UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 20-F

☐ REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR 12(g) OF THE SECURITIES EXCHANGE ACT OF 1934

OR

☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED 30 JUNE 2018.

OR

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES AND EXCHANGE ACT OF 1934

☐ SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Date of event requiring this shell company report                     

For the transition period from                      to                     

Commission file number: 001-09526	Commission file number: 001-31714
BHP BILLITON LIMITED	BHP BILLITON PLC
(ABN 49 004 028 077)	(REG. NO. 3196209)
(Exact name of Registrant as specified in its charter)	(Exact name of Registrant as specified in its charter)
VICTORIA, AUSTRALIA	ENGLAND AND WALES
(Jurisdiction of incorporation or organisation)	(Jurisdiction of incorporation or organisation)
171 COLLINS STREET, MELBOURNE, VICTORIA 3000 AUSTRALIA (Address of principal executive offices)	NOVA SOUTH, 160 VICTORIA STREET LONDON, SW1E 5LB UNITED KINGDOM
	(Address of principal executive offices)

Securities registered or to be registered pursuant to section 12(b) of the Act.

Title of each class	Name of each exchange on which registered	Title of each class	Name of each exchange on which registered
American Depositary Shares*	New York Stock Exchange	American Depositary Shares*	New York Stock Exchange
Ordinary Shares**	New York Stock Exchange	Ordinary Shares, nominal value US$0.50 each**	New York Stock Exchange

* Evidenced by American Depositary Receipts. Each American Depositary Receipt represents two ordinary shares of BHP Billiton Limited or BHP Billiton Plc, as the case may be.

** Not for trading, but only in connection with the listing of the applicable American Depositary Shares.

Securities registered or to be registered pursuant to Section 12(g) of the Act.

None

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act.

None

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.

	BHP Billiton Limited	BHP Billiton Plc
Fully Paid Ordinary Shares	3,211,691,105	2,112,071,796

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ☒    No  ☐

If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.    Yes  ☐    No  ☒

Note – Checking the box above will not relieve any registrant required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 from their obligations under those Sections.

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ☒    No  ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ☐    No  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	☒	Accelerated filer	☐
Non-accelerated filer	☐	Emerging growth company	☐

If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards† provided pursuant to Section 13(a) of the Exchange Act.  ☐

Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:

U.S. GAAP  ☐ International Financial Reporting Standards as issued by the International Accounting
Standards Board  ☒ Other  ☐

If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow. Item 17  ☐    Item 18  ☐

If this is an annual report, indicate by checkmark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ☐    No  ☒

BHP

Our Charter

We are BHP,

a leading global resources company.

Our Purpose	Our Values
Our purpose is to create long-term shareholder value through the discovery, acquisition, development and marketing of natural resources. Our Strategy Our strategy is to own and operate large, long-life, tow-cost, expandable, upstream assets diversified by commodity, geography and market.	Sustainability Putting health and safety first, being environmentally responsible and supporting our communities.
	Integrity Doing what is right and doing what we say we will do.
	Respect Embracing openness, trust, teamwork, diversity and relationships that are mutually beneficial.
	Performance Achieving superior business results by stretching our capabilities.
	Simplicity Focusing our efforts on the things that matter most.
	Accountability Defining and accepting responsibility and delivering on our commitments.
	We are successful when:
	Our people start each day with a sense of purpose and end the day with a sense of accomplishment.
	Our teams are inclusive and diverse.
	Our communities, customers and suppliers value their relationships with us.
	Our asset portfolio is world-class and sustainably developed.
	Our operational discipline and financial strength enables our future growth.
	Our shareholders receive a superior return on their investment.
	Andrew Mackenzie Chief Executive Officer	May 2017

All references to websites in the Annual Report are intended to be inactive textual reference for information only and information contained in or accessible through any such website does not form a part of this Annual Report.

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BHP Billiton Limited. ABN 49 004 028 077. Registered in Australia. Registered office: 171 Collins Street, Melbourne, Victoria 3000, Australia. BHP Billiton Plc. Registration number 3196209. Registered in England and Wales. Registered office: Nova South, 160 Victoria Street London SW1E 5LB United Kingdom. Each of BHP Billiton Limited and BHP Billiton Plc is a member of the Group, which has its headquarters in Australia. BHP is a Dual Listed Company structure comprising BHP Billiton Limited and BHP Billiton Plc. The two entities continue to exist as separate companies but operate as a combined group known as BHP.

The headquarters of BHP Billiton Limited and the global headquarters of the combined Group are located in Melbourne, Australia. The headquarters of BHP Billiton Plc are located in London, United Kingdom. Both companies have identical Boards of Directors and are run by a unified management team. Throughout this publication, the Boards are referred to collectively as the Board. Shareholders in each company have equivalent economic and voting rights in the Group as a whole.

In this Annual Report, the terms ‘BHP’, ‘Group’, ‘BHP Group’, ‘our business’, ‘Company’, ‘organisation’, ‘we’, ‘us’, ‘our’ and ‘ourselves’ refer to BHP Billiton Limited, BHP Billiton Plc and, except where the context otherwise requires, their respective subsidiaries as defined in note 27 ‘Subsidiaries’ in section 5.1 of this Annual Report, unless stated otherwise. Those terms do not include non-operated assets. This Annual Report covers BHP’s assets (including those under exploration, projects in development or execution phases, sites and closed operations) that have been wholly owned and/or operated by BHP and assets that have been owned as a joint venture¹ operated by BHP (referred to in this Report as ‘assets’, ‘operated assets’ or ‘operations’) during the period from 1 July 2017 to 30 June 2018. Our Marketing and Supply business and our functions are also included.

BHP also holds interests in assets that are owned as a joint venture but not operated by BHP (referred to in this Annual Report as ‘non-operated joint ventures’ or ‘non-operated assets’). Notwithstanding that this Annual Report 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 stated otherwise.

¹  References in this Annual Report to a ‘joint venture’ are used for convenience to collectively describe assets that are not wholly owned by BHP. Such references are not intended to characterise the legal relationship between the owners of the asset.

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Contents

1	Strategic Report	1
1.1	Chairman’s Review	1
1.2	Chief Executive Officer’s Report	2
1.3	BHP at a glance: FY2018 performance summary	3
1.4	About BHP	5
1.5	Our performance	13
1.6	Our operating environment	20
1.7	People	49
1.8	Samarco	54
1.9	Sustainability	59
1.10	Our businesses	76
1.11	Summary of financial performance	100
1.12	Performance by commodity	126
1.13	Other information	146
2	Governance at BHP	148
2.1	Governance at BHP	148
2.2	Board of Directors and Executive Leadership Team	151
2.3	Shareholder engagement	160
2.4	Role and responsibilities of the Board	163
2.5	Board membership	166
2.6	Chairman	166
2.7	Renewal and re-election	167
2.8	Director skills, experience and attributes	167
2.9	Director induction, training and development	171
2.10	Independence	173
2.11	Board evaluation	175
2.12	Board meetings and attendance	177
2.13	Board committees	178
2.14	Risk management governance structure	197
2.15	Management	200
2.16	Our conduct	201
2.17	Market disclosure	202
2.18	Remuneration	202
2.19	Directors’ share ownership	202
2.20	Conformance with corporate governance standards	203
2.21	Additional UK disclosure	204
3	Remuneration Report	205
3.1	Annual statement by the Remuneration Committee Chairman	207
3.2	Remuneration policy report	211
3.3	Annual report on remuneration	224
4	Directors’ Report	252
4.1	Review of operations, principal activities and state of affairs	252
4.2	Share capital and buy-back programs	253
4.3	Results, financial instruments and going concern	254
4.4	Directors	254
4.5	Remuneration and share interests	255
4.6	Secretaries	256
4.7	Indemnities and insurance	256

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4.8	Employee policies	257
4.9	Corporate governance	257
4.10	Dividends	257
4.11	Auditors	257
4.12	Non-audit services	258
4.13	Political donations	258
4.14	Exploration, research and development	258
4.15	ASIC Instrument 2016/191	259
4.16	Proceedings on behalf of BHP Billiton Limited	259
4.17	Performance in relation to environmental regulation	259
4.18	Share capital, restrictions on transfer of shares and other additional information	259
5	Financial Statements	261
6	Additional information	262
6.1	Information on mining operations	263
6.2	Production	289
6.3	Reserves	293
6.4	Major projects	311
6.5	Legal proceedings	312
6.6	Glossary	318
7	Shareholder information	337
7.1	History and development	337
7.2	Markets	337
7.3	Organisational structure	337
7.4	Material contracts	340
7.5	Constitution	341
7.6	Share ownership	347
7.7	Dividends	351
7.8	Share price information	352
7.9	American Depositary Receipts fees and charges	354
7.10	Taxation	355
7.11	Government regulations	365
7.12	Ancillary information for our shareholders	369
8	Exhibits	374

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Forward looking statements

This Annual Report contains forward looking statements, including statements regarding trends in commodity prices and currency exchange rates; demand for commodities; production forecasts; plans, strategies and objectives of management; closure or divestment of certain assets, operations or facilities (including associated costs); anticipated production or construction commencement dates; capital costs and scheduling; operating costs; anticipated productive lives of projects, mines and facilities; provisions and contingent liabilities; and tax and regulatory developments.

Forward looking statements may be identified by the use of terminology including, but not limited to, ‘intend’, ‘aim’, ‘project’, ‘anticipate’, ‘estimate’, ‘plan’, ‘believe’, ‘expect’, ‘may’, ‘should’, ‘will’, ‘continue’ or similar words. These statements discuss future expectations concerning the results of assets or financial conditions, or provide other forward looking information.

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 Annual Report. Readers are cautioned not to put undue reliance on forward looking statements.

For example, our future revenues from our assets, projects or mines described in this Annual Report will be based, in part, on the market price of the minerals, metals or petroleum products 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 assets.

Other factors that may affect the actual construction or production commencement dates, costs or production output and anticipated lives of assets, 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 the countries where we are exploring or developing 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 set out in section 1.6.4 of this Annual Report.

Except as required by applicable regulations or by law, BHP does not undertake 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.

Agreements for sale of Onshore US

On 27 July 2018, BHP announced it had entered into agreements for the sale of its entire interests in the Eagle Ford, Haynesville, Permian and Fayetteville Onshore US oil and gas assets for a combined base consideration of US$10.8 billion, payable in cash. BP America Production Company, a wholly owned subsidiary of BP Plc, has agreed to acquire 100% of the issued share capital of Petrohawk Energy Corporation, the BHP subsidiary which holds the Eagle Ford, Haynesville and Permian assets, for a consideration of US$10.5 billion (less customary completion adjustments). MMGJ Hugoton III, LLC, a company owned by Merit Energy Company, has agreed to acquire 100% of the issued share capital of BHP Billiton Petroleum (Arkansas) Inc. and 100% of the membership interests in BHP Billiton Petroleum (Fayetteville) LLC, which hold the Fayetteville assets, for a total consideration of US$0.3 billion (less customary completion adjustments). Both sales are subject to the satisfaction of customary regulatory approvals and conditions precedent.

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For IFRS accounting purposes, Onshore US is treated as Discontinued operations in BHP’s Financial Statements. Unless otherwise stated, information in section 5 of this Annual Report has been presented on a Continuing operations basis to exclude the contribution from Onshore US assets. Details of the contribution of Onshore US assets to the Group’s results are disclosed in note 26 ‘Discontinued operations’ in section 5. All other information in this Annual Report relating to the Group has been presented on a Continuing and Discontinued operations basis to include the contribution from Onshore US assets, unless otherwise stated.

Unless otherwise stated, comparative financial information for FY2017, FY2016, FY2015 and FY2014 has been restated to reflect the announcement of the sale of the Onshore US assets on 27 July 2018 and the demerger of South32 in FY2015, as required by IFRS 5/AASB 5 ‘Non-current Assets Held for Sale and Discontinued Operations’. Consolidated Balance Sheet information for these periods has not been restated as accounting standards do not require it.

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Form 20-F Cross Reference Table

Item Number	Description	Report section reference
1.	Identity of Directors, Senior Management and Advisors	Not applicable
2.	Offer Statistics and Expected Timetable	Not applicable
3.	Key Information
A	Selected financial data	1.11
B	Capitalization and indebtedness	Not applicable
C	Reasons for the offer and use of proceeds	Not applicable
D	Risk factors	1.6.4
4.	Information on the Company
A	History and development of the company	1.3, 1.11, 1.12, 6.4, 6.5, 7.1 to 7.4 and 7.12
B	Business overview	1.3 to 1.4.1, 1.6, 1.10 to 1.12, 7.3, 7.4, 7.12
C	Organizational structure	7.3 and Note 27 to the Financial Statements
D	Property, plant and equipment	1.10.1 to 1.10.3, 1.12, 6.1 to 6.3 and Note 10 to the Financial Statements
4A.	Unresolved Staff Comments	None
5.	Operating and Financial Review and Prospects
A	Operating results	1.5, 1.6, 1.11 to 1.12, 7.12
B	Liquidity and capital resources	1.11.3, 5.1.4 and Note 20 and 31 to the Financial Statements
C	Research and development, patents and licenses, etc.	1.4.1, 1.6.3, 1.10, 1.11, 4.14 and 6.3
D	Trend information	1.6.1, 1.10.1 to 1.10.3, 1.12
E	Off-balance sheet arrangements	1.13 and Notes 31 and 32 to the Financial Statements
F	Tabular disclosure of contractual obligations	1.13 and Notes 31 and 32 to the Financial Statements
6.	Directors, Senior Management and Employees
A	Directors and senior management	2.2
B	Compensation	3
C	Board practices	2.2 and 2.13
D	Employees	1.7
E	Share ownership	2.19, 3.3.18, 3.3.19 and Note 22 to the Financial Statements
7.	Major Shareholders and Related Party Transactions
A	Major shareholders	7.6
B	Related party transactions	Notes 22 and 30 to the Financial Statements
C	Interests of experts and counsel	Not applicable
8.	Financial Information
A	Consolidated statements and other financial information	1.8, 5.1, 5.6, 6.5, 7.7 and the pages beginning on F-1 in this Annual Report
B	Significant changes	Note 33 to the Financial Statements
9.	The Offer and Listing
A	Offer and listing details	7.8
B	Plan of distribution	Not applicable
C	Markets	7.2

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Item Number	Description	Report section reference
D	Selling shareholders	Not applicable
E	Dilution	Not applicable
F	Expenses of the issue	Not applicable
10.	Additional Information
A	Share capital	Not applicable
B	Memorandum and articles of association	7.3 and 7.5
C	Material contracts	7.4
D	Exchange controls	7.11
E	Taxation	7.10
F	Dividends and paying agents	Not applicable
G	Statement by experts	Not applicable
H	Documents on display	7.5
I	Subsidiary information	Note 27 to the Financial Statements
11.	Quantitative and Qualitative Disclosures About Market Risk	1.6, Note 20 to the Financial Statements
12.	Description of Securities Other than Equity Securities
A	Debt securities	Not applicable
B	Warrants and rights	Not applicable
C	Other securities	Not applicable
D	American Depositary Shares	7.9
13.	Defaults, Dividend arrearages and Delinquencies	There have been no defaults, dividend arrearages or delinquencies
14.	Material Modifications to the Rights of Security Holders and Use of Proceeds	There have been no material modifications to the rights of security holders and use of proceeds since our last Annual Report
15.	Controls and Procedures	2.13.1 and 5.6
16A.	Audit committee financial expert	2.8, 2.13.1
16B.	Code of Ethics	2.16
16C.	Principal Accountant Fees and Services	2.13.1 and Note 35 to the Financial Statements
16D.	Exemptions from the Listing Standards for Audit Committees	Not applicable
16E.	Purchases of Equity Securities by the Issuer and Affiliated Purchasers	4.2
16F.	Change in Registrant’s Certifying Accountant	Not applicable
16G.	Corporate Governance	2
16H.	Mine Safety Disclosure	Not applicable
17.	Financial Statements	Not applicable as Item 18 complied with
18.	Financial Statements	The pages beginning on page F-1 in this Annual Report
19.	Exhibits	8

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1    Strategic Report

About this Strategic Report

This Strategic Report in section 1 provides insight into BHP’s strategy, operating and business model, and objectives. It describes the principal risks BHP faces and how these risks might affect our future prospects. It also gives our perspective on our recent operational and financial performance.

This disclosure is intended to assist shareholders and other stakeholders to understand and interpret the Consolidated Financial Statements prepared in accordance with International Financial Reporting Standards (IFRS) included in this Annual Report. The basis of preparation of the Consolidated Financial Statements is set out in section 5.1. We also use alternative performance measures to explain our underlying performance; however, these measures should not be considered as an indication of, or as a substitute for, statutory measures as an indicator of actual operating performance or as a substitute for cash flow as a measure of liquidity. To obtain full details of the financial and operational performance of BHP, this Strategic Report should be read in conjunction with the Consolidated Financial Statements and accompanying notes. Underlying EBITDA is the key measure that management uses internally to assess the performance of the Group’s segments and make decisions on the allocation of resources. Unless otherwise stated, data in section 1 is presented on a Continuing operations and Discontinued operations basis.

This Strategic Report in section 1 meets the requirements of the UK Companies Act 2006 and the Operating and Financial Review required by the Australian Corporations Act 2001.

References to sections of the Annual Report beyond section 1 are references to other sections in this Annual Report 2018. Shareholders may obtain a hard copy of the Annual Report free of charge by contacting our Share Registrars, whose details are set out in our Corporate Directory on the inside back cover of this Annual Report.

1.1    Chairman’s Review

Dear Shareholder,

I am pleased to provide this Annual Report of your Company’s performance in FY2018.

This year, we have further simplified and strengthened BHP, enhanced our Capital Allocation Framework, sharpened our focus on culture and productivity and delivered a solid set of financial results. This has enabled us to announce a record final dividend of 63 US cents per share.

We have also invested in the future. Earlier this year, your Board approved US$2.9 billion in capital expenditure for the South Flank iron ore project in Western Australia, following a thorough evaluation against our Capital Allocation Framework. South Flank offers attractive returns for shareholders and will enhance the average quality grade of BHP’s Western Australia Iron Ore production.

To further strengthen our portfolio, we undertook a robust and competitive sales process for our Onshore US assets in FY2018. We anticipate completing the sale of these assets by the end of October, for US$10.8 billion. We understand that cash returns are important to shareholders, and we expect to return the net proceeds from these transactions to shareholders.

Throughout this first year as Chairman of BHP, I have visited a number of our assets around the world. Wherever I have travelled, I have been struck by the commitment of our people to Our Charter values and their dedication to this great company.

Our people are the backbone of BHP and their safety is of paramount importance. So it is with deep sadness that we report the deaths of two of our colleagues at work in FY2018. We achieve nothing if it is not done safely and in the wake of these tragedies, we have redoubled efforts to protect the health and safety of everyone who works at BHP.

1

Throughout FY2018, I have also met with many of our shareholders and stakeholders. I recently concluded my second global investor roadshow, where discussions centred on five key priorities for BHP – safety, our portfolio, capital discipline, capability and culture, and our social licence. Our unrelenting focus on these key areas is fundamental to our efforts to create value for our shareholders, and to continue to make a difference.

I will provide an update on our progress against these themes at our Annual General Meetings in London and Adelaide, later in the calendar year.

Your Board takes a structured and rigorous approach to succession planning. We consider Board size, tenure and the skills, experience and attributes required to effectively govern and manage risk within BHP to ensure we have the right balance between experience and fresh perspectives. We also take account of the rapidly changing external environment and BHP’s circumstances.

I would like to take this opportunity to acknowledge the significant contribution Wayne Murdy has made to the Board of BHP over the last nine years. Wayne recently advised that he will not stand for re-election at the 2018 Annual General Meetings. On behalf of all of his colleagues on the Board, I would like to thank Wayne for his valuable contribution, friendship and wise counsel, and I wish him all the best for the future.

While we remain cautious about the short-term market outlook, our long-term view remains positive and we are well placed to meet demand for commodities that the world needs well into the future.

I am confident that BHP, led by Andrew Mackenzie and his management team, has the right assets and capability, and your Company is well placed to continue delivering shareholder value and returns.

Thank you for your continued support of BHP.

Ken MacKenzie

Chairman

1.2    Chief Executive Officer’s Report

Dear Shareholder,

BHP has been on a deliberate path to maximise cash flow, maintain capital discipline and increase value and returns to our shareholders. In FY2018, solid operating performance, combined with high commodity prices, saw us achieve a strong set of results.

The safety, health and wellbeing of our people is our number one priority. Tragically, this year two of our colleagues died at work – Daniel Springer at Goonyella Riverside in August 2017 and a colleague at our Permian Basin operations last November. It is vital we learn as much as we can from these tragedies. This year, leaders across BHP held safety engagements with all employees and contractors. We will build on these to share the lessons with as many people as possible.

We also had an increase in our total recordable injury frequency performance to 4.4 per million hours worked. While the increase was modest, I am encouraged that our safety initiatives have helped reduce, by eight per cent, the number of events with the potential to cause a fatality. It is an important leading indicator of future safety performance.

Our commitment to health and safety is an important part of Our Charter value of Sustainability. So too is our commitment to responsible environmental stewardship.

2

This year, BHP released its inaugural Water Report. This is the first step in our long-term plan to disclose more effectively our water use and performance as we strengthen water management and governance across our assets. Increased pressure on water resources throughout the world means we must do more to responsibly meet water needs today and safeguard water supplies for future generations.

We also disclose our performance across a range of other safety, environmental, and community metrics in our Sustainability Report, which reinforces our commitment to transparency and accountability.

Overall, BHP is in very good shape. In FY2018, underlying attributable profit was up 33 per cent to US$8.9 billion. We delivered an eight per cent increase in annual production compared to FY2017 and achieved record output at Western Australia Iron Ore, Queensland Coal and at our Spence copper mine in Chile.

For the second consecutive year, we generated over US$12 billion of free cash flow. Consistent with our strict Capital Allocation Framework, this strong cash generation gives us flexibility in how we balance debt reduction, investment in projects and cash returns to shareholders.

This year, we returned US$6.3 billion to shareholders and announced our highest ever final dividend of 63 US cents per share. We also announced the sale of our Onshore US assets for US$10.8 billion.

Our diversified portfolio of tier one assets and, importantly, our team of talented people made these returns possible. Success is not just about the right portfolio. It’s how we operate our business that makes the difference.

BHP has a highly capable team who have made our work methods fit-for-purpose, embraced the business case for diversity and better connected our workforce.

The combination of our people, strategy and assets will build momentum into 2019 and beyond, and is key to our future success.

Finally, thank you to our people, shareholders, suppliers, customers and host communities. We are truly committed to build shared value, and without you this would not be possible.

Andrew Mackenzie

Chief Executive Officer

1.3    BHP at a glance: FY2018 performance summary

Not required for US reporting. Refer to sections 1.11 and 1.12.

3

1.3    BHP at a glance: What we do

For more information about our economic contributions, download our Economic Contribution Report from bhp.com.

For more information about our sustainability goals and performance, download our Sustainability Report from bhp.com.

⁽¹⁾  All figures include data for Continuing and Discontinued operations.

4

1.4    About BHP

1.4.1    Our strategy

Our strategy is to own and operate large, long-life, low-cost, expandable, upstream assets diversified by commodity, geography and market.

Consistent with this strategy, our plan to create long-term value is focused on six key areas:

Cost efficiencies: Focused on further gains

Since 2012, our annualised productivity gains exceed US$12 billion. The combination of our simplified portfolio, streamlined systems, large scale and connected workforce ensures we are well positioned to deliver approximately US$1 billion in additional productivity gains by the end of FY2019, with strong momentum carried into FY2020.

Technology: Improves safety, costs and unlocks resource

We will continue to integrate and automate our value chain to unlock resource and drive a step change in safety, volume and cost. We have accelerated high-value initiatives across mine autonomy, decision automation and precision mining. We have proving grounds to de-risk and trial technology solutions in real conditions.

Our diverse portfolio allows us to adapt technology developed for one commodity to other areas of the business. For example, our integrated remote operations centres were first deployed in Western Australia Iron Ore, providing an advanced control room that allows us to optimise our production supply chain. The same approach has now been established (or is in the process of being established) at our other operated Minerals assets, such as coal and copper.

Latent capacity: Attractive returns, limited risk

Our latent capacity options are about unlocking untapped production with minimal risk. We have replenished our suite of latent capacity opportunities to optimise and debottleneck our existing mine, rig, port, rail and processing facilities. That means we can achieve more production, or replace production from our existing infrastructure, for lower cost.

The Caval Ridge Southern Circuit (CRSC) project in Central Queensland’s Bowen Basin is a good example of a latent capacity project that is starting to take shape. The CRSC will effectively link the Peak Downs Mine to the coal handling preparation plant at the neighbouring Caval Ridge mine with a new conveyor system, and in doing so, take advantage of unutilised capacity at the prep plant. The plant uses the latest coal processing technology to run very efficiently, and by linking the plant to the mining fleet at Peak Downs, will enable the business to maximise the effectiveness of both operations. We’re able to do this with minimal risk as we are able to draw on our knowledge of other BHP assets in designing and building the conveyor system.

Future options: Worked for value, timed for returns

We have a pipeline of potential growth projects that could create significant shareholder value over the long term, in particular in conventional oil, copper and coal. This includes the Mad Dog Phase 2 project, which has the potential to produce up to 140,000 gross barrels of crude oil per day, and the Spence Growth Option. In the first 10 years of operation, incremental production from the Spence Growth Option is expected to be approximately 185 kilotonnes per annum (ktpa) of payable copper in concentrate and 4 ktpa of payable molybdenum, with first production scheduled for FY2021.

Exploration: Focused on petroleum and copper

We are focused on finding new oil and copper deposits through targeted exploration. Production of these commodities is declining, while demand is forecast to increase.

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In Petroleum, we have made discoveries in four out of the six prospects tested over the past two years, across two key basins. We have also secured more than 100 highly prospective blocks in the Gulf of Mexico, and acquired the Trion discovered resource in Mexico after a competitive process.

Onshore US: Exit to maximise value and returns

On 27 July 2018, we announced that we had entered into agreements for the sale of our entire interest in the Eagle Ford, Haynesville, Permian and Fayetteville Onshore US oil and gas assets for a combined consideration of US$10.8 billion payable in cash (less customary completion adjustments). Both sales are subject to the satisfaction of customary regulatory approvals and conditions precedent. We expect completion of both transactions to occur by the end of October 2018. The effective date at which the right to economic profits transfers to the purchasers is 1 July 2018.

1.4.2    Our Operating Model

Our Operating Model

⁽¹⁾  On 27 July 2018, we announced that we had entered into agreements for the sale of our entire interest in the Eagle Ford, Haynesville, Permian and Fayetteville Onshore US oil and gas assets.

We have a simple and diverse portfolio of tier one assets around the world, with low-cost options for future growth and value creation.

Our assets are high quality, largely located in low-risk locations and have strong development potential.

In addition to having the right assets in the right commodities, we also create value through how we operate our assets.

Our Operating Model allows us to leverage integrated systems and technology, replicate expertise and apply high standards of governance and transparency.

Our Operating Model includes:

Assets: Assets are a set of one or more geographically proximate operations (including open-cut mines, underground mines and onshore and offshore oil and gas production and processing facilities). We produce a broad range of commodities through these assets. Our operated assets include assets that are wholly owned and operated by BHP and assets that are owned as a joint venture and operated by BHP. BHP also holds interests in assets that are owned as a joint venture but are not operated by BHP.

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Asset groups: We group our assets into geographic regions in order to provide effective governance and accelerate performance improvement. We do this through sharing and replicating best practice, combining efforts to take advantage of our scale and through common improvement initiatives. Our oil and gas assets are grouped together as one global Petroleum asset group, reflecting the operating environment in that sector. This allows us to share best practice and promote new technology across our portfolio.

Marketing and Supply: Our commercial businesses are responsible for optimising our working capital and managing our inward and outward supply chains. Our Marketing business sells our products, gets our commodities to market and supports strategic decision-making through market insights. Supply’s role is to source the goods and services we need for our business, sustainably and cost effectively.

Functions: Functions operate along global reporting lines to provide support to all areas of the organisation. Functions have specific accountabilities and deep expertise in areas such as finance, legal, governance, technology, human resources, corporate affairs, health, safety and community.

Leadership: Our Executive Leadership Team (ELT) is responsible for the day-to-day management of the Group and for leading the delivery of our strategic objectives.

We disclose financial and other performance primarily by commodity. This provides the most meaningful insight into the nature and financial outcomes of our business activities and facilitates greater comparability against industry peers.

1.4.3    Managing performance and risk

Corporate strategy and planning

Our corporate planning process is designed to deliver our strategic objective, which is to position BHP to leverage our values, capabilities and competitive resources to meet the evolving needs of markets and to create sustainable long-term value.

To achieve this, we aspire to have the best capabilities in the natural resources industry and apply these capabilities to a portfolio of world-class assets in the most attractive commodities.

Informed by our strategy, our annual corporate planning process is fundamental to creating alignment across BHP; it guides the development of plans, targets and budgets to help us decide where to deploy our capital and resources.

Plans are assessed at the Group level to balance the goal of maximising the value of our individual assets with the goal of creating value and mitigating investment risks at the portfolio level. We evaluate the range of investment opportunities and aim to optimise the portfolio based on our assessment of risk and returns. We then develop a long-term capital plan and guidance for the Group.

Assessment and monitoring

We review our strategy and portfolio against a constantly changing external environment to capture and manage emerging opportunities and risks. Our strategy is cascaded through our planning processes. Long-term scenario planning is used to evaluate our preferred commodities and portfolio of assets, to help us identify new opportunities and to test the robustness of our strategy over a range of possible outcomes. We also use signals tracking to monitor near-term trends and events. Signals also support actions to position BHP to benefit from potential new opportunities and to mitigate risks, while helping to inform major portfolio investment decisions.

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Risk management

Identifying and managing risk and opportunity are central to achieving our strategy and creating long-term value.

We embed risk management in the critical business activities, functions, processes and systems of our assets through the following mechanisms:

• Risk assessments – we regularly identify and assess known, new and emerging risks.

• Risk controls – we put controls in place over material risks and periodically assess the effectiveness of those controls.

• Risk materiality and tolerability evaluation – we assess the materiality of a risk based on the degree of financial and non-financial impacts, including health, safety, environmental, community, reputational and legal impacts. We assess the tolerability of a risk based on a combination of residual risk and control effectiveness.

We apply established processes when entering or commencing new activities in high-risk countries. These include risk assessments and supporting risk management plans to ensure potential reputational, legal, business conduct and corruption-related exposures are managed and legislative compliance is maintained.

For information on our principal risks, refer to section 1.6.4. For information on our risk management governance, refer to sections 2.13.1 and 2.14.

Capital discipline

Our Capital Allocation Framework is the framework by which we assess decisions relating to the most efficient deployment of capital.

We put capital to work to:

• maintain our plant and equipment to support safe and efficient operations over the long term;

• keep our balance sheet strong, to give us stability and flexibility through the cycle;

• reward our shareholders by paying out at least 50 per cent of our Underlying attributable profit in dividends.

We then look at what would be the most valuable risk-adjusted use for any excess capital that remains after these three priorities are met, and decide whether to:

• further reduce our debt;

• return more cash to shareholders through additional dividends or share buy-backs;

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• invest in growth, either through projects within our asset portfolio or through exploration or acquisitions, provided the investment will create more value on a risk-adjusted reward basis than a share buy-back.

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Case study:

South Flank: Creating sustainable value

The Board’s approval of the South Flank project in the central Pilbara, Western Australia was the culmination of a three-year project assessment that involved experts from across our business.

The US$3.06 billion South Flank project was assessed by reference to our Capital Allocation Framework. The decision also took into account environmental, health and safety, water, Indigenous and community considerations.

The project is expected to produce high-quality iron ore for more than 25 years, starting in CY2021. Our view is that population growth and increasing development in emerging economies will continue to drive demand for steel over that period, with infrastructure for renewable energy a key factor in future commodity growth. South Flank’s high-quality ore will be in particular demand as it requires less processing, produces steel of more reliable quality, and produces less pollution.

Throughout the project design and assessment, BHP’s thinking was informed by our commitment to delivering sustainable value to all our stakeholders. As always, safety and productivity were prioritised. The design team used innovative 3D design tools that enable designers to spot potential clashes, bottlenecks or safety issues more readily than with traditional paper-based designs.

The mine design has engineered out over 400 potential causes of significant safety events, meaning a safer workplace for the estimated 2,500 construction and 600 ongoing operational jobs that will be created. Barriers such as requirements for physical strength and extensive manual handling have been eliminated to support the hiring of a diverse workforce.

The mine design also makes the most of new technology, including a conveyor that will generate its own power as it carries ore to be processed. Autonomous drills and trucks will improve both safety and productivity.

Environmental and community considerations were also important inputs into the project design. Dumps and roads were moved to minimise the impact on ghost bats and invertebrate fauna. The project team worked in consultation with the Banjima People, the traditional owners of the land, to identify sensitive environmental and ethnographic and cultural sites. This engagement is ongoing, and the mine design will be reassessed to minimise impact on culturally significant sites.

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1.4.4    Our locations

BHP locations (includes non-operated)

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⁽¹⁾  Non-operated joint venture.

⁽²⁾  On 27 July 2018, we announced that we had entered into agreements for the sale of our entire interest in the Eagle Ford, Haynesville, Permian and Fayetteville Onshore US oil US and gas assets.

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1.5    Our performance

Key performance indicators

Our key performance indicators (KPIs) enable us to measure our sustainable development and financial performance. These KPIs are used to assess performance of our people throughout the Group. For information on our approach to performance and reward, refer to section 1.7. For information on our overall approach to executive remuneration, including remuneration policies and remuneration outcomes, refer to section 3.

Following BHP’s sale of the Onshore US assets announced on 27 July 2018, the contribution of these assets to the Group’s results is presented in this Annual Report as Discontinued operations and related assets and liabilities reclassified to held for sale unless otherwise stated. For more information on the accounting treatment, refer to section 5. To enable more meaningful comparisons with prior year disclosures, and in some cases to comply with applicable statutory requirements, the data in section 1.5 has been presented to include Onshore US, except for Underlying EBITDA. Footnotes to tables and infographics indicate whether data presented in this section 1.5 is inclusive or exclusive of Onshore US.

1.5.1    Financial KPIs

Financial KPIs

⁽¹⁾  Includes data for Continuing and Discontinued operations for the financial years being reported.

⁽²⁾  Excludes data from Discontinued operations for financial years being reported.

⁽³⁾  For more information on alternative performance measures, refer to section 1.11.4.

In FY2018, higher prices and a strong operating performance generated strong cash flow, enabling us to reduce net debt and increase our dividends.

Profit and earnings

Attributable profit of US$3.7 billion in FY2018 includes an exceptional loss of US$5.2 billion (after tax), compared to an attributable profit of US$5.9 billion, including an exceptional loss of US$842 million (after tax), in the prior period. The FY2018 exceptional loss is related to the impairment of Onshore US assets, US tax reform and the Samarco dam failure.

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Our Underlying attributable profit was US$8.9 billion (FY2017: US$6.7 billion).

We reported Underlying EBITDA of US$23.2 billion (FY2017: US$19.4 billion), with higher prices, increased volumes and one-off items (in total US$5.6 billion) more than offsetting the impacts of higher costs, unfavourable exchange rate movements, inflation and other net movements (in total US$1.8 billion).

Cash flow and balance sheet

Our Net operating cash flow of US$18.5 billion in FY2018 reflects higher commodity prices and a strong operating performance during the year.

Our balance sheet was strong, with net debt at US$10.9 billion at FY2018 year-end (FY2017: US$16.3 billion; FY2016: US$26.1 billion), a reduction of more than US$15 billion over two years. The reduction of US$5.4 billion in FY2018 reflects strong free cash generation as well as a favourable non-cash fair value adjustment of US$108 million related to interest rate and exchange rate movements, partially offset by dividends to shareholders of US$5.2 billion and dividends paid to non-controlling interests of US$1.6 billion.

Our gearing ratio in FY2018 was 15.3 per cent (FY2017: 20.6 per cent).

Capital management

Net operating cash flows of US$18.5 billion in FY2018 reflect higher commodity prices and a strong operating performance during the year, with free cash flow⁽¹⁾⁽³⁾ of US$12.5 billion. This is the second consecutive year of free cash flow above US$12 billion.

Our dividend policy provides for a minimum 50 per cent payout of Underlying attributable profit at every reporting period. The minimum dividend payment for the second half was 46 US cents per share. Recognising the importance of cash returns to shareholders, the Board determined to pay an additional amount of 17 US cents per share, taking the final dividend to 63 US cents per share which is covered by free cash flow generated in FY2018. In total, dividends of US$6.3 billion (118 US cents per share, an increase of 42 per cent from FY2017) have been determined for FY2018, including additional amounts of US$1.8 billion above the minimum payout ratio.

Capital and exploration expenditure increased by 29 per cent to US$6.8 billion in FY2018 in line with guidance, reflecting continued investment in high-return latent capacity projects, increased Onshore US drilling activity and an increase post the approval of Mad Dog Phase 2 and the Spence Growth Option in FY2017. Capital and exploration expenditure guidance is unchanged at below US$8 billion per annum for FY2019 and FY2020, subject to exchange rate movements.

Productivity

Strong operating performance at Escondida and Western Australia Iron Ore (WAIO) underpinned a US$374 million productivity gain in the second half of FY2018, bringing the total financial year movement to negative US$96 million. Productivity gains of approximately US$1 billion are now expected for FY2019 with strong momentum carried into FY2020.

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This lower guidance (from the previous guidance of US$2 billion over the two years to the end of FY2019) reflects the announced divestments of Onshore US and Cerro Colorado, being a reduction of US$200 million. In addition, modified assumptions in respect of the pace of productivity uplift over the two-year period at Queensland Coal have resulted in a reduction of approximately US$700 million following the challenging operating conditions at the Broadmeadow and Blackwater mines during FY2018. WAIO unit costs decreased by two per cent to $14.26 per tonne despite the impact of a stronger Australian dollar. Conventional petroleum, Escondida and Queensland Coal unit costs increased by 16 per cent, 15 per cent and 14 per cent, respectively. WAIO unit costs declined due to reductions in labour and a three per cent increase in production as a result of improved productivity and stability across the supply chain. Conventional petroleum unit costs were higher due to lower volumes as a result of the impact of Hurricanes Harvey and Nate on US Petroleum assets and natural field decline. Escondida unit costs increased due to a change in estimated recoverable copper contained in the Escondida sulphide leach pad which benefited costs in the prior period. Queensland Coal unit costs were higher, driven by unfavourable fixed cost dilution from reduced volumes at Broadmeadow and Blackwater mines and additional contractor stripping fleet costs and debottlenecking activities.

Reconciling our financial results to our key performance indicators

⁽¹⁾  Includes US$2,859 million exceptional items related to Onshore US assets. Refer to note 26 ‘Discontinued operations’ in section 5.

⁽²⁾  Includes US$(601) million exceptional items related to Onshore US assets. Refer to note 26 ‘Discontinued operations’ in section 5.

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1.5.2    Non-financial KPIs

Capital management KPIs		Sustainability KPIs
Total shareholder return (TSR) shows the total return to the shareholder during the financial year. It combines both movements in share prices and dividends paid (which are assumed to be reinvested). During FY2018, TSR increased as a result of both the BHP share price and dividends paid, resulting in a 45.6 percentage change from FY2017. From 1 July 2013 to 30 June 2018, BHP underperformed the sector peer group by 18.9 per cent and underperformed the Index TSR by 76.9 per cent. For more information on our approach to capital discipline, refer to section 1.4.3.	Credit ratings are forward-looking opinions on credit risk. Standard & Poor’s and Moody’s credit ratings express the opinion of each agency on the ability and willingness of BHP to meet its financial obligations in full and on time. Standard & Poor’s credit rating of BHP remained at the A level throughout FY2018. It affirmed this rating on 21 November 2017. Moody’s maintained its credit rating of BHP at A3 with a positive outlook throughout FY2018. For more information on liquidity and capital resources, refer to section 1.11.3.	Total recordable injury frequency (TRIF) performance increased by five per cent in FY2018 to 4.4 per million hours worked, compared to 4.2 in FY2017. This was due to an increase in low severity sprain and strain type injuries in Minerals Australia, which occurred primarily in Western Australia Iron Ore and Olympic Dam. These events were not injuries that had fatal or serious injury potential. There were two fatalities at our operated assets in FY2018.

⁽¹⁾  Total recordable injury frequency (TRIF) is an indicator in highlighting broad personal injury trends and is calculated based on the number of recordable injuries per million hours worked. TRIF includes work-related events occurring outside our operated assets from FY2015. In FY2015, we expanded our definition of work-related activities to include events that occur outside our operated assets where we have established the work to be performed and can set and verify the health and safety standards: such as an employee driving in a BHP vehicle between two sites for work. TRIF does not include events at non-operated joint ventures. TRIF includes data for Continuing and Discontinued operations for the financial years being reported.

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Sustainability KPIs

This year we are also reporting on the rate of high potential injuries, which are injury events where there was the potential for a fatality. We are currently able to report data for the last three financial years. High potential injury trends remain a primary focus to assess progress against our most important safety objective: to eliminate fatalities. High potential injuries declined by eight per cent from FY2017 due to a significant reduction in high potential injuries in western Australia Iron Ore and further improvement in Petroleum. For information on our approach to health and safety, and our performance, refer to section 1.9.2 and 1.9.3.	In FY2018, we began working towards a new five-year greenhouse gas (GHG) emissions reduction target. Our new target, which took effect from 1 July 2017, is to maintain our total operational emissions in FY2022 at or below FY2017 levels while we continue to grow our business(3). Our new target builds on our success in achieving our previous five-year target. Our operational emissions (Scopes 1 and 2 combined)(4) in FY2018 totalled 16.5 million tonnes of carbon dioxide equivalent (CO2-e). This is a 1 per cent increase compared to the FY2017 baseline and is primarily due to an increase in Scope 2 emissions from our Minerals Americas business as a result of increased production at our Escondida and Pampa Norte copper assets in Chile, as well as the commissioning of the new Escondida desalination plant(5) For more information on our GHG emissions, refer to section 1.9.8.	Our target is to invest not less than one per cent of our pre-tax profit(6) to contribute to improved quality of life in host communities and support achievement of the United Nations Sustainable Development Goals. Our social investment performance in FY2018 saw BHP deliver projects with a continued focus on good governance, human capability and social inclusion and environment. The total investment of US$77.05 million includes US$7.16 million on community contributions at our non-operated joint ventures and US$1.54 million to facilitate the operation of the BHP Billiton Foundation. For information on our voluntary social investment, refer to section 1.9.5.

