UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 6-K

REPORT OF FOREIGN PRIVATE ISSUER

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

UNDER THE SECURITIES EXCHANGE ACT OF 1934

August 20, 2019

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

20 August 2019

New York Stock Exchange

BHP RESULTS PRESENTATION YEAR ENDED 30 JUNE 2019

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

The webcast for this presentation can be accessed at: https://edge.media-server.com/mmc/p/vd25ua3y

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

Rachel Agnew

Company Secretary

The BHP Group is headquartered in Australia

BHP
Financial results Year ended
30 June 2019
Escondida

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. Queensland Coal comprises the BHP Billiton Mitsubishi Alliance (BMA) asset, jointly operated with Mitsubishi, and the BHP Billiton Mitsui Coal (BMC) asset, operated by BHP. Numbers presented may not add up precisely to the totals provided due to rounding. All footnote content contained on slide 38.
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.
Financial results
20 August 2019 2

BHP
Financial results
Year ended 30 June 2019
Onshore US assets have been presented as discontinued operations.
Andrew Mackenzie Chief Executive Officer
Neptune

BHP’s investment proposition
We have the assets, options, capabilities and discipline to sustainably grow long-term shareholder value and returns
Maximise cash flow
Low-cost producer
efficiency, technology, culture
Volume growth
productivity, project delivery
Constructive outlook
for our commodities, solid demand, disciplined supply
Capital discipline
US$12-17 bn net debt
range updated for IFRS 16
<US$8 bn capex
in FY20 and ~US$8 bn in FY21
Organic opportunities
rich option set across commodities and time periods assessed on risk and return metrics
Value and returns
ROCE to ~20%
by FY22 (at FY17 prices)
Optimised portfolio
post Onshore US divestment
~US$29 bn returned
to shareholders since 1 January 2016
Note: Disciplined supply: reflects lower levels of investment across the industry. Shareholder returns: includes dividends determined since 1 January 2016 and Onshore US proceeds. Details on change in net debt target range provided on slide 30. FY22 ROCE includes negligible impact of leases under IFRS 16.
Financial results
20 August 2019
4

FY19 financial scorecard
>US$17 billion returned to shareholders over the last 12 months
Volumes
Cu Eq broadly flat
2% decline despite weather, grade and field decline and production outages
Net debt
US$9.2 bn
net debt
down US$1.7 bn since June 2018 (pre IFRS 16)
Profitability
US$23.2 bn
Underlying EBITDA and 53% margin
diversified contribution across the portfolio
Shareholder returns
78 US cps (final dividend)
payout ratio of 73%
record 133 US cps full year dividend; US$10.4 billion Onshore US proceeds
Free cash flow
US$10.0 bn
free cash flow
US$20.5 bn including Onshore US proceeds
ROCE
18%
ROCE
up from 15% at H1 FY19
Note: Volumes, EBITDA, EBITDA margin, free cash flow (except as noted), ROCE presented on a continuing operations basis. Other metrics presented on a total operations basis. Net debt excludes impact of IFRS 16. Shareholder returns includes dividends determined in FY19.
Financial results
20 August 2019
5

Sustainability is one of our core values
We will continue our work to improve safety at our operations
Safety
• Tragically, we had a fatality at Saraji
• TRIF at operated assets of 4.7 per million hours worked
• >1.3 million field leadership interactions
18%
high potential injury frequency rate1
Health
• Continued uptake of resilience program
• Successful launch of mental health week
28%
potential material (silica, diesel and coal mine dust) exposures above OEL2
Climate change
• Plans to update scenario analysis, strengthen link to executive remuneration and establish Scope 3 emissions goals
• 14.7 Mt CO2-e of greenhouse gas emissions; 3% lower than baseline target 3
US$400 m
commitment over 5 years to address emissions across our operations and value chain
Community
• Building strong relationships with Indigenous stakeholders
• 1% of pre-tax profits invested in community programs
US$93 m
towards community development projects and donations
Samarco
• Committed to support Renova Foundation on compensation, recovery of communities and environment
• Construction of the resettlement sites continues to progress
• Restart a focus; but must be safe, economically viable and community supported
Note: Presented on a total operations basis, except the greenhouse gas emissions target calculation which is presented on a continuing operations basis
Financial results
20 August 2019
6

BHP
Financial results
Year ended 30 June 2019
Onshore US assets have been presented as discontinued operations.
Peter Beaven Chief Financial Officer

Financial performance
Strong free cash flow generation and EBITDA margin above 50%
Summary FY19 Income statement
(US$ billion)
Total operations (including Onshore US)
Underlying attributable profit 9.1 Net exceptional items (0.8) Attributable profit 8.3
Underlying basic earnings per share 176.1 US cps h5% Final dividend per share 78 US cps h24%
Continuing operations
Underlying EBITDA 23.2 0% Underlying EBITDA margin 53% Underlying EBIT 17.1 h3% Adjusted effective tax rate4 36.0% Adjusted effective tax rate incl. royalties 44.7% Underlying attributable profit 9.5 h 2%
Strong earnings delivery
(US cent per share) (Index, FY16=100) 200 200
150
100 100
50
0 0 FY16 FY17 FY18 FY19 Underlying basic EPS (H1) Underlying basic EPS (H2) Revenue (RHS)
Note: Presented on a total operations basis.
Financial results
20 August 2019
8

