mexico Evaluating opportunities in offshore Mexico • Opportunity details – targeting first exploration well in FY21 – included in Trion Minimum Work Program – established strong relationship with PEMEX • Next steps BHP Chevron – maturing drill ready prospects near Trion CNOOC – evaluating multiple play types Pemex 1 Fields Shell – opportunity to tieback to a Trion hub Prospects Total – potential to expand early mover position Perdido Foldbelt BHP Prospects Timeline SALT SALT CY2020 2021 2022 2023 2024 2025 2026 2027 2028 Oceanic Basement Continental Basement Explore Appraise Paleogene Reservoir Targets 1. Source: Wood Mackenzie. Petroleum briefing 11 November 2019 59

Trinidad & Tobago deep potential Testing multiple play types International offshore boundaries Barbados 29 BHP current leasehold • Opportunity details 23(a) 14 – BHP (65% WI, operator) – Le Clerc opened the Magellan Gas Play and saw deep Trinidad oil shows & Tobago – evaluating multiple play types to test deeper potential 3(a) 6 2(c) • Next steps 5 3 – exploration well planned for FY20 T&T South Foldbelt BHP Prospect BHP Prospect BHP Prospect Timeline CY2020 2021 2022 2023 2024 2025 2026 2027 2028 Explore Appraise Economic Miocene Reservoir Targets Basement Petroleum briefing 11 November 2019 60Trinidad & Tobago deep potential Testing multiple play types International offshore boundaries Barbados 29 BHP current leasehold • Opportunity details 23(a) 14 – BHP (65% WI, operator) – Le Clerc opened the Magellan Gas Play and saw deep Trinidad oil shows & Tobago – evaluating multiple play types to test deeper potential 3(a) 6 2(c) • Next steps 5 3 – exploration well planned for FY20 T&T South Foldbelt BHP Prospect BHP Prospect BHP Prospect Timeline CY2020 2021 2022 2023 2024 2025 2026 2027 2028 Explore Appraise Economic Miocene Reservoir Targets Basement Petroleum briefing 11 November 2019 60

SIGNATURES

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

|  |  |  |  |  | BHP Group Limited and BHP Group Plc
Date: November 11, 2019 |  |  |  | By: |  | /s/ Rachel Agnew
|  |  |  | Name: |  | Rachel Agnew
|  |  |  | Title: |  | Company Secretary