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⁽¹⁾  High potential injuries (HPI) are recordable injuries and first aid cases where there was the potential for a fatality. HPI includes data for Continuing and Discontinued operations for the financial years being reported.

⁽²⁾  Scope 1 and 2 emissions have been calculated on an operational control basis in accordance with the GHG Protocol Corporate Accounting and Reporting Standard. Includes data for Continuing and Discontinued operations for the financial years being reported. Comparisons of data over the period shown should note the demerger of South32 during FY2015 (data from FY2015 onwards excludes emissions from assets that were demerged with South32 from the date of completion of the demerger (25 May 2015)).

⁽³⁾  FY2017 is the base year for our current five-year GHG emissions reduction target, which took effect from FY2018. The FY2017 baseline will be adjusted for any material acquisitions and divestments based on GHG emissions at the time of the transaction; carbon offsets will be used as required. Note that FY2017 was also the final year of our previous five-year target (which we achieved), which was to keep our absolute emissions below an FY2006 baseline (adjusted for material acquisitions and divestments).

⁽⁴⁾  Scope 1 refers to direct GHG emissions from operated assets. Scope 2 refers to indirect GHG emissions from the generation of purchased electricity and steam that is consumed by operated assets (calculated using the market-based method).

⁽⁵⁾  Production-related increases in emissions were partially offset by a change to the electricity emissions factor for Minerals Americas resulting from the interconnection of Chile’s northern (mainly fossil fuel-based) and southern (which has a higher proportion of hydropower and other renewables) grid systems.

⁽⁶⁾  Our voluntary social investment is calculated as one per cent of the average of the previous three years’ pre-tax profit. Expenditure includes BHP’s equity share for operated and non-operated joint ventures, and comprises cash, administrative costs and cost to facilitate the operation of the BHP Billiton Foundation. Social investment figures include data for Continuing and Discontinued operations for the financial years being reported.

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1.5.3    Our contribution in FY2018

In FY2018, our total direct economic contribution was US$33.9 billion, including payments to suppliers, wages and employee benefits, dividends, taxes and royalties, as well as voluntary social investment across our host communities. Of this, we paid US$7.8 billion globally in taxes, royalties and other payments to governments. Our global adjusted effective tax rate was 31.4 per cent⁽¹⁾. Including royalties, this increases to 39.9 per cent. This significant source of taxation revenue assists governments to provide essential services to their citizens and invest in their communities for the future.

During FY2018, we also decreased our gross debt by US$3.7 billion through the repayment of maturing debt, the bond repurchase program and fair value adjustments.

As well as our direct economic contribution, we invested US$6.8 billion into our business through the purchase of property, plant and equipment and expenditure on exploration. This investment typically has a multiplier effect by creating new jobs within our operations and also for the suppliers on whom they rely. For example, our US$3.06 billion investment in the South Flank iron ore project in Western Australia will provide a significant additional economic contribution to the local economy through opportunities for local suppliers – around 85 per cent of the construction budget will be spent in Australia, with 90 per cent of that in Western Australia. It will also create approximately 2,500 construction jobs and 600 ongoing operational roles.

Total economic contribution in FY2018

Figures are rounded to the nearest decimal point and include data for Continuing and Discontinued operations for the financial years being reported.

⁽¹⁾  For the definition of and details of our global adjusted effective tax rate, refer to sections 1.11.4 and 1.11.5.

⁽²⁾  Calculated on an accrual basis.

⁽³⁾ Total social investment includes community contributions and associated administrative costs (including US$1.54 million to facilitate the operation of the BHP Billiton Foundation), and BHP’s equity share in community contributions for both operated and non-operated joint ventures. Our social investment target is not less than one per cent of pre-tax profits invested in community programs, including cash and administrative costs, calculated on the average of the previous three years’ pre-tax profit. Priorities and focus areas are outlined in our Social Investment Framework, detailed in our Sustainability Report 2018.

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1.6    Our operating environment

1.6.1    Market factors and trends

We produce raw materials that are essential to modern life. Our success is tied to the sustainable growth of both emerging and developed economies and, at the same time, the commodities we produce are integral to driving that growth.

As a result, our performance is influenced by a wide range of factors that drive a complex relationship between supply and demand. In line with our purpose of creating long-term shareholder value, we navigate those market factors by thinking and planning in decades. Our diverse portfolio of long-life, low-cost assets allows us to adapt to the changing needs of our customers and protect long-term shareholder value.

Key trends

Our long-term view for our markets remains positive. Population growth and rising living standards are expected to continue to generate demand for energy, metals and fertilisers for decades to come. New demand centres will emerge where the twin levers of industrialisation and urbanisation are still immature today. Technology continues to advance, creating both opportunities and threats. International responses to climate change will evolve.

Against that backdrop, we are confident we have the right assets in the right commodities, with demand diversified by end-use sector and geography. Our exploration and acquisition efforts are critical to maintaining that advantage, as they create a pipeline of products to meet future demand (see section 1.6.3). Exploration is inherently risky (see section 1.6.4), as the geoscience used for locating and accessing resources is complex and uncertain. Exploration and acquisition are also subject to political, infrastructure and other risks that can impact the accessibility of resources.

In the near term, challenges remain. There has been a marked rise in geopolitical uncertainty and protectionism, which have the potential to inhibit international trade, weigh on business confidence and restrain job creation and investment.

Short term

Political and policy uncertainty

Political uncertainty has continued during FY2018. The rise of US-China trade tensions and other protectionist measures, along with an increasingly unpredictable policy formation process in some major economies, serve to reduce consumer confidence and business certainty. By extension, this affects investment and jobs.

Modest economic growth

Protectionism and political uncertainty lower the achievable ceiling for global economic growth while they remain in place.

Balanced risks

Risks to prices in the overall portfolio appear roughly balanced, with mild upside risk in some markets offset by mild downside risk in others.

Prudently cautious

The operating environment is complex, with uncertainty and volatility expected to be high. However, we remain optimistic for the long term.

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Medium term

New supply

New supply, particularly of copper and petroleum, is expected to be required as demand grows and current resources are depleted.

Steeper cost curves

The marginal cost of producing some commodities is likely to rise, particularly for oil and copper, as existing resources deplete and new resources come from lower-quality deposits that are more costly to access.

Sustainable productivity rewarded

As industry wide costs rise, disciplined producers are likely to see margin benefits from accumulated investment in sustainable productivity gains.

Asian growth

China still offers rich opportunities due to its large scale, ongoing urbanisation and the Belt and Road initiative, despite its ongoing structural shift away from manufacturing towards services. India has significant potential for sustained high growth, as does populous southeast Asia.

Long term

Growth in population, wealth

Demand for metals, energy and fertiliser is expected to increase to meet the needs of the world’s growing population and rising living standards.

Urbanisation and new demand centres

New demand centres will emerge where the twin levers of industrialisation and urbanisation are still immature today. They include nations in South Asia, South East Asia, Africa and Latin America.

Decarbonisation

The move towards a low-carbon economy has the potential to drive significant change. Environmental and risk concerns will drive increasing diversification of national energy sources.

Technology

Technology can substantially alter the markets for, and uses of, our products, or create new markets. This can be disruptive in both the positive and negative sense. However, markets for essential products such as ours are typically slow to change. Our diversified portfolio provides some protection against negative disruption of demand caused by technological change. From the supply perspective, advanced mining methods should drive further efficiency, unlocking high-cost resources and offsetting grade decline.

Global long-term outlook

We anticipate ongoing increases in global living standards over the longer term, with urbanisation, industrialisation and trade expected to underpin commodity demand. The development of emerging economies in South and South East Asia should drive particular demand for industrial metals, energy and fertilisers.

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Key geographies

Our customers are geographically diverse. We have structured our business to meet changing demands as global market dynamics shift. Developments in a particular country can affect the demand for our products in that country and in any countries that supply goods for import to that country.

China

China is the largest consumer of our commodities, accounting for roughly half of our sales. As the largest manufacturer and exporter in the world and the second-largest importer, China’s performance is also a significant factor in the health of the global economic system.

China’s GDP growth in the short term is expected to remain steady. Growth is expected to slow modestly in CY2018 in line with the official GDP target range of around 6.5 per cent. We expect to see a cooling of growth rates in the housing and automobile markets, while machinery and infrastructure are expected to provide stability as overall growth slows.

China’s policymakers are likely to continue to seek a balance between pursuing reform and maintaining macroeconomic and financial stability. We expect a continuation of current efforts to reduce debt and deal with housing inflation.

In the long term, China’s economic growth is expected to slow progressively as the working age population falls and the capital stock matures, with productivity reforms offsetting these impacts to some degree.

China’s economic structure is expected to continue to move from industry to services and growth drivers shift from investment and exports towards consumption. This structural change is likely to produce a less volatile underlying growth rhythm in the long run.

United States

As both a major producer and consumer of our products, the United States is important to our performance. With most of our transactions denominated in US dollars, fluctuations in the dollar also influence our performance.

The US economy received a significant boost with the passing of the Tax Cuts and Jobs Act (signed on 22 December 2017). The most significant reforms include a reduction in the corporate tax rate from 35 per cent to 21 per cent and a reduction of marginal income tax rates for five out of seven tax brackets. The Joint Committee on Taxation estimated that these measures would increase the average level of output in the United States by about 0.7 per cent over the next 10 years, with changes front-loaded. However, the monetary policy response of the Federal Reserve, including the impact on the exchange rate, is likely to offset some of the impact of the tax package.

In addition, with the rise of US-China trade tensions, protectionist policies could hurt consumer purchasing power and productivity growth. Purchasing power is reduced through higher prices for imported goods and domestic goods with imported components. Reduced competition and the unintended consequences of restrictive migration policies on the free flow of world-class talent would dent productivity growth.

Japan

Japan’s demographics (ageing population and extremely low birth rate) and its public debt burden are constraints on long-term growth. Without population, immigration and microeconomic reform, growth is likely to stagnate.

Beyond the boost provided by the Tokyo Olympics, in the medium term, with monetary and fiscal policy proving ineffective at spurring domestic demand, any sustained lift in Japanese growth is likely to have to come from external sources.

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Eurozone

Europe’s short-term outlook has improved, with most countries in the region now experiencing growth in domestic demand. While financial fragilities remain, downside risks have been reduced.

Significant microeconomic reform is required in Europe’s southern regions to prevent longer run stagnation. In the more internationally competitive northern regions, lower savings rates would boost growth at home and help to rebalance demand within the common currency zone.

India

India’s short-term outlook seems positive, driven by consumer demand. Economic reform that boosts the supply of basic infrastructure is critical to India’s ability to take advantage of its demographic profile and successfully urbanise.

Progress on key reforms, including GST, real estate regulation, insolvency resolution and demonetisation of high denomination bills, has been encouraging.

We expect India’s GDP growth to average more than seven per cent annually over FY2016 to FY2020, with energy and metals demand rising at a similar pace.

Exchange rates

We are exposed to exchange rate transaction risk on foreign currency sales and purchases. Operating costs and costs of locally sourced equipment are influenced by fluctuations in local currencies, primarily the Australian dollar and Chilean peso. The majority of our sales are denominated in US dollars and we borrow and hold surplus cash predominately in US dollars. Those transactions and balances provide no foreign exchange exposure relative to the US dollar presentation currency of the Group.

The US dollar remained relatively stable during FY2018 against our main local currencies.

We are also exposed to exchange rate translation risk in relation to net monetary liabilities, being our foreign currency denominated monetary assets and liabilities, including certain debt and other long-term liabilities.

Interest rates

We are exposed to interest rate risk on our outstanding borrowings and investments. Our policy on interest rate exposure is to pay on a US dollar floating interest rate basis.

Our earnings are sensitive to changes in interest rates on the floating component of BHP’s borrowings. Our main exposure is to the three-month US LIBOR benchmark, which increased by 104 basis points from 1.3 per cent at 30 June 2017 to 2.34 per cent at 30 June 2018.

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Case study:

BHP and our China customers: Responding to a dynamic market

China’s four-decade long boom has restored the country to its traditional position as the centre of the East Asian economy. We are optimistic that it will continue to be an opportunity-rich region for BHP. Its influence on the development path of other regions is increasing. Two initiatives in particular are highly relevant to our business: the Belt and Road Initiative and supply-side reform.

The Belt and Road Initiative and commodity demand

China’s Belt and Road Initiative (BRI) is the core element in China’s Eurasian foreign policy. BRI is a development strategy that focuses on enhancing regional connectivity and infrastructure depth across Eurasia. Projects captured under BRI include ports, rail, roads, bridges, power stations, oil and gas pipelines and water management. The initiative is expected to connect the country’s underdeveloped hinterland to Europe via Central Asia, and to various points on the Indo-Pacific seaboard via land corridors through South and South East Asia.

Understanding the risks and opportunities posed by China’s future path is critical to the performance of BHP’s portfolio. Based on the results of the study we have carried out, we estimate that BRI will involve expenditure of around US$1.3 trillion and potentially generate up to 150 million tonnes of incremental steel demand, doubling the growth rate of local steel demand from 2011 numbers.

BHP is already preparing to meet this projected long-term demand.

Supply-side reforms and the immediate future

More immediately, BHP is responding to changes in the dynamics of the China market driven by the country’s supply-side reform of its steel industry.

Since the end of the stimulus era that followed the global financial crisis, China’s steel mills have struggled with severe over-capacity and persistent financial difficulties. In an attempt to end this state of affairs, beginning in late 2015 China began removing 150 million tonnes per annum of capacity. The plan was to complete this by 2020, with obsolete and inefficient plants the first to be closed.

The policy has been successful. Industry-wide profitability has now improved materially. Steel industry utilisation rates and mill margins have increased sharply.

This shift has implications for iron and metallurgical coal demand. As steel mills and copper smelters transition to more energy efficient and less carbon intensive technology, structural premiums will emerge for higher-quality products, such as the Premium Low Volatile coking coal produced by BHP’s Coal assets.

China’s increasing focus on environmental protection and ‘ecological civilisation’ has prompted increasingly strict emission standards. This will also support the demand for high-quality products that produce fewer emissions.

Collaborating to build a sustainable industry

As a major metallurgical coal and iron ore supplier, BHP works with our customers, industry and research institutions in China to develop sustainable technologies. China’s contribution to the reduction of worldwide greenhouse gas emissions will be critical for the world to limit the increase in global temperatures to two degrees Celsius.

We are collaborating with Peking University on research into carbon capture and storage. China leads the way in planning and developing large-scale carbon capture and storage projects: if commercially proven, these could be a significant industry for China.

China is also on track to become the global leader in clean energy technology. Renewable energy infrastructure will generate greater demand for commodities. Electric cars and decarbonisation will drive demand for quality as well as quantity. Our industry has a responsibility to be at the forefront of innovation so that we safely, efficiently and sustainably deliver our commodities to the world, throughout any cycle.

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1.6.2     Commodity performance overview

Commodity prices

The following table shows the prices for our most significant commodities for the years ended 30 June 2018, 2017 and 2016. These prices represent selected quoted prices from the relevant sources as indicated and will differ from the realised prices due to differences in quotation periods, quality of products, delivery terms and the range of quoted prices that are used for contracting sales in different markets. For information on realised prices, refer to section 1.12.

Year ended 30 June	2018 Closing		2017 Closing		2016 Closing		2018 Average		2017 Average		2016 Average		2018 vs 2017 Average
Natural gas Asian Spot LNG (1) (US$/MMBtu)		10.3		5.5		5.2		8.5		6.4		6.1		33%
Crude oil (Brent) (2) (US$/bbl)		77.9		47.4		48.4		63.6		49.6		43.2		28%
Ethane (3) (US$/bbl)		14.7		10.3		9.7		11.0		9.5		7.7		17%
Propane (4) (US$/bbl)		39.3		25.1		21.7		36.2		24.9		17.9		46%
Butane (5) (US$/bbl)		45.9		30.8		28.9		41.0		33.3		24.2		23%
Copper (LME cash) (US$/lb)		3.0		2.7		2.2		3.1		2.4		2.2		25%
Iron ore (6) (US$/dmt)		64.5		63.0		55.0		69.0		69.5		51.4		-1%
Metallurgical coal (7) (US$/t)		199.0		148.5		91.5		203.0		190.4		81.6		7%
Energy coal (8) (US$/t)		117.3		82.5		56.5		100.2		80.5		53.4		24%
Nickel (LME cash) (US$/lb)		6.8		4.2		4.3		5.6		4.6		4.2		23%

⁽¹⁾  Platts Liquefied Natural Gas Delivery Ex-Ship (DES) Japan/Korea Marker – typically applies to Asian LNG spot sales.

⁽²⁾  Platts Dated Brent – a benchmark price assessment of the spot market value of physical cargoes of North Sea light sweet crude oil.

⁽³⁾  OPIS Mont Belvieu non-Tet Ethane – typically applies to ethane sales in the US Gulf Coast market.

⁽⁴⁾  OPIS Mont Belvieu non-Tet Propane – typically applies to propane sales in the US Gulf Coast market.

⁽⁵⁾  OPIS Mont Belvieu non-Tet Normal Butane – typically applies to butane sales in the US Gulf Coast market.

⁽⁶⁾  Platts 62 per cent Fe Cost and Freight (CFR) China – used for fines.

⁽⁷⁾  Platts Low-Vol hard coking coal Index FOB Australia – representative of high-quality hard coking coals.

⁽⁸⁾  GlobalCoal FOB Newcastle 6,000kcal/kg NCV – typically applies to coal sales in the Asia Pacific market.

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Impact of changes to commodity prices

The prices we obtain for our products are a key driver of value for BHP. Fluctuations in these commodity prices affect our results, including cash flows and asset values. The estimated impact of changes in commodity prices in FY2018 on our key financial measures is set out below.

	Impact on profit after taxation from Continuing and Discontinued operations (US$M)		Impact on Underlying EBITDA (1) (US$M)
US$1/bbl on oil price		46		47
US¢1/lb on copper price		25		36
US$1/t on iron ore price		163		233
US$1/t on metallurgical coal price		27		38
US$1/t on energy coal price		12		17
US¢1/lb on nickel price		1		2

⁽¹⁾  Excludes data from Discontinued operations.

1.6.3     Exploration

Our exploration program is focused on conventional petroleum and copper. The purpose is to generate attractive, low cost, value accretive options by leveraging our competitive strengths.

Several years ago, we conducted a petroleum global endowment study that informed a new conventional petroleum exploration strategy. The results of that study are encouraging: we have made discoveries in four out of the six prospects tested over the past two years, across two key basins, secured more than 100 highly prospective blocks in the Gulf of Mexico and competitively acquired the Trion discovered resource in Mexico.

Our copper exploration program is at an earlier stage, where we continue to seek, secure and test concessions in regions such as Ecuador, Canada, southwestern United States, South Australia, Chile and Peru.

BHP exploration regions

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Exploration in FY2018

Conventional petroleum

Our petroleum exploration program is focused in regions with significant oil and gas resource potential that have stable and competitive fiscal terms and offer an attractive return on investment. We concentrate our efforts in areas that have the potential to generate high-quality assets: the Gulf of Mexico, the Caribbean and Western Australia.

In FY2018, we discovered oil in multiple horizons with the Wildling-2 well, located north of our operated Shenzi asset in the US Gulf of Mexico. These results follow oil discoveries at Shenzi North in FY2016 and the Caicos well in FY2017. We increased our equity interest in the Murphy operated Samurai prospect, the northern extension of the Wildling sub-basin, from 33.33 to 50 per cent. The Samurai-2 exploration well was spud on 16 April 2018 and encountered hydrocarbons in multiple horizons not previously observed by the Wildling-2 exploration well. The Scimitar prospect, to the north of the Neptune field, was drilled with no commercial hydrocarbons encountered.

In Trinidad and Tobago, following the gas discovery at LeClerc, we commenced Phase 2 of our deepwater exploration drilling campaign to further assess the commercial potential of the Magellan play. The Victoria-1 exploration well was spud on 12 June 2018 and encountered gas. Following completion of the Victoria-1 well, the Bongos-1 exploration well was spud on 20 July 2018 and experienced mechanical difficulty shortly after spud. The Bongos-2 exploration well was spud on 22 July 2018 and encountered hydrocarbons. Drilling is still in progress.

In Mexico, we progressed planning for exploration and appraisal wells at Trion. The exploration and appraisal plan was endorsed by Pemex and approval from Mexico’s National Hydrocarbon Commission was granted in February 2018. Drilling of the next appraisal well is planned for FY2019.

In Western Australia, processed 3D seismic data for the Exmouth sub-basin will be delivered during the September 2018 quarter and will inform the prospectivity in this area.

For more details on conventional petroleum exploration, refer to section 1.12.1.

Copper

Copper exploration is focused on identifying and gaining access to new search spaces while we maintain research and technology activities aligned with our exploration strategy. The field copper exploration activities are directed towards the discovery of large, high-quality copper deposits in Chile, Peru, Ecuador, North America and Australia. These activities encompass early stage reconnaissance work through to more advanced target definition and testing in every country where we have exploration concessions. In parallel, we continue to review other jurisdictions and opportunities to partner with third parties to counter the increasing exploration maturity of our existing geographies.

On 5 September 2018, we announced that we had acquired a 6.1 per cent interest in SolGold Plc, the majority owner and operator of the Cascabel porphyry copper-gold project in Ecuador.

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Exploration expenditure

Our brownfield minerals exploration expenditure decreased by seven per cent in FY2018 to US$112 million, while our greenfield expenditures increased to US$53 million. Expenditure on brownfield and greenfield minerals exploration over the last three financial years is set out below.

Year ended 30 June	2018 US$M		2017 US$M		2016 US$M
Greenfield exploration		53		43		59
Brownfield exploration		112		120		116
Total minerals exploration		165		163		175

For more information on minerals exploration, refer to section 1.12.

Conventional petroleum exploration and appraisal

Petroleum exploration expenditure for FY2018 was US$709 million, of which US$516 million was expensed. Expenditure on petroleum exploration over the last three financial years is set out below.

Year ended 30 June	2018 US$M		2017 US$M		2016 US$M
Conventional petroleum exploration		709		803		577

Our petroleum exploration program had positive results in FY2018. We are pursuing high-quality plays in our three priority basins, and a US$750 million exploration program is planned for FY2019 as we progress testing of our future growth opportunities.

For more information on conventional petroleum exploration, refer to section 1.12.1.

Exploration expense

Exploration expense represents that portion of exploration expenditure that is not capitalised in accordance with our accounting policies, as set out in note 10 ‘Property, plant and equipment’ in section 5.

Exploration expense for each segment over the last three financial years is set out below.

Year ended 30 June	2018 US$M		2017 US$M		2016 US$M
Exploration expense
Petroleum (1)(2)		592		573		277
Copper		53		44		64
Iron Ore		44		70		74
Coal		21		9		18
Group and unallocated items (2)(3)		7		16		1
Total Group		717		712		434

⁽¹⁾  Includes US$76 million (FY2017: US$102 million; FY2016: US$15 million) exploration expense previously capitalised, written off as impaired.

⁽²⁾  Excludes Onshore US exploration expenditure of nil (FY2017: US$2 million; FY2016: US$11 million).

⁽³⁾  Group and unallocated items includes functions, other unallocated operations, including Potash, Nickel West and consolidation adjustments.

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1.6.4    Principal risks

Robust risk assessment and viability statement

The Board has carried out a robust assessment of BHP’s principal risks, including those that could threaten the business model, future performance, solvency or liquidity.

The Directors have assessed the prospects of BHP over the next three years, taking into account our current position and principal risks.

The Directors believe a three-year viability assessment period is appropriate for the following reasons. BHP has a two-year budget, a five-year plan and a longer-term life-of-asset outlook. We have publicly stated our view that while commodity prices remain volatile, our short-term outlook is optimistic. Price and exchange rate volatility results in variability in plans and budgets. A three-year period strikes an appropriate balance between long-term and short-term influences on performance.

The viability assessment took into account, among other things, BHP’s commodity price protocols, including low-case prices; the latest funding and liquidity update; the long-dated maturity profile of BHP’s debt and the maximum debt maturing in any one year; the Group-level risk profile and the mitigating actions available should particular risks materialise; the regular Board strategy and portfolio discussions which address the range of outcomes under the Capital Allocation Framework; the flexibility in BHP’s capital and exploration expenditure programs under the Capital Allocation Framework; and the reserve life of BHP’s minerals assets and the reserves-to-production life of our oil and gas assets.

The Directors’ assessment also took account of additional stress-testing of the balance sheet against two hypothetical significant risk events: a well blow out in the Gulf of Mexico and a low-price environment. A further level of robustness is added given no debt issuance is required in the three-year period and BHP would still have access to US$6.0 billion of credit through its revolving credit facility. The Directors were also mindful of the assessment of our portfolio against scenarios as part of BHP’s corporate planning process to help identify key uncertainties facing the global natural resources sector.

In making this statement, the Directors considered the divestment of Onshore US. The Directors have also made certain assumptions regarding the alignment of production, capital expenditure and operating expenditure with five-year plan forecasts and the alignment of prices with the cyclical low-price case used in the control stress case for balance sheet testing.

Taking account of these matters, and BHP’s current position and principal risks, the Directors have a reasonable expectation that BHP will be able to continue in operation and meet its liabilities as they fall due.

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Risk factors

External risks
Fluctuations in commodity prices (including sustained price shifts) and impacts of ongoing global economic volatility may negatively affect our results, including cash flows and asset values	The prices we obtain for our minerals, oil and gas are determined by, or linked to, prices in world markets, which have historically been subject to significant volatility. Our usual policy is to sell our products at the prevailing market prices. The diversity provided by our relatively broad portfolio of commodities does not necessarily insulate BHP from the effects of price changes. Fluctuations in commodity prices can occur due to price shifts reflecting underlying global economic and geopolitical factors, industry demand, increased supply due to the development of new productive resources or increased production from existing resources, technological change, product substitution and national tariffs. We are particularly exposed to price movements in minerals, oil and gas. For example, a US$1 per tonne decline in the average iron ore price and US$1 per barrel decline in the average oil price would have an estimated impact on FY2018 profit after taxation from Continuing and Discontinued operations of US$163 million and US$46 million, respectively. For more information in relation to commodity price impacts, refer to section 1.6.2. Volatility in global economic growth, particularly in developing economies, has the potential to adversely affect future demand and prices for commodities. Geopolitical uncertainty and protectionism have the potential to inhibit international trade and weigh on business confidence, which creates the risk of constraints on our ability to trade in certain markets and has the potential to increase price volatility. The impact of sustained price shifts and short-term price volatility, including the effects of unwinding the sustained monetary stimulus in the United States and ongoing and protracted uncertainty surrounding the details of the United Kingdom’s exit from the European Union, creates the risk that our financial and operating results, including cash flows and asset values, will be materially and adversely affected by short-term or long-term volatility in the prevailing prices of our products.
Our financial results may be negatively affected by exchange rate fluctuations	The geographic diversity of the countries in which our assets are located means our assets, earnings and cash flows are influenced by a variety of currencies. Fluctuations in the exchange rates of those currencies may have a significant impact on our financial results. The US dollar is the currency in which the majority of our sales are denominated and the currency in which we present our financial performance. Operating costs are influenced by the currencies of those countries where our assets and facilities are located and also by those currencies in which the costs of imported equipment and services are determined.

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External risks
Reduction in Chinese demand may negatively impact our results	The Chinese market has been driving global materials demand and pricing over the past decade. Sales into China generated US$22.9 billion (FY2017: US$18.9 billion) or 52.6 per cent (FY2017: 52.2 per cent) of our revenue in FY2018, on a continuing operations basis. FY2018 sales into China by commodity included 52 per cent Iron Ore, 31 per cent Copper, 15 per cent Coal and two per cent Nickel (reported in Group and Unallocated). A continued slowing in China’s economic growth and demand could result in lower prices for our products and materially and adversely impact our results, including cash flows.
Actions by governments or courts, regulatory change, political events or alleged compliance breaches in the countries in which we operate or assets in which we have an interest could have a negative impact on our business	There are varying degrees of political, judicial and commercial stability in the locations in which we have operated assets and non-operated joint ventures around the globe. At the same time, our exposure to emerging markets may involve additional risks that could have an adverse effect on the profitability of an operation. Risks in the locations in which we have operated assets and non-operated joint ventures could include terrorism, civil unrest, judicial activism, regulatory investigation or inquiry, nationalisation, protectionism, renegotiation or nullification of existing contracts, leases, permits or other agreements, imposts, controls or prohibitions on the production or use of certain products, restrictions on repatriation of earnings or capital and changes in laws and policy, as well as other unforeseeable risks. Risks relating to bribery and corruption, including possible delays or disruption resulting from a refusal to make so-called facilitation payments, may be prevalent in some of the countries where our assets are located. If any of our major operated assets or non-operated joint ventures are affected by one or more of these risks, it could have a material adverse effect on BHP’s overall operating results, financial condition and prospects.
	Our operated assets and non-operated joint ventures are based on material long-term investments that are dependent on long-term fiscal stability, and could be adversely affected by changes in fiscal legislation, changes in interpretation of fiscal legislation, periodic challenges and disagreements with tax authorities and legal proceedings relating to fiscal matters. The natural resources industry continues to be regarded as a source of tax revenue and can also be adversely affected by broader fiscal measures applying to businesses generally. BHP is currently involved in a number of uncertain tax and royalty matters. For more information, refer to note 5 ‘Income tax expense’ in section 5.

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External risks
	Our business is affected by new and evolving government regulations and international standards, such as controls on imports, exports, prices and greenhouse gas emissions. The nature of the industries in which we operate means many of our activities are highly regulated by laws relating to health, safety, environment and community impacts. Increasing requirements relating to regulatory, environmental, social or community approvals can potentially result in significant delays or interruptions and may adversely affect the economics of new mining, oil and gas projects, the expansion of existing assets and operations and the performance of our operated assets and non-operated joint ventures. As regulatory standards and expectations are constantly developing, we may be exposed to increased regulation and compliance costs to meet new operating and reporting standards, as well as unforeseen closure and site rehabilitation expenses.
	Infrastructure, such as rail, ports, power and water, is critical to our business operations. We have assets or potential development projects in countries where government-provided infrastructure or regulatory regimes for access to infrastructure, including our own privately operated infrastructure, may be inadequate, uncertain or subject to legislative change. The impact of climate change may increase competition for, and the regulation of, limited resources, such as power and water. These factors could materially and adversely affect the expansion of our business and ability of our assets to operate efficiently.
	We own assets or interests in countries where land tenure can be uncertain and disputes may arise in relation to ownership and use, including in respect of Indigenous rights. For example, in Australia, the Native Title Act 1993 provides for the establishment and recognition of native title under certain circumstances.
	New or evolving regulations and international standards can be complex, difficult to predict and difficult to influence. Potential compliance costs, litigation expenses, regulatory delays, rehabilitation expenses and operational impacts and costs arising from government action, court decisions, regulatory change and evolving standards could materially and adversely affect BHP’s future results, prospects and our financial condition.

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External risks

We conduct our business in a global environment that encompasses multiple jurisdictions and complex regulatory frameworks. Our governance and compliance processes (which include the review of internal controls over financial reporting and specific internal controls in relation to trade and financial sanctions, market manipulation, competition, data protection and privacy, offers of anything of value to government officials and representatives of state-owned enterprises and disclosure of state or commercial secrets) may not operate to identify financial misstatements or prevent potential breaches of law, or of accounting or governance practice. Our Code of Conduct, together with our mandatory policies such as the anti-corruption, trade and financial sanctions and competition policies, may not prevent instances of fraudulent behaviour and dishonesty nor guarantee compliance with legal or regulatory requirements. This may lead to regulatory fines, disgorgement of profits, litigation, allegations or investigations by regulatory authorities, loss of operating licences and/or reputational damage.

Business risks
Failure to discover or acquire new resources, maintain reserves or develop new assets could negatively affect our future results and financial condition	The demand for our products and production from our assets results in existing reserves being depleted over time. As our revenues and profits are derived from our minerals, oil and gas assets, our future results and financial condition are directly related to the success of our exploration and acquisition efforts, and our ability to generate reserves to meet our future production requirements at a competitive cost. Exploration activity occurs adjacent to established assets and in new regions, in developed and less-developed countries. These activities may increase land tenure, infrastructure and related political risks. A failure in our ability to discover or acquire new resources, maintain reserves or develop new assets or operations in sufficient quantities to maintain or grow the current level of our reserves could negatively affect our future results, financial condition and prospects. Deterioration in commodities pricing may make some existing reserves uneconomic. Our actual exploration drilling activities and future drilling budget will depend on our inventory size and quality, drilling results, commodity prices, drilling and production costs, availability of drilling services and equipment, lease expirations, land access, transportation pipelines, railroads and other infrastructure constraints, regulatory approvals and other factors.
	There are numerous uncertainties inherent in estimating mineral, oil and gas reserves. Geological assumptions about our mineralisation that are valid at the time of estimation may change significantly when new information becomes available. Estimates of reserves that will be recovered, or the cost at which we anticipate reserves will be recovered, are based on uncertain assumptions. The uncertain global financial outlook may affect economic assumptions related to reserve recovery and may require reserve restatements. Changes to reserve estimates could affect our asset carrying values and may also negatively impact our future financial condition and results.

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Business risks
Potential changes to our portfolio of assets through merger, acquisition and divestment activity may have a material adverse effect on our future results and financial condition	We regularly review the composition of our asset portfolio and from time to time may add assets to, or divest assets from, the portfolio. There are a number of risks associated with acquisitions or divestments. These include:
	•   loss of value from a poor investment decision;
	•   loss of potential value from a missed investment opportunity;
	•   adverse market reaction to such changes or the timing or terms on which changes are made;
	•   the imposition of adverse regulatory conditions and obligations;
	•   commercial objectives not being achieved as expected;
	•   unforeseen liabilities arising from changes to the portfolio;
	•   sales revenues and operational performance not meeting our expectations;
	•   anticipated synergies or cost savings being delayed or not being achieved;
	•   inability to retain key staff and transaction-related costs being more than anticipated.
	These factors could materially and adversely affect our reputation, future results and financial condition.
Increased costs and schedule delays may adversely affect our development projects	Although we devote significant time and resources to our project planning, approval and review processes, many of our development projects are highly complex and rely on factors that are outside our control, which may cause us to underestimate the cost or time required to complete a project. For instance, incidents or unexpected conditions encountered during development projects may cause setbacks or cost overruns, required licences, permits or authorisations to build a project may be unobtainable at anticipated costs, or may be obtained only after significant delay and market conditions may change, thereby making a project less profitable than initially projected.
	In addition, we may fail to develop and manage projects as effectively as we anticipate and unforeseen challenges may emerge.
	Any of these may result in increased capital costs and schedule delays at our development projects and materially and adversely affect anticipated financial returns.

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Financial risks
If our liquidity and cash flow deteriorate significantly, it could adversely affect our ability to fund our major capital programs	We seek to maintain a strong balance sheet. However, fluctuations in commodity prices and ongoing global economic volatility could materially and adversely affect our future cash flows and ability to access capital from financial markets at acceptable pricing. If our key financial ratios and credit ratings are not maintained, our liquidity and cash reserves, interest rate costs on borrowed debt, future access to financial capital markets and the ability to fund current and future major capital projects could be adversely affected.
We may not fully recover our investments in mining, oil and gas assets, which may require financial write-downs	One or more of our assets may be adversely affected by changed market or industry structures, commodity prices, technical operating difficulties, inability to recover our mineral, oil or gas reserves and increased operating cost levels. These may cause us to fail to recover all or a portion of our investment in mining, oil and gas assets and may require financial write-downs, including goodwill, adversely affecting our financial results.
The commercial counterparties with whom we transact may not meet their obligations, which may negatively affect our results	We contract with many commercial and financial counterparties, including end-customers, suppliers and financial institutions in the context of global financial markets that remain volatile. We maintain a ‘one book’ approach with commercial counterparties to make sure all credit exposures are quantified and assessed consistently. However, our existing counterparty credit controls may not prevent a material loss due to credit exposure to a major customer segment or financial counterparty. In addition, customers, suppliers, contractors or joint venture partners may fail to perform against existing contracts and obligations. Non-supply of key inputs, such as explosives, tyres, mining and mobile equipment, diesel and other key consumables, may unfavourably impact costs and production at our assets. These factors could negatively affect our financial condition and results of assets.

Operational risks

Unexpected natural and operational catastrophes may adversely impact our assets, functions or people

We have onshore and offshore extractive, processing and logistical operations in many geographic locations. Our key port facilities are located at Coloso and Antofagasta in Chile and Port Hedland and Hay Point in Australia. We have four underground mines, including one underground coal mine. Our operational processes may be subject to operational accidents, such as fires, explosions or gas leaks, road and vehicle incidents, port and shipping incidents, aircraft incidents, underground mine and processing plant fire and explosion, rock fall incidents in underground mining operations, open-cut pit wall or tailings/waste storage facility failures, loss of power supply, railroad incidents, loss of well control, environmental pollution, mechanical critical equipment failures, personnel conveyance equipment failures in underground operations and cyber or conventional security attacks on BHP’s infrastructure. If an operational crisis occurs, the failure to provide adequate communications response to our external stakeholders could result in Group-wide reputational damage.

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Operational risks
	Our minerals, oil and gas assets may also be subject to unexpected natural catastrophes, such as earthquakes, floods, hurricanes and tsunamis. Our northwest Western Australia Iron Ore, Queensland Coal and Gulf of Mexico oil and gas assets are located in areas subject to cyclones or hurricanes. Our Chilean copper and Peruvian base metals assets are located in a known earthquake and tsunami zone.
	We operate corporate offices and service centres globally. A serious natural, civil unrest, terror or criminal event in any of these locations could have an impact on the services provided to the Group and on our people and the community.
	Based on our risk management and the limited value of external insurance in the natural resource sector, our risk financing (insurance) approach is to minimise or not purchase external insurance for certain risks, including property damage and business interruption, sabotage and terrorism, marine cargo, construction, primary public liability and employee benefits. Existing business continuity plans may not provide protection for all the costs that arise from such events, including clean-up costs, litigation and other claims. The impact of these events could lead to disruptions in production, increased costs and loss of facilities. Where external insurance is purchased, third party claims arising from these events may exceed the limit of liability of the insurance policies we have in place. Additionally, any uninsured or underinsured losses could have a material adverse effect on our financial position or results of assets.
Information technology and operational technology services are subject to cybersecurity risks and threats that may materially affect our business and reputation	Our strategy of owning and operating large, long-life and low-cost assets is underpinned by our ability to become fully integrated and highly automated, from resource to market. Many of our business and operational processes are heavily dependent on traditional and emerging technologies to improve safety, lower cost and unlock value.
	Increases in the frequency and magnitude of global cyber events pose potential increased risk of sensitive information being compromised, as well as unplanned and/or extended outages to our operations or to the transportation of other infrastructure utilised by our operations. These events may include (but are not limited to) exploitation of system vulnerabilities, malware, phishing and other sophisticated cyberattacks, and other incidents (for example, due to human error). Such events may result in misappropriation of funds, an impact on asset productivity, adverse impacts to the health and safety of people, environmental damage, poor product quality, loss of intellectual property, disclosure of commercially or personally sensitive information, regulatory fines and/or other costs and reputational damage.

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Operational risks
	Despite reasonable attempts to protect us from cyber events, we are frequently subject to targeted and non-targeted cyberattacks and may be vulnerable to these in the future. In FY2018, there were no cyber events that led to a significant breach of our business-critical technology environment or a material disclosure of market-sensitive information.
Our potential liability from litigation and other actions resulting from the Samarco dam failure is subject to significant uncertainty and cannot be reliably estimated at this time, but could have a material adverse impact on our business	On 5 November 2015, the Samarco Mineração S.A. (Samarco) iron ore operations experienced a tailings dam failure that resulted in a release of mine tailings, flooding the communities of Bento Rodrigues, Gesteira and Paracatu and impacting other communities downstream and the Rio Doce. Samarco is a joint venture owned equally by BHP Billiton Brasil Limitada (BHP Billiton Brasil) and Vale S.A. (Vale). For information on the Samarco dam failure, refer to section 1.8.
	The Samarco dam failure and subsequent suspension of Samarco’s mining and processing operations continue to impact our financial results and will be disclosed as an exceptional item for the year ended 30 June 2018, as described in section 1.8 and in note 3 ‘Significant events – Samarco dam failure’ in section 5.
	Mining and processing operations remain suspended following the dam failure. Samarco is currently progressing plans to resume operations, however, significant uncertainties surrounding the nature and timing of any resumption of operations remain, including as a result of Samarco’s significant debt obligations. For financial information relating to Samarco, refer to note 28 ‘Investments accounted for using the equity method’ in section 5.
	BHP Billiton Brasil is among the defendants named in a number of legal proceedings initiated by individuals, non-governmental organisations (NGOs), corporations and governmental entities in Brazilian federal and state courts following the Samarco dam failure. The other defendants include Samarco, Vale and Fundação Renova. The lawsuits seek various remedies, including rehabilitation costs, compensation to injured individuals and families of the deceased, recovery of personal and property losses, moral damages and injunctive relief.
	Among the claims brought against BHP Billiton Brasil was a public civil claim commenced by the Federal Government of Brazil, the states of Espírito Santo and Minas Gerais, and certain other public authorities (Brazilian Authorities) on 30 November 2015, seeking the establishment of a fund of up to R$20 billion (approximately US$5.2 billion) in aggregate for clean-up costs and damages (R$20bn Public Civil Claim). This claim has now been settled (see below). In addition, a R$155 billion (approximately US$40 billion) claim has been brought by the Federal Public Prosecution Service (on 3 May 2016) for reparation, compensation and moral damages in relation to the Samarco dam failure (R$155bn Federal Public Prosecution Office claim). For more information on some of the legal proceedings relating to the Samarco dam failure, refer to section 6.5.