Group EBITDA waterfall
Strong H2 EBITDA performance offsetting unplanned outages in H1
Underlying EBITDA variance
(US$ billion)
30 External US$1.8 billion Controllable US$(1.8) billion
1.2 1.0 25.0 0.1 0.1 25
23.2 (0.1) 23.2
(0.4) (1.0)
(0.2) (0.7) 20
FY19 productivity performance: US$(1) billion5
15 (US$ billion)
1.0
1.0 (0.8)
10 (0.4)
0.0
(0.8)
(1.0)
5 Productivity Grade Coal unit costs Outages improvements and Nickel West mine plan
0
FY18 Price6 Foreign exchange Inflation Sub-total Growth volumes Productivity volumes Controllable7 cash costs Fuel & energy Non-cash8 Other9 FY19
Note: Presented on a continuing operations basis. Productivity of US$(1) billion includes change in capitalised exploration.
Financial results
20 August 2019
9

Segment performance
Prices and strong operational performance in H2 underpin EBITDA
% of Group EBITDA10 EBITDA: EBITDA margin: ROCE:
Unit cost:
Cost
Cost at FX guidance Guidance
Performance drivers:
Iron Ore11
290 Mtpa run rate achieved in the June quarter14
48% US$11.1 bn 65% 37%
WAIO
(US$/t)
15
13–14 14 14.16
<13 13
12
FY19 FY20e MT FY19 C1 costs US$12.86/t (ex. 3rd party royalties)13
• FY19 productivity improvements, strong Q4
• Derailment in H1 and Tropical Cyclone Veronica in H2
Copper
Record throughput at Chilean operations
19% US$4.6 bn 46% 6%
Escondida
(US$/lb)
1.60
1.20–1.35
<1.15 1.20
0.80 1.14
0.40
FY19 FY20e MT
• FY19 ~12% grade decline and end of negotiation bonus
• FY20 lower by-product credits and higher deferred stripping
• Maintenance initiatives reduce variability in concentrator performance
Coal
Record stripping performance
17% US$4.1 bn 45% 26%
Queensland Coal
(US$/t)
80 67–74
60 69.44 54–61 40
20
FY19 FY20e MT
• FY19 higher stripping costs and weather impacts
• Achieved 48 Mtpa run rate in Q4 FY19
• FY20 higher wash plant maintenance
Petroleum12
Strong field and uptime performance
16% US$3.8 bn 64% 19%
Conventional
(US$/boe)
13
<13 12 10.5–11.5 10.54 11
10
FY19 FY20e MT
• FY19 strong uptime and field performance
• FY20 planned maintenance at Atlantis and natural field decline
Note: Presented on a continuing operations basis.
Financial results
20 August 2019
10

Cash generation
Our diversified portfolio has delivered consistently strong cash flows
Operating cash flow
(US$ billion) (Index, FY10=100)
35 200 30 25
20
100 15
10
5
0 0 FY10 FY11 FY12 FY13 FY14 FY15 FY16 FY17 FY18 FY19
Operating cash flow (H1) Operating cash flow (H2) Onshore US Revenue (RHS)
Free cash flow
(US$ billion) (Index, FY10=100)
25 200
20 200
15
100
10
5
0 0 200 (5)
(10) (100) FY10 FY11 FY12 FY13 FY14 FY15 FY16 FY17 FY18 FY19
Free cash flow (H1) Free cash flow (H2) Onshore US proceeds Revenue (RHS)
Note: Presented on a total operations basis.
Financial results
20 August 2019
11

Capital allocation
Disciplined adherence to our Capital Allocation Framework
FY19
Operating Capital productivity productivity Net operating cash flow US$17.9 bn
Maintenance capital US$2.0 bn Strong balance sheet✓ Minimum 50% payout ratio dividend15 US$4.4 bn
Balance sheet
US$2.8 bn
Additional dividends15 US$7.0 bn
• H2 FY18 and H1 FY19
• US$5.2 bn Onshore US special dividend
Excess cash US$10.2bn
Buy-backs
US$5.2 bn
• US$5.2 bn buy-back
Excludes net cash outflow of US$1.3bn
Organic development US$5.6 bn
• US$2.3 bn improvement
• US$0.5 bn latent capacity
• US$1.5 bn major projects
• US$0.9 bn exploration
• US$0.4 bn Onshore US
Acquisitions/ (Divestments) US$(10.4) bn
• Onshore US sale
• Bruce/Keith sale
Note: Presented on a total operations basis. Excess cash includes dividends paid to NCIs16 of US$(1.2) billion (FY18: US$(1.6) billion); net investment and funding of equity accounted investments of US$(0.6) billion (FY18: US$0.2 billion); excludes exploration expenses of US$0.5 billion (FY18: US$0.6 billion) which is classified as organic development in accordance with the Capital Allocation Framework; Total net cash outflow of US$1.3 billion (FY18: US$0.8 billion). Onshore US proceeds of US$10.4 billion received in FY19.
Financial results
20 August 2019
12

Striking the right balance to maximise value and returns
US$17 billion reduction in net debt; ~US$27 billion reinvested; ~US$29 billion returned to shareholders17
Net debt below target range
(Net debt, US$ billion)
30
20
New target range (IFRS 16) $12-17 bn
10
0
FY16 FY17 FY18 FY19 FY20e Actuals Net debt target
Disciplined investment
(Capital and exploration expenditure, US$ billion)
9
6
3
0
FY16 FY17 FY18 FY19 FY20e FY21e Actuals Guidance
Increased returns to shareholders
(Dividends determined and share buy-backs, US$ billion)
18
~US$17 bn
Onshore US proceeds
6
3
0
FY16 FY17 FY18 FY19 Minimum dividend Additional amount
Note: Net debt target before IFRS 16 adjustments. Presented on a total operations basis.
Financial results
20 August 2019
13