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Operational risks
	On 2 March 2016, BHP Billiton Brasil, together with Vale and Samarco, entered into a Framework Agreement with the Brazilian Authorities to establish a foundation (Fundação Renova) that will develop and execute environmental and socio-economic programs to remediate and provide compensation for damage caused by the Samarco dam failure. A committee (Interfederative Committee) comprising representatives from the Brazilian Federal and State Governments, local municipalities, environmental agencies, impacted communities and Public Defence Office oversees the activities of Fundação Renova in order to monitor, guide and assess the progress of actions agreed in the Framework Agreement.
	In light of the significant uncertainties surrounding the nature and timing of ongoing future operations at Samarco and based on currently available information, at 30 June 2018, BHP Billiton Brasil’s provision for its obligations under the Framework Agreement is US$1.3 billion, before tax and after discounting (30 June 2017, US$1.1 billion).
	The measurement of the provision requires the use of significant judgments, estimates and assumptions and may be affected by, among other factors, potential changes in scope of work and funding amounts required under the Framework Agreement, including the impact of decisions of the Interfederative Committee along with further technical analysis and community participation required under the Preliminary Agreement (defined below) and Governance Agreement (defined below), the outcome of the ongoing negotiations with State and Federal Prosecutors, actual costs incurred in respect of programs delivered, resolution of uncertainty in respect of operational restart, updates to discount and foreign exchange rates, resolution of existing and potential legal claims and the status of the Framework Agreement and the renegotiation process provided in the Governance Agreement (defined below). As a result, future actual expenditures may differ from the amounts currently provided and changes to key assumptions and estimates could result in a material impact on the amount of the provision in future reporting periods.
	On 18 January 2017, BHP Billiton Brasil, together with Vale and Samarco, entered into a Preliminary Agreement with the Federal Prosecutors’ Office in Brazil, which outlines the process and timeline for further negotiations towards a settlement regarding the R$20 billion Public Civil Claim and the R$155 billion Federal Public Prosecution Office claim.
	Under the Preliminary Agreement, BHP Billiton Brasil, Samarco and Vale agreed interim security (Interim Security) comprising R$1.3 billion (approximately US$335 million) in insurance bonds, R$100 million (approximately US$25 million) in liquid assets, a charge of R$800 million (approximately US$210 million) over Samarco’s assets, and R$200 million (approximately US$50 million) to be allocated within the next four years through existing Framework Agreement programs in the Municipalities of Barra Longa, Rio Doce, Santa Cruz do Escalvado and Ponte Nova.

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Operational risks
	On 24 January 2017, BHP Billiton Brasil, Samarco and Vale provided the Interim Security to the Court, which was to remain in place until the earlier of 30 June 2017 and the date that a final settlement arrangement was agreed between the Federal Prosecutors, and BHP Billiton Brasil, Vale and Samarco. Following a series of extensions, the parties reached an agreement in the form of the Governance Agreement (summarised below).
	On 25 June 2018, Samarco, Vale and BHP Billiton Brasil, the other parties to the Framework Agreement, the Public Prosecutors Office and the Public Defense Office agreed an arrangement which settles the R$20 billion Public Civil Claim, enhances community participation in decisions related to the remediation and compensation programs (Programs) under the Framework Agreement, and establishes a process to renegotiate those Programs over two years and to progress settlement of the R$155 billion Federal Public Prosecution Office claim (Governance Agreement). The Governance Agreement was ratified by the 12th Federal Court of Minas Gerais on 8 August 2018, settling the R$20 billion Public Civil Claim and suspending the R$155 billion Federal Public Prosecution Office claim for a period of two years from the date of ratification.
	During the two-year period, the parties will work together to design a single process for the renegotiation of the Programs and progress settlement of the R$155 billion Federal Public Prosecution Office claim.
	The renegotiation of the Programs will be based on certain agreed principles, such as full reparation consistent with Brazilian law, the requirement for a technical basis for any proposed changes, consideration of findings from the socio-economic and socio-environmental experts appointed by Samarco, Vale and BHP Billiton Brasil, consideration of findings from experts appointed by the Prosecutors, and consideration of the feedback from impacted communities. During the renegotiation period and up until revisions to the Programs are agreed, the Fundação Renova will continue to implement the Programs in accordance with the terms of the Framework Agreement and the Governance Agreement.
	The Interim Security provided under the Preliminary Agreement is maintained for a period of 30 months under the Governance Agreement, after which Samarco, Vale and BHP Billiton Brasil will be required to provide security of an amount equal to Fundação Renova’s annual budget up to a limit of R$2.2 billion.

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Operational risks
	As noted above, BHP Billiton Brasil has been named as a defendant in numerous other lawsuits that are at early stages of proceedings. The lawsuits seek various remedies, including rehabilitation costs, compensation to injured individuals and families of the deceased, recovery of personal and property losses and injunctive relief. In addition, government inquiries and investigations relating to the Samarco dam failure have been commenced by numerous agencies of the Brazilian Government and are ongoing, including criminal investigations by the federal and state police, and by federal prosecutors.
	Other lawsuits and investigations are at the early stages of proceedings, including two shareholder actions filed in Australia against BHP and a Samarco bondholder action filed in the United States against Samarco, Vale, BHP Billiton Brasil and BHP. For more information on the shareholder and bondholder actions and other lawsuits relating to the Samarco dam failure, refer to section 6.5. Additional lawsuits and government investigations relating to the Samarco dam failure may be brought against BHP Billiton Brasil and possibly other BHP entities in Brazil or other jurisdictions.
	Given the status of the legal proceedings referred to above, it is not possible to provide a range of possible outcomes or a reliable estimate of potential future exposures for BHP, unless otherwise stated. Ultimately, all of these legal matters could have a material adverse impact on BHP’s business, competitive position, cash flows, prospects, liquidity and shareholder returns.
	Our potential costs and liabilities in relation to the Samarco dam failure are subject to a high degree of uncertainty and cannot be reliably estimated at this time. The total amounts that we may be required to pay will be dependent on many factors, including the timing and nature of a potential restart of operations at Samarco, the number of claims that become payable, the quantum of any fines levied, the outcome of litigation and the amount and timing of payments under any judgements or settlements. Nevertheless, such potential costs and liabilities could have a material adverse effect on our business, competitive position, cash flows, prospects, liquidity and shareholder returns.
Cost pressures and reduced productivity could negatively impact our operating margins and expansion plans	Cost pressures may continue to occur across the resources industry. As the prices for our products are determined by the global commodity markets, we do not generally have the ability to offset these cost pressures through corresponding price increases, which can adversely affect our operating margins. Although our efforts to reduce costs and a number of key cost inputs are commodity price-linked, the inability to reduce costs and a timing lag could materially and adversely impact our operating margins for an extended period.

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Operational risks
	Some of our assets, such as those producing copper, are energy or water intensive. As a result, BHP’s costs and earnings could be materially and adversely affected by rising costs or supply interruptions. These could include the unavailability of energy, fuel or water due to a variety of reasons, including fluctuations in climate, inadequate infrastructure capacity, interruptions in supply due to equipment failure or other causes and the inability to extend supply contracts on economic terms.
	Many of our Australian employees have conditions of employment, including wages, governed by the operation of the Australian Fair Work Act 2009. Conditions of employment are often contained within collective agreements that are required to be renegotiated on expiry (typically every three to four years). In some instances, under the operation of the Fair Work Act it can be expected that unions will pursue increases to conditions of employment, including wages, and/or claims for greater union involvement in business decision-making.
	In circumstances where a collective agreement is being renegotiated, industrial action is permitted under the Fair Work Act. Industrial action and any subsequent settlement to mitigate associated commercial damage can adversely affect productivity and customer perceptions as a reliable supplier, and contribute to increases in costs.
	The industrial relations environment in Chile remains challenging and it is possible that we will see further disruptions. Recent changes to labour legislation in Chile have resulted in the right to have a single negotiating body across different operations owned by a single company. This change may lead to a higher risk of operational stoppages that can contribute to an increase in costs and a reduction in productivity.
	More broadly, cost and productivity pressures on BHP and our contractors and sub-contractors may increase the risk of industrial action and employment litigation. These factors could lead to increased operating costs at existing assets, interruptions or delays and could negatively impact our operating margins and expansion plans.
Non-operated joint ventures have their own management and operating standards, joint venture partners or other companies managing those non-operated joint ventures may take action contrary to our standards or fail to adopt standards equivalent to BHP’s standards, and commercial counterparties may not comply with our standards	We have interests in assets that are operated and managed by joint venture partners or by other companies. Those joint venture partners or other companies have their own management and operating standards, controls and procedures, including their own health, safety, environment and community (HSEC) standards and may take action contrary to BHP’s management and operating standards, controls and procedures. Failure by those joint venture partners or other companies to adopt equivalent standards, controls and procedures at these non-operated joint ventures could lead to operational incidents or accidents, materially higher costs and reduced production, litigation and regulatory action, delays or interruptions and adversely impact our results, prospects and reputation.

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Operational risks
	Commercial counterparties, such as our suppliers, contractors and customers, may not comply with our HSEC standards or other standards we apply causing adverse reputational and legal impacts.

Sustainability risks
Safety, health, environmental and community impacts, incidents or accidents may adversely affect our people, assets and reputation or licence to operate	Safety Potential safety events that may have a material adverse impact on our people, assets, reputation or licence to operate include fire, explosion or rock fall incidents in underground mining operations, personnel conveyance equipment failures in underground operations, aircraft incidents, road incidents involving buses and light vehicles, incidents between light vehicles and mobile mining equipment, shipping or vessel incidents, ground control failures, uncontrolled tailings containment breaches, well blowouts, explosions or gas leaks and accidents involving inadequate isolation, working from heights or lifting operations.
	Our employees, contractors and third parties may be subjected to safety risks when travelling to and from sites or while onsite at an asset or corporate office.
	Health
	Health risks faced include fatigue, musculoskeletal illnesses and occupational exposure to substances or agents, including noise, silica, coal mine dust, diesel exhaust particulate, nickel and sulphuric acid mist, radiation and mental illness. Longer-term health impacts may arise due to unanticipated workplace exposures or historical exposures of our workforce or communities to hazardous substances. These effects may create future financial compensation obligations, adversely impact our people, reputation, regulatory approvals or licence to operate and affect the way we conduct our assets.
	Given the global location of our assets, we could be affected by a public health emergency such as influenza or other infectious disease outbreaks in any of the regions in which our assets are located.
	Environment
	Our assets by their nature have the potential to adversely impact air quality, biodiversity, water resources and related ecosystem services. Changes in scientific understanding of these impacts, regulatory requirements or stakeholder expectations may prevent, delay or reverse project approvals and result in increased costs for mitigation, offsets or compensatory actions.
	Environmental incidents have the potential to lead to material adverse impacts on our people, communities, assets, reputation or licence to operate. These include uncontrolled tailings containment breaches, subsidence from mining activities, escape of polluting substances and uncontrolled releases of hydrocarbons.

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Sustainability risks
	We provide for operational closure and site rehabilitation. Our operating and closed facilities are required to have closure plans. Changes in regulatory or community expectations may result in the relevant plans not being adequate. This may increase financial provisioning and costs at the affected assets.
	Climate change
	The physical and non-physical impacts of climate change may affect our assets, productivity and the markets in which we sell our products. This includes acute and chronic changes in weather patterns, policy and regulatory change, technological development and market and economic responses. Fossil fuel-related emissions are a significant source of greenhouse gases contributing to climate change. We produce fossil fuels such as coal, oil and gas for sale to customers. We use fossil fuels in our mining and processing operations either directly or through the purchase of fossil fuel based electricity.
	A number of national governments have already introduced, or are contemplating the introduction of, regulatory responses to greenhouse gas emissions, including from the extraction and combustion of fossil fuels to address the impacts of climate change. This includes countries where we have assets such as Australia, the United States and Chile, as well as customer markets such as China, India and Europe. In addition, the international community completed a global climate agreement at the 21st Conference of the Parties (COP21) in Paris in December 2015. The absence of regulatory certainty, global policy inconsistencies and the challenges presented by managing our portfolio across a variety of regulatory frameworks have the potential to adversely affect our assets and supply chain. From a medium- to long-term perspective, we are likely to see some adverse changes in the cost position of our greenhouse gas-intensive assets as a result of regulatory impacts in the countries where we do business. These proposed regulatory mechanisms may adversely affect our assets directly, or indirectly through our suppliers and customers. Assessments of the potential impact of future climate change regulation are uncertain given the wide scope of potential regulatory change in the many countries in which we do business. Examples of this include China, which launched the world’s largest emissions trading system in 2017, and Australia, where the Federal Government repealed a carbon tax in 2014 and introduced new legislation to take its place.
	There is a potential gap between the current valuation of fossil fuel reserves on the balance sheets of companies and in global equities markets and the reduced value that could result if a significant proportion of reserves were rendered incapable of extraction in an economically viable fashion due to technology, regulatory or market responses to climate change. The Group’s asset carrying values may be affected by any resulting adverse impacts to reserve estimates and our inability to make productive use of such reserves may also negatively impact our financial condition and results.

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Sustainability risks
	The growth of alternative energy supply options, such as renewables and nuclear, could also present a change to the energy mix that may reduce the value of fossil fuel assets.
	The physical effects of climate change on our assets may include changes in rainfall patterns, water shortages, rising sea levels, increased storm intensities and higher temperatures. These effects could materially and adversely affect the financial performance of our assets.
	Community
	Our assets and activities may directly impact communities and also risk the potential for adverse impacts on human rights or breaches of other international laws or conventions.
	Local communities may become dissatisfied with our operations or oppose our new development projects, including through legal action, leading to potential schedule delay, increased costs and reduced production. Community-related risks may include community protests or civil unrest, adverse human rights impacts, community health and safety complaints and grievances, shareholder activism and civil society activism. In extreme cases the risks may affect viability, adversely impacting our reputation and licence to operate.
	Hydraulic fracturing
	Our Onshore US assets have involved hydraulic fracturing, which includes using water, sand and a small amount of chemicals to fracture hydrocarbon-bearing subsurface rock formations, to allow the flow of hydrocarbons into the wellbore. We depend on the use of hydraulic fracturing techniques in our Onshore US drilling and completion programs.
	In the United States, the hydraulic fracturing process is typically regulated by relevant US state regulatory bodies. Arkansas, Louisiana and Texas (the states in which we currently operate) have adopted various laws and regulations, or issued regulatory guidance, concerning hydraulic fracturing. Some states are considering changes to regulations in relation to permitting, public disclosure, and/or well construction requirements on hydraulic fracturing and related operations, including the possibility of outright bans on the process. For more information, refer to section 7.10.
	On 27 July 2018, BHP announced that we had entered into agreements for the sale of our entire interest in the Eagle Ford, Haynesville, Permian and Fayetteville Onshore US oil and gas assets. Both sales are subject to the satisfaction of customary regulatory approvals and conditions precedent. We expect completion of both transactions to occur by the end of October 2018.

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Sustainability risks
	While we have not experienced a material delay or substantially higher operating costs in our Onshore US assets as a result of current regulatory requirements, we cannot predict whether additional federal, state or local laws or regulations will be enacted prior to the completion of the two sale transactions and, if so, what such actions would require or prohibit. Additional legislation or regulation could subject those assets to delays and increased costs, or prohibit certain activities prior to completion of the transactions. Separately, additional legislation or regulation could impose liabilities on previous owners or operators of properties where hydraulic fracturing has taken place, which may be applicable to BHP notwithstanding the subsequent sale of those assets.
	Governance and compliance
	Our processes are mandated and governed by the global Our Requirements standards and supporting strategies and frameworks. A failure to maintain effective global frameworks and associated controls may lead to a major health, safety or environmental incident.

1.6.5    Management of principal risks

The scope of our operations and the number of industries in which we operate and engage mean that a range of factors may impact our results. Principal risks that could negatively affect our results and performance are described in section 1.6.4. Our approach to managing these risks is outlined below.

Principal risk area	Risk management approach
External risks
Risks arise from fluctuations in commodity prices and demand in major markets (in particular China) or changes in currency exchange rates and actions by governments, including new regulations and standards, alleged compliance breaches and political events that impact long-term fiscal stability	The diversification of our portfolio of commodities, markets, geographies and currencies is a key strategy for reducing the effects of volatility. Section 1.6.1 describes external factors and trends affecting our results and note 20 ‘Financial risk management’ in section 5 outlines BHP’s financial risk management strategy, including market, commodity and currency risk. The Financial Risk Management Committee oversees these risks as described in sections 2.14 and 2.15. We also engage with governments and other key stakeholders to make sure the potential adverse impacts of proposed fiscal, tax, resource investment, infrastructure access, regulatory changes and evolving international standards are understood and, where possible, mitigated.
	Our Code of Conduct sets out requirements related to working with integrity, including dealings with government officials and third parties as described in section 2.16. Processes and controls are in place for the internal control over financial reporting, including under Sarbanes-Oxley. We have established anti-corruption, competition and trade sanctions performance requirements, which are overseen by the Ethics and Compliance function as described in section 1.9.1. The Disclosure Committee oversees our compliance with securities dealing obligations and continuous and periodic disclosure obligations, as described in sections 2.14, 2.15 and 2.17.

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Principal risk area	Risk management approach
Business risks
Risks include the inherent uncertainty of identifying and proving reserves, adding and divesting assets and managing our capital development projects	Our Geoscience and Resource Engineering Centres of Excellence manage assurance and technical leadership for Ore Reserves reporting as described in section 6.3.2. Our governance over reporting of Petroleum reserves is described in section 6.3.1.
	We have established investment approval processes that apply to all investment decisions, including mergers and acquisitions activity. An Investment Committee oversees these as described in sections 2.14 and 2.15. We have an ongoing strategy practice that assesses the competitive advantage of our business, enables identification of risks and opportunities for our portfolio that allows us to challenge bias when evaluating future growth options and attractive growth options under a range of divergent future states. Our Capital Allocation Framework provides the structure and governance for adding growth options to our portfolio.
	Our global Projects function (through its regional Project development and delivery teams and the Projects Centre of Excellence) aims to make sure projects are safe, predictable and competitive.
Financial risks
Continued volatility in global financial markets may adversely impact future cash flows, our ability to adequately access and source capital from financial markets and our credit rating. Volatility may impact planned expenditures, as well as the ability to recover investments in mining, oil and gas projects. In addition, the commercial counterparties (customers, suppliers, contractors and financial institutions) we transact with may, due to adverse market conditions, fail to meet their contractual obligations	We seek to maintain a strong balance sheet, supported by our portfolio risk management strategy. As part of this strategy, the diversification of our portfolio reduces overall cash flow volatility. Commodity prices and exchange rates are not generally hedged, and wherever possible, we take the prevailing market price. We use Cash Flow at Risk analysis to monitor volatilities and key financial ratios. Credit limits and review controls are established for all customers and financial counterparties. The Financial Risk Management Committee oversees these, as described in sections 2.14 and 2.15. Note 20 ‘Financial risk management’ in section 5 outlines our financial risk management strategy.

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Principal risk area	Risk management approach
Operational risks
Unexpected natural and operational catastrophes may adversely affect our assets. Information technology and operational technology services are subject to cybersecurity risks and threats that may materially affect our business and reputation. Our potential liabilities from litigation and other actions resulting from the Samarco dam failure are subject to significant uncertainty and cannot be reliably estimated at this time. Operating cost pressures and reduced productivity could negatively affect operating margins and expansion plans. Non-operated joint ventures may not comply with our standards	By applying our risk management processes, we seek to identify catastrophic operational risks and implement the critical controls and performance requirements to maintain control effectiveness. Business continuity plans and crisis and emergency management plans are established to mitigate consequences. Consistent with our portfolio risk management approach, we continue to be largely self-insured for losses arising from property damage, business interruption and construction. Given we rely heavily on information technology and operational technology to operate assets, we employ a number of measures to protect, detect and respond to cyber events. A cyber risk management strategy has been developed to address how we maintain the security of our technology assets that support our operations across the globe. This strategy includes activities to be undertaken, including employee cybersecurity awareness and training programs, monitoring of our enterprise and operational technology networks, vulnerability identification and remediation activities, secure-by-design architecture and processes for the management of third party technology risks. We have a dedicated in-house cybersecurity function that supports business groups, continuously improves our cyber defence capability and responds to cyber incidents where required. When incidents occur, they are investigated through root-cause analysis and, as required, follow-up actions are undertaken.
	The Board receives periodic updates on cyber risk management activities, including relevant information on any significant cyber incidents that have occurred. In the event of a significant cyber incident, an incident notification plan is in place to facilitate timely communication of the incident to stakeholders, including the Board, Corporate Affairs, Government Relations and/or Investor Relations.
	The Board continues to oversee the Group’s response to the tragedy at Samarco, with the work of the Samarco Sub-Committee having transitioned to the Risk and Audit Committee, the Sustainability Committee and the Board, as appropriate. The Board and its Committees continue to examine and oversee the progress of actions in relation to the management of tailings dams (refer to section 1.8 and the BHP Sustainability Report 2018 for more information) and non-operated joint venture arrangements, the contribution to the Fundação Renova, the availability of funding to Samarco and continued negotiations in respect of the framework for the settlement of the public civil claims.
	We aim to maintain adequate operating margins through our strategic objective to position BHP to match our values, capabilities and competitive resources to the evolving needs of markets, to create sustainable long-term value for shareholders and other stakeholders.
	Our concentrated effort to reduce operating costs and drive productivity improvements has realised tangible results, with a reduction in controllable costs.

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Principal risk area	Risk management approach
	The capability to sustain productivity improvements is being further enhanced through continued refinements to our Operating Model. The Operating Model is designed to deliver a simple and scalable BHP, providing a competitive advantage through defining work, organisational and performance measurements. Defined global business processes, including 1SAP, provide a standardised way of working across BHP. Common processes generate useful data and improve operating discipline. Global sourcing arrangements have been established to ensure continuity of supply and competitive costs for key supply inputs. We seek to influence the application of our standards to non-operated joint ventures.
	From an industrial relations perspective, detailed planning is undertaken to support the renegotiation of employment agreements and is supported by training and access to expertise in negotiation and agreement making.
Sustainability risks
HSEC incidents or accidents may adversely affect people or neighbouring communities, assets, reputation and our licence to operate. The potential physical impacts and related responses to climate change may impact the value of BHP, our assets and markets	Our approach to sustainability risks is reflected in Our Charter and described in section 1.9. The Our Requirements standards set out Group-wide HSEC-related performance requirements designed to support effective management control of these risks. The global HSE planning process and the validation of the Our Requirements standards identify gaps in these standards, and inform global improvements to the HSE framework.
	Our approach to corporate planning, investment decision-making and portfolio management provides a focus on the identification, assessment and management of climate change risks. We have been applying an internal price on carbon in our investment decisions for more than a decade. Through a comprehensive and strategic approach to corporate planning, we use a divergent set of scenarios to assess our portfolio, including consideration of a broad range of potential policy responses to and impacts from climate change. We also track signals across the external environment to provide timely insights into the potential impacts on our portfolio.
	For more information on the management of climate change, refer to section 1.9.8.
	Our approach to engagement with community stakeholders is outlined in the Our Requirements for Communications, Community and External Engagement standard. We undertake stakeholder identification and analysis, social impact and opportunity assessments, community perception surveys and human rights impact assessments to identify, mitigate or manage key potential social and human rights risks, as described in section 1.9.
	The Our Requirements for Risk Management standard provides the framework for risk management relating to climate change and material health, safety, environmental and community risks. We conduct internal audits to test compliance with the Our Requirements standards and develop action plans to address any gaps. Key findings are reported to senior management and reports are considered by relevant Board committees.

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1.7    People

Everyone who works at BHP is required to hold themselves accountable for living BHP values as outlined in Our Charter; to put safety first; to make people a priority; to be functionally excellent; and to work with integrity.

1.7.1    Our leaders

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1.7.2    Our people

With a workforce of more than 62,000 employees and contractors working across 90 locations worldwide, BHP’s culture is shaped to support the creation of value from our portfolio. We are committed to investing in our workforce so that our people have the right skills and a healthy culture in which to thrive.

At BHP, we provide competitive remuneration to reward employees for their expertise and commitment to fulfilling our business strategy and contribution to our long-term success. Our remuneration frameworks and principles are designed to inspire our employees to embrace the core objectives and values that reflect our commitment to safety, culture and productivity. The primary focus areas for FY2018 included building a culture that promotes trustful relationships and care, increasing the capability of our leaders, and recruiting a diverse workforce. In particular, we work with our leaders to develop their capabilities, recognising the vital role they play in developing engaged employees and supporting ongoing improvements in safety and productivity.

For example, in FY2018, 40 General Managers from our operations around the globe (who are responsible for 75 per cent of BHP’s workforce) attended 10 days of face-to-face workshops and contributed to projects aimed at solving complex business problems. They received intensive technical and leadership training that formed part of a strategy to cultivate a diverse general manager cohort with the capability to run safe, effective and efficient operations. The leadership programs will be expanded in FY2019 to include more operational managers.

More than 90 per cent of maintenance managers from Minerals Australia attended our Maintenances Academies, a development initiative from our Maintenance Centre of Excellence. The sessions broadened leaders’ technical knowledge, leadership capability and collaboration with peers.

Outside of leadership capability, we are streamlining our systems, processes, tools and behaviours to improve operational capability.

Our people policies

We have a comprehensive set of frameworks that support our culture, and drive our focus on safety and productivity.

Our Charter is central to everything we do. It describes our purpose, our values, how we measure our success, who we are, what we do and what we stand for.

Our Code of Conduct demonstrates how to practically apply the commitments and values set out in Our Charter and reflects many of the standards and procedures we apply throughout BHP. We have a business conduct advisory service, as well as internal dispute and grievance handling processes, to report and address any potential breaches of Our Code.

The Our Requirements standards outline the minimum mandatory standards we expect of those who work for, or on behalf of, BHP. Some of those standards relate to people activities, such as recruitment and talent retention.

Our all-employee share purchase plan, Shareplus, is available to all permanent full-time and part-time employees and those on fixed term contracts, except where local regulations limit operation of the scheme. In these instances, alternative arrangements are in place.

Through all of these documents, we make it clear that discrimination on any basis is not acceptable. In instances where employees require support for a disability, we work with them to identify any roles that meet their skill, experience and capability and offer retraining where required.

The information in this section illustrates how these policies have been implemented and the steps that we take to measure their effectiveness.

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Inclusion and diversity

At BHP, we believe that all our people should have the opportunity to fulfil their potential and thrive in an inclusive and diverse workplace. Inclusion and diversity promote safety, productivity and wellbeing within BHP. We employ, develop and promote people based on merit and do not tolerate any form of unlawful discrimination, bullying or harassment. Our systems, processes and practices empower fair treatment.

For more information on Board diversity and our Board’s support for inclusion and diversity, refer to section 2.5.

Case study

Job sharing in Queensland Coal

Diversity in all of its forms improves our workplace. The business case for this is clear.

We’ve observed that our most inclusive and gender diverse teams perform better than the BHP average in areas such as safety, production, cost efficiency, employee engagement and mental health. Flexible working is also an important factor in attracting the best and most diverse mix of people to BHP.

So we’re working to make flexible work part of the everyday experience of all our people. As of FY2018, almost half of our people were working flexibly – and another nine per cent have indicated that they plan to work flexibly in the next 12 months.

Our Queensland Coal mines are leading the way with a site-based flexible work program. Employees at our Coal operations can take advantage of a job share register to find other employees who are interested in setting up a job share arrangement, even if they’re from different crews.

Billy Brant and David Kerr are both Maintenance Superintendents at Caval Ridge and work part-time, job sharing. Six months have passed since Billy and Dave started job sharing and Tony Ladewig, a Maintenance Superintendent at Caval Ridge, says that, from his perspective, the flexible work arrangement is working really well.

‘Both Billy and Dave return supercharged, and this gives me a lift as well – by simply being around their positive energy,’ said Tony.

Given the success of the Coal job share register, the program is now being considered by other BHP sites around the world.

Gender balance

We have an aspirational goal to achieve gender balance globally by CY2025. At the end of FY2018, there were 915 more women at BHP than at the same time in the previous year, contributing to an increase in the representation of women by 1.9 per cent up to 22.4 per cent. These results show we are making progress, although we did not achieve the three per cent annual growth to which we aspire.

The external hiring ratio of 39.8 per cent women and 60.2 per cent men remains the strongest contributor to improved female representation outcomes, and is a marked increase in female hiring compared to FY2015 (10.4 per cent). The turnover of women (9.7 per cent) is still higher than the rate for men (6.5 per cent). However, the take up of flexible working (a key lead indicator of improving the representation of women) has increased to 46 per cent in FY2018 from 41 per cent in FY2017.

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The focus areas of our strategy to achieve a more diverse and inclusive workplace include:

• embedding flexibility in the way we work;

• encouraging and working with our supply chain partners to support our commitment to inclusion and diversity;

• uncovering and taking steps to mitigate potential bias in our behaviours, systems, policies and processes;

• ensuring our brand is attractive to a diverse range of people.

Flexible working

Flexible work promotes greater workforce diversity.

We have seen both long-distance commuters and residential employees at our operations implement flexible rosters, job share arrangements and take breaks from work. This has challenged the prevailing mindset that flexibility is only available to office-based employees. For example, in Western Australia Iron Ore, 28 (seven per cent) of our train drivers are now working flexibly via job sharing arrangements.

Working with suppliers

BHP’s Supply team continues to lead a comprehensive program of work to build inclusion and diversity incentives into contracts in Australia. We engage with mobile equipment manufacturers to design tools and equipment for use by a diverse workforce and encourage them to embrace diversity in their work teams. BHP has encouraged suppliers to support greater diversity through ergonomic design and product development.

Mitigating potential bias

A number of employees have been trained to recognise and mitigate potential bias through more inclusive behaviour towards all employees. Policies and systems have been changed to reduce potential bias. BHP has taken steps to reduce potential bias in recruitment and conducts an annual pay gap review, the results of which are reported to the Board’s Remuneration Committee. Together, these measures seek to address future pay disparities between men and women.

Employer brand

Inclusion and diversity continue to be a strong theme in our internal communications to our employees. To ensure BHP and our industry are attractive to a diverse range of people external to the business, we implemented a number of initiatives in FY2018. For example, we ran proactive media and online campaigns that highlighted our progress in flexible work and our broader inclusion and diversity agenda.

LGBT+ inclusion

At BHP, we want to provide a safe, inclusive and supportive workplace for all. It’s part of bringing your whole self to work. Jasper is BHP’s employee inclusion group for BHP’s lesbian, gay, bisexual, transgender and others (LGBT+) community and its allies. Formally endorsed by the Executive Leadership Team and Global Inclusion and Diversity Council, Jasper’s aim is to drive a safe and inclusive work environment for everyone by providing advice on ways to reduce bias and ensure LGBT+ people are respected and valued no matter their sexual or gender identity.

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Indigenous employment

We aim to provide employment opportunities in our host communities that contribute to sustainable social and economic benefits for Indigenous peoples. In Minerals Australia, Indigenous employment increased from 4.1 per cent to 4.4 per cent and 25 per cent of all apprentices and 7.2 per cent of graduates were Aboriginal and Torres Strait Islander peoples. In North America, we have focused on working with our contracting partners to support the employment of First Nations and Métis peoples, who comprise 6.2 per cent of our workforce at the Jansen Potash Project. The South American Indigenous Peoples Plan focuses on establishing targets and designing a pilot program to recruit and retain Indigenous peoples. For more information, refer to our Sustainability Report 2018.

Employee relations

In FY2018, BHP Mitsubishi Alliance Pty Ltd concluded a two-year negotiation of its primary enterprise agreement in Australia, with no lost time due to industrial action. Overall, BHP has achieved a year with only 24 hours of lost time due to industrial action in Minera Escondida Limitada. On 17 August 2018, Escondida successfully completed negotiations with Union N°1 and signed a new collective agreement, effective for 36 months from 1 August 2018.

1.7.3    Employees and contractors

The data in this section (consistent with previous years) are averages. We take the number of employees and contractors (where applicable) at the last day of each calendar month for a 10-month period to calculate an average for the year. This does not necessarily reflect the number of employees and contractors as at the end of FY2018. All the data in this section includes Continuing and Discontinued operations for the financial years being reported.

The diagram below shows the average number of employees and contractors over the last three financial years, and a breakdown of our average number of employees by geographic region over the last three financial years.

⁽¹⁾  Data includes Continuing and Discontinued operations for the financial years being reported.

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The table below shows the gender composition of our employees, senior leaders and the Board over the last three financial years.

	2018		2017		2016
Female employees (1)		5,907		4,868		4,708
Male employees (1)		21,254		21,278		22,119
Female senior managers (2)(3)		70		65		65
Male senior managers (2)(3)		235		211		251
Female Board members (2)		3		3		3
Male Board members (2)		7		7		7

⁽¹⁾  Based on the average of the number of employees at the last day of each calendar month for a 10-month period to April, which is then used to calculate an average for the year to 30 June. Data includes Continuing and Discontinued operations for the financial years being reported. These numbers differ from the ‘point in time’ snapshot as used in internal management reporting for the purposes of monitoring progress against our goals, which are reported in section 1.7.2.

⁽²⁾  Based on actual numbers as at 30 June 2018, not rolling averages. Data includes Continuing and Discontinued operations for the financial years being reported.

⁽³⁾  For the purposes of the UK Companies Act 2006, we are required to show information for ‘senior managers’, which are defined to include both senior leaders and any persons who are directors of any subsidiary company, even if they are not senior leaders. In FY2018, there were 290 senior leaders at BHP. There were 15 Directors of subsidiary companies who are not senior leaders, comprising 13 men and 2 women. Therefore, for UK law purposes, the total number of senior managers was 235 men and 70 women (23 per cent women) in FY2018. Data includes Continuing and Discontinued operations for the financial years being reported.

1.8    Samarco

The Fundão dam failure

On 5 November 2015, the Fundão tailings dam operated by Samarco Mineração S.A. (Samarco) failed. Samarco is a non-operated joint venture owned by BHP Billiton Brasil Limitada (BHP Billiton Brasil) and Vale S.A. (Vale), with each having a 50 per cent shareholding.

A significant volume of tailings (water and mud-like waste resulting from the iron ore beneficiation process) was released. Tragically, 19 people died – five community members and 14 people who were working on the dam when it failed. The communities of Bento Rodrigues, Gesteira and Paracatu were flooded. A number of other communities further downstream in the states of Minas Gerais and Espírito Santo were also affected by the tailings, as was the environment of the Rio Doce basin.

Our response and support for Fundação Renova

Over two years into the recovery process, we remain committed to doing the right thing for the people and the environment in the Rio Doce region, in a challenging and complex operating context.

In accordance with the Framework Agreement with the relevant Brazilian authorities that was signed in March 2016, work to restore the environment and re-establish communities is being undertaken by Fundação Renova. Fundação Renova is a not-for-profit, private foundation, established by BHP Billiton Brasil, Vale and Samarco. As well as remediating the impacts of the dam failure, Fundação Renova is implementing a range of compensatory actions aimed at leaving a lasting positive legacy for the people and environment of the Rio Doce.

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BHP is focused on supporting Fundação Renova’s operations through representation on the Board of Governors and Board Committees, making available secondees who work within the Foundation to provide their technical expertise on priority areas, and regular peer engagement on issues such as safety, risk management, human rights and compliance.

Fundação Renova

The activities of Fundação Renova are overseen by an Interfederative Committee comprising representatives from the Brazilian Federal and State Governments, local municipalities, environmental agencies, impacted communities and the Public Defense Office, who monitor, guide and assess the progress of actions agreed in the Framework Agreement.

Fundação Renova is governed by a Board of Governors, comprising representatives nominated by BHP Billiton Brasil, Vale, Samarco and the Interfederative Committee. The Board of Governors appoints an Executive Board, including the CEO, which is responsible for the operational management of the Foundation. Fundação Renova’s Chief Executive is Roberto Waack, a biologist with an extensive background in sustainability-related organisations, including World Wide Fund for Nature (WWF) Brazil, Global Reporting Initiative, Forest Stewardship Council, Ethos Institute and the Brazilian Biodiversity Fund.

Fundação Renova’s governance structure also comprises a Fiscal Council, Advisory Council, seven Board Committees, a technical sub-committee, a Compliance Manager and an Ombudsman. The Advisory Council includes representation from impacted communities and community development and education experts.

Fundação Renova’s staff of approximately 500 people is supported by around 5,000 contractors. Its CY2018 budget is R$2.19billion.

Due to the diversity, scale and complexity of the programs, Fundação Renova collaborates and engages broadly with affected communities, scientific and academic institutions, regulators and civil society.

An independent scientific technical and advisory panel, established by the International Union for Conservation of Nature (IUCN), is providing expert advice to Fundação Renova. Chaired by Yolanda Kakabadse, formerly Environment Minister for Ecuador and President of WWF International, the panel meets monthly. In addition, the panel has undertaken two field visits to the impacted areas in Brazil, incorporating extensive engagement with affected and interested parties. Guided by the principles of independence, transparency, accountability and engagement, the panel will publish short-term issues papers and longer-term thematic papers, with the first paper scheduled for release in the first quarter of FY2019. Other papers planned will cover topics such as the ecological processes to maintain coastal lakes, the impact of fishing bans and economic alternatives for the region.

Resettlement

One of Fundação Renova’s priority social programs is the livelihood restoration program to relocate and rebuild the communities of Bento Rodrigues, Paracatu and Gesteira. A key to the success of this program is the participation of affected community members, their technical advisers, State Prosecutors, municipal leaders, regulators and other interested parties.

The process involves the identification and acquisition of land, design and planning for the urban development, including all services and public buildings (schools, health centres, squares, covered sports grounds and religious buildings) and construction of new houses for the affected people. The resettlement also involves the employment of community members and provision of support services to help them resume their way of life.

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The resettlement of Bento Rodrigues is progressing, with active participation of community members, government agencies and local prosecutors. Following the selection of the preferred location for the new town in 2016, the land has been acquired. On 8 February 2018, the community members voted overwhelmingly in favour of the town plan they helped to design, and in May they commenced working with architects to design their new homes. Preparations for site works, including laydown areas and construction site facilities, are underway. On 5 July, the state environment regulator issued the licence in a public ceremony. The authorisations of the State Urban Planning Regulator and Municipality were issued on 1 August 2018, allowing the construction of the Bento community to commence.

The same process is being followed for Paracatu. The land has been selected and the urban plan is expected to be approved by the community in September 2018. Progress at Gesteira, the smallest of the three resettlements, has been delayed by a series of land access issues and discussions around the exact number of families to be included in the resettlement. Fundação Renova has worked hard to resolve these issues and is now working with the community and its technical advisers to determine a solution.

Based on current planning, it is expected that all resettlements will be completed in 2020.

Remediation

Through FY2018, Fundação Renova’s work included the continued monitoring and maintaining of the emergency vegetation established on the terrestrial areas impacted by the initial tailings flow along the rivers and tributaries, resulting in ongoing improvements to water quality. Negotiations commenced with regulators and landowners to determine the long-term remediation plans of these areas for biodiversity, agricultural and urban uses.

A pilot study was conducted to assess the methodology for evaluating alternative tailings remediation options. It concluded that the river was quickly re-establishing its geomorphological processes and that large-scale actions to try and remove tailings from the bed or banks of rivers would likely lead to greater environmental harm than allowing the normal river processes to naturally remediate the tailings material. The pilot study was submitted to the regulators in May 2018 for review and will be subject to further discussions as to how the methodology could be applied to other sections of the rivers.

Water quality in the Gualaxo do Norte River has achieved the turbidity target set in the Framework Agreement a year earlier than required. All immediate river and tributary remediation activities to limit further contribution of tailings have been completed. Longer-term remediation measures are in the process of being designed in consultation with regulators and other stakeholders.

Water quality, aquatic habitat and fish surveys continue to be conducted in the rivers and coastal zone to understand the impact of the tailings flow and the rate of recovery of the ecological systems. Results from these studies indicate that, while sediment in the river channels along the spill flow path upstream of Candonga continues to limit the re-establishment of habitats and aquatic fauna diversity and abundance, the natural sediment transport processes will ultimately restore suitable habitat. Methods to enhance the rate of habitat recovery are being investigated.

The studies clearly demonstrate that the fish are safe for human consumption in terms of metal concentrations. Fishing bans remain in place for native species in the Rio Doce and impacted tributaries in Minas Gerais and all species along a zone of the Espírito Santo coast. Regulators have required more studies to be undertaken along the river and coast by research institutions, with preliminary results scheduled for late CY2019. Given the significant impacts of the fishing bans on the livelihoods of commercial and subsistence fishermen and the social cohesion within their communities, BHP Billiton Brasil has been providing technical support to Fundação Renova to accelerate the collection of data to address the concerns of regulators and the community. This includes analysis of the safety of fish for human consumption and the status of fish populations to support lifting of the bans.

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Environmental compensation programs for the rehabilitation of 40,000 hectares are in the final stages of design, with 3,000 hectares scheduled to be completed in CY2019. More than 500 degraded natural springs have been revegetated as part of a Framework Agreement commitment to rehabilitate 5,000 springs over 10 years.

The retention structures to contain the tailings material remaining within the Fundão Valley continue to operate as designed and limit further contributions from this source to river turbidity.

Financial assistance and compensation

Fundação Renova has distributed around 9,500 financial assistance cards to those whose livelihoods were impacted by the dam failure, including registered and informal commercial fishermen who are unable to fish due to the imposition of fishing bans in the Rio Doce and along the coast of Espirito Santo. The payments are designed to ensure those impacted have the capacity to support themselves and their families pending the re-establishment of conditions that enable them to resume their economic activities.

During FY2018, assistance was expanded to include a number of new geographic areas and to cover subsistence fishermen who rely on fish for food security. The form of assistance is still being finalised.

A mediated compensation program is also being implemented throughout the impacted regions, which is intended to fairly compensate all individuals impacted by the dam failure. It comprises two key components:

(1) The Water Damages component compensated people for an interruption to public water supplies for seven to 10 days following the dam failure. Of 440,000 people who were eligible for compensation, just over 260,000 participated in the program, at a cost of approximately R$265 million.

(2) The General Damages component covers all other impacts, including loss of life, injury, property, business impacts, loss of income and moral damages. The program was designed based on inputs from public agencies, technical entities and impacted families and has been validated by the Interfederative Committee. Around 20,000 people have been registered under the program, with around 6,600 people having received their payments by 27 July 2018. Claimants who choose not to participate in the program or are deemed to be ineligible under the program rules retain the right to progress their claims through the courts.

Governance Agreement

On 25 June 2018, Samarco, Vale and BHP Billiton Brasil, the other parties to the Framework Agreement, the Public Prosecutors Office and the Public Defense Office agreed an arrangement (the Governance Agreement) which settles the R$20 billion (approximately US$5.2 billion) civil claim (R$20 billion Public Civil Claim), enhances community participation in decisions related to the remediation and compensation programs under the Framework Agreement (Programs) and establishes a process to renegotiate those Programs over two years and to progress settlement of the R$155 billion (approximately US$40 billion) civil claim (R$155 billion Federal Public Prosecution Office claim).

Legal claims

The Governance Agreement was ratified by the 12th Federal Court of Minas Gerais on 8 August 2018, settling the R$20 billion Public Civil Claim and suspending the R$155 billion Federal Public Prosecution Office claim for a period of two years from the date of ratification.

Renegotiation process

During the two-year period, the parties will work together to design a single process for the renegotiation of the Programs and progress settlement of the R$155 billion Federal Public Prosecution Office claim. The renegotiation process will take into account the principles and rules established under the Framework Agreement, and will be aimed at improvement of the Programs, with the involvement of the affected communities.

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The renegotiation of the Programs will be based on certain agreed principles, such as full reparation consistent with Brazilian law, the requirement for a technical basis for any proposed changes, consideration of findings from the socio-economic and socio-environmental experts appointed by Samarco, Vale and BHP Billiton Brasil, consideration of findings from experts appointed by the Prosecutors and consideration of the feedback from the impacted communities. During the renegotiation period and up until revisions to the Programs are agreed, the Fundação Renova will continue to implement the Programs in accordance with the terms of the Framework Agreement and the Governance Agreement.

Governance arrangements

A revised governance structure has been agreed, based on the Framework Agreement, that enhances community participation in the process.

Prior to the Governance Agreement, the Interfederative Committee comprised 12 members, with six being appointed by Samarco, Vale and BHP Billiton Brasil and one by the Interfederative Committee. The revised structure includes four additional members of the Interfederative Committee, with three being appointed by affected communities and one by the Public Defense Office. It also includes two additional members of the Renova Board who will be appointed by the affected communities.

A network of Local and Regional Commissions has also been established along the Rio Doce to secure community participation in the decision-making relating to the Programs.

Restart

Restart of Samarco’s operations remains a focus but is subject to separate negotiations with relevant parties and will occur only if it is safe, economically viable and has the support of the community. Resuming operations requires the granting of licences by state and federal authorities, community hearings and an appropriate restructure of Samarco’s debt.

Progress on our commitments

Following the investigation into the causes of the dam failure, BHP identified a number of actions that we would take in our management of tailings dams and non-operated joint venture arrangements to help to prevent a similar event from occurring.

Dam management

We committed to undertake dam safety reviews in accordance with the Canadian Dam Association’s process, assess technology options to enhance dam management and create a centralised dam management function.

Dam safety reviews: We have performed dam safety reviews following the procedures recommended by the Canadian Dam Association for significant active, inactive and closed tailings facilities across the Group. Implementation of the recommendations is currently in progress. No significant deficiencies that represent an immediate threat to the stability of the dams have been identified.

Technology: Monitoring systems at all significant tailings dams have been supplemented where necessary and continue to be improved as new instrumentation and methods become available. We are funding studies to develop early warning technologies and improve knowledge of the liquefaction phenomenon. We are also working with vendors on the testing and development of advanced tailings dewatering methods.

Dam management: A global tailings expert has been appointed to provide centralised governance and technical expertise.

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More information on our ongoing dams and tailings management is available in our Sustainability Report 2018 at bhp.com.

Working with non-operated joint ventures

We also undertook to centralise management of our interest in all major non-operated minerals joint ventures in the Minerals Americas operating group and to work to establish a new global standard for non-operated joint ventures (NOJVs).

We have created a centralised team that is a single point of accountability for NOJVs within BHP. That team has developed a global standard which defines the requirements for managing BHP’s interest in our NOJVs. The team has also set out a strategy for managing our interest in NOJVs, focused on supporting strong governance, managing risk and creating value from our investment, within the limits of our rights as joint venture partners. For more information on the team and its work, refer to section 1.10.

More information on health, safety and environment performance at our NOJVs is available in our Sustainability Report 2018 at bhp.com.

1.9    Sustainability

Full details of our sustainability approach and performance are set out in our Sustainability Report 2018 available at bhp.com.

BHP’s strategy of owning and operating long-life assets means that we think and plan in decades. We can create long-term value only if we safeguard the sustainability of our operations with the support of the communities in which we work. To do that, we must form and maintain deep, authentic and respectful relationships with all our stakeholders.

1.9.1    Our approach to sustainability

Sustainability is one of the core values set out in Our Charter. To us, sustainability means putting health and safety first, being environmentally responsible and supporting our communities. The wellbeing of our people, the community and the environment is considered in everything that we do.

The Board oversees our sustainability approach, with the Board’s Sustainability Committee assisting with governance and monitoring. The Sustainability Committee also oversees HSEC-related risks, legal and regulatory compliance and overall HSEC and other human rights performance. The Board’s Risk and Audit Committee assists with oversight of the Group’s systems of risk management.

We set clear targets to challenge ourselves, drive improvement and allow stakeholders to assess our performance in areas that matter most. To realise these targets, we embed sustainability performance measures throughout the Group, from Group-wide key performance indicators to balanced scorecards for individual employees.

All data in this section 1.9 includes Continuing and Discontinued operations for the financial years being reported.

Transparency and accountability

Transparency and accountability are fundamental to trust. It is trust that underpins the social contract, in which corporations, governments and communities agree to work together for our mutual best interest. Without transparency, there cannot be accountability for sharing the proceeds of wealth and fair distribution of taxes.

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Our commitment to transparency goes beyond complying with regulation. We need to demonstrate that we are playing our part in the social contract to maintain our licence to operate for the long term. Our approach is guided by our Transparency Principles of responsibility, openness, fairness and accountability. We were the first in our sector to disclose payments to governments on a project-by-project basis in 2015. This year, we have also disclosed our profit, number of employees and adjusted effective tax rates on a country-by-country basis.

Economic transparency is not our only focus. We have a strong record of supporting robust reporting on climate change issues. We were one of the first companies to report in accordance with the recommendations of the Financial Stability Board’s Task Force on Climate-related Financial Disclosures. In August 2018, we published a comprehensive report of our water risks and usage.

Our conduct

Wherever we operate, we strive to do so with integrity – doing what is right and doing what we say we will do. This is fundamental to building and maintaining the trust we need for long-term value creation.

Our Code of Conduct (Our Code) sets the standard for BHP’s commitment to working with integrity and respect. Our Code sets out standards of behaviour for our people in their dealings with governments and communities, third parties, and each other. Our Code guides us in our daily work and demonstrates how to practically apply the commitments and values set out in Our Charter. Acting in accordance with Our Code is a condition of employment for everyone who works for and on behalf of BHP and it is accessible to all our people and external stakeholders on our website (bhp.com). All our people are required to undertake annual training on Our Code.

BHP does not tolerate any form of retaliation against anyone who speaks up about potential misconduct or participates in an investigation.

Anti-corruption

Corruption misallocates resources, reinforces poverty, undermines the integrity of government and community decision-making and wastes opportunities that arise from resource development. We are committed to contributing to the global fight against corruption and working with business, government and civil society to support this effort.

Our commitment to anti-corruption compliance is embodied in Our Charter and Our Code. We also have a specific anti-corruption procedure, which sets out mandatory requirements to identify and manage the risk of anti-corruption laws being breached. We prohibit authorising, offering, giving or promising anything of value directly or indirectly to a government official to influence official action, or to anyone to encourage them to perform their work disloyally or otherwise improperly. We also require our people to take care that third parties acting on our behalf do not violate anti-corruption laws. A breach of these requirements can result in disciplinary action, including dismissal.

Our Ethics and Compliance function has a mandate to design and govern BHP’s compliance frameworks for key compliance risks, including anti-bribery and corruption. The function is independent of our assets and asset groups, and comprises teams that are co-located in our main global locations and a specialised Compliance Legal team. The Chief Compliance Officer reports twice a year to the Risk and Audit Committee, and separately to the Committee Chairman, also twice a year.

Our anti-corruption compliance program is designed to meet the requirements of the US Foreign Corrupt Practices Act, the UK Bribery Act, the Australian Criminal Code and applicable laws of all places where we do business. These laws are consistent with the standards of the OECD Convention on Combating Bribery of Foreign Public Officials in International Business Transactions. We regularly review our anti-corruption compliance program to make any changes required by regulatory developments.

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In addition to anti-corruption training as part of annual training on Our Code, additional risk-based anti-corruption training was completed by 7,406 employees in FY2018 and numerous employees of business partners and community partners.

1.9.2    Safety

Our highest priority is the safety of all those impacted by our operations, including our employees and contractors and the communities in which we operate. We achieve nothing if we do not do it safely.

BHP has a goal of zero fatalities. Tragically, two of our colleagues died in FY2018. Daniel Springer, a contractor from Independent Mining Services, suffered fatal injuries in August 2017 as a result of an incident while removing a curved wear plate from the back of an excavator bucket at Goonyella Riverside Mine. In November 2017, a sub-contractor from our Onshore US asset suffered fatal injuries when he was struck by a forklift during well-completion operations in the Permian Basin.

Following both events, teams were established to identify organisational improvements that could prevent similar events occurring again. The investigations were facilitated by an external expert and led by independent senior leaders.

In response to these incidents, Group-wide actions have been taken to review and improve our management processes and our minimum safety requirements for engaging and managing contractors.

We have also reviewed how we investigate incidents and found there were opportunities to improve process, leadership and culture so that we can more effectively embed the lessons from safety incidents across our business.

We successfully launched a Group-wide common approach to field leadership during FY2018. Since deployment, we have completed more than one million field leadership activities with our employees and contractors, which highlights how well this program has been embedded into our daily leadership routines.

Our safety performance

Total recordable injury frequency (TRIF) performance increased by five per cent during FY2018 to 4.4 per million hours worked, compared to 4.2 in FY2017. This was due to an increase in low severity sprain and strain type injuries in Minerals Australia, which occurred primarily in Western Australia Iron Ore and Olympic Dam. These events were not injuries that had fatal or serious potential. Through Field Leadership engagement and formal awareness programs, we are improving the identification and management of the hazards that cause sprain and strain injuries in task-based risk assessments done by the workforce every day. The increase in TRIF performance at Minerals Australia was offset by an 18 per cent reduction in TRIF performance in Minerals Americas to a level less than two.

Total recordable injury frequency (per million hours worked)

Year ended 30 June	2018		2017		2016
Total recordable injury frequency (1)		4.4		4.2		4.3

⁽¹⁾  Includes data for Continuing and Discontinued operations for the financial years being reported.

This year, we are also reporting on the rate of high potential injuries. We are currently able to report data for the last three years. High potential injury trends remain a primary focus to assess progress against our most important safety objective: to eliminate fatalities. High potential injuries declined by eight per cent from FY2017 due to a significant reduction in high potential injuries in Western Australia Iron Ore and further improvement in Petroleum.

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High potential injury events

Year ended 30 June	2018		2017		2016
High potential injury events (1)		56		61		88

⁽¹⁾  Includes recordable injuries and first aid cases where there was the potential for a fatality. This data covers Continuing and Discontinued operations for the financial years being reported.

1.9.3    Health

Recognising that our operations can impact the health of our people, we set clear requirements to manage and protect the health and wellbeing of our workforce, now and into the future. We set minimum mandatory controls to identify and manage health risks for both employees and contractors. Health risks at our workplaces include occupational exposure to diesel particulate matter (DPM), silica and coal mine dust, musculoskeletal stressors, noise and mental health impacts.

Occupational illnesses

The majority of our reported occupational illnesses are musculoskeletal illness and noise-induced hearing loss. We continue to work to minimise these risks through controls such as hearing protection and task redesign to reduce manual handling requirements.

The incidence of employee occupational illness in FY2018 was 4.18 per million hours worked, a decrease of 15 per cent compared with FY2017. The reported incidence of contractor occupational illness was 1.92 per million hours worked, an increase of 34 per cent compared with FY2017. The overall increase in contractor illnesses has been predominantly driven by an increase in predominantly musculoskeletal illness cases in Minerals Australia. This is recognised as an area of focus, with work planned in FY2019 to address the rise in cases.

We do not have full oversight of incidence of contractor noise-induced hearing loss in many parts of BHP due to regulatory regimes and limited access to data. We are working with our contractors to resolve these issues.

Periodic medical surveillance is conducted to detect signs of potential illness at an early stage, and assist our people in the recovery and management of illness that is a result of exposure at our workplace. In FY2019, we will review our medical testing programs to look for opportunities to improve the programs and further enhance our ability to detect potential issues.

Exposure to airborne contaminants

We manage exposures to DPM, silica, coal mine dust and other potentially harmful agents through the setting of internally specified occupational exposure limits (OELs). In setting those OELs for our most important exposures, we monitor and review scientific literature, engage with regulators and OEL-setting agencies, benchmark against peers, and seek independent advice. Our process for continuous monitoring and evaluation of our internal OELs is designed to ensure they remain in line with, or are more stringent than, applicable regulated health limits.

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For our most material exposures of DPM, silica and coal mine dust, we have committed to a five-year target to achieve a 50 per cent reduction in the number of workers potentially exposed⁽³⁾ as compared to our FY2017 baseline exposure profile (as of 30 June 2017⁽⁴⁾) by 30 June 2022. In FY2018, planned exposure reduction projects were implemented across the Group resulting in an overall reduction of 31 per cent compared to the FY2017 baseline. Planned growth projects across the Group may result in an increase in some potential exposures in the short term; however, commitments to achieve planned exposure reductions over the five-year target period remain.

Coal mine dust lung diseases

As at 30 June 2018, six cases of coal mine dust lung diseases (CMDLD⁽⁵⁾) among our current employees had been reported to the Queensland Department of Natural Resources, Mines and Energy. We continue to provide counselling, medical support and redeployment options (where relevant) for all six colleagues. Four of the six have been able to continue working.

During FY2018, an additional three former BHP workers had workers compensation claims accepted for CMDLD resulting in a total, as at 30 June 2018, of five former workers diagnosed with CMDLD since January 2016 (noting that no Australian coal mine worker had been diagnosed with CMDLD in the preceding two decades). Our Charter values guide our response and the support we offer, and we continue to review how this can be improved.

Through the combination of further reductions in coal mine dust and silica potential exposures across BHP sites (driven by our current five-year exposure reduction targets and planned reductions in our OELs) and the statutory health surveillance schemes in Queensland and New South Wales, we believe the necessary controls are in place to prevent serious disabling disease and fatalities in our workforce from existing workplace conditions.

Mental health

Consistent with our culture of care, the mental health of our people is a priority for BHP. We have made good progress with the implementation of our Group-wide Mental Health Framework. Our initial focus was on culture, aimed at reducing the stigma associated with mental illness and raising awareness of mental health conditions, as well as building capacity and confidence to recognise and support individuals experiencing mental health issues.

In FY2018, we expanded our program to include positive activities to support a healthy, thriving workforce. This included the development of a peer-led Resilience Program designed to improve personal and team ability to respond and adapt to changing life circumstances and to build longer-term wellbeing. In addition to the Resilience Program, we developed a centralised resource to help our people improve their mental health and support colleagues, friends and family: the Thrive mental health toolkit, and included a wellbeing category in our Engagement and Perception Survey, helping inform our mental health strategy and better equipping our leaders to support their people.

⁽³⁾  For exposures exceeding our baseline occupational exposure limits discounting the use of personal protective equipment, where required.

⁽⁴⁾  The baseline exposure profile is derived through a combination of quantitative exposure measurements and qualitative assessments undertaken by specialist occupational hygienists consistent with best practice as defined by the American Industrial Hygiene Association.

⁽⁵⁾  CMDLD is the name given to the lung diseases related to exposure to coal mine dust and include coal workers’ pneumoconiosis, silicosis, mixed dust pneumoconiosis and chronic obstructive pulmonary disease.

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1.9.4    Respecting human rights

Respecting human rights wherever we operate is critical to the sustainability of our business and is consistent with our commitment to operate in a manner consistent with the United Nations (UN) Declaration on Human Rights, the UN Guiding Principles on Business and Human Rights, the Voluntary Principles on Security and Human Rights and the 10 UN Global Compact principles.

Society increasingly expects businesses to respect human rights throughout the value chain and we continue to work closely with our stakeholders to understand opportunities to make a positive contribution towards human rights.

The most relevant human rights risks for BHP are rights related to occupational health and safety, security, labour conditions and the rights of Indigenous peoples and communities impacted by our operations. Human rights are integrated into BHP’s risk management system through the Our Requirements standards. We seek to identify and manage human rights risks and perform due diligence across all our activities. We engage regularly with communities, investors, civil society and industry associations on human rights-related issues and impacts of our operations on communities.

Our expectations of our people and contractors and suppliers (where under relevant contractual obligation) are set out in Our Code of Conduct and other relevant standards. Performance against those standards is overseen by our management and subject to internal audit.

We set minimum mandatory requirements for all our suppliers and relevant contractors, including zero tolerance in relation to child labour and forced or compulsory labour, freedom of association, living wage, non-discrimination and diversity, workplace health and safety, community interaction and treatment of employees. We acknowledge the challenges of respecting human rights throughout our value chain and are committed to working with our suppliers and business partners to adopt principles and standards similar to BHP’s.

FY2018 saw continued progress and implementation of good practice in respect of human rights across BHP. Key activities included:

(1) Supply due diligence – Tailored human rights risk-related questions have been included in the supplier assessment questionnaire in our new Global Contractor Management System, and our Supply team completed the next phase of its work to improve the transparency and confidence of human rights risk management in our supply chain.

(2) Seafarers’ human rights – A project was commenced by our Marketing business to better understand the potential exposure of shipping crews on our charter vessels to human rights and ethics concerns and to develop an inspection process that is designed to ensure any such exposures are identified, assessed and controlled.

(3) Water stewardship – Our global strategy on water stewardship includes a social and human rights perspective. This includes mapping the project vision and activities against good practices in relation to human rights and reviewing trends and expectations regarding the human right to water and sanitation.

UK Modern Slavery Act

In accordance with the Modern Slavery Act 2015 (UK), we publish an annual statement describing the steps we take to understand the potential for modern slavery and human trafficking risks across our operating and supplier jurisdictions. We are committed to building an ongoing dialogue with stakeholders, including suppliers and regulators, to improve our understanding of these risks.

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That statement, together with information on BHP’s systems and processes for meeting the UN Guiding Principles on Business and Human Rights, human rights governance and our zero tolerance requirements in relation to human rights in our supply chain, is available online at bhp.com/respectinghumanrights.

1.9.5    Supporting communities

We work respectfully with stakeholders to identify and address impacts from our operations, to understand their expectations and to identify opportunities to actively address social needs. We seek to build good relationships with our stakeholders based on mutual respect, open and ongoing communications and transparency over our activities. In particular, we respect the rights of Indigenous peoples and aim to contribute to their sustainable long-term economic empowerment, social development needs and cultural wellbeing.

Engaging with host communities

Our community practitioners use a range of tools tailored to the needs of our stakeholders. We plan, implement, evaluate and document stakeholder engagement activities, ensuring we include a range of culturally and socially inclusive engagement activities and update our plans annually. Tools include stakeholder mapping, complaints and grievance reporting procedures, perception surveys, social impact and opportunity assessments and human rights impact assessments. Through these, we gain valuable insights into what we do well and where we need to improve our performance.

We also regularly engage with shareholders, their representatives and non-governmental organisations at a Board and senior management level in order to understand their expectations and concerns. For more information, refer to section 2.3 Shareholder engagement.

Supporting local economic growth

We support local businesses by seeking to source products and services locally. All our assets are required to have local procurement plans that benefit local suppliers, create employment and build capacity through training of small business entrepreneurs.

During FY2018, 24 per cent of our external expenditure was with local suppliers. An additional 73 per cent of our supply expenditure was within the regions in which we operate. Of the US$16 billion paid to more than 10,000 suppliers across the globe, US$3.8 billion was paid to local suppliers in the communities in which we operate, supporting their further development.

Our expenditure with local suppliers in FY2018 was mostly in the United States (81 per cent), Trinidad and Tobago (47 per cent), Chile (20 per cent) and Australia (13 per cent).

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Case study:

BHP’s Local Buying Program

The Local Buying Program (Program) was established in 2012 as a means to encourage better relationships between our operations and local small businesses, build capability and capacity across the local supply chain and boost regional economic development in our host communities.

The Program makes it easier for business owners to competitively bid for supply opportunities through a streamlined onboarding, procurement and payment process, which includes 21 day payment terms.

BHP has engaged a cost-neutral organisation, C-Res, to directly manage all transactional activities through the Program, while also providing ongoing support, engagement and mentoring of registered local suppliers.

The Program’s continuing success has seen it expand to include all of BHP’s core assets within Minerals Australia, including Queensland Coal, NSW Energy Coal, Olympic Dam and Western Australia Iron Ore.

Since its launch in 2012, more than 1,000 local suppliers have registered with the Program, and over 20,000 work packages and expenditure over A$230 million with local businesses have been approved. In FY2018, more than 8,000 work packages and expenditure with local businesses of more than A$94 million were approved. Businesses were paid within an average of 13 days from invoice.

NQ Car & Truck Rentals

NQ Car & Truck Rentals (a commercial and industrial vehicle rental business) has been an established part of the Mackay and Coalfields communities in Central Queensland for more than 16 years.

Tracie Combie, the owner of NQ Car & Truck Rentals, says that joining the Program in 2014 has given her the stability she needs to grow her company sustainably.

NQ Car & Truck Rentals has been awarded 36 work packages from our BMA and BMC operations, generating more than $920,000 in approved expenditure, and at the time of publication, employing four full-time workers in the company’s head office, up from one full-time and one trainee before joining.

The Program has given Tracie the opportunity to provide casual work for the aged, returning to work mothers and people with a disability, and enabled her to diversify and expand her fleet of trucks from 40 (mostly cars and small trucks) to 80 (which now includes buses, trailers and mine compliant vehicles).

Voluntary social investment

Our target is to invest not less than one per cent of our pre-tax profit⁽¹⁾ to contribute to improved quality of life in host communities and support achievement of the United Nations Sustainable Development Goals.

Our social investment performance in FY2018 saw BHP deliver projects with a continued focus on good governance, human capability and social inclusion and environment. The total investment of US$77.05 million includes US$7.16 million on community contributions at our non-operated joint ventures, and US$1.54 million to facilitate the operation of the BHP Billiton Foundation.

⁽¹⁾  Our voluntary social investment is calculated as one per cent of the average of the previous three years’ pre-tax profit.

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1.9.6    Indigenous peoples

Many of our operations are located on or near traditional lands. We respect the rights of Indigenous peoples and acknowledge their right to maintain their culture, identity, traditions and customs. We also seek to contribute to their sustainable long-term economic empowerment, social development needs and cultural wellbeing. Our approach to engaging and supporting Indigenous peoples is articulated in our Indigenous Peoples Statement, which is aligned with the ICMM Indigenous Peoples Policy Statement.

We have a five-year target to implement our Indigenous Peoples Strategy across all our assets through the development of Regional Indigenous Peoples Plans. The Strategy focuses on four priority areas: governance; economic empowerment; social and cultural support; and public engagement. In FY2018, all regions (Australia, the United States, Chile and Canada) had regional Indigenous Peoples plans established to progress the Strategy. Further details on our Indigenous Peoples Policy Statement and Strategy are available in our Sustainability Report 2018 and online at bhp.com.

1.9.7    Protecting the environment

Pressure on land and water resources is growing, amplified by climate change. Maintaining the right to access these resources relies on our ability to demonstrate responsible management and contribute to a resilient environment. BHP has comprehensive governance, risk management, policies and processes to help reduce the potential impact of our operations.

Our approach to environmental management is set out in the Our Requirements for Environment and Climate Change and Our Requirements for Planning, Risk Management standards. These standards and our processes of audit and assurance have been designed taking account of the ISO management system requirements, such as ISO14001 for Environmental Management. The Our Requirements standards also include specific minimum performance standards in a number of areas.

Compliance with the Our Requirements standards is checked by our internal audit processes, which are designed to cover all operating sites on a two year rotation.

Supporting biodiversity

We have a five-year target to improve marine and terrestrial biodiversity outcomes by developing a framework to evaluate and verify the benefits of our actions, in collaboration with others. In FY2018, we commenced development of that framework through collaboration with Conservation International and also with Proteus, a voluntary partnership between UN Environment World Conservation Monitoring Centre (UNEP-WCMC) and 12 extractives industry companies. The framework will be used to measure BHP’s achievement of our longer-term biodiversity goal: ‘in line with United Nations Sustainable Development Goals (UN SDGs) 14 and 15, BHP will, by FY2030, have made a measurable contribution to the conservation, restoration and sustainable use of marine and terrestrial ecosystems in all regions where we operate.’

BHP also looks for opportunities to improve the conservation, restoration and sustainable use of marine and terrestrial ecosystems in all regions in which we operate, both through our own activities and in collaboration with others. In FY2018, our Petroleum business partnered with Pemex to develop the Trion discovery in the Gulf of Mexico. As the first foreign company to partner with Mexico in developing their significant petroleum resources, BHP has been working with the Mexican Government as it develops its offshore petroleum regulatory framework, by sharing leading practice environmental guidance from networks such as IPIECA (the global oil and gas industry association for environmental and social issues) and the International Association of Oil & Gas Producers.

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Rehabilitation and closure

Closure of part or all of an operation brings with it potentially significant financial, environmental and social impacts. Recognising this, in FY2017, BHP developed a new Our Requirements standard for closure. The new standard will apply to exploration, projects and operational or closure activities for all our sites, including both our operated assets and non-operated assets (where commercial terms allow). The standard will also apply to our investment or divestment decisions.

Our standards also require us to minimise the potential of adverse environmental impacts following closure. Our closed sites are required to have closure management plans, with long-term monitoring to verify that controls are effective and performance standards are maintained.

Towards water stewardship

The need for water creates complex, region-wide interrelationships between communities, government, business and the environment. This means we all must work more cooperatively to effectively balance multiple needs and safeguard water supplies for future generations.

Transparency through appropriate disclosure of water use, performance and interactions across all sectors is critical to effective water governance. In August 2018, we published our inaugural Water Report. This Report is our first step towards more accessible and transparent reporting of our interactions with water – from extraction to use and discharge – and of our water-related performance and risks.

The water stewardship priority supports our longer-term goal for water: ‘in line with SDG 6, BHP will collaborate to enable integrated water resource management in all catchments where we operate by FY2030.’ We also have a five-year target to reduce FY2022 freshwater withdrawal by 15 per cent from FY2017 levels. The most significant contributor towards this goal in FY2018 was the completion and inauguration of the expanded desalination plant at our Escondida asset in Chile. The FY2018 result represents a two per cent decrease from FY2017 levels and progress towards our target.

For more information on BHP and water, read our BHP Water Report 2018 at bhp.com/water.

1.9.8     Climate change

Our climate change strategy focuses on reducing our operational GHG emissions, investing in low emissions technologies, promoting product stewardship, managing climate-related risk and opportunity and working with others to enhance the global policy and market response.

More information on each element of our strategy is available online at bhp.com/climate.

Climate change governance

Responding to climate change is a priority governance and strategic issue for BHP. Our Board is actively engaged in the governance of climate change issues, supported by the Sustainability Committee. Management has primary responsibility for the design and implementation of our climate change strategy.

Reducing our operational emissions is a key performance indicator for our business and our performance against our targets (outlined in this section) is reflected in senior executive and leadership remuneration.

All data in this section includes Continuing and Discontinued operations for the financial years being reported.

Stakeholder engagement

Our climate change strategy is supported by active engagement with our stakeholders, including investors, policy makers, peer companies and non-governmental organisations.

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We periodically hold one-on-one and group meetings with investors and their advisers. In FY2018, our climate-related investor engagement included meetings held in Australia, the United Kingdom, the United States and South Africa.

We also seek input and insight from external experts, such as the BHP Forum on Corporate Responsibility (FCR). The FCR, which is composed of civil society leaders and BHP executives, has played a critical role in the development of our position on climate change. During FY2018, the FCR met twice, with both meetings including discussion of the delivery of our climate change strategy, including our emissions reduction targets.

Informed by this engagement, we regularly review our approach to climate change in response to emerging scientific knowledge, changes in global climate policy and regulation, developments in low emissions technologies and evolving stakeholder expectations.

For information on our program of engagement, refer to section 2.3.

Climate-related financial disclosures

Our climate-related disclosures in this Report are aligned with the recommendations of the Financial Stability Board’s Task Force on Climate-related Financial Disclosures (TCFD). We believe the TCFD recommendations represent an important step towards establishing a widely accepted framework for climate-related financial risk disclosure and we have been a firm supporter of this work. Our Vice President of Sustainability and Climate Change, Dr Fiona Wild, is a member of the Task Force.

We are committed to continuing to work with the TCFD and our peers in the resources sector to support the wider adoption of the TCFD recommendations and the development of more effective disclosure practices within the sector.

As responding to climate change is an integral part of our strategy and operations, our TCFD-aligned disclosures can be found throughout this Report. The table below shows how our disclosures in this Report align to the TCFD recommendations and where the relevant information can be found.

Location of TCFD-aligned disclosures

TCFD recommendation	BHP disclosure	Reference
Governance – Disclose the organisation’s governance around climate-related risks and opportunities
a) Describe the Board’s oversight of climate-related risks and opportunities.	Principal risks Board skills and experience – climate change Sustainability Committee – role and focus		1.6.4 2.8 2.13.4
b) Describe management’s role in assessing and managing climate-related risks and opportunities.	Managing performance and risk Climate change – managing risk and opportunity Sustainability Committee – role and focus FY2018 STI performance outcomes		1.4.3 1.9.8 2.13.4 3.3.2
Strategy – Disclose the actual and potential impacts of climate-related risks and opportunities on the organisation’s businesses, strategy, and financial planning where such information is material
a) Describe the climate-related risks and opportunities the organisation has identified over the short, medium, and long term.	Principal risks – external risks Principal risks – operational risks Principal risks – sustainability risks Climate change – managing risk and opportunity		1.6.4 1.6.4 1.6.4 1.9.8

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TCFD recommendation	BHP disclosure	Reference
b) Describe the impact of climate-related risks and opportunities on the organisation’s businesses, strategy, and financial planning.	Principal risks – external risks Principal risks – operational risks Principal risks – sustainability risks Climate change – managing risk and opportunity		1.6.4 1.6.4 1.6.4 1.9.8
c) Describe the resilience of the organisation’s strategy, taking into consideration different climate-related scenarios, including a 2°C or lower scenario.	Climate change – evaluating the resilience of our portfolio		1.9.8
Risk management – Disclose how the organisation identifies, assesses, and manages climate-related risks
a) Describe the organisation’s processes for identifying and assessing climate-related risks.	Managing performance and risk Management of principal risks – sustainability risks		1.4.3 1.6.5
b) Describe the organisation’s processes for managing climate-related risks.	Managing performance and risk Management of principal risks – sustainability risks		1.4.3 1.6.5
c) Describe how processes for identifying, assessing, and managing climate-related risks are integrated into the organisation’s overall risk management.	Managing performance and risk Non-financial KPIs – sustainability KPIs Management of principle risks – sustainability risks		1.4.3 1.5.2 1.6.5
Metrics and targets – Disclose the metrics and targets used to assess and manage relevant climate-related risks and opportunities where such information is material
a) Disclose the metrics used by the organisation to assess climate-related risks and opportunities in line with its strategy and risk management process.	Non-financial KPIs – sustainability KPIs Climate change – delivering against our emissions reduction targets Climate change – managing our value chain emissions		1.5.2 1.9.8 1.9.8
b) Disclose Scope 1, Scope 2, and, if appropriate, Scope 3 greenhouse gas (GHG) emissions, and the related risks.	Non-financial KPIs – sustainability KPIs Climate change – delivering against our emissions reduction targets Climate change – managing our value chain emissions		1.5.2 1.9.8 1.9.8
c) Describe the targets used by the organisation to manage climate-related risks and opportunities and performance against targets.	Non-financial KPIs – sustainability KPIs Climate change – delivering against our emissions reduction targets FY2018 STI performance outcomes		1.5.2 1.9.8 3.3.2

Managing our operational emissions

As a major energy consumer, BHP considers energy use management, energy security and GHG emissions reduction at our operations as key components of our climate change strategy.

Delivering against our emissions reduction targets

In FY2018, we began working towards a new five-year GHG emissions reduction target. Our new target, which took effect from 1 July 2017, is to maintain our total operational emissions in FY2022 at or below FY2017 levels ⁶ while we continue to grow our business. Our new target builds on our success in achieving our previous five-year target.

⁶  FY2017 baseline will be adjusted for any material acquisitions and divestments based on GHG emissions at the time of the transaction. Carbon offsets will be used as required.

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Our operational emissions (Scopes 1 and 2 combined) in FY2018 totalled 16.5 million tonnes of carbon dioxide equivalent (CO₂-e). This is a 1 per cent increase compared to the FY2017 baseline, and is primarily due to an increase in Scope 2 emissions from our Minerals Americas business as a result of increased production at our Escondida and Pampa Norte copper assets in Chile, as well as the commissioning of the new Escondida desalination plant. ⁷

Our five-year target and our longer-term emissions reduction goal underpin our strategy and are an important driver of internal performance. In FY2019, we will continue to focus on the delivery of our five-year target and on defining a pathway to net-zero emissions over the coming decades.

Scope 1 and 2 GHG emissions (million tonnes CO₂-e) ⁸

Year ended 30 June	2018		2017		2016
Scope 1 9		10.6		10.5		11.3
Scope 2 10		5.9		5.8		6.7
Scope 1 & 2 total		16.5		16.3		18.0

Our FY2018 GHG intensity was 2.3 tonnes of CO₂-e per tonne of copper equivalent production (FY2017: 2.2 tonnes of CO₂-e). Our FY2018 energy intensity was 21 gigajoules per tonne of copper equivalent production. ¹¹

More information on our GHG metrics and targets, including a breakdown of our emissions by source, additional historical data, details of our performance against our current and previous target, and information on our approach to target setting is available online at bhp.com/climate.

Investing in low emissions technologies

Defining a pathway to net-zero emissions for our long-life assets requires planning for the long term and a deep understanding of the development pathway for low emissions technologies. Our strategy is to develop emerging, and deploy existing, technologies that make step-change reductions in GHG emissions, both from our own operations and from the downstream processing and use of our products (as described below).

⁷  Production-related increases in emissions were partially offset by a change to the electricity emissions factor for Minerals Americas resulting from the interconnection of Chile’s northern (mainly fossil fuel-based) and southern (which has a higher proportion of hydropower and other renewables) grid systems.

⁸  Scope 1 and 2 emissions have been calculated on an operational control basis in accordance with the GHG Protocol Corporate Accounting and Reporting Standard. Data includes Continuing and Discontinued operations for the financial years being reported.

⁹  Scope 1 refers to direct GHG emissions from operated assets.

¹⁰  Scope 2 refers to indirect GHG emissions from the generation of purchased electricity and steam that is consumed by operated assets (calculated using the market-based method).

¹¹  Copper equivalent production has been calculated based on FY2018 average realised product prices for FY2018 production, and FY2017 average realised product prices for FY2017 production. FY2017 GHG intensity has been adjusted since it was previously reported to use production figures based on BHP operational control consistent with GHG reporting boundaries.

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We have a suite of initiatives currently underway aimed at achieving reductions across our major operational emissions sources:

Zero-carbon electricity supply: emissions from electricity use make up 46 per cent of our operational emissions. This includes both the power we generate ourselves and the power we buy from grids around the world.¹² Our strategy seeks to accelerate the transition to lower carbon sources of electricity while balancing cost, reliability and emissions reductions.

Zero-carbon material movement: emissions from fuel and distillate make up 35 per cent of our operational emissions, primarily from the consumption of diesel in the course of material movement (for example haul trucks). Our strategy is to accelerate and de-risk technologies and innovations that can transition operations over time to alternate fuels and greater electrification of mining equipment and mining methods.

Fugitive emissions: fugitive methane emissions from our petroleum and coal assets make up 18 per cent of our operational emissions. Our strategy is to pursue innovation in mitigation technologies for these emissions, which are among the most technically and economically challenging to reduce.

In evaluating low emissions technology investment opportunities, we consider technologies with the potential to deliver results across a range of time horizons; emphasise investments that can deliver material GHG savings; consider the ability of projects and technologies to leverage our global Operating Model (replicability, scale and market breadth); and evaluate the potential for building capacity, capability and internal awareness across our business.

Case studies on our low emissions technology investments are available online at bhp.com/climate.

Promoting product stewardship

Emissions from our value chain (Scope 3¹³ emissions) are significantly higher than those from our own operations. We recognise that we have a stewardship role in working with our customers, suppliers and other value chain participants to seek to influence emissions reductions across the full lifecycle of our products.

Managing our value chain emissions

In FY2018, Scope 3 emissions in our value chain were 596 million tonnes of CO₂-e. The most significant contributors to this total were emissions from the downstream processing and use of our products, which accounted for around 97 per cent of total Scope 3 emissions. In particular, Scope 3 emissions emanating from the steelmaking process (the processing and use of our iron ore and metallurgical coal) accounted for over 65 per cent of the total.¹⁴

¹²  Includes Scope 1 emissions from our natural gas-fired power generation as well as Scope 2 emissions from purchased electricity.

¹³  Scope 3 refers to all other indirect GHG emissions (not included in Scope 2) from activities across our value chain, including upstream emissions related to the extraction and production of purchased materials and fuels; downstream emissions related to the processing and use of our products; both upstream and downstream transportation and distribution; and emissions from our non-operated joint ventures.

¹⁴  Scope 3 emissions reporting necessarily requires a degree of overlap in reporting boundaries due to our involvement at multiple points in the life cycle of the commodities we produce and consume. A significant example of this is that Scope 3 emissions reported under the ‘Processing of sold products’ category include the processing of our iron ore to steel. This third party activity also consumes metallurgical coal as an input, a portion of which is produced by us. For reporting purposes, we account for Scope 3 emissions from combustion of metallurgical coal with all other fossil fuels under the ‘Use of sold products’ category, such that a portion of metallurgical coal emissions is accounted for under two categories. This is an expected outcome of emissions reporting between the different scopes defined under standard GHG accounting practices and is not considered to detract from the overall value of our Scope 3 emissions disclosure.

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Scope 3 GHG emissions (million tonnes CO₂-e)¹⁵

Scope 3 category		2018
Upstream	Purchased goods and services (including capital goods)		8.2
	Fuel and energy related activities		1.4
	Upstream transportation and distribution 16		3.6
	Business travel		0.1
	Employee commuting		<0.1
Downstream	Downstream transportation and distribution 17		5.0
	Processing of sold products 18		322.6
	– Iron ore to steel		317.4
	– Copper cathode to copper wire		5.2
	Use of sold products		253.8
	– Metallurgical coal		112.3
	– Energy coal		71.0
	– Natural gas		36.4
	– Crude oil and condensates 19		29.6
	– Natural gas liquids (NGLs)		4.5
	Investments (i.e. our non-operated joint ventures) 20		1.7
Scope 3 total 21			596.4

More information on Scope 3 emissions associated with our business and the methodologies used to calculate them is available online at bhp.com/climate.

¹⁵  Scope 3 emissions have been calculated using methodologies consistent with the GHG Protocol Corporate Value Chain (Scope 3) Accounting and Reporting Standard. Data includes Continuing and Discontinued operations for the financial years being reported.

¹⁶  Includes product transport where freight costs are covered by BHP (e.g. under Cost and Freight (CFR) or similar terms), as well as purchased transport services for process inputs to our operations.

¹⁷  Product transport where freight costs are not covered by BHP (e.g. under Free on Board (FOB) or similar terms).

¹⁸  All iron ore production is assumed to be processed into steel and all copper metal production is assumed to be processed into copper wire for end-use. Processing of nickel, zinc, gold, silver, ethane and uranium oxide is not currently included, as production volumes are much lower than iron ore and copper and a large range of possible end uses apply. Processing/refining of petroleum products is also excluded as these emissions are considered immaterial compared to the end-use product combustion reported in the ‘Use of sold products’ category.

¹⁹  All crude oil and condensates are conservatively assumed to be refined and combusted as diesel.

²⁰  For BHP, this category covers the Scope 1 and 2 emissions (on an equity basis) from our assets that are owned as a joint venture but not operated by BHP.

²¹  There is an element of double counting across emissions categories for our iron ore and metallurgical coal products; both are used in the same process (steelmaking) further downstream, which inflates the total Scope 3 emissions figure.

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Accelerating the development of carbon capture and storage

We are working in partnership with others across our value chain to accelerate the development of technologies with the potential to reduce emissions from the processing and use of our products. Carbon capture and storage (CCS) is a key low emissions technology with the potential to play a pivotal role in reducing emissions from industrial processes such as steel production as well as emissions from the power sector and from oil and gas production.

While we recognise that progress is required in developing policy frameworks to support the wider deployment of this technology, our CCS investments and partnerships focus on mechanisms to reduce costs and accelerate development timeframes. Our investments include activities aimed at knowledge sharing from commercial-scale projects, development of sectoral deployment roadmaps and funding for research and development at leading universities and research institutes.

Case studies on our CCS investments and partnerships are available online at bhp.com/climate.

Managing risk and opportunity

We recognise the physical and non-physical impacts of climate change may affect our assets, productivity, the markets in which we sell our products and the communities in which we operate. Risks related to the physical impacts of climate change include acute risks resulting from increased severity of extreme weather events and chronic risks resulting from longer-term changes in climate patterns. Non-physical risks arise from a variety of policy, legal, technological and market responses to the challenges posed by climate change and the transition to a lower carbon economy.

A broader discussion of our climate-related risk factors and risk management approach is provided as part of our TCFD-aligned disclosures located throughout this Report, as described above.