Return on Capital Employed
FY19 ROCE 18%; tailored plans to improve ROCE at every asset
ROCE by asset
(%)
40 Excludes investment in major projects in execution
35
30 Antamina18
25
20
WAIO Queensland NSWEC
Coal Pampa Norte
15
Conventional Cerrejón18
10 Petroleum
5 Escondida
Olympic Dam
0
Potash (5) Exploration19
0 10 20 30 40 50 60
Average capital employed (US$ billion)
Returns
(ROCE excluding Onshore US, %) 20
15 10 5
0
FY16 FY17 FY18 FY19
FY17 average realised prices Actual
ROCE to ~20% by FY22 (at FY17 prices)
Note: Presented on a continuing operations basis. ROCE represents attributable profit after tax excluding exceptional items and net finance costs (after tax) divided by average capital employed. Capital employed is net assets before net debt.
Financial results
20 August 2019
14

BHP
Financial results
Year ended 30 June 2019
Onshore US assets have been presented as discontinued operations.
Andrew Mackenzie Chief Executive Officer

Market outlook
Near-term uncertainty, attractive medium-term fundamentals, long run strategic themes
Short term
Policy Growth uncertainty modest
Sentiment Prudently mixed cautious
Medium term
Steeper New supply cost curves
Sustainable Emerging productivity Asia
Long term
Growth in
Electrification population, of transport wealth
Decarbonisation Biosphere of power stewardship
Note: Further information on BHP’s economic and commodity outlook can be found at www.bhp.com/prospects.
Financial results
20 August 2019
16

Our strategic framework
We aspire to have industry-leading capabilities applied to a portfolio of world-class assets in the most attractive commodities
Culture and capabilities that enable the execution of our business strategy
Unlocking value through Transformation
• BHP Operating System
• Value Chain Automation
• World Class Functions
• Operations Services
• Centres of Excellence:
Engineering and Maintenance, Geoscience, Projects
Best Best culture and Value and commodities capabilities
returns
Best assets
Commodities with high economic rent potential that match our capabilities
Increasing options in our favoured commodities
• Copper
• Oil
Further simplifying our portfolio
• Onshore US sale
• Bruce/Keith sale
Assets that are resilient through the cycle, have embedded growth options and match our capabilities
Driven by a commitment to transformation, capital discipline and social value
Financial results
20 August 2019
17

Minerals Australia
Reliability to drive cost reductions and strong operating performance
Operational performance momentum builds into FY20
• WAIO production up 20% and unit costs down >50% since FY14
– 15% increase in train payloads enabled by improved mine performance, rail stability and port availability
• Queensland Coal production up 12% and unit costs down >15% since FY14 – reflects productivity initiatives including improved truck utilisation to help offset 14% increase in strip ratios and Crinum mine closure in FY16
Focused on operational reliability and asset integrity
• WAIO: undertaking significant maintenance program at port in H1 FY20
• Olympic Dam: 50% of multi-year integrity program completed at the surface operation; crane replacement is planned for FY20
• Queensland Coal: major wash plant maintenance in Q1 FY20
Unlocking further value
• Operations Services to accelerate safety and productivity improvements
• Autonomous truck hauling across WAIO and Queensland Coal sites in feasibility
• Oak Dam phase two drilling results under evaluation
• Nickel West: ore reserves (contained nickel) increased by >75% since FY18; will support future expansion options20
Record costs performance and run rate at WAIO
(US$/t) (Iron ore production, Mtpa)
30 Q4 run rate14 300
15 250
10 200 FY14 FY15 FY16 FY17 FY18 FY19 FY20e Medium term Unit costs Production
Strip ratio headwinds at BMA to unwind over the medium term
(US$/t) (Queensland Coal, prime to product strip ratio)
95 12
80 10
65 8
50 6 FY14 FY15 FY16 FY17 FY18 FY19 FY20e Medium term Unit costs Strip ratio
Financial results
20 August 2019
18

Minerals Americas
Transformation key to performance uplift
Record throughput at all Chilean operations
• Escondida: transformation programs underpin increased throughput in H2 FY19 to average 356 ktpd – production impact of a ~35% concentrate grade decline over past 5 years capped at ~5% by capital efficient concentrator strategy and early desalination adoption
• Pampa Norte: recovery optimisation initiatives and strong throughput to help offset ~11% lower grade during FY20
Power strategy to bolster renewables position
• Extension of desalinated water plant at Escondida on track for first water December 2019
• Aim to source almost all power from renewables at lower cost than the current carbon sources at Escondida and Spence in the medium term
Optionality expanded
• Spence Growth Option on track, first copper expected in H1 FY21
• Jansen remains strategic option; current scope to finish early CY21
• New interests in exploration across Ecuador, Canada and Mexico
Escondida step change in mining and concentrator performance
(Material moved, Mt/FTE) (Throughput, ktpd) 150 450
LCE ramp up
120 300
90 150
Escondida labour strike
60 0 FY14 FY16 FY18 FY20 Medium term Concentrator throughput (RHS) Mining labour productivity (LHS)
Stable unit cost despite 9 US¢/lb increase in water and power since FY14
(Escondida unit cost, US$/lb) (Index, FY14=100) 1.50 200
1.00 150
0.50 100
0.00 50 FY14 FY15 FY16 FY17 FY18 FY19 FY20e Medium term Unit costs Grade (RHS) Water and power % of unit cost (RHS)
Note: LCE: Los Colorados Extension project.
Financial results
20 August 2019
19

Petroleum
Strong operating performance supported by promising short, medium and long-term growth options
High-return options within current portfolio to offset field decline
• Uptime and field performance delivered 1% volume growth in FY19
• West Barracouta tracking to plan, first gas expected in CY21
• ~30 improvement and infill well programs with average returns of >40%
• Five projects to seek approval in the next 12 months
Pipeline of major projects to lift production in the medium term
• Atlantis Phase 3 tracking to plan, first production expected in CY20
• Ruby approved, first production expected in CY21
• Mad Dog 2 tracking to plan, first production expected in CY22
• Six additional projects under study with average returns of ~25%
Exploration and appraisal program continues progressing well
• Trion: 3DEL encountered oil above prior well intersections
• GoM: Samurai exited for value; assessing Wildling development options
• Trinidad: Phase 3 successful; Phase 4 to commence in Q1 FY20
• Recent additions lift 2C Contingent Resources back to FY12 levels
• Material production from exploration options expected mid-2020s
Exploration and appraisal success...
(Net exploration wells) (Successful wells/wells drilled, %)
8 100
4 50
0 0 FY17 FY18 FY19 FY20 (YTD)
Net exploration wells Technical success rate (RHS)21
…has materially increased resources
(Net 2C Contingent Resources, MMboe) h >55% 2,000
1,000
0
FY12 FY13 FY14 FY15 FY16 FY17 Appraisal, production assets FY18 Appraisal, production assets FY19 discoveries, discoveries,
Note: GoM – Gulf of Mexico.
Financial results
20 August 2019
20

We expect to deliver on our plans in FY20
Continued progress against our focus areas
Maximise cash flow
Cu Eq volumes
2% higher despite 7% reduction in petroleum
Transformation
latent capacity projects tracking to plan; at iron ore and coal operations autonomous truck studies continue
Capital discipline
Net debt
to remain at lower end of revised US$12-17 bn target range
<US$8 bn capex
includes 6 major projects diversified across commodities, on track and on budget
Value and returns
19% ROCE
at spot prices
Shareholder returns
>US$3.9 bn dividends to be paid in H1 FY20 (73% payout ratio)
Note: FY20 volumes based on mid point of guidance. Details on change in net debt range provided on slide 30. Spot prices as of 13 August 2019. FY20 ROCE includes negligible impact of leases under IFRS 16.
Financial results
20 August 2019
21

Broad suite of attractive opportunities Optionality
Transformation, future options and exploration evaluated and ranked based on returns, risk and optionality In execution
T&T, GoM Ecuador, South
Higher South Flank Atlantis Phase 3 exploration Australia exploration (Iron ore) (Petroleum) return (Petroleum) (Copper)
Nickel West
Trion appraisal Latent capacity Mad Dog Phase 2 expansion (Petroleum) (EWSE, WAIO290, (Petroleum) (Nickel) West Barracouta)
Resolution Wards Well Spence Growth Option Scarborough (Copper) (Metallurgical coal) (Copper) (Petroleum)
Olympic Dam Autonomous Haulage South Walker Creek Jansen Stage 1 Expansion Project Australia Lower (Metallurgical coal) (Potash) (Copper) (Minerals Australia)
return
Higher risk Lower risk
Options assessed against our strategic themes to test portfolio resilience in the long term
Note: Olympic Dam Expansion Project refers to heap leach technology development option. T&T: Trinidad and Tobago; GoM: Gulf of Mexico; EWSE: Escondida Water Supply Extension.
Financial results
20 August 2019
22

BHP’s investment proposition
We have the assets, options, capabilities and discipline to sustainably grow long-term shareholder value and returns
Maximise cash flow
Low-cost producer
efficiency, technology, culture
Volume growth
productivity, project delivery
Constructive outlook
for our commodities, solid demand, disciplined supply
Capital discipline
US$12-17 bn net debt
range updated for IFRS 16
<US$8 bn capex
in FY20 and ~US$8 bn in FY21
Organic opportunities
rich option set across commodities and time periods assessed on risk and return metrics
Value and returns
ROCE to ~20%
by FY22 (at FY17 prices)
Optimised portfolio
post Onshore US divestment
~US$29 bn returned
to shareholders since 1 January 2016
Note: Disciplined supply: reflects lower levels of investment across the industry. Shareholder returns: includes dividends determined since 1 January 2016 and Onshore US proceeds. Details on change in net debt target range provided on slide 30. FY22 ROCE includes negligible impact of leases under IFRS 16.
Financial results
20 August 2019
23

BHP

BHP
Appendix

Samarco and Renova Foundation
Resettlement a priority social program
Rehabilitation (Renova Foundation)
Communities
• Bento Rodrigues: 132 families finalised house design, first house build started in July 2019. School construction underway
• Paracatu town site earthworks underway; Gesteira urban plan being designed with community
River stabilisation
• River stabilisation largely complete
• In May 2019, Brazil’s National Sanitary
Surveillance Agency (ANVISA) attested to the safe consumption in certain quantities of fish and crustaceans from the Doce River basin and coastal region
Compensation (Renova Foundation)
• BRL$1.7 billion indemnification and financial aid paid to June 2019
• More than 8,700 general damages claims resolved
• 13,160 families continue to receive income support through emergency financial aid
Samarco legal developments and restart
• Preparation work for construction of new tailings disposal system at Alegria Sul Pit expected to be completed in September 2019
• Working towards restart but will only occur if safe, economically viable and community in support
• Restart requires licensing approvals and the funding needed for preparation works
• Progressing plans for decommissioning two upstream dams in Germano complex
Note: Fishing bans still in place. Fish and crustaceans daily dosages of 200mg for adult and 50mg for children; Water damages compensation does not include legal claims in court under dispute.
Financial results
20 August 2019
26