Adapting to the physical impacts of climate change

We take a robust, risk-based approach to adapting to the physical impacts of climate change. We work with globally recognised agencies to obtain regional analyses of climate science to inform resilience planning at an asset level and improve our understanding of the potential climate vulnerabilities of our operations and host communities.

Our operations are required to build climate resilience into their activities through compliance with the Our Requirements for Environment and Climate Change standard. We also require new investments to assess and manage risks associated with the forecast physical impacts of climate change. As well as this ongoing business resilience planning, we continue to look at ways we can contribute to community and ecosystem resilience.

Case studies on our adaptation activities are available online at bhp.com/climate.

Evaluating the resilience of our portfolio

We consider the impacts of climate change in our strategy process. We recognise the world could respond in a number of different ways to address climate change. We use a broad range of scenarios to consider how divergent policy, technology, market and societal outcomes could impact our portfolio, including low plausibility, extreme shock events. We also continually monitor the macro environment for climate change related developments that would serve as a call to action for us to reassess the resilience of our portfolio.

Our investment evaluation process includes an assessment of non-quantifiable risks such as those that could impact the people and the environment that underpin our licence to operate. The process has also incorporated market and sector based carbon prices for more than a decade.

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Our Climate Change: Portfolio Analysis (2015) and Climate Change: Portfolio Analysis – Views after Paris (2016) reports, which are available online at bhp.com/climate, describe in more detail how we have used scenario analysis to evaluate the resilience of our portfolio to both an orderly and a more rapid transition to a 2°C world.

We are committed to keeping our stakeholders informed of the potential impact of climate change on our business, and continue to review and consider developing best practice and evolving stakeholder expectations.

Contributing to the global response

Climate change is a global challenge that requires collaboration. We prioritise working with others to enhance the global policy and market response.

Supporting the development of effective climate and energy policy

Industry has a key role to play in supporting policy development. We engage with governments and other stakeholders to contribute to the development of an effective, long-term policy framework that can deliver a measured transition to a lower carbon economy.

We believe an effective policy framework should include a complementary set of measures, including a price on carbon, support for low emissions technology and measures to build resilience. We are a signatory to the World Bank’s ‘Putting a Price on Carbon’ statement and a partner in the Carbon Pricing Leadership Coalition, a global initiative that brings together leaders from industry, government, academia and civil society with the goal of putting in place effective carbon pricing policies.

We also advocate for a framework of policy settings that will accelerate the deployment of CCS. We are a member of the Global CCS Institute and, in FY2018, we joined the UK Government’s newly formed Council on Carbon Capture Usage and Storage (CCUS).

We contribute to policy reviews throughout our global operating regions. Our climate and energy policy submissions are available online at bhp.com/climate.

Industry association membership

We believe industry associations have the capacity to play a key role in advancing the development of standards, best practice and constructive policy that are of benefit to members, the economy and society. We also recognise there is increasing stakeholder interest in the nature and role of industry associations and the extent to which the positions of industry associations on key issues are aligned with those of member companies.

During FY2018, we completed a review of our membership of those industry associations that hold an active position on climate and energy policy. Our Industry association review report, published in December 2017, sets out a list of the material differences between the positions we hold on climate and energy policy, and the advocacy positions on climate and energy policy taken by industry associations to which we belong. It also describes the outcomes of the review of our membership of those industry associations. In light of the material difference identified by the review and the narrow range of activities of benefit to BHP from membership, we determined to cease membership of the World Coal Association (WCA).

More information on our approach to industry associations, including the Industry association review report, is available online at bhp.com.

Promoting market mechanisms to reduce global emissions

In addition to measures to reduce our own emissions, we support the development of market mechanisms that reduce global GHG emissions through projects that generate carbon credits.

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Our climate change strategy includes a focus on reducing emissions from deforestation through support for REDD+, the UN program for reducing emissions from deforestation and forest degradation. For example, in partnership with the International Finance Corporation (IFC) and Conservation International (CI) we developed a first-of-its-kind US$152 million Forests Bond, issued by the IFC in 2016. BHP provides a price-support mechanism for the bond, which supports the Kasigau Corridor REDD+ project in Kenya. During FY2018, we purchased additional carbon credits from the Kasigau Corridor project and continued our support of the Alto Mayo REDD+ project in Peru.

In partnership with CI and Baker McKenzie, in FY2018, we launched the Finance for Forests (F4F) initiative, which aims to share our experiences to help encourage replication of these investments and the exploration of other innovative private finance tools to conserve forests and further advance REDD+. We co-hosted (along with CI and Baker McKenzie) F4F roundtables in the United States and the United Kingdom, which were attended by representatives of the public, private and philanthropic sectors.

More information on our approach to REDD+ is available online at bhp.com/climate.

1.10    Our businesses

The maps in this section should be read in conjunction with the information on mining operations table in section 6.1.

1.10.1    Minerals Australia

The Minerals Australia asset group includes operated assets in Western Australia, Queensland, New South Wales and South Australia.

Copper asset

Olympic Dam

Overview

Located 560 kilometres north of Adelaide, Olympic Dam is one of the world’s most significant deposits of copper, gold, silver and uranium.

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Olympic Dam is made up of underground and surface operations and operates a fully integrated processing facility from ore to metal. The underground mine is made up of more than 450 kilometres of underground roads and tunnels. Ore mined underground is hauled by an automated train system to crushing, storage and ore hoisting facilities.

The processing plant consists of two grinding circuits in which high-quality copper concentrate is extracted from sulphide ore through a flotation extraction process. Olympic Dam has a fully integrated metallurgical complex with a grinding and concentrating circuit, a hydrometallurgical plant incorporating solvent extraction circuits for copper and uranium, a copper smelter, a copper refinery and a recovery circuit for precious metals.

Key developments during FY2018

The major smelter maintenance upgrade in August 2017 was the largest planned shutdown ever undertaken at Olympic Dam and ran for more than 100 days. Other major upgrade work was carried out on the refinery, concentrator and site technology to ensure the ongoing reliability and safety of the Olympic Dam operation.

Guidance for Olympic Dam was reduced to approximately 135 kilotonnes (kt) following a slower than planned ramp-up after completion of the major smelter maintenance campaign. However, Olympic Dam slightly exceeded the revised guidance for the full FY2018 at 137 kt.

First ore from the higher-grade Southern Mine Area was extracted in early FY2018 with development continuing.

Looking ahead

Following the key infrastructure upgrade in FY2018, Olympic Dam will see a gradual increase in copper production with continued development into the Southern Mine Area.

There are other expansion plans for Olympic Dam, such as the Brownfield Expansion Project, which is expected to be considered by the Board in CY2020, and could see production grow to approximately 330 kilotonnes per annum (ktpa).

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Iron ore asset

Western Australia Iron Ore

Overview

Western Australia Iron Ore (WAIO) is an integrated system of four processing hubs and five mines connected by more than 1,000 kilometres of rail infrastructure and port facilities in the Pilbara region of northern Western Australia.

WAIO’s Pilbara reserve base is relatively concentrated, allowing development to be planned around integrated mining hubs which are connected to the mines and satellite orebodies by conveyors or spur lines. This approach enables the value of installed infrastructure to be maximised by using the same processing plant and rail infrastructure for a number of orebodies.

At each processing hub – Newman, Yandi, Mining Area C and Jimblebar – the ore is crushed, beneficiated (where necessary) and blended to create high-grade hematite lump and fines products. Iron ore products are then transported along the Port Hedland – Newman Rail Line to the Finucane Island and Nelson Point port facilities at Port Hedland.

There are four main WAIO joint ventures (JVs): Mt Newman, Yandi, Mt Goldsworthy and Jimblebar. BHP’s interest in each of the joint ventures is 85 per cent, with Mitsui and ITOCHU owning the remaining 15 per cent. The joint ventures are unincorporated, except Jimblebar.

BHP, Mitsui and ITOCHU have also entered into separate joint venture agreements with some customers that involve the sublease of parts of WAIO’s existing mineral leases at Wheelarra and POSMAC. The Wheelarra JV sublease expired in March 2018 and the Wheelarra JV is now in the process of being wound up. As such, control of the sublease area reverted to the Jimblebar JV in March 2018.

The ore from the Wheelarra and POSMAC JVs is sold to the main joint ventures. BHP is entitled to 85 per cent of this production.

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All ore is transported by rail on the Mt Newman JV and Mt Goldsworthy JV rail lines to the port facilities. WAIO’s port facilities at Nelson Point are owned by the Mt Newman JV and Finucane Island is owned by the Mt Goldsworthy JV.

Key developments during FY2018

WAIO achieved record production in FY2018, supported by record production at Jimblebar and Mining Area C, and improved rail reliability. WAIO has also recorded ongoing productivity improvements, such as the development of a rail-scheduling tool that continually learns and applies new algorithms to optimise rail movements. WAIO has adopted a manufacturing mindset to lower operational costs through improved truck availability and fuel consumption, increased equipment reliability and extended equipment life.

The Jimblebar truck fleet became fully autonomous in November 2017. The autonomous fleet reduces people exposure to hazardous environments, saves time and allows for greater accuracy.

In February 2018, BHP received approval to amend its environmental licence to increase capacity at its Port Hedland operations to 290 million tonnes per annum (Mtpa).

On 14 June 2018, the BHP Board approved US$2.9 billion in capital expenditure for the development of the new South Flank project. This is in addition to BHP’s pre-commitment funding of US$184 million, which was approved in June 2017. South Flank will fully replace production from the 80 Mtpa (100 per cent basis) Yandi Mine, with first ore targeted in the CY2021. It will contribute to an increase in WAIO’s average iron grade from 61 per cent to 62 per cent, and the overall proportion of lump from 25 per cent to approximately 35 per cent.

Looking ahead

We will continue to focus on productivity improvements through standardised work processes, simplification and further cost reduction, coupled with supply chain debottlenecking initiatives at the port and rail to improve stability and reliability of the network and increase production to 290 Mtpa. A program of work to optimise maintenance schedules across our supply chain and improve port reliability and performance is planned for the September 2018 quarter, with a corresponding impact expected on production and unit costs.

Coal assets

Our coal assets in Australia consist of open-cut and underground mines. At our open-cut mines, overburden is removed after blasting, using either draglines or truck and shovel. Coal is then extracted using excavators or loaders and loaded onto trucks to be taken to stockpiles or directly to a beneficiation facility.

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At our underground mine, coal is extracted by either longwall or continuous miner. The coal is then transported to stockpiles on the surface by conveyor. Coal from stockpiles is crushed and, for a number of the operations, washed and processed through a coal preparation plant. Domestic coal is transported to nearby customers via conveyor or rail, while export coal is transported to ports on trains. As part of the coal supply chain, both single and multi-user rail and port infrastructure is used.

Queensland Coal

Overview

Queensland Coal comprises the BHP Billiton Mitsubishi Alliance (BMA) and BHP Billiton Mitsui Coal (BMC) assets in the Bowen Basin in Central Queensland, Australia.

The Bowen Basin’s high-quality metallurgical coals are ideally suited to efficient blast furnace operations. The region’s proximity to Asian customers means it is well positioned to competitively supply the seaborne market.

Queensland Coal has access to key infrastructure in the Bowen Basin, including a modern, multi-user rail network and its own coal-loading terminal at Hay Point, located near the city of Mackay. Queensland Coal also has contracted capacity at three other multi-user port facilities: the Port of Gladstone (RG Tanna Coal Terminal), Dalrymple Bay Coal Terminal and Abbot Point Coal Terminal.

BHP Billiton Mitsubishi Alliance (BMA)

BMA is Australia’s largest coal producer and supplier of seaborne metallurgical coal. It is owned 50:50 by BHP and Mitsubishi Development.

BMA operates seven Bowen Basin mines (Goonyella Riverside, Broadmeadow, Daunia, Peak Downs, Saraji, Blackwater and Caval Ridge) and owns and operates the Hay Point Coal Terminal near Mackay. With the exception of the Broadmeadow underground longwall operation, BMA’s mines are open-cut, using draglines and truck and shovel fleets for overburden removal.

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BHP Billiton Mitsui Coal (BMC)

BMC owns and operates two open-cut metallurgical coal mines in the Bowen Basin – South Walker Creek Mine and Poitrel Mine. BMC is owned by BHP (80 per cent) and Mitsui and Co (20 per cent).

South Walker Creek Mine is located on the eastern flank of the Bowen Basin, 35 kilometres west of the town of Nebo and 132 kilometres west of the Hay Point port facilities. Poitrel Mine is situated southeast of the town of Moranbah and began open-cut operations in October 2006.

Key developments during FY2018

Queensland Coal production was impacted in late 2017 and early 2018 by challenging roof conditions at Broadmeadow underground mine and geotechnical issues triggered by wet weather at Blackwater open-cut mine. This was partially offset by record production at five mines, underpinned by improved stripping and truck performance, higher wash-plant throughput from debottlenecking activities and utilisation of latent dragline capacity at Caval Ridge Mine. Mining operations at Blackwater stabilised during the March 2018 quarter and returned to full capacity during the June 2018 quarter as inventory levels were rebuilt. At Broadmeadow, progression through the fault zone was completed during the June 2018 quarter.

For BMA, construction has advanced on the US$204 million (100 per cent basis) Caval Ridge Southern Circuit (CRSC) project in the Bowen Basin, which was approved by BHP in March 2017. The CRSC project includes an 11-kilometre overland conveyor system that will transport coal from Peak Downs Mine to the coal handling preparation plant at the nearby Caval Ridge Mine. The project is creating up to 400 new construction jobs and will lock in around 200 ongoing operational roles to operate the expanded contract mining fleet and to perform maintenance on the new infrastructure. It will also enable full utilisation of the 11.5 Mtpa wash plant with ramp-up early in FY2019.

On 30 May 2018, the BMA joint venture partners entered into an agreement to sell the Gregory Crinum Mine to Sojitz Corporation for A$100 million (100 per cent basis). Gregory Crinum is a hard coking coal mine located 60 kilometres northeast of Emerald in the Bowen Basin. It consists of the Crinum underground mine, Gregory open-cut mine, undeveloped coal resources and on-site infrastructure, including a coal handling and preparation plant, maintenance workshops and administration facilities. Gregory Crinum Mine’s capacity was 6 million tonnes (Mt) of hard coking coal per annum when production ceased and it was placed into care and maintenance in January 2016. In addition to the sale of the mine to Sojitz, BMA will provide appropriate funding for rehabilitation of existing areas of disturbance at the site. Completion of the sale is subject to the fulfilment of conditions precedent, including customary regulatory approvals.

On 6 February 2018, BMC completed the transaction with Peabody Energy to secure full ownership of the Red Mountain Joint Venture (RMJV) assets, which was announced in August 2017. The RMJV assets, which include a coal handling and preparation plant and rail loadout loop, will continue to service BMC’s Poitrel Mine and Peabody’s Millennium Mine, as well as providing train load out services for BMA Daunia Mine. Peabody will continue to use the infrastructure under a tolling arrangement with BMC. BMA will also continue to use the train load out.

Looking ahead

Construction of the CRSC project commenced in April 2017 and is scheduled to be completed by the end of CY2018. The first coal on conveyor is expected in October 2018.

In addition to the new conveyor and associated tie-ins, the project will fund a new stockpile pad and run-of-mine station at Peak Downs. It includes an upgrade of the existing coal handling preparation plant and stockyard at Caval Ridge. BMA also intends to invest in new mining fleet, including excavators and trucks.

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Potential future opportunities also include an expansion of the Caval Ridge wash plant that would unlock a further 5.7 Mtpa (100 per cent basis).

New South Wales Energy Coal

Overview

New South Wales Energy Coal (NSWEC) consists of the Mt Arthur Coal open-cut energy coal mine in the Hunter Valley region of New South Wales, Australia. The site produces coal for domestic and international customers in the energy sector.

Key developments during FY2018

We are continuing to optimise the mine design by re-opening the Ayredale pit to gain earlier access to a higher margin resource over the next decade and constructed multiple elevated roadways to reduce haulage cycle times and increase productivity.

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Nickel West

Overview

Nickel West is a fully integrated mine-to-market nickel business. All nickel operations (mines, concentrators, a smelter and refinery) are located in Western Australia. The integrated business adds value throughout our nickel supply chain, with the majority of Nickel West’s current production sold as powder and briquettes.

Low-grade disseminated sulphide ore is mined from Mt Keith, a large open-pit operation. The ore is crushed and processed on-site to produce nickel concentrate. High-grade nickel sulphide ore is mined at Cliffs and Leinster underground mines and Rocky’s Reward open-pit mine. The ore is processed through a concentrator and dryer at Leinster. Nickel West’s concentrator plant in Kambalda processes ore and concentrate purchased from third parties.

The three streams of nickel concentrate come together at the Nickel West Kalgoorlie smelter, a vital part of our integrated business. The smelter uses a flash furnace to smelt concentrate to produce nickel matte. Nickel West Kwinana then refines granulated nickel matte from the Kalgoorlie smelter into premium-grade nickel powder and briquettes containing 99.8 per cent nickel. Nickel matte and metal are exported to overseas markets via the Port of Fremantle.

Key developments in FY2018

In FY2018, Nickel West began its transition to become a global supplier to the battery materials market, approving funding and beginning preparatory works for the first phase of a nickel sulphate plant which will be located at the Kwinana Nickel Refinery. Stage 1 is expected to produce 100 ktpa of nickel sulphate. A mini-plant has been constructed to deliver samples of nickel sulphate product to customers.

In FY2018, we continued to progress regulatory environmental approvals and consulted with Traditional Owners regarding a satellite pit at the Mt Keith operation, which will supply ore to the Mt Keith concentrator.

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The Venus project has been approved for execution at the Leinster Nickel operation, with definitional drilling and development having commenced. A study reviewed the resource beneath the Perseverance Sub-Level Cave and recommended the installation of a small Block Cave. Pre-commitment funding to start the development on 1 July 2018 was approved.

Looking ahead

First production from the nickel sulphate plant at the Kwinana Nickel Refinery is expected at the end of the FY2019. We continue to explore options for a Stage 2, 200 kt nickel sulphate facility.

We will continue test work on a cobalt sulphate circuit plant at the Kwinana Nickel Refinery, which would produce a cobalt sulphate product.

At Mt Keith, we will commence mining at the Mt Keith Satellite Project, subject to regulatory approvals.

At Leinster, we anticipate declaring reserves for Venus and commencing production by the end of FY2019. We will potentially start developing the Leinster Block Cave and begin an extensive exploration program utilising the underground platform created by the Venus drives.

1.10.2    Minerals Americas

The Minerals Americas asset group includes projects, operated assets and non-operated joint ventures in Canada, Chile, Peru, the United States, Colombia and Brazil. These produce copper, zinc, iron ore and coal.

Operated assets

Copper

Our operated copper assets in the Americas, Escondida and Pampa Norte, are open-cut mines. At these mines, overburden is removed after blasting, using a truck and shovel. Ore is then extracted and further processed into high-quality copper concentrate or cathode. Copper concentrate is obtained through a grinding and flotation process, while copper cathode is produced from a leaching, solvent extraction and electrowinning process. Copper concentrate is transported to ports via pipeline, while cathode is transported by either rail or road. From the port, it is exported to our customers around the world.

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Escondida (Chile)

Overview

We operate and own 57.5 per cent of the Escondida mine, which is a leading producer of copper concentrate and cathodes. Escondida, located in the Atacama Desert in northern Chile, is a copper porphyry deposit. Following the commissioning of the Escondida Water Supply project and ramp-up of the Los Colorados Concentrator in the September 2017 quarter, Escondida´s two open-cut mines feed three concentrator plants (which use grinding and flotation technologies to produce copper concentrate), as well as two leaching operations (oxide and sulphide).

Key developments during FY2018

Escondida copper production in FY2018 increased by 57 per cent to 1,213 kt, reflecting a full year of production following the industrial action in the previous year and supported by the start-up of the Los Colorados Extension project on 10 September 2017. The addition of the third concentrator helps offset grade decline over the next decade and adds incremental annual copper production. Production attributed to the Los Colorados concentrator in FY2018 was 208.9kt.

The Escondida Water Supply Expansion (EWSE) project was sanctioned by the joint venture parties in March 2018 and will deliver its first water in FY2020. EWSE comprises the expansion of the Escondida Water Supply (EWS) conveyance system by 1,300 litres per second and desalination plant system by 800 litres per second. This project, in conjunction with the existing desalination installed capacity, will reduce reliance on ground water sources and enable Escondida to achieve its production plans. At the end of FY2018, the proportion of desalinated water in use at Escondida was 38 per cent.

The next step in Escondida’s transition to desalinated water is the sustainable reduction of ground water usage with the goal of eliminating ground water usage entirely by 2030, in line with BHP’s commitment to changing the balance of its water supply sources. The strategy focuses on increasing the use of desalinated water, recovering more water from operational processes and gradually reducing the use of water from aquifers.

In October 2017, Escondida and Union N°2 of Supervisors and Staff signed a new collective bargaining agreement valid until 30 September 2020.

The agreement with Workers Union N°1 expired on 1 August 2018. On 17 August 2018, Escondida successfully completed negotiations with Union N°1 and signed a new collective agreement, effective for 36 months from 1 August 2018.

Looking ahead

Production of between 1,120 and 1,180 kt is forecast in FY2019, as higher expected throughput is offset by a significant decrease in average concentrator head grade consistent with the mine plan.

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As well as continuing to expand the capacity of the existing desalination plant to reduce ground water usage, we will also realise further latent capacity by debottlenecking the concentrators and maximising concentrator throughput, implementing leaching process improvements to sustain cathodes production and increase fleet run time by optimising maintenance.

Pampa Norte (Chile)

Overview

Pampa Norte consists of two wholly owned assets in the Atacama Desert in northern Chile – Spence and Cerro Colorado. Spence and Cerro Colorado produce high-quality copper cathode, using oxide and sulphide ore treatment through leaching, solvent extraction and electrowinning processes.

Key developments during FY2018

Pampa Norte copper production for FY2018 increased by four per cent to 264 kt, supported by record copper cathode production of 200 kt at Spence for the full-year driven by higher throughput in the dry area through better maintenance and production practices, and the Spence Recovery Optimisation project implemented in December 2016, enabling higher recoveries.

In August 2017, the BHP Board approved an investment of US$2.5 billion for the development of the Spence Growth Option (SGO). The project involves the design, engineering and construction of a 95 kilotonnes per day (ktpd) concentrator and the outsourcing of a 1,000 litre per second desalination plant, creating up to 5,000 jobs during the construction phase. SGO will extend the life of the mine by more than 50 years and is expected to increase copper production capacity by approximately 185 ktpa, with first production expected in FY2021. The current copper cathode stream will continue until FY2025.

Since the approval date, SGO has achieved key operational milestones, starting execution phase earlier than planned. Earthwork and foundations for the concentrator area have started and camp construction plan is on track, delivering 2,000 beds as of 30 June 2018. Furthermore, the desalination Build Own Operate Transfer (BOOT) contract has been awarded.

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During FY2018, Spence reached an agreement with the Supervisors’ Union and signed a new contract effective for three years from 1 April 2018. On 12 June 2018, the company completed negotiations with the Workers’ Union that resulted in a new collective bargaining contract for three years, effective from 1 June 2018.

On 13 July 2018, Compañía Minera Cerro Colorado and its Supervisors and Staff Union signed a new collective bargaining agreement for three years effective from 1 July 2018.

BHP has entered into an agreement to sell Cerro Colorado to private equity manager EMR Capital. The sale is subject to financing and customary closing conditions, and is expected to be completed during the December 2018 quarter.

Looking ahead

Production at Spence is expected to be between 185 and 200 kt in FY2019, with volumes weighted to the second half as planned maintenance in May and June 2018 contributed to a lower stacking rate.

In line with operational initiatives under evaluation, Spence will continue evaluating materials handling and fleet replenishment options, with a view to fully leverage the use of technology at the mine site. This includes considering a redesign of the mine’s operational philosophy, with a crushing and conveying ore system complemented by autonomous trucks. The timing and sequencing of these options is pertinent to reducing health and safety risks and operating costs, with technology enabled solutions potentially significantly reducing risks associated with crash, collision and rollover, silica exposure, dust and greenhouse gas emissions.

The existing agreement between Cerro Colorado and the Operators and Maintainers Union expired on 31 August 2018. Cerro Colorado is currently in negotiations with the Union to sign a new agreement.

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Potash

Overview

Potash is a potassium-rich salt mainly used in fertiliser to improve the quality and yield of agricultural production. As an essential nutrient for plant growth, potash is a vital link in the global food supply chain. The demands on that supply chain are intensifying; there will be more people to feed in future, as well as rising calorific intake comprising more varied diets. The strains this will place on finite land supply mean sustainable increases in crop yields will be crucial and potash fertilisers will be critical in replenishing our soils.

Jansen Potash Project

BHP holds exploration permits and mining leases covering approximately 9,600 square kilometers in the province of Saskatchewan, Canada. The Jansen Potash Project is located approximately 140 kilometers east of Saskatoon. We currently own 100 per cent of this Project.

Jansen’s large resource endowment provides the opportunity to develop it in stages, with anticipated initial capacity of 4 Mtpa.

Key developments during FY2018

Over the year, our focus was on the safe excavation and preliminary lining of two 7.3-metre diameter shafts. Excavation of both the service shaft and the production shaft was completed by the end of August 2018, at a depth of 1,005 metres and 975 metres respectively. Both shafts reached potash in the Upper and Lower Patience Lake formations during FY2018. Jansen is intended to mine the Lower Patience Lake formation, which lies between 935 metres and 940 metres.

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In June 2018, the Board approved further funding to cover support services at the site as work continues on completion of the shafts, updating the approved investment for the current scope of work on the Jansen Potash Project to US$2.7 billion.

Looking ahead

Future work will include installing watertight composite concrete and steel final liners in both shafts. We continue to assess how to reduce risk and unlock value as we complete the shafts. At the end of FY2018, the current scope of work was 79 per cent complete. In the meantime, we are considering multiple options to maximise the value of Jansen, including further improvements to capital efficiency, optimisation of design and diluting our interest by bringing in a partner. As with all decisions relating to the deployment of capital, next steps with the Project will be assessed by reference to our Capital Allocation Framework.

Non-operated minerals joint ventures

BHP holds interests in companies and joint ventures that we do not operate. Our non-operated minerals joint ventures (NOJVs) include Antamina (33.75 per cent ownership), Resolution (45 per cent ownership), Cerrejón (33.33 per cent ownership), Samarco (50 per cent ownership) and Nimba (43 per cent ownership) (NOJVs).

We engage with our non-operated minerals joint venture partners and operator companies through our Non-Operated Joint Ventures team, which seeks to sustainably maximise returns and manage risks of our investment in NOJVs. While NOJVs have their own operating and management standards, we seek to influence operator companies to adopt appropriate governance and risk management standards (within the limits of the relevant joint venture agreements).

The team engages with our NOJV partners and companies and other relevant internal and external stakeholders and provides a single point of accountability for all NOJVs within BHP. The team also looks for opportunities to contribute to an improvement in joint venture governance across the mining sector. In the year since the team was established, we have built up the capabilities that we need to influence our NOJV partners and defined a strategy based on three pillars:

• Governance: support strong governance and day-to-day working relationships with our NOJV partners. As a shareholder of our NOJVs, our priority is to improve governance at NOJVs through benchmarking of board practices, influencing changes at the board level and supporting operator companies to embed clear accountabilities and governance principles.

• Risk: support operator companies to implement strong risk management discipline at NOJVs in accordance with the global risk management standards from the International Standards Organisation, ISO 31000. We are working to influence operator companies to align their risk process to these standards, elevate risk management at the operator boards and management committees and develop a strategy to improve risk practices. One of our goals in doing so is to gain a clearer understanding of BHP’s risk exposure from its NOJVs so that we can then define and implement more targeted controls for those risks.

• Value: become a highly trusted adviser to our NOJVs, encouraging them to achieve the best performance and create value for shareholders. We work to encourage all shareholders of NOJVs to consider the best strategic option to increase long-term value.

More information on health, safety and environment performance at our NOJVs is available in our Sustainability Report 2018, available online at bhp.com.

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Non-operated minerals joint ventures

Copper

Antamina (Peru)

Overview

We own 33.75 per cent of Antamina, a large, low-cost copper and zinc mine in north central Peru. Antamina is a joint venture between BHP (33.75 per cent), Glencore (33.75 per cent), Teck Resources (22.5 per cent) and Mitsubishi Corporation (10 per cent) and is operated by Compañía Minera Antamina S.A. Antamina by-products include molybdenum and silver.

Key developments during FY2018

Copper production for FY2018 increased by four per cent to 140 kt, with zinc increasing by 37 per cent to 120 kt. Throughout FY2018, Antamina continued to study options to debottleneck the operation and increase throughput, with strong focus on evaluating new technologies.

Looking ahead

Antamina remains focused on improving productivity and reducing unit cash costs. Copper production is expected to remain at similar levels in FY2019 at approximately 135 kt, while zinc production is expected to be approximately 85 kt, consistent with the mine plan. The three-year Antamina Union Agreement expired on 31 July 2018. Antamina is currently in negotiations with the Union to sign a new agreement.

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Resolution Copper (United States)

Overview

We hold a 45 per cent interest in the Resolution Copper project in the US state of Arizona, which is operated by Rio Tinto (55 per cent interest). Resolution Copper is one of the largest undeveloped copper projects in the world and has the potential to become the largest copper producer in North America. The Resolution Copper deposit lies more than 1,600 metres beneath the surface. Resolution Copper is working with regulators and the community to plan the development of the resource and obtain the necessary permits.

Key developments during FY2018

Restoration of the historic No. 9 shaft, originally constructed in 1971, has continued. The initial phase of the project is to rehabilitate the shaft down to its current depth at 1,460 metres below the surface. Eventually, the shaft will be extended down to approximately 2,086 metres and will link with the existing No. 10 shaft.

Studies to identify the best development pathway for the project progressed in FY2018. The multi-year National Environmental Policy Act permitting process and community engagement are progressing positively. Our share of the project expenditure for FY2018 was US$57 million.

Looking ahead

We remain focused on optimising the Resolution Copper project and working with the operator, Rio Tinto, to develop the project in a manner that creates sustainable benefits for all stakeholders. Next key milestones for the project are in December 2018 when rehabilitation of Shaft 9 is due to be completed and CY2019 when a draft version of the environmental impact study is expected to be made public. A single preferred investment alternative has not yet been selected for the final investment decision.

Coal

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Cerrejón (Colombia)

Overview

We have a one-third interest in Cerrejón, which owns, operates and markets one of the world’s largest open-cut export energy coal mines, located in the La Guajira province of Colombia. Cerrejón also owns and operates integrated rail and port facilities through which the majority of production is exported to European, Asian, North and South American customers.

Cerrejón’s coal assets consist of an open-cut mine. Overburden is removed after blasting, using either draglines or truck and shovel. Coal is then extracted using excavators or loaders and loaded onto trucks to be taken to stockpiles or directly to our beneficiation facility.

Coal from stockpiles is crushed, of which a certain portion is washed and processed through the coal preparation plant. Domestic coal is transported to nearby customers via conveyor. Export coal is transported to the port via trains.

Cerrejón production declined three per cent to 10,616 kt in FY2018, due to unfavourable weather impacts on mine sequencing, equipment availability and higher strip ratio areas being mined.

Looking ahead

Cerrejón is focused on stability of throughput with current installed capacity and securing the necessary permits to access ore reserves.

Iron ore

Samarco (Brazil)

BHP Billiton Brasil Limitada and Vale S.A. each holds a 50 per cent shareholding in Samarco Mineração S.A. (Samarco), the owner of the Samarco iron ore mine in Brazil.

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Overview

As a result of the tragic dam failure at Samarco in November 2015, operations at Samarco remain suspended. For more information on the Samarco dam failure, refer to section 1.8.

Samarco comprises a mine and three concentrators located in the state of Minas Gerais, and four pellet plants and a port located in Anchieta in the state of Espírito Santo. Three 400-kilometre pipelines connect the mine site to the pelletising facilities.

Samarco’s main product is iron ore pellets. Prior to the suspension of operations, the extraction and beneficiation of iron ore were conducted at the Germano facilities in the municipalities of Mariana and Ouro Preto. Front end loaders were used to extract the ore and convey it from the mines. Ore beneficiation then occurred in concentrators, where crushing, milling, desliming and flotation processes produced iron concentrate. The concentrate leaves the concentrators as slurry and is pumped through the slurry pipelines from the Germano facilities to the pellet plants in Ubu, Anchieta, where the slurry is processed into pellets. The iron ore pellets are then heat treated. The pellet output is stored in a stockpile yard before being shipped out of the Samarco-owned Port of Ubu in Anchieta.

Key developments during FY2018

For information on the progress made on remediation, resettlement and compensation in response to the Fundão dam failure, refer to section 1.8.

Looking ahead

Restart of Samarco’s operations remains a focus, but is subject to separate negotiations with relevant parties and will occur only if it is safe, economically viable and has the support of the community. Resuming operations requires the granting of licences by state and federal authorities, community hearings and an appropriate restructure of Samarco’s debt.

1.10.3     Petroleum

Conventional petroleum

BHP has owned oil and gas assets since the 1960s. We have high-margin conventional assets located in the US Gulf of Mexico, Australia, Trinidad and Tobago, Algeria and the United Kingdom, as well as prospects in Mexico and Barbados. Our conventional petroleum business includes exploration, appraisal, development and production activities. We produce crude oil and condensate, gas and natural gas liquids (NGLs) that are sold on the international spot market or delivered domestically under contracts with varying terms, depending on the location of the asset.

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United States

Gulf of Mexico

Overview

We operate two fields in the US waters of Gulf of Mexico – Shenzi (44 per cent interest) and Neptune (35 per cent interest).

We hold non-operating interests in two other fields – Atlantis (44 per cent interest) and Mad Dog (23.9 per cent interest).

All our producing fields are located between 155 and 210 kilometres offshore from the US state of Louisiana. We also own 25 per cent and 22 per cent, respectively, of the companies that own and operate the Caesar oil pipeline and the Cleopatra gas pipeline. These pipelines transport oil and gas from the Green Canyon area, where our US Gulf of Mexico fields are located, to connecting pipelines that transport product onshore.

Key developments during FY2018

Mad Dog Phase 2, located in the Green Canyon area in the Deepwater Gulf of Mexico, is an extension of the existing Mad Dog field. The Mad Dog Phase 2 project is in response to the successful Mad Dog South appraisal well, which confirmed significant hydrocarbons in the southern portion of this field.

The project cost has more than halved since 2013, with a revised field development concept leading to significant cost reductions. It is now estimated to be US$9 billion on a 100 per cent basis (US$2.2 billion BHP share). The Mad Dog Phase 2 project was sanctioned by BP (the operator) in December 2016, and was approved by the BHP Board in February 2017. The project includes a new floating production facility with the capacity to produce up to 140,000 gross barrels of crude oil per day from up to 14 production wells. Production is expected to begin in FY2022.

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Australia

Overview

Bass Strait

We have produced oil and gas from Bass Strait (50 per cent interest) for close to 50 years. Our operations are located between 25 and 80 kilometres off the southeastern coast of Australia. The Gippsland Basin Joint Venture, operated by Esso Australia (a subsidiary of ExxonMobil), participated in the original discovery and development of hydrocarbons in the field. More recently, the Kipper gas field under the Kipper Unit Joint Venture (also operated by Esso Australia) has brought online additional gas and liquids production that are processed via the existing Gippsland Basin Joint Venture facilities.

We sell the majority of our Bass Strait crude oil and condensate production to local refineries in Australia. Gas is piped onshore to the joint venture’s Longford processing facility, from where we sell our share of production to domestic retailers and end users. Liquefied petroleum gas (LPG) is dispatched via pipeline, road tanker or sea tanker. Ethane is dispatched via pipeline to a petrochemical plant in western Melbourne.

North West Shelf

We are a joint venture participant in the North West Shelf Project (12.5–16.67 per cent interest), located approximately 125 kilometres northwest of Dampier in Western Australia. The North West Shelf Project supplies gas to the Western Australian domestic market and liquefied natural gas (LNG) to buyers primarily in Japan, South Korea and China.

North West Shelf gas is piped from offshore fields to the onshore Karratha Gas Plant for processing. LPG, condensate and LNG are transported to market by ship, while domestic gas is transported by the Dampier-to-Bunbury and Pilbara Energy pipelines to buyers.

We are also a joint venture partner in four nearby oil fields – Cossack, Wanaea, Lambert and Hermes. All North West Shelf gas and oil joint ventures are operated by Woodside.

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Pyrenees

We operate six oil fields in Pyrenees, which are located offshore around 23 kilometres northwest of Northwest Cape, Western Australia. We had an effective 62 per cent interest in the fields as at 30 June 2018 based on inception-to-date production from two permits in which we have interests of 71.43 per cent and 40 per cent, respectively. The development uses a floating, production, storage and off-take (FPSO) facility.

Macedon

We are the operator of Macedon (71.43 per cent interest), an offshore gas field located around 75 kilometres west of Onslow, Western Australia and an onshore gas processing facility, located around 17 kilometres southwest of Onslow.

The operation consists of four subsea wells, with gas piped onshore to the processing plant. After processing, the gas is delivered into a pipeline and sold to the West Australian domestic market.

Minerva

We are the operator of the Minerva Joint Venture (90 per cent interest), a gas field located 11 kilometres south-southwest of Port Campbell in western Victoria. The operation consists of two subsea wells, with gas piped onshore to a processing plant. After processing, the gas is delivered into a pipeline and sold domestically.

On 1 May 2018, BHP entered into an agreement for the sale of its interests in the onshore gas plant with subsidiaries of Cooper Energy and Mitsui E&P Australia Pty Ltd. The agreement, which is conditional on completion of regulatory approvals and assignments, provides for the transfer of the plant and associated land after the cessation of current operations processing gas from the Minerva gas field. Following Minerva end-of-field life, the wells will be plugged and abandoned.

Key developments during FY2018

North West Shelf Other: Greater Western Flank–B

The Greater Western Flank ‘2’ project was sanctioned by the Board in December 2015 and represents the second phase of development of the core Greater Western Flank fields, behind the GWF-A development. It is located to the southwest of the existing Goodwyn A platform. The development comprises six fields and eight subsea wells. Execution activities are in progress, with first production expected in CY2019. Our share of development costs is around US$216 million.

Scarborough

Development planning for the large Scarborough gas field (located offshore from Western Australia) is in progress. Further work to optimise a preferred development option is ongoing. On 14 November 2016, we completed the divestment of 50 per cent of our interest in the undeveloped Scarborough area gas fields to Woodside Energy Limited (Woodside).

The transaction included half of BHP’s interests in WA-1-R, WA-62-R, WA-61-R and WA-63-R, for an initial cash consideration of US$250 million and a further US$150 million payable at the time a final investment decision is made for the development of the Scarborough gas field. Following the transaction, BHP holds a 25 per cent non-operated interest in WA-1-R and a 50 per cent non-operated interest in WA-61-R, WA-62-R and WA-63-R. Woodside became the operator of the WA-1-R lease in March 2018 following its acquisition of Esso’s working interest in the title. BHP has an option to acquire a further 10 per cent interest in WA-1-R from Woodside on equivalent terms to its Esso transaction. This option may be exercised at any time prior to the earlier of 31 December 2019 and the date approval is given to commence the front-end engineering and design phase of the development of the Scarborough gas field.

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Other conventional petroleum assets

Overview

Trinidad and Tobago

We operate the Greater Angostura field (45 per cent interest in the production sharing contract), an integrated oil and gas development located offshore 40 kilometres east of Trinidad. The crude oil is sold on a spot basis to international markets, while the gas is sold domestically under term contracts.

Algeria

Our Algerian asset comprises an effective 29.3 per cent interest in the ROD Integrated Development, which consists of six satellite oil fields that pump oil back to a dedicated processing train. The oil is sold on a spot basis to international markets. ROD is jointly operated by Sonatrach and ENI.

United Kingdom

We hold 16 per cent non-operating interest in the Bruce oil and gas field in the North Sea and a 31.83 per cent non-operating interest in the Keith oil and gas field, a subsea tie-back. Operatorship of the Keith field was transferred to BP on 31 July 2015. Oil and gas from both fields are processed via the Bruce platform facilities.

For more information, refer to section 1.12.1.

Unconventional petroleum

Onshore US

On 27 July 2018, BHP announced that we had entered into agreements for the sale of our entire interest in the Eagle Ford, Permian, Haynesville and Fayetteville Onshore US oil and gas assets for a combined base consideration of US$10.8 billion payable in cash (less customary completion adjustments). Both sales are subject to the satisfaction of customary regulatory approvals and conditions precedent. We expect completion to occur by the end of October 2018. The effective date at which the right to economic profits transfers is 1 July 2018.

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Eagle Ford

The Eagle Ford area (approximately 236,000 net acres) consists of Black Hawk and Hawkville fields, with production operations located primarily in the southern Texas counties of DeWitt, Karnes, McMullen and LaSalle. We produce condensate, gas and NGLs from the two fields. The condensate and gas produced are sold domestically in the United States via connections to intrastate and interstate pipelines, and internationally through the export of processed condensate. Our average net working interest is around 62 per cent. We act as joint venture operator for approximately 34 per cent of our gross wells. In DeWitt county, we are operators for the drilling and completion phases of the majority of wells. The Eagle Ford gathering system consists of around 1,436 kilometres of pipelines in both Black Hawk and Hawkville fields that deliver volumes to multiple central delivery points, from which volumes are treated and transported to market. We operate the gathering system and own 75 per cent of it, while the remaining 25 per cent is held by Kinder Morgan.

Permian

The Permian production operation is located primarily in the western Texas county of Reeves and consists of approximately 83,000 net acres. We produce oil, gas and NGLs. The oil and gas are sold domestically in the United States via connections to intrastate and interstate pipelines. Our average net working interest is approximately 84 per cent. We acted as joint venture operator for around 83 per cent of our gross wells. Permian has approximately 162 kilometres of water pipelines and a gathering system that consists of approximately 211 kilometres of gas pipelines that deliver volumes to third party processing plants, from where processed volumes are transported to market.

Haynesville

The Haynesville production operation is located primarily in northern Louisiana and consists of approximately 193,000 net acres. We produce gas that is sold domestically in the United States via connections to intrastate and interstate pipelines. Our average net working interest (operated and non-operated) is approximately 37 per cent. We acted as joint venture operator for around 38 per cent of our gross wells.