Broad suite of attractive opportunities
Latent capacity average returns of >100%; major project average returns of ~17%; exploration offers upside potential
Jansen current scope: 84% complete
Petroleum
Jansen Stage 1: study underway
Copper
Orphan Basin: Exploration plan submitted
Iron Ore
Trion: Appraisal results in line with expectations Coal
Mad Dog Phase 2: 53% complete Potash
OD SMA: record underground development Atlantis Phase 3: 13% complete Ruby: approved August 2019 OD BFX: Pre-feasibility study phase Wildling: assessing appraisal and development options Northern T&T: phase 3 successful Oak Dam: assessing second phase of drilling Western GOM: OBN survey acquisition complete Southern T&T: assessing potential resource
CRSC: first coal conveyed October 2018 Ecuador: 11.2% of SolGold acquired
Queensland Coal debottlenecking: latent
Greater Western Flank-B: first production achieved capacity SGO: 60% complete Scarborough: assessing development options EWSE: scheduled completion December 2019 WAIO to 290 Mtpa: supply chain productivity
South Flank: 39% complete
West Barracouta: approved December 2018
Note: Only near-term opportunities shown on map. BXF – Brownfield Expansion; CRSC – Caval Ridge Southern Circuit; EWSE – Escondida Water Supply Expansion; SGO – Spence Growth Option; SMA – Southern Mine Area.
Financial results
20 August 2019
27

Unlocking value for BHP through transformation
The world is undergoing significant change… we will be bolder and adapt faster to take advantage of this
Transformation
Ways of work
Culture and capabilities
Strategic and innovative partnerships
Current programs
World Class Functions Centres of Excellence
• Reduce bureaucracy, • Centrally defined global fewer silos best practice
• 30% reduction in • Equipment consistently overhead costs22 to exceed benchmark
Enhancing our access BHP Operating System to capability
• Front-line-led continuous
• Flexible partnerships improvement
• Deployed across seven to access talent
• Technical and locations engineering excellence
Value Chain Automation Innovative solutions for
• Equipment automating operations
• Decision automation • Address sustainability challenges (e.g. carbon capture, water, tailings)
Shared social and environmental value
• Strategic partnerships for mutual benefit
Outcomes
Operational stability
Quantum shift in safety, performance and value
Continued increase in productivity
Flexibility to rapidly capture opportunities
Technology
IROCs
Replication accelerating across portfolio
Autonomous trucks
Safety incidents down by >80%23
Autonomous drills
Across WAIO
Autonomous TLOs
Additional 2.4t iron ore per ore car
Geophysics modelling
Oak Dam discovery OBN application
Note: IROC – Integrated Remote Operating Centre; WAIO – Western Australian Iron Ore; TLO – Train Load Out; OBN – Ocean Bottom Node.
Financial results
20 August 2019 28

Balance sheet
Net debt of US$9.2 billion and gearing of 15.1%
Movements in net debt
(US$ billion)
15
10.9
10 9.2
1.2
11.4 0.6 -
0.4 5
0
5.2 -5
-10
(20.5)
-15
FY18 Free cash Share Dividends Dividends Non-cash Other FY19 flow buy-back paid paid fair value movements
16
to NCI movement24
Debt maturity profile25
(US$ billion)
8 6 4 2
0
FY20 FY21 FY22 FY23 FY24 FY25 FY26 FY27 FY28 Post FY29
US$ Euro Sterling A$ C$ Bonds26 Bonds26 Bonds26 Bonds Bonds
Subsidiaries 39% 31% 14% 3% 3% 10% % of portfolio Capital markets 90% Asset financing 10%
Note: Presented on a total operations basis.
Financial results
20 August 2019
29

IFRS 16 leases: overview
Operating lease commitments brought onto balance sheet from 1 July 2019
• Effective from 1 July 2019
• Removes distinction between operating and finance leases; introduces new identification criteria
Overview - results in operating leases being recognised on balance sheet; no change to treatment of finance leases—key impacts shown on slide 31
• No change to underlying cash flows
• Applied on a modified retrospective basis (i.e. additional lease assets equal additional lease liabilities; no restatement of historical financials)
Implementation
• Grandfathering rules not applied (i.e. applied to all existing contracts on 1 July 2019) approach
• Short term, variable payment and low-value leases will remain off-balance sheet and continue to be recorded as operating expenses
• Additional lease liability of ~US$2.3 bn recognised on 1 July 2019
– broadly split between: office buildings; freight contracts; and other (e.g. mining and other equipment, rigs, accommodation)
– freight contracts include Continuous Voyage Charters (CVCs) which were not a lease under old IAS 17 criteria
– CVCs are priced with reference to the volatile freight index (C5 Dry Baltic) and must be remeasured each period
• Small favourable impact expected to unit costs (0-5%) as lease costs shift from operating expenses to depreciation and interest Key impacts • Net debt target range changed to US$12-17 bn
– change in net debt definition to include fair value of debt-related derivatives at 30 June 2019 (US$0.2 bn increase), unrelated to IFRS 16 – initial impact of IFRS 16 on 1 July 2019 (~US$2.3 bn increase) – additional new leases commencing in FY20 (including SGO desalination plant) and renewals of existing lease arrangements (~US$1.3 bn increase)
• No material impact on NPAT; minimum dividend calculations unaffected
Financial results
20 August 2019 30

IFRS 16 leases: impacts
Accounting change only; no impact to net cash flows
Balance sheet27
Right of use assets (PP&E)
US$2.3 bn27
Lease liabilities (Interest bearing liabilities)
US$2.3 bn
Income statement
Operating costs
US$0.8 bn
EBITDA
US$0.8 bn
Depreciation
US$0.7 bn
Interest
US$0.1 bn
No material impact on income statement
Cash flow statement
Operating cash outflow
US$0.7 bn
Investing cash flow no impact
Financing cash outflow
US$0.7 bn
No impact on net cash flows
Disclosures
Operating lease commitments (IAS 17)
~US$2 bn
Short term, variable, low value leases
Financial metrics
Net debt
US$2.3 bn
Gearing
3%28
EBITDA margin
2%
Unit cash costs
0-5%
ROCE negligible impact
Financial results
20 August 2019
31