Fayetteville

The Fayetteville production operation is located in north central Arkansas and consists of approximately 258,000 net acres. We produce gas that is sold domestically in the United States via connections to intrastate and interstate pipelines. Our average net working interest (operated and non-operated) is approximately 21 per cent. We acted as joint venture operator for around 19 per cent of our gross wells. The Fayetteville gathering system consists of around 770 kilometres of pipelines that deliver volumes to multiple compressor stations where processed volumes are transported to market.

Non-operated petroleum joint ventures

In our current non-operated petroleum joint ventures, we have processes in place to identify and manage risks within the rights afforded by the respective joint operating agreements. This includes (as permitted by the relevant operator and/or joint venture arrangements) verification of risk control strategies through field visits, review and analysis of the operator’s performance data, participation in operator audits and sharing of BHP risk management strategies and processes.

1.10.4    Marketing and Supply

Marketing and Supply are separate core businesses of BHP, connected under the Commercial function. They are the link between BHP’s global operations, our customers and our local and global suppliers, and are aligned to our assets.

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Marketing

Marketing focuses on optimising realised prices and sales outcomes, presenting a single face to markets and customers across multiple assets. This allows our assets to focus on safety, volume and cost. Marketing secures sales of BHP products through building long-term, sustainable relationships with our customers and manages the associated risks of getting our resources to market. Marketing provides governance of credit, manages market and price risks and supports strategic and commercial decision-making by analysing commodity markets and providing short- and long-term insights.

Supply

Supply is our global procurement division, which purchases goods and services that are used by our assets and functions. Supply works with our assets to optimise equipment performance, reduce operating cost and improve working capital. Supply manages supply chain risk and develops sustainable relationships with both global suppliers and local businesses in our communities.

Our commercial value chain

By connecting all our commercial activities under a single function and locating them close to our key markets, we have a single strategic view of our entire value chain. This allows us to operate on both sides of the commercial coin. It helps us create effective partnerships with our communities through local procurement and deepen our relationships with our customers and suppliers globally. It expands our view of how our markets might evolve, so that we can adapt our strategy to take action in a changing market, including optimising our supply chains. The combined function allows us to rapidly replicate good practice and share market insights across teams. It ensures effective governance and risk management, while driving productivity through a centralised freight business that procures safe, sustainable procurement solutions.

Ensuring long-term sustainability of our value chain

Marketing and Supply’s outlook on the global economy, the resource industry and each of the commodities in our portfolio supports asset and portfolio investment decisions, strategic planning, valuations and capital management. The Commercial teams also inform broader organisational priorities such as our position on climate change. This includes setting global standards for a sustainable and ethical supply chain that takes into account human rights and environmental risks.

Marketing and Supply: Strategically located close to our key markets

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1.11    Summary of financial performance

1.11.1    Group overview

We prepare our Consolidated Financial Statements in accordance with International Financial Reporting Standards (IFRS), as issued by the International Accounting Standards Board. We publish our Consolidated Financial Statements in US dollars. All Consolidated Income Statement, Consolidated Balance Sheet and Consolidated Cash Flow Statement information below has been derived from audited financial statements. For more information, refer to section 5.

Unless otherwise stated, comparative financial information for FY2017, FY2016, FY2015 and FY2014 has been restated to reflect the announcement of the sale of the Onshore US assets on 27 July 2018 and the demerger of South32 in FY2015, as required by IFRS 5/AASB 5 ‘Non-current Assets Held for Sale and Discontinued Operations’. Consolidated Balance Sheet information for these periods has not been restated as accounting standards do not require it.

Information in this section has been presented on a Continuing operations basis to exclude the contribution from Onshore US assets and assets that were demerged with South32 in FY2015, unless otherwise noted. Details of the contribution of the Onshore US assets to the Group’s results are disclosed in note 26 ‘Discontinued operations’ in section 5.

Year ended 30 June US$M	2018			2017			2016			2015			2014
Consolidated Income Statement (section 5.1.1)
Revenue		43,638			36,135			28,567			40,413			52,123
Profit from operations		15,996			12,554			2,804			12,887			22,812
Profit/(loss) after taxation from Continuing operations		7,744			6,694			(312	)		7,306			15,068
(Loss)/profit after taxation from Discontinued operations		(2,921	)		(472	)		(5,895	)		(4,428	)		156
Profit/(loss) after taxation from Continuing and Discontinued operations attributable to BHP shareholders (Attributable profit/(loss)) (1)		3,705			5,890			(6,385	)		1,910			13,832
Dividends per ordinary share – paid during the period (US cents)		98.0			54.0			78.0			124.0			118.0
Dividends per ordinary share – determined in respect of the period (US cents)		118.0			83.0			30.0			124.0			121.0
Basic earnings/(loss) per ordinary share (US cents) (1)(2)		69.6			110.7			(120.0	)		35.9			260.0
Diluted earnings/(loss) per ordinary share (US cents) (1)(2)		69.4			110.4			(120.0	)		35.8			259.1
Basic earnings/(loss) from Continuing operations per ordinary share (US cents) (2)		125.0			119.8			(10.2	)		119.6			258.4
Diluted earnings/(loss) from Continuing operations per ordinary share (US cents) (2)		124.6			119.5			(10.2	)		119.3			257.5
Number of ordinary shares (million)
– At period end		5,324			5,324			5,324			5,324			5,348
– Weighted average		5,323			5,323			5,322			5,318			5,321
– Diluted		5,337			5,336			5,322			5,333			5,338
Consolidated Balance Sheet (section 5.1.3) (3)
Total assets		111,993			117,006			118,953			124,580			151,413
Net assets		60,670			62,726			60,071			70,545			85,382
Share capital (including share premium)		2,761			2,761			2,761			2,761			2,773
Total equity attributable to BHP shareholders		55,592			57,258			54,290			64,768			79,143

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Year ended 30 June US$M	2018		2017		2016		2015		2014
Consolidated Cash Flow Statement (section 5.1.4)
Net operating cash flows (4)		18,461		16,804		10,625		19,296		25,364
Capital and exploration expenditure (5)		6,753		5,220		7,711		13,412		17,003
Other financial information
Net debt (6)		10,934		16,321		26,102		24,417		25,786
Underlying attributable profit (6)		8,933		6,732		1,215		7,109		13,447
Underlying EBITDA (6)		23,183		19,350		11,720		19,816		28,029
Underlying EBIT (6)		16,562		13,190		5,324		13,296		22,261
Underlying basic earnings per share (US cents) (6)		167.8		126.5		22.8		133.7		252.7

⁽¹⁾ Includes (Loss)/profit after taxation from Discontinued operations attributable to BHP shareholders.

⁽²⁾ For more information on earnings per share, refer to note 6 ‘Earnings per share’ in section 5.

⁽³⁾ The Consolidated Balance Sheet for FY2018 includes the assets and liabilities held for sale in relation to Onshore US, FY2014 includes the assets and liabilities demerged to South32 as IFRS 5/AASB 5 ‘Non-current Assets Held for Sale and Discontinued Operations’ does not require the Consolidated Balance Sheet to be restated for comparative periods.

⁽⁴⁾ Net operating cash flows are after dividends received, net interest paid and net taxation paid and includes Net operating cash flows from Discontinued operations.

⁽⁵⁾ Capital and exploration expenditure is presented on a cash basis and represents purchases of property, plant and equipment plus exploration expenditure from the Consolidated Cash Flow Statement in section 5 and includes purchases of property, plant and equipment plus exploration expenditure from Discontinued operations. Refer to note 26 ‘Discontinued operations’ in section 5. FY2015 and FY2014 capital and exploration expenditure has been restated to include Discontinued operations. Purchase of property, plant and equipment includes capitalised deferred stripping of US$880 million for FY2018 (FY2017: US$416 million) and excludes capitalised interest. Exploration expenditure is capitalised in accordance with our accounting policies, as set out in note 10 ‘Property, plant and equipment’ in section 5.

⁽⁶⁾ We use alternative performance measures to reflect the underlying performance of the Group. Underlying attributable profit and Underlying basic earnings per share includes Continuing and Discontinued operations. Refer to section 1.11.4 for a reconciliation of alternative performance measures to their respective IFRS measure. Refer to section 1.11.5 for the definition and method of calculation of alternative performance measures. Refer to note 18 ‘Net debt’ in section 5 for the composition of Net debt.

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1.11.2    Financial results

The following table expands on the Consolidated Income Statement in section 5.1.1, to provide more information on the revenue and expenses of the Group in FY2018.

Year ended 30 June	2018 US$M			2017 US$M			2016 US$M
Continuing operations
Revenue (1)		43,638			36,135			28,567
Other income		247			662			432
Employee benefits expense		(3,990	)		(3,694	)		(3,605	)
Changes in inventories of finished goods and work in progress		142			743			(287	)
Raw materials and consumables used		(4,389	)		(3,830	)		(3,985	)
Freight and transportation		(2,294	)		(1,786	)		(1,648	)
External services		(5,217	)		(4,341	)		(4,370	)
Third party commodity purchases		(1,452	)		(1,151	)		(994	)
Net foreign exchange losses/(gains)		93			(103	)		153
Government royalties paid and payable		(2,168	)		(1,986	)		(1,349	)
Exploration and evaluation expenditure incurred and expensed in the current period		(641	)		(610	)		(419	)
Depreciation and amortisation expense		(6,288	)		(6,184	)		(6,210	)
Impairment of assets		(333	)		(193	)		(186	)
Operating lease rentals		(421	)		(391	)		(372	)
All other operating expenses		(1,078	)		(989	)		(819	)
Expenses excluding net finance costs		(28,036	)		(24,515	)		(24,091	)
Profit/(loss) from equity accounted investments, related impairments and expenses		147			272			(2,104	)
Profit from operations		15,996			12,554			2,804
Net finance costs		(1,245	)		(1,417	)		(1,013	)
Total taxation expense		(7,007	)		(4,443	)		(2,103	)
Profit/(loss) after taxation from Continuing operations		7,744			6,694			(312	)
Discontinued operations
Loss after taxation from Discontinued operations		(2,921	)		(472	)		(5,895	)
Profit/(loss) after taxation from Continuing and Discontinued operations		4,823			6,222			(6,207	)
Attributable to non-controlling interests		1,118			332			178
Attributable to BHP shareholders		3,705			5,890			(6,385	)

⁽¹⁾ Includes the sale of third party products.

Financial results for year ended 30 June 2018 compared with the year ended 30 June 2017

Profit after taxation attributable to BHP shareholders decreased from a profit of US$5.9 billion in FY2017 to a profit of US$3.7 billion in FY2018.

Revenue of US$43.6 billion increased by US$7.5 billion, or 21 per cent, from FY2017. This increase was primarily attributable to higher average realised prices across most commodities and higher production volumes at Escondida and WAIO as a result of the ramp-up of Los Colorados Extension project and improved productivity and stability across the supply chain, respectively. This was partially offset by lower volumes from Olympic Dam (smelter maintenance campaign) and the impact of challenging operating conditions at two Queensland Coal mines (Broadmeadow and Blackwater) coupled with lower petroleum volumes due to Hurricane Harvey and Hurricane Nate, and expected natural field decline. For information on our average realised prices and production of our commodities, refer to section 1.12.

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Total expenses of US$28.0 billion increased by US$3.5 billion or 14 per cent, from FY2017. Higher external services of US$876 million has been driven by increased contractors at Olympic Dam to support the smelter maintenance campaign and development into the South Mining Area, and additional contractor stripping fleet costs at Queensland Coal following challenging operating conditions at Broadmeadow and Blackwater. The increase in changes in inventories of finished goods and work in progress of US$601 million was primarily driven by the commissioning of the Los Colorados Extension project at Escondida that resulted in the drawdown of prior year planned build of mined ores and a change in estimated recoverable copper contained in the Escondida sulphide leach pad which benefited costs in the prior period. Raw materials and consumables used increased by US$559 million driven by operating the Los Colorados Extension project at Escondida and higher diesel costs across the Group. Freight and transportation increased by US$508 million driven by higher market freight rates and an eight per cent Group copper equivalent production volume growth.

Profit/(loss) from equity accounted investments, related impairments and expenses of US$147 million has decreased by US$125 million from FY2017. The decrease is primarily due to a change in estimate to the Samarco dam failure provision offset by higher sales volumes from Antamina and higher average realised prices received by equity accounted investments in FY2018.

Net finance costs of US$1.2 billion decreased by US$172 million, or 12 per cent, from FY2017 reflecting a lower average debt balance following the bond repurchase program and repayment on maturity of Group debt. This was partially offset by higher benchmark interest rates in the period as well as costs related to the September 2017 bond repurchase. For more information on net finance costs, refer to section 1.11.3 and note 18 ‘Net debt’ in section 5.

Total taxation expense of US$7.0 billion increased by US$2.6 billion from FY2017. The increase is primarily due to the impacts of the US tax reform and higher profits in FY2018. For more information on income tax expense, refer to note 5 ‘Income tax expense’ in section 5.

Financial results for the year ended 30 June 2017 compared with year ended 30 June 2016

Profit after taxation from Continuing and Discontinued operations attributable to BHP shareholders increased from a loss of US$6.4 billion in FY2016 to a profit of US$5.9 billion in FY2017.

Revenue of US$36.1 billion increased by US$7.6 billion, or 26 per cent, from FY2016. This increase was primarily attributable to higher average realised prices, partially offset by lower production at Escondida mainly due to industrial action and at Queensland Coal due to the impact of Cyclone Debbie. For information on our average realised prices and production of our commodities, refer to section 1.12.

Total expenses of US$24.5 billion increased by US$424 million, or two per cent, from FY2016. Changes in inventories of finished goods and work in progress of US$1,030 million was primarily driven by a planned build of mined ore at Escondida ahead of the commissioning of the Los Colorados Extension project in the September 2017 quarter, and a benefit relative to FY2016 due to an inventory drawdown at Olympic Dam in the prior year. This was partially offset by an increase to government royalties paid and payable of US$637 million, driven by higher revenues as explained earlier in this section.

Profit/(loss) from equity accounted investments, related impairments and expenses of US$272 million has increased by US$2.4 billion from FY2016. The increase is primarily due to the initial financial impact of the Samarco dam failure decreasing the FY2016 result and higher average realised prices received by operating equity accounted investments in FY2017.

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Net finance costs of US$1.4 billion increased by US$404 million, or 40 per cent, from FY2016 reflecting higher benchmark interest rates, costs related to the March 2017 bond repurchase program and increased discounting charges to provisions and other liabilities, primarily relating to the Samarco dam failure (US$127 million). This was partially offset by a lower average debt balance following the repayment on maturity of Group debt and the bond repurchase program. For more information on net finance costs, refer to section 1.11.3 and note 18 ‘Net debt’ in section 5.

Total taxation expense, including royalty-related taxation and exchange rate movements, was US$4.4 billion representing a statutory effective tax rate of 39.9 per cent. The FY2017 taxation expense reflects higher profits as explained earlier in this section.

Principal factors that affect Revenue, Profit from operations and Underlying EBITDA

The following table describes the impact of the principal factors that affected Revenue, Profit from operations and Underlying EBITDA for FY2018 and relates them back to our Consolidated Income Statement. For information on the method of calculation of the principal factors that affect Revenue, Profit from operations and Underlying EBITDA, refer to section 1.11.6.

	Revenue US$M			Total expenses, Other income and Profit/(loss) from equity accounted investments US$M			Profit from operations US$M			Depreciation, amortisation and impairments and Exceptional Items US$M		Underlying EBITDA US$M
For the year ended 30 June 2017
Revenue		36,135
Other income					662
Expenses excluding net finance costs					(24,515	)
Profit from equity accounted investments, related impairments and expenses					272
Total other income, expenses excluding net finance costs and Profit from equity accounted investments, related impairments and expenses					(23,581	)
Profit from operations								12,554
Depreciation, amortisation and impairments (1)											6,160
Exceptional items (refer to note 2 ‘Exceptional items’ in section 5)											636
Underlying EBITDA													19,350
Change in sales prices		4,597			(328	)		4,269			–		4,269
Price-linked costs		–			(124	)		(124	)		–		(124	)
Net price impact		4,597			(452	)		4,145			–		4,145
Productivity volumes		1,378			(354	)		1,024			–		1,024
Growth volumes		(324	)		68			(256	)		–		(256	)
Changes in volumes		1,054			(286	)		768			–		768
Operating cash costs		–			(1,114	)		(1,114	)		–		(1,114	)
Exploration and business development		–			(129	)		(129	)		–		(129	)
Change in controllable cash costs (2)		–			(1,243	)		(1,243	)		–		(1,243	)
Exchange rates		32			(280	)		(248	)		–		(248	)
Inflation on costs		–			(389	)		(389	)		–		(389	)

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	Revenue US$M			Total expenses, Other income and Profit/(loss) from equity accounted investments US$M			Profit from operations US$M			Depreciation, amortisation and impairments and Exceptional Items US$M			Underlying EBITDA US$M
Fuel and energy		–			(224	)		(224	)		–			(224	)
Non-cash		–			425			425			–			425
One-off items		–			719			719			–			719
Change in other costs		32			251			283			–			283
Asset sales		–			(142	)		(142	)		–			(142	)
Ceased and sold operations		(11	)		15			4			–			4
Other		1,831			(1,813	)		18			–			18
Depreciation, amortisation and impairments (1)		–			(461	)		(461	)		461			–
Exceptional items		–			70			70			(70	)		–
For the year ended 30 June 2018
Revenue		43,638
Other income					247
Expenses excluding net finance costs					(28,036	)
Profit from equity accounted investments, related impairments and expenses					147
Total other income, expenses excluding net finance costs and Profit from equity accounted investments, related impairments and expenses					(27,642	)
Profit from operations								15,996
Depreciation, amortisation and impairments (1)											6,621
Exceptional items (refer to note 2 ‘Exceptional items’ in section 5)											566
Underlying EBITDA														23,183

⁽¹⁾ Depreciation and impairments that we classify as exceptional items are excluded from depreciation, amortisation and impairments. Depreciation, amortisation and impairments includes non-exceptional impairments of US$333 million (FY2017: US$188 million).

⁽²⁾ Collectively, we refer to the change in operating cash costs and change in exploration and business development as change in controllable cash costs. Operating cash costs by definition do not include non-cash costs. The change in operating cash costs also excludes the impact of exchange rates and inflation, changes in fuel and energy costs, changes in exploration and business development costs and one-off items. These items are excluded so as to provide a consistent measurement of changes in costs across all segments, based on the factors that are within the control and responsibility of the segment. Change in controllable cash costs and change in operating cash costs are not measures that are recognised by IFRS. They may differ from similarly titled measures reported by other companies.

Principal factors affecting Underlying EBITDA for the year ended 30 June 2018 compared with year ended 30 June 2017

Higher average realised prices across most of our key commodities increased Underlying EBITDA by US$4.3 billion in FY2018. This was partially offset by an increase to price-linked costs of US$124 million reflecting higher royalty charges.

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Productivity volumes in Underlying EBITDA improved by US$1.0 billion primarily as a result of the release of latent capacity at Escondida (ramp-up of Los Colorados Extension project) and WAIO (improved productivity and stability across the supply chain), partially offset by lower volumes from Olympic Dam (smelter maintenance campaign) and the impact of challenging operating conditions at two Queensland Coal mines (Broadmeadow and Blackwater). This was partially offset by US$256 million lower growth volumes due to Hurricane Harvey and Hurricane Nate, and expected natural field decline.

Higher costs reflect unfavourable fixed cost dilution at Olympic Dam (smelter maintenance campaign) and conventional petroleum (natural field decline), challenging operating conditions at two Queensland Coal mines (Broadmeadow and Blackwater) and a favourable change in estimated recoverable copper in the Escondida sulphide leach pad in the prior period, partially offset by lower labour and contractor costs at WAIO and the impact of higher exploration expenditure attributable to an increase in planning activity in Mexico and the Scimitar well write-off, partially offset by expensing of the Burrokeet and Wildling wells in the prior year.

A weaker US dollar against the Australian dollar and Chilean peso decreased Underlying EBITDA by US$248 million during the period.

Higher capitalisation of deferred stripping at Escondida and increased underground mine development capitalisation at Olympic Dam as development extends into the Southern Mine Area increased Underlying EBITDA by US$425 million.

Principal factors affecting Underlying EBITDA for the year ended 30 June 2017 compared with year ended 30 June 2016

Higher average realised prices across our key commodities increased Underlying EBITDA by US$8.5 billion in FY2017. This was partially offset by an increase in price linked costs of US$810 million reflecting higher royalty charges.

Productivity volumes in Underlying EBITDA improved by US$340 million primarily as a result of ongoing efficiency improvements and the release of latent capacity across the Group, excluding US$602 million one-off items from the industrial action at Escondida, power outage at Olympic Dam and the impact of Cyclone Debbie at Queensland Coal.

Our focus on best-in-class performance underpinned a US$981 million reduction in controllable cash costs during FY2017. Lower costs reflect a decrease in labour and contractor costs per tonne produced at WAIO, favourable impacts from inventory movements across the mineral assets and a change in estimated recoverable copper in the Escondida sulphide leach pad. These are partially offset by additional WAIO rail maintenance costs, closure and rehabilitation adjustments in petroleum and the impact of higher exploration expenditure attributable to expensing the Burrokeet wells in Trinidad and Tobago and the Wildling-1 well in the Gulf of Mexico.

A weaker US dollar against the Australian dollar and Chilean peso decreased Underlying EBITDA by US$516 million during the period.

Increased depletion of capitalised stripping and a lower strip ratio consistent with the Escondida mine plan further reduced Underlying EBITDA by US$357 million.

106

Cash flow

The following table provides a summary of the Consolidated Cash Flow Statement contained in section 5.1.4 to show the key sources and uses of cash during the periods presented:

Year ended 30 June	2018 US$M			2017 US$M			2016 US$M
Cash generated from operations		22,949			18,612			12,091
Dividends received		709			636			301
Net interest paid		(887	)		(984	)		(701	)
Settlement of cash management related instruments		(292	)		(140	)		–
Net taxation paid		(4,918	)		(2,248	)		(1,851	)
Net operating cash flows from Continuing operations		17,561			15,876			9,840
Net operating cash flows from Discontinued operations		900			928			785
Net operating cash flows		18,461			16,804			10,625
Purchases of property, plant and equipment		(4,979	)		(3,697	)		(5,707	)
Exploration expenditure		(874	)		(966	)		(752	)
Subtotal: Capital and exploration expenditure		(5,853	)		(4,663	)		(6,459	)
Exploration expenditure expensed and included in operating cash flows		641			610			419
Net investment and funding of equity accounted investments		204			(234	)		(217	)
Other investing activities		(52	)		563			239
Net investing cash flows from Continuing operations		(5,060	)		(3,724	)		(6,018	)
Net investing cash flows from Discontinued operations		(861	)		(437	)		(1,227	)
Net investing cash flows		(5,921	)		(4,161	)		(7,245	)
Net (repayment of)/proceeds from interest bearing liabilities		(3,878	)		(5,501	)		4,614
Dividends paid		(5,220	)		(2,921	)		(4,130	)
Dividends paid to non-controlling interests		(1,582	)		(575	)		(62	)
Other financing activities		(171	)		(108	)		(106	)
Net financing cash flows from Continuing operations		(10,851	)		(9,105	)		316
Net financing cash flows from Discontinued operations		(40	)		(28	)		(32	)
Net financing cash flows		(10,891	)		(9,133	)		284
Net increase in cash and cash equivalents		1,649			3,510			3,664
Net increase in cash and cash equivalents from Continuing operations		1,650			3,047			4,138
Net (decrease)/increase in cash and cash equivalents from Discontinued operations		(1	)		463			(474	)

Financial results for year ended 30 June 2018 compared with the year ended 30 June 2017

Net operating cash inflows of US$18.5 billion increased by US$1.7 billion. This increase reflects higher commodity prices and a strong operating performance. This was partially offset by higher net taxation paid as a result of higher profits in the current year and a final corporate income tax payment in Australia of US$1.3 billion related to the prior year.

Net investing cash outflows of US$5.9 billion increased by US$1.8 billion. The increase reflects continued investment in high-return latent capacity projects, higher Onshore US drilling activity and an increase in spend post the approval of Mad Dog Phase 2 and the Spence Growth Option projects in FY2017.

For additional information and a breakdown of capital and exploration expenditure on a commodity basis, refer to section 1.12.

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Net financing cash outflows of US$10.9 billion increased by US$1.8 billion. This reflects higher dividends to BHP shareholders of US$2.3 billion and higher dividends to non-controlling interests of US$1.0 billion partially offset by lower repayments of interest bearing liabilities of US$1.6 billion.

For additional information, refer to section 1.11.3 and note 18 ‘Net debt’ in section 5.

Financial results for the year ended 30 June 2017 compared with year ended 30 June 2016

Net operating cash inflows of US$16.8 billion increased by US$6.2 billion. This increase reflects, higher commodity prices, a continued focus on cash cost efficiency and higher dividends received from equity accounted investments in line with higher prices. This was partially offset by higher net interest paid due to higher benchmark interest rates, settlement of cash management related instruments and higher net taxation paid as a result of higher profits.

Net investing cash outflows of US$4.2 billion decreased by US$3.1 billion. The decrease reflects lower planned capital spend on major projects in FY2017 and higher cash proceeds from divestment and sale of assets during FY2017.

Net financing cash outflows of US$9.1 billion increased by US$9.4 billion. This primarily reflects the Group’s focus on debt reduction with US$3.3 billion of senior debt repaid at maturity and US$2.5 billion paid on bonds repurchased during March 2017 compared with an inflow of US$4.6 billion in FY2016 primarily due to the Group issuing multi-currency hybrid notes of US$6.4 billion. This was partially offset by lower dividends paid in FY2017 compared to FY2016 in line with the revised dividend policy.

For additional information, refer to section 1.11.3 and note 18 ‘Net debt’ in section 5.

1.11.3    Debt and sources of liquidity

Our policies on debt and liquidity management have the following objectives:

• a strong balance sheet through the cycle;

• diversification of funding sources;

• maintain borrowings and excess cash predominantly in US dollars.

Year ended 30 June 2018 compared with year ended 30 June 2017

Interest bearing liabilities, net debt and gearing

At the end of FY2018, Interest bearing liabilities were US$26.8 billion (FY2017: US$30.5 billion) and Cash and cash equivalents were US$15.9 billion (FY2017: US$14.2 billion). This resulted in net debt⁽¹⁾ of US$10.9 billion, which represented a decrease of US$5.4 billion compared with the net debt position at 30 June 2017. Gearing, which is the ratio of net debt to net debt plus net assets, was 15.3 per cent at 30 June 2018, compared with 20.6 per cent at 30 June 2017.

During FY2018, the Group continued its bias towards debt reduction. This included the decision not to refinance A$1.0 billion of Group-level debt (which matured in FY2018) and the execution of a US$2.9 billion bond repurchase program. In late September 2017, BHP concluded this bond repurchase program, which was funded by BHP’s strong cash position and targeted short-dated bonds maturing before FY2024. The early repayment of the bonds has extended BHP’s average debt maturity profile and enhanced BHP’s capital structure.

The following US bonds were partially repurchased:

• US$860 million senior notes due 2022;

• US$1,500 million senior notes due 2023.

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The following EUR and GBP bonds were partially repurchased:

• €600 million senior notes due 2020;

• €1,250 million senior notes due 2020;

• €650 million senior notes due 2022;

• €750 million senior notes due 2024;

• £750 million senior notes due 2024.

The decision not to refinance maturing Group debt and the bond repurchase program contributed to a US$3.7 billion overall decrease in interest bearing liabilities in FY2018.

At the subsidiary level, Escondida issued US$0.5 billion of new long-term debt to fund capital expenditure associated with key projects.

Funding sources

No new Group-level debt was issued in FY2018 and debt that matured during the year was not refinanced.

Our Group-level borrowing facilities are not subject to financial covenants. Certain specific financing facilities in relation to specific assets are the subject of financial covenants that vary from facility to facility, but this would be considered normal for such facilities. In addition to the Group’s uncommitted debt issuance programs, we hold the following committed standby facilities:

	Facility available 2018 US$M		Drawn 2018 US$M		Undrawn 2018 US$M		Facility available 2017 US$M		Drawn 2017 US$M		Undrawn 2017 US$M
Revolving credit facility (2)		6,000		–		6,000		6,000		–		6,000
Total financing facilities		6,000		–		6,000		6,000		–		6,000

⁽¹⁾  We use alternative performance measures to reflect the underlying performance of BHP. For the definition and method of calculation of alternative performance measures, refer to section 1.11.5. For the composition of net debt, refer to note 18 ‘Net debt’ in section 5.

⁽²⁾  BHP’s committed US$6.0 billion revolving credit facility operates as a back-stop to the Company’s uncommitted commercial paper program. The combined amount drawn under the facility or as commercial paper will not exceed US$6.0 billion. As at 30 June 2018, US$ nil commercial paper was drawn (FY2017: US$ nil), therefore US$6.0 billion of committed facility was available to use (FY2017: US$6.0 billion). The revolving credit facility expires on 7 May 2021. A commitment fee is payable on the undrawn balance and an interest rate comprising an interbank rate plus a margin applies to any drawn balance. The agreed margins are typical for a credit facility extended to a company with BHP’s credit rating.

For more information regarding the maturity profile of our debt obligations and details of our standby and support agreements, refer to note 20 ‘Financial risk management’ in section 5.

In BHP’s opinion, working capital is sufficient for BHP’s present requirements.

BHP’s credit ratings are currently A3/P-2 outlook positive (Moody’s – long-term/short-term) and A/A-1 outlook stable (Standard & Poor’s – long-term/short-term). A credit rating is not a recommendation to buy, sell or hold securities and may be subject to suspension, reduction or withdrawal at any time by an assigning rating agency. Any rating should be evaluated independently of any other information.

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The following table expands on the net debt, to provide more information on the cash and non-cash movements in FY2018.

Year ended 30 June	2018 US$M					2017 US$M
Net debt at the beginning of the financial year				(16,321	)				(26,102	)
Net operating cash flows		18,461					16,804
Net investing cash flows		(5,921	)				(4,161	)
Free cash flow				12,540					12,643
Carrying value of interest bearing liability repayments		3,573					5,385
Net settlements of interest bearing liabilities and debt related instruments		(3,878	)				(5,501	)
Dividends paid		(5,220	)				(2,921	)
Dividends paid to non-controlling interest		(1,582	)				(575	)
Other financing activities (1)		(211	)				(136	)
Other cash movements				(7,318	)				(3,748	)
Interest rate movements (2)		353					1,337
Foreign exchange impacts on debt (3)		(245	)				(149	)
Foreign exchange impacts on cash (3)		56					322
Finance lease obligation contracted during the period		–					(593	)
Others		1					(31	)
Non-cash movements				165					886
Net debt at the end of the financial year				(10,934	)				(16,321	)

⁽¹⁾ Other financing activities mainly comprises purchases of shares by Employee Share Option Plan trusts of US$171 million (FY2017: US$108 million).

⁽²⁾  Interest rate movements reflect the movement in the mark to market (fair value) adjustment of corporate bond floating interest rates.

⁽³⁾  Foreign exchange impacts reflect the revaluation of local currency debt and cash to US dollars the Group’s functional currency.

The Group hedges against the volatility in both exchange and interest rates on debt, with associated movements in derivatives reported in Other financial assets/liabilities as effective hedged derivatives (cross currency and interest rate swaps), in accordance with accounting standards. Refer to note 20 ‘Financial risk management’ in section 5.

Year ended 30 June 2017 compared with year ended 30 June 2016

Interest bearing liabilities, net debt and gearing

At the end of FY2017, Interest bearing liabilities were US$30.5 billion (2016: US$36.4 billion) and Cash and cash equivalents were US$14.2 billion (FY2016: US$10.3 billion). Included within Cash and cash equivalents were short-term deposits of US$13.3 billion compared with US$9.8 billion in FY2016. This resulted in net debt of US$16.3 billion, which represented a decrease of US$9.8 billion compared with the net debt position at 30 June 2016. Gearing, which is the ratio of net debt to net debt plus net assets, was 20.6 per cent at 30 June 2017, compared with 30.3 per cent at 30 June 2016.

110

During FY2017, the Group had a bias towards debt reduction. This included the decision not to refinance US$3.3 billion of Group-level debt (which matured in FY2017) and the execution of a US$2.5 billion bond repurchase program. On 23 March 2017, BHP concluded this bond repurchase program, which was funded by BHP’s strong cash position and targeted short dated US dollar bonds maturing before FY2023. The early repayment of the bonds has extended BHP’s average debt maturity profile and enhanced BHP’s capital structure.

The following bonds were repurchased:

• US$500 million senior notes due 2018;

• US$980 million senior notes due 2019;

• US$720 million senior notes due 2021;

• US$140 million senior notes due 2022.

The decision not to refinance maturing Group debt and the bond repurchase program contributed to a US$5.9 billion overall decrease in interest bearing liabilities in FY2017.

At the subsidiary level, Escondida issued US$1.5 billion of new long-term debt to refinance US$0.8 billion of short-term debt, US$0.4 billion of long-term debt due for refinancing and to fund capital expenditure associated with key projects.

Funding sources

No new Group-level debt was issued in FY2017, and debt that matured during the year was not refinanced.

None of our Group-level borrowing facilities is subject to financial covenants. Certain specific financing facilities in relation to specific assets are the subject of financial covenants that vary from facility to facility, but which would be considered normal for such facilities.

1.11.4     Alternative performance measures

We use various alternative performance measures to reflect our underlying performance. Our two primary measures of performance are Underlying attributable profit and Underlying EBITDA. These measures, and other alternative performance measures, are reconciled below and defined in section 1.11.5.

We believe these alternative performance measures provide useful information, but should not be considered as an indication of, or as a substitute for, Attributable profit/(loss) and other statutory measures as an indicator of actual operating performance or as an alternative to cash flow as a measure of liquidity.

We consider Underlying attributable profit to be a key measure that provides insight on the amount of profit available for distribution to shareholders, which aligns to our purpose as outlined in Our Charter. Underlying attributable profit is also the key performance indicator against which short-term incentive outcomes for our senior executives are measured and, in our view, is a relevant measure to assess the financial performance of the Group for this purpose.

Underlying EBITDA is the key alternative performance measure that management uses internally to assess the performance of the Group’s segments and make decisions on the allocation of resources. In the Group’s view this is more relevant to capital intensive industries with long-life assets.

Underlying EBITDA and Underlying EBIT are included in the FY2018 Consolidated Financial Statements, as required by IFRS 8 ‘Operating Segments’.

111

Reconciling alternative performance measures

The following tables provide reconciliations between the alternative performance measure and the respective IFRS measure. Section 1.11.5 outlines the definition and calculation methodology of our alternative performance measures.

Year ended 30 June 2018 US$M	Petroleum			Copper			Iron Ore			Coal			Group and unallocated items/ eliminations (3)			BHP Group
Continuing operations
Revenue		5,408			13,287			14,810			8,889			1,244					43,638
Revenue – Group production (1)		5,396			11,860			14,756			8,887			1,225			42,124
Revenue – Third party products (1)		12			1,427			54			2			19			1,514
Other income		52			10			139			41			5					247
Depreciation and amortisation expense		(1,719	)		(1,920	)		(1,721	)		(686	)		(242	)				(6,288	)
Net impairments		(76	)		(213	)		(14	)		(29	)		(1	)				(333	)
Third party commodity purchases		(11	)		(1,367	)		(53	)		(3	)		(18	)				(1,452	)
All other operating expenses		(2,104	)		(5,875	)		(5,996	)		(4,722	)		(1,266	)				(19,963	)
Non-exceptional items		(2,104	)		(5,875	)		(5,966	)		(4,722	)		(1,239	)		(19,906	)
Exceptional items attributable to BHP shareholders		–			–			(30	)		–			(27	)		(57	)
Expenses excluding net finance costs		(3,910	)		(9,375	)		(7,784	)		(5,440	)		(1,527	)				(28,036	)
Profit/(loss) from equity accounted investments, related impairments and expenses		(4	)		467			(509	)		192			1					147
Non-exceptional items		(4	)		467			–			192			1			656
Exceptional items attributable to BHP shareholders		–			–			(509	)		–			–			(509	)
Subtotal		1,546			4,389			6,656			3,682			(277	)				15,996
Net finance costs																			(1,245	)
Non-exceptional items																	(1,161	)
Exceptional items attributable to BHP shareholders																	(84	)
Profit before taxation																			14,751
Total taxation expense																			(7,007	)
Non-exceptional items																	(4,687	)
Exceptional items attributable to BHP shareholders																	(2,320	)
Profit after taxation from Continuing operations																			7,744

112

Year ended 30 June 2018 US$M	Petroleum		Copper		Iron Ore		Coal			Group and unallocated items/ eliminations (3)			BHP Group
Discontinued operations
Loss after taxation from Discontinued operations															(2,921	)
Profit after taxation from Continuing and Discontinued operations															4,823
Attributable to non-controlling interests														1,118
Attributable to BHP shareholders														3,705
Reconciliation to Underlying attributable profit, Underlying EBITDA and Underlying EBIT
Exceptional items Continuing operations		–		–		539		–			27			2,404	2,970
Exceptional items Discontinued operations															2,258
Subtotal: Exceptional items attributable to BHP shareholders															5,228
Profit after taxation attributable to non-controlling interests															(1,118	)
Underlying attributable profit (2)															8,933
Profit after taxation attributable to non-controlling interests															1,118
Loss after taxation from Discontinued operations															2,921
Exceptional items Discontinued operations															(2,258	)
Taxation expense from non-exceptional items															4,687
Net finance costs from non-exceptional items															1,161
Underlying EBIT															16,562
Depreciation, amortisation and impairments excluding exceptional items		1,795		2,133		1,735		715			243				6,621
Underlying EBITDA (2)		3,341		6,522		8,930		4,397			(7	)			23,183
Underlying EBITDA – Group production (1)		3,340		6,462		8,929		4,398			(8	)		23,121
Underlying EBITDA – Third party products (1)		1		60		1		(1	)		1			62

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Year ended 30 June 2018 US$M	Petroleum			Copper			Iron Ore			Coal			Group and unallocated items/ eliminations (3)	BHP Group
Basic and Underlying basic earnings per share
Underlying attributable profit (US$M) (2)															8,933
Weighted basic average number of shares (Million)															5,323
Underlying basic earnings per ordinary share (US cents)															167.8
Adjusted for: Exceptional items attributable to BHP shareholders per share															(98.2	)
Basic earnings per ordinary share (US cents)															69.6
Segment contribution to Underlying EBITDA
Segment contribution to the Group’s Underlying EBITDA (4)		14	%		28	%		39	%		19	%			100	%
Margin calculation
Underlying EBITDA margin – Group production		62	%		54	%		61	%		49	%			55	%
Underlying EBITDA margin – Third party products		8	%		4	%		2	%		–				4	%

Year ended 30 June 2018	Profit before taxation US$M		Income tax (expense)/ benefit US$M			%
Adjusted effective tax rate reconciliation
Statutory effective tax rate		14,751		(7,007	)		47.5
Adjusted for:
Exchange rate movements		–		(152	)
Exceptional items		650		2,320
Adjusted effective tax rate		15,401		(4,839	)		31.4

Year ended 30 June 2017 US$M	Petroleum		Copper		Iron Ore		Coal		Group and unallocated items/ elimination (3)		BHP Group
Continuing operations
Revenue		4,722		8,335		14,624		7,578		876			36,135
Revenue – Group production (1)		4,713		7,232		14,543		7,578		869		34,935
Revenue – Third party products (1)		9		1,103		81		–		7		1,200

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Year ended 30 June 2017 US$M	Petroleum			Copper			Iron Ore			Coal			Group and unallocated items/ elimination (3)			BHP Group
Other income		191			62			172			192			45					662
Non-exceptional items		191			62			172			23			45			493
Exceptional items attributable to BHP shareholders		–			–			–			169			–			169
Depreciation and amortisation expense		(1,648	)		(1,737	)		(1,828	)		(719	)		(252	)				(6,184	)
Non-exceptional items		(1,648	)		(1,525	)		(1,828	)		(719	)		(252	)		(5,972	)
Exceptional items attributable to non-controlling interests		–			(90	)		–			–			–			(90	)
Exceptional items attributable to BHP shareholders		–			(122	)		–			–			–			(122	)
Net impairments		(102	)		(14	)		(52	)		(20	)		(5	)				(193	)
Non-exceptional items		(102	)		(14	)		(52	)		(15	)		(5	)		(188	)
Exceptional items attributable to BHP shareholders		–			–			–			(5	)		–			(5	)
Third party commodity purchases		(6	)		(1,080	)		(58	)		–			(7	)				(1,151	)
All other operating expenses		(1,787	)		(4,401	)		(5,692	)		(3,969	)		(1,138	)				(16,987	)
Non-exceptional items		(1,787	)		(4,067	)		(5,661	)		(3,969	)		(1,087	)		(16,571	)
Exceptional items attributable to non-controlling interests		–			(142	)		–			–			–			(142	)
Exceptional items attributable to BHP shareholders		–			(192	)		(31	)		–			(51	)		(274	)
Expenses excluding net finance costs		(3,543	)		(7,232	)		(7,630	)		(4,708	)		(1,402	)				(24,515	)
Profit/(loss) from equity accounted investments, related impairments and expenses		(3	)		295			(172	)		152			–					272
Non-exceptional items		(3	)		295			–			152			–			444
Exceptional items attributable to BHP shareholders		–			–			(172	)		–			–			(172	)
Subtotal		1,367			1,460			6,994			3,214			(481	)				12,554
Net finance costs																			(1,417	)
Non-exceptional items																	(1,290	)
Exceptional items attributable to BHP shareholders																	(127	)
Profit before taxation																			11,137
Total taxation expense																			(4,443	)
Non-exceptional items																	(4,200	)
Exceptional items attributable to non-controlling interests																	68
Exceptional items attributable to BHP shareholders																	(311	)