Projects in feasibility
Autonomous truck hauling Jansen Stage 1
Australia Saskatchewan, Canada
Automating ~500 haul trucks across Shaft equipping, mine development, processing facility, Western Australia Iron Ore and Queensland Coal sites site infrastructure and outbound logistics.
Operator BHP BHP
BHP ownership Various 100%
5,300 – 5,700
Capex (US$m) <800 Sustaining capital ~US$15/t (real) long term average; +/- 20% in any given year.
Feasibility study phase
Phase / timing First of several investment decision expected in CY19 Feasibility study phase (capex represents full amount)
~5 years from sanction to commissioning First production / Project delivery Staged site rollout from CY20 onwards ~2 years from first production to ramp up Volumes (100% basis at peak) n/a 4.3 – 4.5Mtpa (Potassium chloride, KCL) 6% royalty
Federal and Provincial Corporate income tax and Potash Other considerations Site by site decision on roll out Production Tax29 Jansen Stage 1 expected mine life of 100 years
Financial results
20 August 2019 32

BHP guidance
Group FY20e FY21e
Capital and exploration expenditure (US$bn) <8.0 ~8.0 Cash basis. Including:
Maintenance 2.1 Includes non-discretionary capital expenditure to maintain asset integrity, reduce risks and meet compliance requirements. Also includes capitalised deferred development and production stripping (FY20e: US$0.8 billion).
Improvement 2.9 Includes Conventional Petroleum infill drilling and South Flank. Latent capacity 0.4 Includes EWSE, WAIO to 290 Mtpa and West Barracouta.
Major growth 1.7 Includes Spence Growth Option, Mad Dog Phase 2, Jansen, Atlantis Phase 3 and Ruby
Exploration 0.9 Includes US$0.7 billion Petroleum and ~US$60 million Copper exploration programs planned for FY20.
Conventional Petroleum FY20e Medium term
Petroleum production (MMboe) 110 – 116 ~110 FY20 volumes expected to decrease due to planned maintenance at Atlantis and natural field decline across the portfolio. Decline of ~1.5% p.a. over medium term includes projects yet to be sanctioned. ~110 Mboe represents average over medium term.
Capital expenditure (US$bn) 1.2 Sanctioned Capex First production Production (BHP share) (100% basis at peak) Mad Dog Phase 2 February 2017 US$2.2 bn CY22 140,000 boe/d West Barracouta December 2018 ~US$140 m CY21 104 MMscf/d Atlantis Phase 3 February 2019 ~US$700 m CY20 38,000 boe/d Ruby August 2019 ~US$340 m CY21 16,000 bopd (oil) and
(~US$280 m excl. pre-commitment) 80 MMscf/d (gas)
Exploration expenditure (US$bn) 0.7 Focused on Mexico, the Gulf of Mexico, Canada and the Caribbean.
Unit cost (US$/boe) 10.5 – 11.5 <13 Excludes inventory movements, embedded derivatives movements, freight, third party product purchases and exploration expense. Based on exchange rate of AUD/USD 0.70.
Financial results
20 August 2019 33

BHP guidance (continued)
Copper FY20e Medium term
Copper production (kt) 1,705 – 1,820 Escondida: 1.16 – 1.23 Mt; Olympic Dam: 180 – 205 kt; Pampa Norte 230 – 250 kt; Antamina: 135 kt (zinc 110kt).
Capital and exploration expenditure (US$bn) 2.5 Includes ~US$60 million exploration expenditure.
Sanctioned Capex First production Production (BHP share) (100% basis) EWSE March 2018 US$308 m FY20 1,300 l/s of water Spence Growth Option August 2017 US$2.46 bn H1 FY21 ~185 ktpa of incremental copper (over first 10 years)
Escondida
Copper production (kt, 100% basis) 1,160 – 1,230 ~1,200 ~1,200 kt represents average over medium term.
Unit cash costs (US$/lb) 1.20 – 1.35 <1.15 Excludes freight; net of by-product credits; based on an exchange rate of USD/CLP 683. Unit costs expected to be impacted by lower byproduct credits (compared to FY19) in the short term. Medium term unit costs flat despite higher water and power costs.
Iron Ore FY20e Medium term
Iron ore production (Mt) 242 – 253 Excludes production from Samarco. Major car dumper maintenance planned for September 2019 quarter
Capital and exploration expenditure (US$bn) 2.4 Sanctioned Capex First production Production (BHP share) (100% basis) South Flank June 2018 US$3.1 bn CY21 80 Mtpa sustaining mine
Western Australia Iron Ore
Iron ore production (Mt, 100% basis) 273 – 286 290
Unit cash costs (US$/t) 13 – 14 <13 Excludes freight and royalties; based on an exchange rate of AUD/USD 0.70.
Sustaining capital expenditure (US$/t) 4 Medium term average; +/- 50% in any given year. Includes South Flank; excludes costs associated with Value Chain Automation.
Financial results
20 August 2019 34

BHP guidance (continued)
Coal FY20e Medium term
Metallurgical coal production (Mt) 41 – 45 49 – 54 FY20 volumes Planned wash plant shutdowns in Sept Q19 at Goonyella, Peak downs and Caval Ridge Energy coal production (Mt) 24 – 26 NSWEC: 15 – 17 Mt; Cerrejón: ~9 Mt.
Capital and exploration expenditure (US$bn) 0.7
Queensland Coal
Production (Mt, 100% basis) 73 – 79
Unit cash costs (US$/t) 67 – 74 54 – 61 Excludes freight and royalties; based on an exchange rate of AUD/USD 0.70.
Sustaining capital expenditure (US$/t) 8 Medium term average; +/- 50% in any given year. Excludes costs associated with Value Chain Automation.
Other FY20e
Other capex (US$bn) 0.5 Includes Nickel West and Jansen. Including: Jansen current scope (US$bn) ~0.215 US$2.7 billion; completion in early 2021.
Financial results
20 August 2019 35

Key Underlying EBITDA sensitivities
Approximate impact30 on FY20 Underlying EBITDA of changes of: US$ million
US$1/t on iron ore price31 233 US$1/bbl on oil price32 39 US$1/t on metallurgical coal price 39 US¢1/lb on copper price31 36 US$1/t on energy coal price31 15 US¢1/lb on nickel price 1.6 AUD (USË~1/A$) operations33 121 CLP (US¢1/CLP) operations33 27
Financial results
20 August 2019 36

Statement of Petroleum Resources
Petroleum resources
The estimates of Conventional Petroleum contingent resources contained in this presentation are on a Net revenue interest basis and are based on, and fairly represent, information and supporting documentation prepared under the supervision of Mr A. G. Gadgil, who is employed by BHP. Mr Gadgil is a member of the Society of Petroleum Engineers and has the required qualifications and experience to act as a qualified petroleum reserves and resources evaluator under the ASX Listing Rules. This presentation is issued with the prior written consent of Mr Gadgil who agrees with the form and context in which the petroleum contingent resources are presented. Aggregates of contingent resources estimates contained in this presentation have been calculated by arithmetic summation of field/project estimates by category using deterministic methodology. The custody transfer point(s)/point(s) of sale applicable for each field or project are the reference point for contingent resources. Contingent resources estimates contained in this presentation have not been adjusted for risk. Unless noted otherwise, contingent resources are as at 30 June 2019. In this presentation millions of barrels of oil equivalent are abbreviated as Mmboe. The total boe conversion is based on the following: 6,000 scf of natural gas equals 1 boe. BHP estimates proved reserve volumes according to SEC disclosure regulations and files these in our annual Form 20-F with the SEC. All unproved volumes are estimated using SPE-PRMS 2018 guidelines which allow escalations to prices and costs, and as such, would be on a different basis than that prescribed by the SEC, and are therefore excluded from our SEC filings. Non-proved estimates are inherently more uncertain than proved.
Petroleum exploration well information
Well Location Target Formation age BHP equity Spud date Water depth Total well depth Status (as of August 7 2019)
LeClerc-1 Trinidad & Tobago Block 5 Oil Pliocene 65% (BHP Operator) 21 May 2016 1,800 m 5,771 m Hydrocarbons encountered; Plugged and abandoned LeClerc-ST1 Trinidad & Tobago Block 5 Oil Miocene 100% (BHP Operator) 6 July 2016 1,800 m 6,973 m Hydrocarbons encountered; Plugged and abandoned Wildling-1 US Gulf of Mexico GC520 Oil Miocene 100% (BHP Operator) 8 January 2017 1,230 m 5,950 m Plugged and abandoned due to mechanical failure Wildling-2 US Gulf of Mexico GC520 Oil Miocene 100% (BHP Operator) 15 April 2017 1,267 m 10,205 m Hydrocarbons encountered, temporarily abandoned Wildling-2 ST01 US Gulf of Mexico GC520 Oil Miocene 100% (BHP Operator) 11 August 2017 1,267 m 10,177 m Hydrocarbons encountered, temporarily abandoned Samurai-2 US Gulf of Mexico GC432 Oil Miocene 50% (Murphy Operator) 16 April 2018 1,088 m 9,777 m Hydrocarbons encountered; plugged and abandoned Samurai-2 ST01 US Gulf of Mexico GC476 Oil Miocene 50% (Murphy Operator) 25 August 2018 1,088 m 10,088 m Plugged and abandoned Victoria-1 Trinidad & Tobago Block TTDAA 5 Gas Pleistocene/Pliocene 65% (BHP Operator) 12 June 2018 1,828 m 3,282 m Hydrocarbons encountered; plugged and abandoned Bongos-1 Trinidad & Tobago Block TTDAA 14 Gas Pliocene/Miocene 70% (BHP Operator) 20 July 2018 1,909 m 2,469 m Plugged and abandoned due to mechanical failure Bongos-2 Trinidad & Tobago Block TTDAA 14 Gas Pliocene/Miocene 70% (BHP Operator) 22 July 2018 1,910 m 5,151 m Hydrocarbons encountered; plugged and abandoned Trion-2DEL Mexico Block AE-0093 Oil Eocene 60% (BHP Operator) 15 November 2018 2,379 m 4,659 m Hydrocarbons encountered; Plugged and abandoned Trion-2DEL ST01 Mexico Block AE-0093 Oil Eocene 60% (BHP Operator) 4 January 2019 2,379 m 5,002 m Hydrocarbons encountered; Plugged and abandoned Trion-3DEL Mexico Block AE-0093 Oil Eocene 60% (BHP Operator) 9 July 2019 2,595 m 4,614 m Hydrocarbons encountered, Plugged and abandoned
2C Contingent Resources additions in FY2018 as of 30 June 2018: Trion – 166 MMboe, LeClerc – 26 MMboe, Producing Assets – 86 MMboe
2C Contingent Resources additions in FY2019 as of 30 June 2019: Trion – 56 MMboe, Wildling – 68, Samurai – 19 MMboe, Bongos – 228, Victoria – 15 MMboe, Producing Assets – 26 MMboe
Financial results
20 August 2019 37