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Year ended 30 June 2017 US$M	Petroleum		Copper		Iron Ore		Coal			Group and unallocated items/ elimination (3)		BHP Group
Profit after taxation from Continuing operations														6,694
Discontinued operations
Loss after taxation from Discontinued operations														(472	)
Profit after taxation from Continuing and Discontinued operations														6,222
Attributable to non-controlling interests													332
Attributable to BHP shareholders													5,890
Reconciliation to Underlying attributable profit, Underlying EBITDA and Underlying EBIT
Exceptional items Continuing operations		–		546		203		(164	)		51		370	1,006
Exceptional items attributable to non-controlling interests														(232	)
Tax effect of exceptional items attributable to non-controlling interests														68
Subtotal: Exceptional items attributable to BHP shareholders														842
Profit after taxation attributable to non-controlling interests														(332	)
Underlying attributable profit (2)														6,732
Profit after taxation attributable to non-controlling interests														332
Loss after taxation from Discontinued operations														472
Exceptional items attributable to non-controlling interests														232
Tax effect of exceptional items attributable to non-controlling interests														(68	)
Taxation expense from non-exceptional items														4,200
Net finance costs from non-exceptional items														1,290
Underlying EBIT														13,190
Depreciation, amortisation and impairments excluding exceptional items		1,750		1,539		1,880		734			257			6,160

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Year ended 30 June 2017 US$M	Petroleum			Copper			Iron Ore			Coal			Group and unallocated items/ elimination (3)			BHP Group
Underlying EBITDA (2)		3,117			3,545			9,077			3,784			(173	)			19,350
Underlying EBITDA – Group production (1)		3,114			3,522			9,054			3,784			(173	)		19,301
Underlying EBITDA – Third party products (1)		3			23			23			–			–			49
Basic and Underlying basic earnings per share
Underlying attributable profit (US$M) (2)																		6,732
Weighted basic average number of shares (Million)																		5,323
Underlying basic earnings per ordinary share (US cents)																		126.5
Adjusted for: Exceptional items attributable to BHP shareholders per share																		(15.8	)
Basic earnings per ordinary share (US cents)																		110.7
Segment contribution to Underlying EBITDA
Segment contribution to the Group’s Underlying EBITDA (4)		16	%		18	%		47	%		19	%						100	%
Margin calculation
Underlying EBITDA margin – Group production		66	%		49	%		62	%		50	%						55	%
Underlying EBITDA margin – Third party products		33	%		2	%		28	%		–							4	%

Year ended 30 June 2017	Profit before taxation US$M		Income tax (expense)/ benefit US$M			%
Adjusted effective tax rate reconciliation
Statutory effective tax rate		11,137		(4,443	)		39.9
Adjusted for:
Exchange rate movements		–		88
Exceptional items		763		243
Adjusted effective tax rate		11,900		(4,112	)		34.6

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Year ended 30 June 2016 US$M	Petroleum			Copper			Iron Ore			Coal			Group and unallocated items/ elimination (3)			BHP Group
Continuing operations
Revenue		4,549			8,249			10,538			4,518			713					28,567
Revenue – Group production (1)		4,452			7,411			10,454			4,512			701			27,530
Revenue – Third party products (1)		97			838			84			6			12			1,037
Other income		435			87			256			48			(394	)				432
Depreciation and amortisation expense		(1,696	)		(1,560	)		(1,817	)		(890	)		(247	)				(6,210	)
Net impairments		(24	)		(17	)		(42	)		(94	)		(9	)				(186	)
Third party commodity purchases		(92	)		(792	)		(92	)		(6	)		(12	)				(994	)
All other operating expenses		(1,847	)		(5,080	)		(5,247	)		(3,916	)		(611	)				(16,701	)
Non-exceptional items		(1,847	)		(5,080	)		(5,239	)		(3,916	)		(479	)		(16,561	)
Exceptional items attributable to BHP shareholders		–			–			(8	)		–			(132	)		(140	)
Expenses excluding net finance costs		(3,659	)		(7,449	)		(7,198	)		(4,906	)		(879	)				(24,091	)
Profit/(loss) from equity accounted investments, related impairments and expenses		(7	)		155			(2,244	)		(9	)		1					(2,104	)
Non-exceptional items		(7	)		155			136			(9	)		1			276
Exceptional items attributable to BHP shareholders		–			–			(2,380	)		–			–			(2,380	)
Subtotal		1,318			1,042			1,352			(349	)		(559	)				2,804
Net finance costs																			(1,013	)
Profit before taxation																			1,791
Total taxation expense																			(2,103	)
Non-exceptional items																	(1,856	)
Exceptional items attributable to BHP shareholders																	(247	)
Loss after taxation from Continued operations																			(312	)
Discontinued operations
Loss after taxation from Discontinued operations																			(5,895	)
Loss after taxation from Continuing and Discontinued operations																			(6,207	)
Attributable to non-controlling interests																	178
Attributable to BHP shareholders																	(6,385	)

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Year ended 30 June 2016 US$M	Petroleum		Copper		Iron Ore			Coal		Group and unallocated items/ elimination (3)			BHP Group
Reconciliation to Underlying attributable profit, Underlying EBITDA and Underlying EBIT
Exceptional items Continuing operations		–		–		2,388			–		132			247	2,767
Exceptional items Discontinued operations															4,884
Exceptional items Discontinued operations attributable to non-controlling interests															(51	)
Subtotal: Exceptional items attributable to BHP shareholders															7,600
Profit after taxation attributable to non-controlling interests															(178	)
Underlying attributable profit (2)															1,215
Profit after taxation attributable to non-controlling interests															178
Loss after taxation from Discontinued operations															5,895
Exceptional items Discontinued operations															(4,884	)
Exceptional items Discontinued operations attributable to non-controlling interests															51
Taxation expense from non-exceptional items															1,856
Net finance costs from non-exceptional items															1,013
Underlying EBIT															5,324
Add: Depreciation, amortisation and impairments excluding exceptional items		1,720		1,577		1,859			984		256				6,396
Underlying EBITDA (2)		3,038		2,619		5,599			635		(171	)			11,720
Underlying EBITDA – Group production (1)		3,033		2,573		5,607			635		(171	)		11,677
Underlying EBITDA – Third party products (1)		5		46		(8	)		–		–			43

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Year ended 30 June 2016 US$M	Petroleum			Copper			Iron Ore			Coal			Group and unallocated items/ elimination (3)	BHP Group
Basic and Underlying basic earnings per share
Underlying attributable profit (US$M) (2)															1,215
Weighted basic average number of shares (Million)															5,322
Underlying basic earnings per ordinary share (US cents)															22.8
Adjusted for: Exceptional items attributable to BHP shareholders per share															(142.8	)
Basic earnings/(loss) per ordinary share (US cents)															(120.0	)
Segment contribution to Underlying EBITDA
Segment contribution to the Group’s Underlying EBITDA (4)		26	%		22	%		47	%		5	%			100	%
Margin calculation
Underlying EBITDA margin – Group production		68	%		35	%		54	%		14	%			42	%
Underlying EBITDA margin – Third party products		5	%		5	%		(10	)%		–				4	%

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Year ended 30 June 2016	Profit before taxation US$M		Income tax (expense)/ benefit US$M			%
Adjusted effective tax rate reconciliation
Statutory effective tax rate		1,791		(2,103	)		–
Adjusted for:
Exchange rate movements		–		125
Exceptional items		2,520		247
Adjusted effective tax rate		4,311		(1,731	)		40.2

⁽¹⁾ We differentiate sales of our production from sales of third party products to better measure the operational profitability of our operations as a percentage of revenue. These tables show the breakdown between our production and third party products, which is necessary for the calculation of the Underlying EBITDA margin and margin on third party products.

We engage in third party trading for the following reasons:

• Production variability and occasional shortfalls from our assets means that we sometimes source third party materials to ensure a steady supply of product to our customers.

• To optimise our supply chain outcomes, we may buy physical product from third parties.

• To support the development of liquid markets, we will sometimes source third party physical product and manage risk through both the physical and financial markets.

⁽²⁾ We exclude exceptional items from Underlying attributable profit and Underlying EBITDA in order to enhance the comparability of such measures from period-to-period and provide our investors with further clarity in order to assess the underlying performance of our operations. Management monitors exceptional items separately. Additional information can be found in note 2 ‘Exceptional items’, note 3 ‘Significant events – Samarco dam failure’ and note 26 ‘Discontinued operations’ in section 5.

⁽³⁾ Group and unallocated items includes functions and other unallocated operations, including Potash and Nickel West and consolidation adjustments. Revenue not attributable to reportable segments comprises the sale of freight and fuel to third parties. Exploration and technology activities are recognised within relevant segments.

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⁽⁴⁾ Percentage contribution to Group Underlying EBITDA, excluding Group and unallocated items.

Year ended 30 June 2018 US$M	Revenue			Other income and expenses excluding net finance costs			Exceptional items		Depreciation, amortisation and impairments excluding exceptional items		Underlying EBITDA
Potash		–			(139	)		–		4		(135	)
Nickel West		1,300			(1,085	)		–		76		291
Corporate and eliminations		(56	)		(297	)		27		163		(163	)
Total		1,244			(1,521	)		27		243		(7	)
Year ended 30 June 2017 US$M	Revenue			Other income and expenses excluding net finance costs			Exceptional items		Depreciation, amortisation and impairments excluding exceptional items		Underlying EBITDA
Potash		–			(118	)		–		10		(108	)
Nickel West		952			(995	)		–		87		44
Corporate and eliminations		(76	)		(244	)		51		160		(109	)
Total		876			(1,357	)		51		257		(173	)
Year ended 30 June 2016 US$M	Revenue			Other income and expenses excluding net finance costs			Exceptional items		Depreciation, amortisation and impairments excluding exceptional items		Underlying EBITDA
Potash		–			(155	)		–		6		(149	)
Nickel West		819			(1,009	)		–		76		(114	)
Corporate and eliminations		(106	)		(108	)		132		174		92
Total		713			(1,272	)		132		256		(171	)

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Net operating assets

The following table reconciles Net operating assets for the Group to Net assets on the Consolidated Balance Sheet:

Year ended 30 June	2018 US$M			2017 US$M
Net operating assets
Petroleum		8,052			9,011
Copper		23,679			24,100
Iron Ore		18,320			19,175
Coal		9,853			10,136
Group and unallocated items (1)		2,789			2,446
Total		62,693			64,868
Reconciled to Net assets
Onshore US (2)		–			14,170
Cash and cash equivalents		15,871			14,153
Trade and other receivables (3)		36			665
Other financial assets (4)		974			980
Current tax assets		106			195
Deferred tax assets		4,041			5,788
Assets held for sale (2)		11,939			–
Trade and other payables (5)		(363	)		(390	)
Interest bearing liabilities		(26,805	)		(30,474	)
Other financial liabilities (6)		(1,218	)		(1,345	)
Current tax payable		(1,773	)		(2,119	)
Non-current tax payable		(137	)		–
Deferred tax liabilities		(3,472	)		(3,765	)
Liabilities held for sale (2)		(1,222	)		–
Net assets		60,670			62,726

⁽¹⁾ Group and unallocated items includes functions and other unallocated operations including Potash and Nickel West and consolidation adjustments.

⁽²⁾ Represents Onshore US assets and liabilities treated as held for sale.

⁽³⁾ Represents loans to associates of US$13 million (FY2017: US$644 million) and accrued interest receivable of US$23 million (FY2017: US$21 million) included within other receivables.

⁽⁴⁾ Represents cross currency and interest rate swaps, forward exchange contracts of US$140 million (FY2017: US$ nil) and available for sale shares and other investments (refer to note 20 ‘Financial risk management’ in section 5) included in other financial assets.

⁽⁵⁾ Represents accrued interest payable included within other payables.

⁽⁶⁾  Represents cross currency and interest rate swaps (refer to note 20 ‘Financial risk management’ in section 5) included in other financial liabilities.

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Free cash flow

The following table reconciles Free cash flow to Net increase/(decrease) in cash and cash equivalents:

Year ended 30 June	2018 US$M			2017 US$M			2016 US$M
Net operating cash flows		18,461			16,804			10,625
Net investing cash flows		(5,921	)		(4,161	)		(7,245	)
Free cash flow		12,540			12,643			3,380
Net financing cash flows		(10,891	)		(9,133	)		284
Net increase in cash and cash equivalents		1,649			3,510			3,664
Net increase in cash and cash equivalents from Continuing operations		1,650			3,047			4,138
Net (decrease)/increase in cash and cash equivalents from Discontinued operations		(1	)		463			(474	)

1.11.5     Definition and calculation of alternative performance measures

Our primary alternative performance measures are defined and calculated as follows:

Alternative performance measure	Method of calculation
Underlying attributable profit	Profit/(loss) after taxation attributable to BHP shareholders excluding any exceptional items attributable to BHP shareholders as described in note 2 ‘Exceptional items’ in section 5.
Underlying EBITDA	Earnings before net finance costs, depreciation, amortisation and impairments, taxation expense, Discontinued operations and exceptional items. Underlying EBITDA includes BHP’s share of profit/(loss) from investments accounted for using the equity method, including net finance costs, depreciation, amortisation and impairments and taxation (expense)/benefit.
Underlying EBIT	Underlying EBITDA, including depreciation, amortisation and impairments.

Further alternative performance measures are defined and calculated as follows:

Adjusted effective tax rate	Total taxation (expense)/benefit, excluding exceptional items and exchange rate movements included in taxation (expense)/benefit divided by profit/(loss) before taxation and exceptional items. Management believes this measure provides useful information regarding the tax impacts from underlying operations.
Exceptional items attributable to BHP shareholders per share	Exceptional items attributable to BHP shareholders divided by the weighted basic average number of shares.
Free cash flow (1)	Net operating cash flows less Net investing cash flows.
Gearing ratio (1)	Ratio of Net debt to Net debt plus Net assets.
Margin on third party products	Underlying EBITDA from third party products divided by third party product revenue.

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Net debt (1)	Interest bearing liabilities less Cash and cash equivalents for the total operations within the Group at the reporting date.
Net operating assets	Operating assets net of operating liabilities, including the carrying value of equity accounted investments and predominantly excludes cash balances, loans to associates, interest bearing liabilities and deferred tax balances. The carrying value of investments accounted for using the equity accounted method represents the balance of the Group’s investment in equity accounted investments, with no adjustment for any cash balances, interest bearing liabilities and deferred tax balances of the equity accounted investment. Management believes this measure provides useful information by isolating the net operating assets of the business from the financing and tax balances which, in combination with our other measures, provides a meaningful indicator of underlying performance.
Segment contribution to the Group’s Underlying EBITDA	Segment Underlying EBITDA divided by the Group’s Underlying EBITDA excluding Group and unallocated items.
Underlying basic earnings per share	Underlying attributable profit divided by the weighted average number of basic shares.
Underlying EBITDA margin	Underlying EBITDA, excluding third party product Underlying EBITDA, divided by revenue excluding third party product revenue.

⁽¹⁾ Calculation is performed with reference to IFRS measures.

1.11.6     Definition and calculation of principal factors

The method of calculation of the principal factors that affect Revenue, Profit from operations and Underlying EBITDA is as follows:

Principal factor	Method of calculation
Change in sales prices	Change in average realised price for each operation from the corresponding period to the current period, multiplied by current period volumes.
Price-linked costs	Change in price-linked costs for each operation from the corresponding period to the current period, multiplied by current period volumes.
Productivity volumes	Change in volumes for each operation not included in the Growth category from the corresponding period to the current period, multiplied by the prior year Underlying EBITDA margin.
Growth volumes	Volume – Growth comprises Underlying EBITDA for operations that are new or acquired in the current period minus Underlying EBITDA for operations that are new or acquired in the corresponding period, change in volumes for operations identified as a Growth project from the corresponding period to the current period multiplied by the prior year Underlying EBITDA margin, and change in volume for our petroleum assets from the corresponding period to the current period multiplied by the prior year Underlying EBITDA margin.

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Principal factor	Method of calculation
Controllable cash costs	Operating cash costs and exploration and business development costs. Management believes this measure provides useful information regarding the Group’s financial performance because it considers these expenses to be the principal operating and overhead expenses that are most directly under the Group’s control.
Operating cash costs	Change in total costs, other than price-linked costs, exchange rates, inflation on costs, fuel and energy costs, non-cash costs and one-off items as defined below for each operation from the corresponding period to the current period.
Exploration and business development	Exploration and business development expense in the current period minus exploration and business development expense in the corresponding period.
Exchange rates	Change in exchange rate multiplied by current period local currency revenue and expenses. The majority of the Group’s selling prices are denominated in US dollars and so there is little impact of exchange rate changes on Revenue.
Inflation on costs	Change in inflation rate applied to expenses, other than depreciation and amortisation, price-linked costs, exploration and business development expenses, expenses in ceased and sold operations and expenses in new and acquired operations.
Fuel and energy	Fuel and energy expense in the current period minus fuel and energy expense in the corresponding period.
Non-cash	Includes non-cash items mainly depletion of stripping capitalised.
One-off items	Change in costs exceeding a pre-determined threshold associated with an unexpected event that had not occurred in the last two years and is not reasonably likely to occur within the next two years.
Asset sales	Profit/(loss) on the sale of assets or operations in the current period minus profit/(loss) on sale in the corresponding period.
Ceased and sold operations	Underlying EBITDA for operations that ceased or were sold in the current period minus Underlying EBITDA for operations that ceased or were sold in the corresponding period.
Share of operating profit from equity accounted investments	Share of operating profit from equity accounted investments for the period minus share of operating profit from equity accounted investments in the corresponding period.
Other	Variances not explained by the above factors.

1.12    Performance by commodity

Management believes the following financial information presented by commodity provides a meaningful indication of the underlying performance of the assets, including equity accounted investments, of each reportable segment. Information relating to assets that are accounted for as equity accounted investments are shown to reflect BHP’s share, unless otherwise noted, to provide insight into the drivers of these assets.

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For the purposes of this financial information, segments are reported on a statutory basis in accordance with IFRS 8 ‘Operating Segments’. The tables for each commodity include an ‘adjustment for equity accounted investments’ to reconcile the equity accounted results to the statutory segment results.

For a reconciliation of alternative performance measures to their respective IFRS measure and an explanation as to the use of Underlying EBITDA and Underlying EBIT in assessing our performance, refer to section 1.11.4. For the definition and method of calculation of alternative performance measures, refer to section 1.11.5. For more information as to the statutory determination of our reportable segments, refer to note 1 ‘Segment reporting’ in section 5.

Unit costs is one of the financial measures used to monitor the performance of our individual assets and is included in the analysis of each reportable segment.

1.12.1    Petroleum

Detailed below is financial information for our Petroleum assets excluding Onshore US for FY2018 and FY2017 and an analysis of Petroleum’s financial performance for FY2018 compared with FY2017.

Year ended 30 June 2018 US$M	Revenue  (1)			Underlying EBITDA			D&A			Underlying EBIT			Net operating assets (8)			Capital expenditure		Exploration gross  (2)		Exploration to profit (3)
Australia Production Unit (4)		568			422			247			175			740			–
Bass Strait		1,285			948			494			454			2,504			29
North West Shelf		1,400			1,058			230			828			1,574			167
Atlantis		833			666			332			334			1,307			159
Shenzi		576			470			193			277			743			32
Mad Dog		229			160			50			110			947			189
Trinidad/Tobago		161			(53	)		38			(91	)		256			16
Algeria		234			186			28			158			37			6
Exploration		–			(516	)		127			(643	)		953			–
Other (5)		126			54			59			(5	)		(142	)		58
Total Petroleum from Group production		5,412			3,395			1,798			1,597			8,919			656		709		592
Closed mines (6)		–			(52	)		–			(52	)		(867	)		–		–		–
Third party products		12			1			–			1			–			–
Total Petroleum		5,424			3,344			1,798			1,546			8,052			656		709		592
Adjustment for equity accounted investments (7)		(16	)		(3	)		(3	)		–			–			–		–		–
Total Petroleum statutory result		5,408			3,341			1,795			1,546			8,052			656		709		592

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Year ended 30 June 2017 US$M	Revenue (1)			Underlying EBITDA			D&A			Underlying EBIT			Net operating assets (8)			Capital expenditure		Exploration gross (2)		Exploration to profit (3)
Australia Production Unit (4)		601			451			275			176			924			15
Bass Strait		1,096			824			261			563			2,981			154
North West Shelf		1,190			1,013			199			814			1,630			209
Atlantis		677			551			471			80			1,486			174
Shenzi		509			402			204			198			956			37
Mad Dog		202			155			57			98			722			113
Trinidad/Tobago		110			26			33			(7	)		422			81
Algeria		212			167			34			133			22			13
Exploration		–			(471	)		157			(628	)		892			–
Other (5)		133			15			62			(47	)		(181	)		121
Total Petroleum from Group production		4,730			3,133			1,753			1,380			9,854			917		803		573
Closed mines (6)		–			(16	)		–			(16	)		(843	)		–		–		–
Third party products		9			3			–			3			–			–
Total Petroleum		4,739			3,120			1,753			1,367			9,011			917		803		573
Adjustment for equity accounted investments (7)		(17	)		(3	)		(3	)		–			–			–		–		–
Total Petroleum statutory result		4,722			3,117			1,750			1,367			9,011			917		803		573

⁽¹⁾ Total Petroleum statutory result revenue includes: crude oil US$2,933 million (FY2017: US$2,528 million), natural gas US$1,124 million (FY2017: US$1,029 million), LNG US$920 million (FY2017: US$858 million), NGL US$294 million (FY2017: US$265 million) and other which includes third party products US$137 million (FY2017: US$42 million).

⁽²⁾ Includes US$193 million of capitalised exploration (FY2017: US$332 million).

⁽³⁾ Includes US$76 million of exploration expenditure previously capitalised, written off as impaired (included in depreciation and amortisation) (FY2017: US$102 million).

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

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

⁽⁶⁾ Comprises closed mining and smelting operations in Canada and the United States. Petroleum manages the closed mines due to their geographic location.

⁽⁷⁾ Total Petroleum statutory result Revenue excludes US$16 million (FY2017: US$17 million) revenue related to the Caesar oil pipeline and the Cleopatra gas pipeline. Total Petroleum statutory result Underlying EBITDA includes US$3 million (FY2017: US$3 million) D&A related to the Caesar oil pipeline and the Cleopatra gas pipeline.

⁽⁸⁾ Refer to section 1.11.4 for a reconciliation of Net operating assets to Net assets and section 1.11.5 for the definition and method of calculation of Net operating assets.

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Key drivers of conventional petroleum’s financial results

Price overview

Overall, oil and gas prices have performed favourably in FY2018. Petroleum commodities were supported by OPEC-led output cuts for crude oil and stronger demand. Asian liquefied natural gas (LNG) also saw stronger demand.

Trends in each of the major markets are outlined below.

Crude oil

Our average realised sales price for crude oil was US$60.57 per barrel (FY2017: US$47.48 per barrel). Crude oil prices trended higher during FY2018. High compliance to agreed production cuts by OPEC members and non-OPEC participants (the ‘Vienna Group’) and strong demand growth both contributed to a substantial reduction in the inventory overhang. The tighter market and rising geopolitical tensions out-weighed rising US production to push prices to multi-year highs. A roughly balanced market is expected in CY2018. The long-term outlook remains positive, underpinned by rising demand from the developing world and natural field decline on the supply side.

Liquefied natural gas

Our average realised sales price for LNG was US$8.07 per Mscf (FY2017: US$6.84 per Mscf). Overall, the Japan-Korea Marker (JKM) price for LNG was higher on average compared to the previous financial year. Prices hit a three-year high in January on firm winter demand from end users in North Asia, particularly China where imports surged +47 per cent year-on-year. On the supply side, slippage in the start date of new projects along with unplanned outages also contributed to the tighter market throughout the north Asian winter. We forecast a relatively tight market heading into winter; however, a further lift in new supply is likely to weigh on the market in CY2019. Longer term, the outlook for LNG remains positive, underpinned by rising energy demand from emerging economies and the need for low-emission and flexible fuels to supplement intermittent renewables. Depleting indigenous gas supplies will also increase the dependence of some major consumers on the export market.

Production

Total conventional petroleum production for FY2018 decreased by six per cent to 120 MMboe as a result of Hurricane Harvey and Hurricane Nate in the Gulf of Mexico, along with natural field decline across the portfolio.

For more information on individual asset production in FY2018, FY2017 and FY2016, refer to section 6.2.

Financial results

Overall, conventional petroleum revenue for FY2018 increased by US$686 million to US$5.4 billion. Gulf of Mexico, which includes Atlantis, Shenzi and Mad Dog, increased by US$250 million to US$1.6 billion. In Australia, Bass Strait and North West Shelf collectively increased by US$399 million to US$2.7 billion and the Australian Production Unit, which includes Macedon, Pyrenees and Minerva, decreased by US$33 million to US$568 million.

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Underlying EBITDA for Petroleum increased by US$224 million to US$3.3 billion. Price impacts, net of price-linked costs, increased Underlying EBITDA by US$975 million. During the period, Underlying EBITDA decreased by US$256 million due to the impact of Hurricane Harvey and Hurricane Nate on US assets and natural field decline. Controllable cash costs increased by US$64 million reflecting higher exploration expenses, due to expensing the Scimitar well (including sidetrack) and increased planning activities in Mexico, partially offset by the impact of wells expensed in the prior year, coupled with US$100 million unfavourable fixed cost dilution from declining volumes. Profit on sale of assets decreased by US$142 million reflecting the sale of 50 per cent of BHP’s interest in the undeveloped Scarborough area gas fields in FY2017. Revaluation of embedded derivatives at Trinidad also negatively impacted Underlying EBITDA by US$117 million.

Conventional petroleum unit costs increased by 16 per cent to US$10.06 per barrel of oil equivalent due to the impact of lower volumes. The calculation of conventional petroleum unit costs is set out in the table below.

Conventional petroleum unit costs (1) US$M	FY2018		FY2017
Revenue		5,408		4,722
Underlying EBITDA		3,393		3,133
Gross costs		2,015		1,589
Less: exploration expense (2)		516		471
Less: freight		152		140
Less: development and evaluation		34		22
Less: other (3)		106		(151	)
Net costs		1,207		1,107
Production (MMboe, equity share)		120		128
Cost per Boe (US$) (4)(5)		10.06		8.65

⁽¹⁾ Conventional petroleum assets exclude divisional activities reported in Other and closed mining and smelting operations in Canada and the United States.

⁽²⁾ Exploration expense represents conventional petroleum’s share of total exploration expense.

⁽³⁾ Other includes non-cash profit on sales of assets, inventory movements, foreign exchange and the impact from the revaluation of embedded derivatives in the Trinidad and Tobago gas contract.

⁽⁴⁾ FY2017 restated to exclude development and evaluation as these costs do not represent our cost performance in relation to current production.

⁽⁵⁾ FY2018 based on an exchange rate of AUD/USD 0.78.

Delivery commitments

We have delivery commitments of natural gas and LNG in conventional petroleum of approximately 1,873 billion cubic feet through FY2031 (56 per cent Australia and Asia, 44 per cent Trinidad). We have crude and condensate delivery commitments of around 10.5 million barrels through FY2019 (48 per cent United States, 38 per cent Australia and Asia and 14 per cent others) and LPG commitments of 271,974 metric tonnes through FY2019. We have sufficient proved reserves and production capacity to fulfil these delivery commitments.

We have obligations for contracted capacity on transportation pipelines and gathering systems, on which we are the shipper. In FY2019, volume commitments to gather and transport are 15 million barrels of oil and 24 million cubic feet of gas. The agreements with the gas gatherers and transporters have annual escalation clauses.

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Other information

Drilling

The number of wells in the process of drilling and/or completion as of 30 June 2018 was as follows:

	Exploratory wells				Development wells				Total
	Gross		Net (1)		Gross		Net (1)		Gross		Net (1)
Australia		–		–		8		1		8		1
United States (2)		1		1		74		44		75		45
Other		1		1		–		–		1		1
Total		2		2		82		45		84		47

⁽¹⁾ Represents our share of the gross well count.

⁽²⁾ Incudes 74 (net: 44) development wells attributable to Discontinued operations of Onshore US.

Conventional petroleum

BHP’s net share of capital development expenditure in FY2018, which is presented on a cash basis within this section, was US$656 million (FY2017: US$917 million). While the majority of the expenditure in FY2018 was incurred by operating partners at our Australian and Gulf of Mexico non-operated assets, we also incurred capital expenditure at our operated Australian, Gulf of Mexico, Algeria and Trinidad and Tobago assets.

Australia

BHP’s net share of capital development expenditure in FY2018, which is presented on a cash basis within this section, was US$196 million. The expenditure was primarily related to:

• North West Shelf: GWF-2 subsea tie back well development, Karratha Gas Plant refurbishment projects and external corrosion compliance.

• Bass Strait: Snapper A21a offshore wellwork and MLB450 pipeline installation along with rationalisation of crude processing facility onshore.

Gulf of Mexico

BHP’s net share of capital development expenditure in FY2018, which is presented on a cash basis within this section, was US$380 million. The expenditure was primarily related to:

• Atlantis: execution of development activity on two wells.

• Mad Dog: execution phase of Phase 2 development, including three wells, with additional development activity on one well at Spar A.

Conventional petroleum exploration and appraisal

The majority of the expenditure incurred in FY2018 was in our focus areas including Gulf of Mexico (US and Mexico) and Trinidad and Tobago. We also incurred expenditure in Western Australia and Brazil.

Access

We acquired acreage in the US sector of the Gulf of Mexico during FY2018. We were awarded three blocks from Lease sale 250 held in March 2018 at 100 per cent interest, EB 914 and EB 699 in the western Gulf of Mexico and GC 823 to the west of the Mad Dog field, which we co-own with BP and Chevron. In addition, we acquired a 50 per cent interest in the Murphy operated Samurai prospect in GC 432 and GC 476.

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Exploration program expenditure details

Our gross expenditure on exploration was US$709 million in FY2018, of which US$516 million was expensed.

Exploration and appraisal wells drilled, or in the process of drilling, during the year included:

Well	Location	Target	BHP equity	Spud date	Water depth	Total well depth	Status
Wildling-2	US Gulf of Mexico GC520	Oil	100% (BHP Operator)	15 April 2017	1,267m	10,205 m	Hydrocarbons encountered, temporarily abandoned
Wildling-2 ST01	US Gulf of Mexico GC520	Oil	100% (BHP Operator)	11 August 2017	1,267m	10,177 m	Hydrocarbons encountered, temporarily abandoned
Scimitar	US Gulf of Mexico GC392	Oil	65% (BHP Operator)	1 October 2017	1,289 m	9,836 m	Plugged and abandoned
Scimitar-ST	US Gulf of Mexico GC392	Oil	85% (BHP Operator)	23 January 2018	1,289 m	8,246 m	Plugged and abandoned
Samurai-2	US Gulf of Mexico GC 432	Oil	50% (Murphy Operator)	16 April 2018	1,088 m	8,615 m	Hydrocarbons encountered, drilling ahead
Victoria-1	Trinidad & Tobago Block 5	Gas	65% (BHP Operator)	12 June 2018	1,828 m	2,545 m	Hydrocarbons encountered, drilling ahead

In the US Gulf of Mexico, we completed drilling the Wildling-2 well, which encountered oil in multiple horizons. A sidetrack was drilled to further appraise the extent of the discovery and also encountered oil in multiple horizons. Both the Wildling-2 well and sidetrack were temporarily abandoned. In the northern extension of the Wildling mini basin, the Murphy operated Samurai-2 exploration well was spud on 16 April 2018 and encountered hydrocarbons in multiple horizons not previously observed by the Wildling-2 exploration well. Evaluation is ongoing to assess the scale of the discoveries in the Wildling mini basin with plans to continue drilling in the second half of FY2019. The Scimitar well, to the north of the Neptune field, was spud on 1 October 2017 and a subsequent sidetrack was spud on 23 January 2018. No hydrocarbons were encountered and the well was plugged and abandoned.

Seismic data acquisition and reprocessing were completed in order to evaluate prospects in the US and Mexico.

In Trinidad and Tobago, following the gas discovery at LeClerc, we commenced Phase 2 of our deepwater exploration drilling campaign to further assess the commercial potential of the Magellan play. The Victoria-1 exploration well was spud on 12 June 2018 and encountered gas. The well was plugged and abandoned on 18 July 2018. We plan to drill the Concepcion prospect to further test the Magellan play in the 2019 financial year. Following completion of the Victoria-1 well, the Deepwater Invictus has been mobilised to the Bongos prospect in our Northern licence area in Trinidad and Tobago. The Bongos-1 exploration well was spud on 20 July 2018 and experienced mechanical difficulty shortly after spud. The Bongos-2 exploration well was spud on 22 July 2018 and encountered hydrocarbons. Drilling is still in progress.

In Mexico, planning continues for the exploration and appraisal wells at Trion. We expect to begin drilling of the next appraisal well in FY2019.

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In Western Australia, processed 3D seismic data for the Exmouth sub-basin will be delivered during the September 2018 quarter and will inform the prospectivity in this area.

In Brazil, we formally relinquished our two blocks in the deepwater Foz do Amazonas Basin during the period, prior to the commencement of Exploration Period 2 (two well commitment).

Outlook

In our conventional business, volumes are expected to be between 113 and 118 MMboe in FY2019 as a result of additional downtime from planned dry dock maintenance at Pyrenees and natural field decline across the portfolio.

Conventional unit costs for FY2019 are expected to be under US$11 per barrel, reflecting the impact of lower volumes, partially offset by productivity improvements.

Conventional petroleum capital expenditure of approximately US$730 million is planned in FY2019. Conventional petroleum capital expenditure for FY2019 includes US$600 million of development and US$130 million of maintenance.

A US$750 million exploration and appraisal program is planned for FY2019.

Onshore US: Discontinued operations

Onshore US delivered a strong operating performance in FY2018, with total production of 72 MMboe, exceeding our full year guidance of between 61 and 67 MMboe as a result of improved well performance from larger completions and longer laterals. Drilling and development expenditure for FY2018 was US$0.9 billion, a reduction of US$0.2 billion relative to guidance reflecting better well performance, and lower drilling and completions activity which was tailored to support value in the exit process.

This strong performance positioned these assets well for divestment and on 27 July 2018, BHP announced we had entered into agreements for the sale of its entire interests in the Eagle Ford, Haynesville, Permian and Fayetteville Onshore US oil and gas assets for a combined base consideration of US$10.8 billion, payable in cash (less customary completion adjustments). BP America Production Company, a wholly owned subsidiary of BP Plc, has agreed to acquire 100 per cent of the issued share capital of Petrohawk Energy Corporation, the BHP subsidiary that holds the Eagle Ford, Haynesville and Permian assets, for a consideration of US$10.5 billion (less customary completion adjustments). MMGJ Hugoton III, LLC, a company owned by Merit Energy Company, has agreed to acquire 100 per cent of the issued share capital of BHP Billiton Petroleum (Arkansas) Inc. and 100 per cent of the membership interests in BHP Billiton Petroleum (Fayetteville) LLC, which hold the Fayetteville assets, for a total consideration of US$0.3 billion (less customary completion adjustments). Both sales are subject to the satisfaction of customary regulatory approvals and conditions precedent.

Until completion of the transactions, expected by the end of October 2018, we intend to operate five rigs in Onshore US and incur capital expenditure at an annualised rate broadly consistent with FY2018.

Onshore US assets have been classified as held for sale and are disclosed as Discontinued operations. Refer to note 26 ‘Discontinued operations’ in section 5 for further information.

Performance for the year ended 30 June 2017 compared with year ended 30 June 2016

Production

Total conventional petroleum production for FY2017 decreased by two per cent to 128 MMboe.

Conventional liquids volumes decreased by eight per cent to 63 MMboe as an additional infill well at Mad Dog and higher production at North West Shelf and Algeria partially offset planned maintenance at Atlantis and natural field decline across the portfolio.

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Financial results

Conventional petroleum revenue increased by US$173 million to US$4.7 billion. Gulf of Mexico, which includes Atlantis, Shenzi and Mad Dog, increased by US$114 million to US$1.4 billion. In Australia, Bass Strait and North West Shelf collectively increased by US$185 million to US$2.3 billion and the Australian Production Unit, which includes Macedon, Pyrenees and Minerva, decreased by US$106 million to US$601 million.

Underlying EBITDA for Petroleum increased by US$79 million to US$3.1 billion. Price impacts, net of price-linked costs, increased Underlying EBITDA by US$260 million. Controllable cash costs increased by US$287 million reflecting higher exploration expenses, attributable to expensing the Burrokeet wells in Trinidad and Tobago and the Wildling-1 well in the Gulf of Mexico. During the period, gains on asset divestments of US$125 million were recognised, with the majority related to the sale of 50 per cent of BHP’s interest in the undeveloped Scarborough area gas fields to Woodside Energy Limited.

Conventional petroleum unit costs were US$8.65 per barrel due to lower volumes.

Conventional petroleum capital development expenditure for FY2017 declined by 28 per cent to US$917 million.

Exploration expenditure for FY2017 was US$803 million, of which US$471 million was expensed. Our exploration strategy is to focus on material opportunities, at high working interest, with a bias for liquids and operatorship. While the majority of the expenditure incurred in FY2017 was in our Gulf of Mexico, Trinidad and Tobago, and Mexico focus areas, we also incurred expenditure in Western Australia and Brazil.

1.12.2    Copper

Detailed below is financial information for our Copper assets for FY2018 and FY2017 and an analysis of Copper’s financial performance for FY2018 compared with FY2017.

Year ended 30 June 2018 US$M	Revenue			Underlying EBITDA			D&A			Underlying EBIT			Net operating assets (6)			Capital expenditure			Exploration gross		Exploration to profit
Escondida (1)		8,774			4,921			1,601			3,320			13,666			997
Pampa Norte (2)		1,831			924			298			626			1,967			757
Antamina (3)		1,438			955			111			844			1,313			183
Olympic Dam		1,255			267			228			39			6,937			669
Other (3)(4)		–			(193	)		8			(201	)		(204	)		5
Total Copper from Group production		13,298			6,874			2,246			4,628			23,679			2,611
Third party products		1,427			60			–			60			–			–
Total Copper		14,725			6,934			2,246			4,688			23,679			2,611			53		53
Adjustment for equity accounted investments (5)		(1,438	)		(412	)		(113	)		(299	)		–			(183	)		–		–
Total Copper statutory result		13,287			6,522			2,133			4,389			23,679			2,428			53		53

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Year ended 30 June 2017 US$M	Revenue			Underlying EBITDA			D&A			Underlying EBIT			Net operating assets (6)			Capital expenditure			Exploration gross		Exploration to profit
Escondida (1)		4,544			2,397			996			1,401			14,972			999
Pampa Norte (2)		1,401			620			314			306			1,662			213
Antamina (3)		1,119			664			114			550			1,265			188
Olympic Dam		1,287			284			224			60			6,367			267
Other (3)(4)		–			(118	)		7			(125	)		(166	)		5
Total Copper from Group production		8,351			3,847			1,655			2,192			24,100			1,672
Third party products		1,103			23			–			23			–			–
Total Copper		9,454			3,870			1,655			2,215			24,100			1,672			44		44
Adjustment for equity accounted investments (5)		(1,119	)		(325	)		(116	)		(209	)		–			(188	)		–		–
Total Copper statutory result		8,335			3,545			1,539			2,006			24,100			1,484			44		44

⁽¹⁾  Escondida is consolidated under IFRS 10 and reported on a 100 per cent basis.

⁽²⁾ Includes Spence and Cerro Colorado.

⁽³⁾  Antamina and Resolution are equity accounted investments and their financial information presented above, with the exception of net operating assets, reflects BHP’s share.

⁽⁴⁾ Predominantly comprises divisional activities, greenfield exploration and business development. Includes Resolution.

⁽⁵⁾ Total Copper statutory result Revenue excludes US$1,438 million (FY2017: US$1,119 million) revenue related to Antamina. Total Copper statutory result Underlying EBITDA includes US$113 million (FY2017: US$116 million) D&A and US$299 million (FY2017: US$209 million) net finance costs and taxation expense related to Antamina and Resolution that are also included in Underlying EBIT. Copper statutory result Capital expenditure excludes US$183 million (FY2017: US$188 million) related to Antamina.

⁽⁶⁾ Refer to section 1.11.4 for a reconciliation of Net operating assets to Net assets and section 1.11.5 for the definition and method of calculation of Net operating assets.

Key drivers of Copper’s financial results

Price overview

Our average realised sales price for FY2018 was US$3.12 per pound (FY2017: US$2.54 per pound). Copper prices improved in the first half. Solid demand conditions, the announcement of a Chinese ban of low-grade scrap imports and the expectation of disruptions related to labour negotiations in Chile and Peru in CY2018 added to positive sentiment. In the second half of FY2018, the relatively smooth resolution of South American labour negotiations and trade policy uncertainty resulted in copper prices easing late in the half. In the near term, incremental mine production from committed projects and rising scrap availability should continue to meet demand needs. However, in the longer term we expect demand to continue growing steadily, led by a solid performance in traditional end-use sectors. Exposure to the electrification megatrend provides some upside. A deficit is expected to emerge early next decade as grade declines, a rise in costs and a scarcity of high-quality future development opportunities are likely to constrain the industry’s ability to cheaply meet this demand growth.

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Production

Total Copper production for FY2018 increased by 32 per cent to 1.8 Mt.

Escondida copper production for FY2018 increased by 57 per cent to 1,213 kt, reflecting a full year of production following the industrial action in the previous year and supported by the start-up of the Los Colorados Extension project on 10 September 2017. Pampa Norte copper production increased by four per cent to 264 kt supported by record production at Spence of 200 kt reflecting better recoveries and higher utilisation of the solvent extraction and electrowinning plants. Olympic Dam copper production decreased by 18 per cent to 137 kt as a result of the planned major smelter maintenance campaign in the first half of FY2018 and a slower than planned ramp-up. The operation returned to full capacity during the June 2018 quarter. Antamina copper production increased by four per cent to 140 kt and zinc production increased 37 per cent to 120 kt due to higher head grades as mining continued through a zinc-rich ore zone.

For more information on individual asset production in FY2018, FY2017 and FY2016, refer to section 6.2.

Financial results

Copper revenue increased by US$5.0 billion to US$13.3 billion in FY2018. Escondida revenue increased by US$4.2 billion to US$8.8 billion.