Footnotes
1. Slide 6: High potential injury frequency rate: injury events where there was the potential for a fatality.
2. Slide 6: Occupational Exposure Limits (OELs): as compared to FY18 reported exposures and discounting the protection afforded by respiratory protective equipment.
3. Slide 6: Greenhouse gas emissions: subject to final sustainability assurance review. Our target is, by FY22, to maintain operational (Scope 1 & 2) greenhouse gas emissions at or below FY17 levels. The FY17 baseline has been adjusted for the divestment of our Onshore US assets to ensure ongoing comparability of performance.
4. Slide 8: Adjusted effective tax rate: excludes the influence of exchange rate movements and exceptional items.
5. Slide 9: Productivity: outages: reflect reported outages from the December half year of US$0.8 billion; grade: relates to grade decline at Escondida of US$0.8 billion; coal unit costs and Nickel West mine plan: relates to higher than expected unit costs in Coal (lower volumes, wet weather, and higher strip ratio and contractor stripping costs) and Nickel West (mine plan changes) of US$0.4 billion.
6. Slide 9: Price: net of price-linked costs.
7. Slide 9: Controllable cash costs: reflects increased maintenance activities; costs related to unplanned production outages at WAIO, Olympic Dam, Nickel West and Spence in the first half; higher strip ratios and contractor stripping costs at our Australian coal operations; partially offset by favourable inventory movements and the benefit from higher overall volumes at Olympic Dam as a result of the smelter maintenance campaign in the prior year.
8. Slide 9: Non-cash: includes net deferred stripping costs.
9. Slide 9: Other: includes one-off items and other items (including profit/loss from equity accounted investments).
10. Slide 10: Segment EBITDA: percentage contribution to Group Underlying EBITDA, excluding Group and unallocated items.
11. Slide 10: Iron ore: unit cost, C1 unit cost excluding third party royalties, EBITDA margin and ROCE refer to Western Australia Iron Ore.
12. Slide 10: Petroleum: EBITDA margin includes closed mines. ROCE refers to Conventional Petroleum excludes closed mines.
13. Slide 10: WAIO C1 cost: excludes third party royalties, exploration expenses, depletion of production stripping, demurrage, exchange rate gains/losses, net inventory movements and other income.
14. Slide 10,18: Q4 FY19 run rate: excludes the impact from Tropical Cyclone Veronica.
15. Slide 12: Dividend: represents final dividend determined by the Board for FY18 and paid in September 2018, dividend determined by the Board for H1 FY19 and paid in March 2019.
16. Slide 12,29: NCIs: dividends paid to non-controlling interests of US$1.2 billion predominantly relate to Escondida.
17. Slide 13: Shareholder returns: dividends determined since FY16.
18. Slide 14: Antamina and Cerrejón: equity accounted investments; average capital employed represents BHP’s equity interest.
19. Slide 14: Conventional Petroleum exploration: ROCE truncated for illustrative purposes.
20. Slide 18: Ore Reserves increase by 654kt to 1,506kt contained nickel. Refer to slide seven for full Ore Reserves statement of tonnages, grades and confidence classification in the Think Nickel presentation delivered to the Diggers and Dealers conference on the 5th August 2019. https://www.bhp.com/-/media/documents/media/reports-and-presentations/2019/190804_diggersdealers2019.pdf
21. Slide 20: Exploration wells and success rate: refers to the number of wells completed at any time during the respective year, regardless of when drilling was initiated. A successful well is an exploratory or extension well that is not a dry well or met its appraisal objective. Successful wells include wells in which hydrocarbons were encountered and the drilling or completion of which, has been suspended pending further drilling. Excludes wells that had mechanical issues (Burrokeet-1 and Wildling-1 in FY17 and Bongos-1 in FY19) where the opportunities were tested by a subsequent well.
22. Slide 28: Represents potential reduction from FY18 in scope Global Function costs.
23. Slide 28: Represents safety incidents reduction in heavy vehicles.
24. Slide 29: Non-cash fair value movement: relates to foreign exchange variance due to the revaluation of local currency denominated cash and debt to USD and movements in interest rates.
25. Slide 29: Debt maturity profile: all debt balances are represented in notional USD values and based on financial years; as at 30 June 2019; subsidiary debt is presented in accordance with IFRS 10 and IFRS 11.
26. Slide 29: Debt maturity profile: includes hybrid bonds (27% of portfolio: 14% in USD, 9% in Euro, 4% in Sterling) with maturity shown at first call date.
27. Slide 31: As at 1 July 2019. PP&E: Excludes small decrease for change in classification of onerous lease provisions on implementation of IFRS 16. 28. Slide 31: Gearing as at 30 June 2019 15.1% (pre IFRS 16).
29. Slide 32: Below are tax consideration for Jansen Stage 1 project. Withholding tax on dividend payments under the current corporate structure is 5%.
- Royalties: 6% of mine gate revenue (revenue less port and rail costs)
- Federal and Provincial Corporate Income taxes: Combined top rate 27% (Carried forward losses from pre-production years can be utilised to decrease future taxable profits)
- Potash Production Tax (PPT), two components. Both components are calculated based on K2O tonnes. Thus potassium chloride (KCL) needs to be converted to potassium oxide (K2O), with a conversion rate of 0.6.
• A base payment levied at a rate of 35% on the producer’s annual resource profits, subject to minimum payment of CAD$11.00 and a maximum of CAD$12.33 per K2O tonne sold. New producers may qualify for a base payment holiday for the first 10 years of production.
• A profit tax imposed on the producer’s gross annual profit tax that is determined by rates, which increase with profits per tonne sold, as follows: 15% of the profit per tonne below CAD $67.36 and 35% of the profit per tonne above CAD $67.36 (tax brackets are indexed for inflation). Profit tax is assessed on a maximum of 35% of total tonnes sold, but producers may claim a base payment credit with respect to amount of tonnes that are subject to both the base payment and the profit tax. There are no tax holidays available for the profit tax.
30. Slide 36: EBITDA sensitivities: assumes total volume exposed to price; determined on the basis of BHP’s existing portfolio.
31. Slide 36: EBITDA sensitivities: excludes impact of equity accounted investments.
32. Slide 36: EBITDA sensitivities: excludes impact of change in input costs across the Group. 33. Slide 36: EBITDA sensitivities: based on average exchange rate for the period.
Financial results
20 August 2019 38

BHP

SIGNATURES

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