Underlying EBITDA for Copper increased by US$3.0 billion to US$6.5 billion. Price impacts, net of price-linked costs, increased Underlying EBITDA by US$2.3 billion. Higher volumes increased Underlying EBITDA by $1.6 billion mainly driven by a full year of production at Escondida following the industrial action in the previous year, supported by the ramp-up of the Los Colorados Extension project and record production at Spence. Controllable cash costs increased by US$924 million, mainly due to a US$288 million change in estimated recoverable copper contained in the Escondida sulphide leach pad which benefited costs in the prior period, a US$176 million increase in labour and contractor costs at Olympic Dam, to support operating stability projects and expansion plans, a US$126 million planned drawdown of mined ore inventory at Escondida ahead of the commissioning of the Los Colorados Extension project and US$89 million unfavourable fixed cost dilution at Olympic Dam as a result of lower volumes due to the smelter maintenance campaign. Non-cash costs, which includes net development stripping, decreased by US$417 million, reflecting higher capitalised stripping at Escondida and Pampa Norte and increased underground mine capitalisation at Olympic Dam as mining expands into the Southern Mine Area.

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Unit costs at our operated copper assets increased by nine per cent to US$1.25 per pound and included a 15 per cent increase at Escondida to US$1.07 per pound. Unfavourable exchange rate movements and general inflation also impacted unit costs in FY2018. The calculation of operated copper assets and Escondida unit costs is set out in the table below.

	Operated copper assets unit costs (1)				Escondida unit costs
US$M	FY2018		FY2017		FY2018		FY2017
Revenue		11,860		7,232		8,774		4,544
Underlying EBITDA		6,112		3,301		4,921		2,397
Gross costs		5,748		3,931		3,853		2,147
Less: by-product credits		754		580		447		213
Less: freight		133		71		123		60
Less: treatment and refining charges		428		302		428		302
Net costs		4,433		2,978		2,855		1,572
Sales (kt, equity share)		1,614		1,177		1,209		767
Sales (Mlb, equity share)		3,558		2,595		2,664		1,691
Cost per pound (US$) (2)		1.25		1.15		1.07		0.93

⁽¹⁾ Operated copper assets include Escondida, Pampa Norte and Olympic Dam.

⁽²⁾  FY2018 based on exchange rates of AUD/USD 0.78 and USD/CLP 625.

Outlook

Total Copper production of between 1,675 and 1,770 kt is expected in FY2019. Escondida production of between 1,120 and 1,180 kt is forecast for FY2019, as higher expected throughput is offset by a significant decrease in average concentrator head grade consistent with the mine plan. The Escondida Water Supply Expansion is in execution phase and will deliver first water production in FY2020. Production at Spence is expected to be between 185 and 200 kt in FY2019, with volumes weighted to the second half as planned maintenance in May and June 2018 resulted in a lower staking rate.

Escondida unit cost guidance for FY2019 is expected to increase to less than US$1.15 per pound, reflecting the inclusion of costs to settle labour negotiations. A decrease in average concentrator head grade of more than 15 per cent, consistent with the mine plan, and an increase in the usage of higher cost desalinated water will be offset by improved labour productivity and maintenance optimisation strategies. A lower mining cost per tonne of material moved is expected as continued improvements in truck runtime, labour productivity and targeted maintenance supports higher throughput from three concentrators.

Performance for the year ended 30 June 2017 compared with year ended 30 June 2016

Production

Total Copper production for FY2017 decreased by 16 per cent to 1.3 Mt.

Escondida copper production decreased by 21 per cent to 772 kt as a result of a four-day site-wide suspension of operations following a fatality in October 2016, 44 days of industrial action in the March 2017 quarter and severe weather in early June 2017. Pampa Norte copper production increased by one per cent to 254 kt supported by record cathode production and ore milled at Spence following the completion of the Recovery Optimisation project. Olympic Dam copper production decreased by 18 per cent to 166 kt following the state-wide power outage during September and October 2016 and unplanned maintenance at the refinery during December 2016 and January 2017. Antamina copper production decreased by nine per cent to 134 kt as record material mined was more than offset by lower copper grades as mining continues through a planned zinc rich ore zone.

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Financial results

Copper revenue increased by US$86 million to US$8.3 billion in FY2017.

Underlying EBITDA for Copper increased by US$926 million to US$3.5 billion. Price impacts, net of price-linked costs, increased Underlying EBITDA by US$1.0 billion. Controllable cash costs decreased by US$731 million, mainly due to a US$203 million planned build of mined ore ahead of the commissioning of the Los Colorados Extension project, a US$160 million ore inventory drawdown as a result of extending the operation of Los Colorados by four months in FY2016 and a US$77 million benefit related to the increase in estimated recoverable copper contained in the sulphide leach pad following commissioning of the Escondida Bioleach Pad Extension project. In addition, there was a US$103 million benefit due to an inventory drawdown at Olympic Dam in the prior year. Non-cash costs, which includes net deferred stripping, increased by US$304 million, reflecting lower capitalised development stripping at Escondida and Pampa Norte consistent with the optimised mine plans. One-off items reduced Underlying EBITDA by US$492 million and reflects US$387 million in lost volume from the 44 days of industrial action at Escondida and US$105 million due to the state-wide power outage and resultant shutdown at Olympic Dam. The idle capacity and other strike-related costs incurred as a result of the Escondida industrial action were reported as exceptional and are therefore not included in one-off items.

Unit costs at our operated copper assets decreased by four per cent to US$1.15 per pound, excluding the idle capacity and other strike-related costs incurred as a result of the industrial action at Escondida. Escondida unit costs decreased by 17 per cent to US$0.93 per pound, excluding the impact of the industrial action which was reported as an exceptional item. If costs related to the industrial action were included, unit costs would have been US$1.13 per pound.

1.12.3    Iron Ore

Detailed below is financial information for our Iron Ore assets for FY2018 and FY2017 and an analysis of Iron Ore’s financial performance for FY2018 compared with FY2017.

Year ended 30 June 2018 US$M	Revenue		Underlying EBITDA		D&A		Underlying EBIT		Net operating assets (4)			Capital expenditure		Exploration gross		Exploration to profit
Western Australia Iron Ore		14,596		8,869		1,721		7,148		19,406			1,047
Samarco (1)		–		–		–		–		(1,278	)		–
Other (2)		160		60		14		46		192			27
Total Iron Ore from Group production		14,756		8,929		1,735		7,194		18,320			1,074
Third party products (3)		54		1		–		1		–			–
Total Iron Ore		14,810		8,930		1,735		7,195		18,320			1,074		84		44
Adjustment for equity accounted investments		–		–		–		–		–			–		–		–
Total Iron Ore statutory result		14,810		8,930		1,735		7,195		18,320			1,074		84		44

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Year ended 30 June 2017 US$M	Revenue		Underlying EBITDA		D&A		Underlying EBIT		Net operating assets (4)			Capital expenditure		Exploration gross		Exploration to profit
Western Australia Iron Ore		14,395		9,001		1,873		7,128		20,040			716
Samarco (1)		–		–		–		–		(1,049	)		–
Other (2)		148		53		7		46		184			89
Total Iron Ore from Group production		14,543		9,054		1,880		7,174		19,175			805
Third party products (3)		81		23		–		23		–			–
Total Iron Ore		14,624		9,077		1,880		7,197		19,175			805		94		70
Adjustment for equity accounted investments		–		–		–		–		–			–		–		–
Total Iron Ore statutory result		14,624		9,077		1,880		7,197		19,175			805		94		70

⁽¹⁾ Samarco is an equity accounted investment and its financial information presented above, with the exception of net operating assets, reflects BHP Billiton Brasil Ltda’s share. All financial impacts following the Samarco dam failure have been reported as exceptional items in both reporting periods.

⁽²⁾ Predominantly comprises divisional activities, towage services, business development and ceased operations.

⁽³⁾ Includes inter-segment and external sales of contracted gas purchases.

⁽⁴⁾ Refer to section 1.11.4 for a reconciliation of Net operating assets to Net assets and section 1.11.5 for the definition and method of calculation of Net operating assets.

Key drivers of Iron Ore’s financial results

Price overview

Iron Ore’s average realised sales price for FY2018 was US$57 per wet metric tonne (wmt) (FY2017: US$58 per wmt). Platts 62 per cent Fe iron ore fines indices remained firm, underpinned by the preference for high-quality iron ore on the back of strong steel margins and iron-making capacity constraints in China due to environment related production cuts. The reduced Chinese domestic concentrate supply from ongoing environmental campaigns added to supply tightness in the high grade segment. The price spread between different grades of iron ore remained wide, as mills focussed on productivity maximisation. In the short term, supply growth from seaborne high-quality iron ore suppliers and ample iron ore inventories sitting at Chinese ports are expected to put a cap on the iron ore market. In the medium to long term, we see technical product quality differentiation to remain an important element in price formation. This thesis is underpinned by the fundamental improvement in steel profitability, the building of large-scale blast furnaces in coastal regions and the enforcement of more stringent environmental policies.

Production

Total Iron ore production from WAIO for FY2018 increased by three per cent to a record 238 Mt, or 275 Mt on a 100 per cent basis as a result of improved productivity and stability across the supply chain and production records at Jimblebar and Mining Area C. Mining and processing operations at Samarco remain suspended. For further information on the Samarco dam failure, refer to section 1.8.

For more information on individual asset production in FY2018, FY2017 and FY2016, refer to section 6.2.

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Financial results

Total Iron Ore revenue increased by US$186 million to US$14.8 billion.

Underlying EBITDA for Iron Ore decreased by US$147 million to US$8.9 billion. Price impact, net of price-linked costs and higher other non-controllable costs including fuel and energy, decreased Underlying EBITDA by US$614 million. Higher volumes and cost efficiencies reflecting continued reductions in labour and maintenance costs through improved equipment productivity and maintenance strategies increased Underlying EBITDA by US$568 million.

WAIO unit costs decreased by two per cent to US$14.26 per tonne despite the impact of a stronger Australian dollar. The calculation of WAIO unit costs is set out in the table below.

WAIO unit costs (US$M)	FY2018		FY2017
Revenue		14,596		14,395
Underlying EBITDA		8,869		9,001
Gross costs		5,727		5,394
Less: freight		1,276		983
Less: royalties		1,075		1,035
Net costs		3,376		3,376
Sales (kt, equity share)		236,771		231,208
Cost per tonne (US$) (1)		14.26		14.60

⁽¹⁾  FY2018 based on exchange rates of AUD/USD 0.78.

Exploration activities

Western Australia

WAIO has a substantial existing deposit supported by considerable additional mineralisation, all within a 250-kilometre radius of our existing infrastructure. This concentration of ore bodies also gives WAIO the flexibility to add growth tonnes to existing hub infrastructure and link brownfield developments to our existing mainline rail and port facilities. The total area covered by exploration and mining tenure amounts to 4,677 square kilometres, excluding crown leases and general purpose and miscellaneous licences that are used for infrastructure space and access.

Guinea Iron Ore

We have a 42.8 per cent interest in a joint venture that holds the Nimba Mining Concession. In addition to the Mining Concession, the extension of two exploration licences covering satellite areas in southeast Guinea are currently being discussed with the Guinean mining authorities. We will continue to assess our options for the Mount Nimba iron ore project.

Outlook

WAIO production of between 241 and 250 Mt, or between 273 and 283 Mt on a 100 per cent basis is expected in FY2019. This reflects a program of work to optimise maintenance schedules across our supply chain and improve port reliability and performance which is planned for the September 2018 quarter, with a corresponding impact expected on production and unit costs.

WAIO unit costs guidance remains broadly unchanged at less than US$14 per tonne in FY2019.

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Performance for the year ended 30 June 2017 compared with year ended 30 June 2016

Production

Total Iron ore production for FY2017 increased by four per cent to 231 Mt, or 268 Mt on a 100 per cent basis, following record annual production at Western Australia Iron Ore (WAIO). This increase reflected strong productivity improvements across the supply chain as well as the commissioning of a new primary crusher and additional conveying capacity at Jimblebar. Mining and processing operations at Samarco remain suspended.

Financial results

Total Iron ore revenue increased by US$4.1 billion to US$14.6 billion, due to a 32 per cent increase in the average realised price of iron ore.

Underlying EBITDA for Iron ore increased by US$3.5 billion to US$9.1 billion. Price impact, net of price-linked costs, increased Underlying EBITDA by US$3.2 billion. Higher volumes and cost efficiencies increased Underlying EBITDA by US$533 million. This was partially offset by a weaker US dollar against the Australian dollar which unfavourably impacted Underlying EBITDA by US$151 million.

WAIO unit costs decreased by three per cent to US$14.60 per tonne, underpinned by reductions in labour and contractor costs and increased equipment productivity. This was partially offset by a stronger Australian dollar, additional costs related to the accelerated rail renewal and maintenance program of US$0.20 per tonne that was completed in May 2017 and a stock write-off at Yandi.

1.12.4    Coal

Detailed below is financial information for our Coal assets for FY2018 and FY2017 and an analysis of Coal’s financial performance for FY2018 compared with FY2017.

Year ended 30 June 2018 US$M	Revenue			Underlying EBITDA			D&A			Underlying EBIT			Net operating assets (6)			Capital expenditure			Exploration gross		Exploration to profit
Queensland Coal		7,388			3,647			596			3,051			8,355			391
New Mexico		–			–			–			–			–			–
New South Wales Energy Coal (2)		1,605			652			149			503			994			18
Colombia (2)		818			395			95			300			883			54
Other (3)		–			(10	)		3			(13	)		(379	)		–
Total Coal from Group production		9,811			4,684			843			3,841			9,853			463
Third party products		2			(1	)		–			(1	)		–			–
Total Coal		9,813			4,683			843			3,840			9,853			463			21		21
Adjustment for equity accounted investments (4)(5)		(924	)		(286	)		(128	)		(158	)		–			(54	)		–		–
Total Coal statutory result		8,889			4,397			715			3,682			9,853			409			21		21

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Year ended 30 June 2017 US$M	Revenue			Underlying EBITDA			D&A			Underlying EBIT			Net operating assets (6)(7)			Capital expenditure			Exploration gross		Exploration to profit
Queensland Coal		6,316			3,256			605			2,651			8,581			235
New Mexico (1)		3			(6	)		3			(9	)		–			1
New South Wales Energy Coal (2)		1,351			525			154			371			1,080			11
Colombia (2)		749			363			96			267			873			34
Other (3)		8			(57	)		4			(61	)		(398	)		–
Total Coal from Group production		8,427			4,081			862			3,219			10,136			281
Third party products		–			–			–			–			–			–
Total Coal		8,427			4,081			862			3,219			10,136			281			9		9
Adjustment for equity accounted investments (4)(5)		(849	)		(297	)		(128	)		(169	)		–			(35	)		–		–
Total Coal statutory result		7,578			3,784			734			3,050			10,136			246			9		9

⁽¹⁾  Includes the Navajo mine (divested in July 2016).

⁽²⁾  Newcastle Coal Infrastructure Group and Cerrejón are equity accounted investments and their financial information presented above, with the exception of net operating assets, reflects BHP’s share.

⁽³⁾  Predominantly comprises divisional activities, IndoMet Coal (divested in October 2016) and ceased operations.

⁽⁴⁾  Total Coal statutory result Revenue excludes US$818 million (FY2017: US$749 million) revenue related to Cerrejón. Total Coal statutory result Underlying EBITDA includes US$95 million (FY2017: US$96 million) D&A and US$108 million (FY2017: US$116 million) net finance costs and taxation expense related to Cerrejón, that are also included in Underlying EBIT. Coal statutory result Capital expenditure excludes US$54 million (FY2017: US$34 million) related to Cerrejón.

⁽⁵⁾  Total Coal statutory result Revenue excludes US$106 million (FY2017: US$100 million) revenue related to Newcastle Coal Infrastructure Group. Total Coal statutory result excludes US$83 million (FY2017: US$85 million) Underlying EBITDA, US$33 million (FY2017: US$32 million) D&A and US$50 million (FY2017: US$53 million) Underlying EBIT related to Newcastle Coal Infrastructure Group until future profits exceed accumulated losses. Total Coal statutory result Capital expenditure excludes US$ nil (FY2017: US$1 million) related to Newcastle Coal Infrastructure Group.

⁽⁶⁾  Refer to section 1.11.4 for a reconciliation of Net operating assets to Net assets and section 1.11.5 for the definition and method of calculation of Net operating assets.

⁽⁷⁾  Queensland Coal net operating assets have been restated to reflect ceased operations in Other on a consistent basis with FY2018. There is no change to the overall net operating assets position.

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Key drivers of Coal’s financial results

Price overview

Metallurgical coal

Our average realised sales price for FY2018 was US$195 per tonne for hard coking coal (FY2017: US$180 per tonne) and US$132 per tonne for weak coking coal (FY2017: US$121 per tonne). Metallurgical coal prices reached a high in the middle of FY2018 amid healthy demand conditions and improved steel margins. Prices eased from this peak coming out of the Asian winter given stable supply and lower Chinese demand. In the short term, supply constraints should ease with additional volumes expected from various regions. Within this broader view, the application of China’s coal supply reform policy remains a major source of uncertainty. Over the longer term, emerging markets such as India are expected to support seaborne demand growth. High-quality metallurgical coals will continue to offer steelmakers value-in-use benefits.

Energy coal

Our average realised sales price for FY2018 was US$87 per tonne (FY2017: US$75 per tonne). The Global Coal Newcastle 6,000 kcal/kg price increase was driven by strong growth in Chinese seaborne demand. This was evident across both the heating and cooling seasons. There was also strong industrial demand over the summer. Seaborne demand from India benefited from disappointing domestic production. In the short term, Chinese imports are unlikely to repeat their recent strength. In the long term, global demand for energy coal is expected to grow only modestly, with Indian and South East Asian demand offsetting weakness in OECD countries amidst slowing demand from China.

Production

Metallurgical coal production increased by seven per cent to a record 43 Mt in FY2018 as record stripping performance, increased truck hours and higher wash-plant utilisation from low-cost debottlenecking activities offset lower volumes from Broadmeadow and Blackwater. Energy coal production was flat at 29 Mt as a strong performance at New South Wales Energy Coal was partially offset by the impacts of wet weather and higher strip ratio areas being mined at Cerrejón.

For more information on individual asset production in FY2018, FY2017 and FY2016, refer to section 6.2.

Financial results

Coal revenue increased by US$1.3 billion to US$8.9 billion in FY2018. The increase in revenue was primarily due to increases in the average realised coal prices.

Underlying EBITDA for Coal increased by US$613 million to US$4.4 billion. Prices, net of price-linked costs, increased Underlying EBITDA by US$1.1 billion. Controllable cash costs decreased Underlying EBITDA by US$430 million, driven by US$150 million unfavourable fixed cost dilution from reduced volumes at Broadmeadow and Blackwater, US$109 million additional contractor stripping fleet costs and debottlenecking activities, US$63 million increased maintenance costs due to a higher number of planned shutdowns and major component replacements and US$45 million increased contractor costs from the re-opening of the Ayredale Pit at NSWEC.

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Queensland Coal unit costs increased by 14 per cent to US$68 per tonne, including the impact of a stronger Australian dollar. NSWEC unit costs increased by 12 per cent to US$46 per tonne, including the impact of a stronger Australian dollar. The calculation of Queensland Coal’s and NSWEC’s unit costs is set out in the table below.

	Queensland Coal unit costs				NSWEC unit costs
US$M	FY2018		FY2017		FY2018		FY2017
Revenue		7,388		6,316		1,605		1,351
Underlying EBITDA		3,647		3,256		652		525
Gross costs		3,741		3,060		953		826
Less: freight		150		111		–		–
Less: royalties		740		631		111		94
Net costs		2,851		2,318		842		732
Sales (kt, equity share)		41,899		38,846		18,022		17,899
Cost per tonne (US$) (1)		68.04		59.67		46.72		40.90

⁽¹⁾  FY2018 based on exchange rates of AUD/USD 0.78.

Outlook

Metallurgical coal production is expected to increase to between 43 and 46 Mt in FY2019, with volumes weighted to the second half of the year. An extensive maintenance program is planned for the first half of FY2019, with a corresponding impact expected on production and unit costs. Energy coal production is expected to remain broadly unchanged at approximately 28 to 29 Mt in FY2019.

Queensland Coal unit costs are expected to be between US$68 and US$72 per tonne as a result of an eight per cent increase in strip ratios, higher diesel prices, local inflationary pressures and an extensive maintenance program planned for the first half of FY2019. NSWEC unit costs are expected to be between US$43 and US$48 per tonne in FY2019 reflecting mine progression through geological constraints from the monocline transition, higher strip ratios and diesel prices, as well as increased contract mining costs. Geological constraints are expected to continue into the medium term, with unit costs forecast to remain at approximately US$45 per tonne during this period.

Performance for the year ended 30 June 2017 compared with year ended 30 June 2016

Production

Metallurgical coal production decreased by six per cent to 40 Mt in FY2017. Production decreased as a result of damage caused by Cyclone Debbie to third party rail infrastructure. It was partially offset by record annual production at Peak Downs and Saraji. Energy coal production increased by seven per cent to 29 Mt as a result of a stronger performance at Cerrejón following constrained production in FY2016 during drought conditions. In addition, New South Wales Energy Coal (NSWEC) benefited from a lower strip ratio and additional bypass coal.

Financial results

Coal revenue increased by US$3.1 billion to US$7.6 billion in FY2017. The increase in revenue was primarily due to increases in the average realised coal prices.

Underlying EBITDA for Coal increased by US$3.1 billion to US$3.8 billion. Prices, net of price-linked costs, increased Underlying EBITDA by US$3.2 billion.

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Queensland Coal unit costs increased by eight per cent to US$60 per tonne as a result of lower sales volumes due to the impacts of Cyclone Debbie and a stronger Australian dollar. NSWEC unit costs of US$41 per tonne were in line with the prior year as a reduction in labour costs and favourable inventory movements were offset by a stronger Australian dollar.

1.12.5    Other assets

Nickel West

Key drivers of Nickel West’s financial results

Price overview

Our average realised sales price for FY2018 was US$12,592 per tonne (FY2017: US$10,184 per tonne). Nickel prices rose steadily across FY2018, from below US$10,000 per tonne at the beginning of July, to current levels around US$15,000 per tonne at the end of June. Demand growth has been broad-based, coming from both stainless and non-stainless applications. Nickel use in batteries, while relatively small at present, has garnered much attention. On the supply side, rising nickel pig iron production and nickel ore exports from Indonesia kept the global deficit in check. Exchange stocks of refined nickel metal remain high relative to historical levels, but have been declining across FY2018. In the near term, supply of nickel from Indonesia (in multiple forms) is expected to grow, which should prevent an acceleration in the drawdown of stocks. In the long term, the battery sector is expected to provide strong growth in demand for high-purity nickel supply.

Production

Nickel West production in FY2018 increased by six per cent to 91 kt, with increased production at the Mt Keith and Leinster operations supporting record metal production. Nickel production for FY2019 is expected to remain broadly unchanged from that of FY2018.

For more information on individual asset production in FY2018, FY2017 and FY2016, refer to section 6.2.

Financial results

Higher production and higher realised sales prices resulted in revenue increasing by US$348 million to US$1.3 billion.

Underlying EBITDA for Nickel West increased by US$247 million to US$291 million predominantly due to higher prices, and improved mill utilisation and concentrator recoveries which supported record metal production.

Performance for the year ended 30 June 2017 compared with year ended 30 June 2016

Production

Nickel West production in FY2017 increased by five per cent to 85 kt. Debottlenecking activities at the Kwinana refinery have resulted in record refined metal production.

Financial results

Higher production and higher realised sales prices resulted in revenue increasing by US$133 million to US$952 million.

Underlying EBITDA for Nickel West increased by US$158 million to US$44 million due to increased production rates across the supply chain following the triennial statutory shutdowns in FY2016, partially offset by a stronger Australian dollar.

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Potash

Potash recorded an Underlying EBITDA loss of US$135 million in FY2018, compared to a loss of US$108 million in FY2017.

Performance for the year ended 30 June 2017 compared with year ended 30 June 2016

Potash recorded an Underlying EBITDA loss of US$108 million in FY2017, compared to a loss of US$149 million in FY2016. The reduction in loss was due to a decrease in operating cash costs, particularly labour costs.

1.13    Other information

Application of critical accounting policies

The preparation of the Financial Statements requires management to make judgements and estimates and form assumptions that affect the amounts of assets, liabilities, contingent liabilities, revenues and expenses reported in the Financial Statements. On an ongoing basis, management evaluates its judgements and estimates in relation to assets, liabilities, contingent liabilities, revenue and expenses. Management bases its judgements and estimates on historical experience and on other factors it believes to be reasonable under the circumstances, the results of which form the basis of the reported amounts that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions and conditions.

The Group has identified a number of critical accounting policies under which significant judgements, estimates and assumptions are made. Actual results may differ for these estimates under different assumptions and conditions. This may materially affect financial results and the financial position to be reported in future. These critical accounting policies are as follows:

• significant events – Samarco dam failure;

• taxation;

• inventories;

• exploration and evaluation;

• development expenditure;

• overburden removal costs;

• depreciation of property, plant and equipment;

• impairments of non-current assets – recoverable amount;

• closure and rehabilitation provisions.

In accordance with IFRS, we are required to include information regarding the nature of the judgements and estimates and potential impacts on our financial results or financial position in the Financial Statements. This information can be found in section 5.1.

Quantitative and qualitative disclosures about market risk

We identified our principal market risks in section 1.6.4. A description of how we manage our market risks, including both quantitative and qualitative information about our market risk sensitive instruments outstanding at 30 June 2018, is contained in note 20 ‘Financial risk management’ in section 5.1.

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Off-balance sheet arrangements and contractual commitments

Information in relation to our material off-balance sheet arrangements, principally contingent liabilities, commitments for capital expenditure and commitments under leases at 30 June 2018 is provided in note 31 ‘Commitments’ and note 32 ‘Contingent liabilities’ in section 5.1.

Subsidiary information

Information about our significant subsidiaries is included in note 27 ‘Subsidiaries’ in section 5.1 and in Exhibit 8.1 – List of Subsidiaries.

Related party transactions

Related party transactions are outlined in note 30 ‘Related party transactions’ in section 5.1.

Significant changes since the end of the year

Significant changes since the end of the year are outlined in note 33 ‘Subsequent events’ in section 5.1.

The Strategic Report is made in accordance with a resolution of the Board.

Ken MacKenzie

Chairman

Dated: 6 September 2018

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2    Governance at BHP

2.1    Governance at BHP

2.1.1    Chairman’s letter

Dear Shareholder,

At the 2017 Annual General Meeting, I discussed our priorities, being safety, our portfolio, capital discipline, capability and culture, and social licence to operate. We made good progress with these priorities during FY2018, and I want to touch on a few aspects here that are relevant to governance.

Safety

Our first priority is safety, and our commitment to safety is relentless and unwavering. The impact of the tragic fatalities that occurred during FY2018 on the families, friends and colleagues of those who died is immeasurable and permanent, and we extend our deepest sympathies to those affected. The Sustainability Committee, as well as the full Board, considered in detail the findings of the investigations into the Goonyella fatality and the Permian Basin fatality, as well as the fatality at our non-operated joint venture, Cerrejón. We have shared those findings not only with our own teams, but also externally with other mining companies. We have also continued to focus on verification of safety controls and on improving safety risk culture.

Portfolio

BHP has a strong portfolio, with quality assets built around attractive commodities in iron ore, coal, copper and conventional petroleum. We keep the composition of our portfolio of assets under review. This has led to a number of changes during the year, with further simplification of our portfolio due to the divestment of Cerro Colorado in Chile and Gregory Crinum in Australia. In July 2018, we announced the sale of our Onshore US assets for a base consideration of US$10.8 billion. The sale of those assets is consistent with our long-term plan to continue to simplify and strengthen our portfolio to generate shareholder value and returns for decades to come.

Capital discipline

Over recent years, we have made significant progress on strengthening our Capital Allocation Framework, the framework by which we assess decisions relating to the deployment of capital. Application of the Framework assists us to make the most out of every dollar we earn as we direct capital between investments, the balance sheet and returns to shareholders. We have also been more transparent and provided greater clarity about our plans to keep net debt within a targeted range of US$10 billion to US$15 billion, and capital expenditure below US$8 billion per annum from FY2018 to FY2020. During FY2018, we established a Capital Allocation Working Group, consisting of members of the Board as well as management, to work together to further enhance our capital allocation processes. The work of that Group, which was concluded in FY2018, is outlined in section 2.13.5.

Culture and capability

I believe culture is a genuine differentiator and source of competitive advantage. There are many positive attributes at BHP; hard-working people, who have a real focus on the Group’s Charter values and doing the right thing. But there is always room for improvement. At BHP, we believe we can drive cultural change in terms of reducing bureaucracy and improving productivity.

Your CEO, Andrew Mackenzie, has coined the phrase ‘optimise without’, meaning that employees need to look for ways to achieve productivity gains without cost or volume as inputs. If we can do this, we will be leaner and more agile in our decision-making.

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Board composition

As you would expect, Board composition continues to be a topic of discussion during my meetings with shareholders. Investors – like the Board – believe that regular refreshment is important, but they are also aware of the value that corporate memory brings to a board.

As part of ongoing planning for Non-executive Director succession, the Board has maintained a skills matrix for several years. Following a review of Board succession planning, the Board has refreshed its approach. The requirements for Board composition are now framed with an overarching statement, and the desired skills and experience included in our updated matrix. The overarching statement, skills, experience and attributes take into account, and respond to, the changing external environment and BHP’s core business characteristics. This is set out in section 2.8 Director skills, experience and attributes.

The Board has 10 members, including the CEO. I am a proponent of a relatively small Board. However, for a company like BHP, which has four key Board committees (with the Sustainability Committee being critically important in our industry), a Board size of 10 to 12 is appropriate. As at 30 June, the average tenure of Directors was five years and two months. BHP has an aspiration to achieve gender balance across our workforce – and on our Board – by FY2025, and Board diversity remains a focus.

As set out in last year’s Annual Report, in August 2017, we announced the appointment of Terry Bowen and John Mogford to the Board. In addition, Wayne Murdy has decided to retire from the Board after the 2018 AGMs. On behalf of all shareholders, I thank Wayne for his wise counsel and valuable contribution to the Board and the Group over many years and wish him all the best for the future. Our search for a new Non-executive Director with mining experience is well under way and we expect to make an appointment early in calendar year 2019.

Social licence to operate

There has been a lot said on social licence in the past year. It remains as important as ever to do the right thing and fulfil our social contract. Having invested in many different communities through our 130-year history, we are acutely aware that public acceptance and trust are hard to measure when you have them, but easy to measure when you lose them. We recognise that we must do more to enhance our social licence.

The Board has continued to focus on responding to the tragedy at Samarco. Please see section 1.8 for information on our ongoing response to the Samarco dam failure.

Conclusion

During the past few months, I have met with many of our institutional shareholders along with members of our retail shareholder base. Direct engagement with investors remains invaluable to the Board and the management of BHP.

I have also, during FY2018, visited many of our operations around the world. This has continued to reinforce to me the quality of BHP’s assets and people, and the prospects for continuing to create long-term value for our shareholders.

Ken MacKenzie

Chairman

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2.1.2    Governance structure

Our philosophy of governance goes beyond compliance. We believe high-quality governance supports long-term value creation: simply put, good governance is good business. Our approach is to adopt what we consider to be the best of the prevailing governance standards in Australia, the United Kingdom and the United States.

In the same spirit, we do not see governance as just a matter for the Board. Good governance is also the responsibility of executive management and is embedded throughout BHP. In this, the Board and management are guided by Our Charter values, including our value of Sustainability, in how we operate our business, interact with our stakeholders and plan for the future.

Update on UK governance reform

In July 2018, the Financial Reporting Council released the 2018 UK Corporate Governance Code and the Guidance on Board Effectiveness. The new Code emphasises the importance of demonstrating, through reporting, how the governance of a company contributes to its long-term sustainable success and achieves wider objectives. We agree that good governance contributes to sustainable success, and recognise the renewed emphasis on business building trust by forging strong relationships with key stakeholders. We also understand the importance of a corporate culture that is aligned with BHP’s purpose and business strategy, and which promotes integrity and includes diversity.

BHP is well placed to comply with the new Code. For example, the Board has considered culture and purpose at regular intervals over the past few years. The Risk and Audit Committee already considers whistleblowing as part of its twice-yearly review of EthicsPoint data and trends. We also have a long-standing practice of enabling the Board and committees to receive a broad range of stakeholder information and views.

We are reviewing the new Code to ensure our governance framework remains aligned with best practice. We will complete this review before the start of FY2019 and report against the new Code in the Annual Report in 2020.

BHP governance structure

The following diagram describes the governance framework at BHP. It shows the interaction between our shareholders and the Board, as well as the relationship between the Board and the Chief Executive Officer (CEO). It also illustrates the flow of delegation from shareholders.

Robust processes are in place to ensure the delegation flows through the Board and its committees to the CEO, the Executive Leadership Team (ELT) and into the organisation. At the same time, accountability flows upwards from the Group to shareholders. This process helps ensure alignment with shareholders.

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Our Charter is central to the governance framework of BHP. It embodies our corporate purpose, strategy and values and defines when we are successful. We foster a culture that values and rewards high ethical standards, personal and corporate integrity and respect for others.

BHP governance structure

2.2    Board of Directors and Executive Leadership Team

2.2.1    Board of Directors

Ken MacKenzie

BEng, FIEA, FAICD, 54

Chairman and Independent Non-executive Director

Director of BHP Billiton Limited and BHP Billiton Plc since September 2016.

Chairman of BHP Billiton Limited and BHP Billiton Plc from 1 September 2017.

Skills and experience: Mr MacKenzie has extensive global and executive experience and a deeply strategic approach, with a focus on capital discipline and the creation of long-term shareholder value. He has insight and understanding in relation to organisational culture, the external environment, the diverse interests of our stakeholders and emerging issues related to our social licence to operate.

Mr MacKenzie was the Managing Director and Chief Executive Officer of Amcor Limited, a global packaging company with operations in over 40 countries, from 2005 until 2015. During his 23-year career with Amcor, Mr MacKenzie gained extensive experience across all of Amcor’s major business segments in developed and emerging markets in the Americas, Australia, Asia and Europe.

Other directorships and offices (current and recent):

• Former Managing Director and Chief Executive Officer of Amcor Limited (from July 2005 to April 2015)

• Advisory Board member of American Securities Capital Partners LLC (since January 2016)

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• Advisory Board member of Adamantem Capital (since September 2016)

• Former Senior Adviser to McKinsey & Company (from January 2016 to June 2017)

Board Committee membership:

• Chairman of the Nomination and Governance Committee

• Member of the Sustainability Committee

Andrew Mackenzie

BSc (Geology), PhD (Chemistry), 61

Non-independent

Director of BHP Billiton Limited and BHP Billiton Plc since May 2013.

Mr Mackenzie was appointed Chief Executive Officer on 10 May 2013.

Skills and experience: Mr Mackenzie has over 30 years’ experience, including in oil and gas, minerals, strategy and capital discipline over long-term cycles, technology, global markets, public policy and commodity value chains. He also has non-executive director experience.

Mr Mackenzie joined BHP in November 2008 as Chief Executive Non-Ferrous, with responsibility for over half of BHP’s 100,000 strong workforce across four continents. He was appointed Chief Executive Officer in May 2013. Prior to BHP, Mr Mackenzie held various executive roles at Rio Tinto, including as Chief Executive of Diamonds and Minerals, and at BP, where he held a number of senior roles, including as Group Vice President for Technology and Engineering, and Group Vice President for Chemicals. Mr Mackenzie was previously a non-executive director of Centrica plc.

Other directorships and offices (current and recent):

• Fellow of the Royal Society of London (since May 2014)

• Director (since May 2013) and Deputy Chair (since November 2017) of the International Council on Mining and Metals

• Former Director of the Grattan Institute (from May 2013 to November 2017)

• Former Non-executive Director of Centrica plc (from September 2005 to May 2013)

Terry Bowen

BAcct, FCPA, MAICD, 51

Independent Non-executive Director

Director of BHP Billiton Limited and BHP Billiton Plc since October 2017.

Skills and experience: Mr Bowen has significant executive experience across a range of diversified industries. He has deep financial expertise, and extensive experience in capital allocation discipline, commodity value chains and strategy.

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He served as an Executive Director and Finance Director of Wesfarmers Limited from 2009 to 2017, which included chairing a number of Wesfarmers’ operating divisions. Wesfarmers is a conglomerate with interests predominantly in Australian and New Zealand retail, chemicals, fertilisers, coal mining and industrial and safety products. Prior to this, Mr Bowen held various senior executive roles within Wesfarmers, including as Finance Director of Coles, Managing Director of Industrial and Safety and Finance Director of Wesfarmers Landmark. He also served as the inaugural Chief Financial Officer of Jetstar Airways Limited from 2003 to 2005 and before this, held senior finance roles over an 11-year career with Tubemakers of Australia Limited. Mr Bowen is a former Director of Gresham Partners and past President of the National Executive of the Group of 100 Inc. He is also currently the Managing Partner and Head of the Operations Group at BGH Capital.

The Board is satisfied that Mr Bowen meets the criteria for financial experience as outlined in the UK Corporate Code, competence in accounting and auditing as required by the UK Financial Conduct Authority’s Corporate Governance Rules and the audit committee financial expert requirements under the US Securities and Exchange Commission (SEC) Rules.

Other directorships and offices (current and recent):

• Managing Partner and Head of the Operations Group at BGH Capital (since 2018)

• Former Executive Director and Finance Director of Wesfarmers Limited (from 2009 to 2017)

• Director of West Coast Eagles Football Club (since 2017)

• Former Chairman of West Australian Opera Company Incorporated (from 2014 to 2017)

• Former Director of Gresham Partners Holdings Limited and Gresham Partners Group Limited (from 2009 to 2017)

• Former Director of the Harry Perkins Institute of Medical Research Incorporated (from 2010 to 2013)

• Former Chief Financial Officer of Jetstar Airways Limited (from 2003 to 2005)

Board Committee membership:

• Member of the Risk and Audit Committee

Malcolm Broomhead

MBA, BE, FAICD, 66

Independent Non-executive Director

Director of BHP Billiton Limited and BHP Billiton Plc since March 2010.

Skills and experience: Mr Broomhead has extensive experience as a non-executive director of global organisations, and as a chief executive of large global industrial and mining companies. Mr Broomhead has a broad strategic perspective and understanding of the long-term cyclical nature of the resources industry and commodity value chains, with proven health, safety and environment, and capital allocation performance.

Mr Broomhead was Managing Director and Chief Executive Officer of Orica Limited (a global mining company) from 2001 until September 2005. Prior to joining Orica, he held a number of senior positions at North Limited, including Managing Director and Chief Executive Officer and, prior to that, held senior management positions with Halcrow (UK), MIM Holdings, Peko Wallsend and Industrial Equity.

Other directorships and offices (current and recent):

• Chairman of Orica Limited (since January 2016) and a Director (since December 2015)

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• Former Chairman of Asciano Limited (from October 2009 to August 2016)

• Former Director of Coates Group Holdings Pty Ltd (from January 2008 to July 2013)

• Director of the Walter and Eliza Hall Institute of Medical Research (since July 2014)

• Chairman of the Australia China One Belt One Road Advisory Board (since August 2016)

Board Committee membership:

• Chairman of the Sustainability Committee

• Member of the Nomination and Governance Committee

Anita Frew

BA (Hons), MRes, Hon. D.Sc, 61

Independent Non-executive Director

Director of BHP Billiton Limited and BHP Billiton Plc since September 2015.

Skills and experience: Ms Frew has an extensive breadth of non-executive experience in diverse industries, including chemicals, engineering, industrial and finance. In particular, Ms Frew has valuable insight and experience in the creation of shareholder value, organisational change, mergers and acquisitions, risk and health, safety and environment.

Ms Frew is the Chairman of Croda International Plc (a British speciality chemicals company) and Deputy Chairman and Senior Independent Director of Lloyds Banking Group Plc. Prior to this, she was the Chairman of Victrex Plc, Senior Independent Director of Aberdeen Asset Management Plc and IMI Plc and a Non-executive Director of Northumbrian Water.

Other directorships and offices (current and recent):

• Chairman of Croda International Plc (since September 2015)

• Director (from 2010), Deputy Chairman (since December 2014) and Senior Independent Director (since May 2017) of Lloyds Banking Group Plc

• Former Senior Independent Director of Aberdeen Asset Management Plc (from October 2004 to September 2014)

• Former Senior Independent Director of IMI Plc (from March 2006 to May 2015)

• Former Chairman of Victrex Plc (from 2008 to October 2014)

Board Committee membership:

• Member of the Remuneration Committee

• Member of the Risk and Audit Committee

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Carolyn Hewson

AO, BEc (Hons), MA, FAICD, 63

Independent Non-executive Director

Director of BHP Billiton Limited and BHP Billiton Plc since March 2010.

Skills and experience: Ms Hewson has extensive non-executive experience in a number of sectors, as well as executive experience in financial markets, risk management and investment management. Through her non-executive roles, Ms Hewson brings experience and insight on strategy and risk through cycles, social licence issues, the changing external environment and the promotion of corporate culture.

Ms Hewson is a former investment banker with over 35 years’ experience in the finance sector. She was previously an Executive Director of Schroders Australia Limited and has extensive financial markets, risk management and investment management expertise. Ms Hewson is a former Director of BT Investment Management Limited, Westpac Banking Corporation, AMP Limited, CSR Limited, AGL Energy Limited, the Australian Gas Light Company, South Australian Water and the Economic Development Board of South Australia.

Other directorships and offices (current and recent):

• Member of Federal Government Growth Centres Advisory Committee (since January 2015)

• Director of Stockland Group (since March 2009)

• Trustee Westpac Foundation (since May 2015)

• Former Member of Australian Federal Government Financial Systems Inquiry (from January 2014 to December 2014)

• Former Member of the Advisory Board of Nanosonics Limited (from June 2007 to August 2015)

• Former Director of BT Investment Management Limited (from December 2007 to December 2013)

• Former Director of Australian Charities Fund Operations Limited (from June 2000 to February 2014)

• Former Director and Patron of the Neurosurgical Research Foundation (from April 1993 to December 2013)

• Former Trustee and Chairman of Westpac Buckland Fund (from January 2011 to December 2013) and Chairman of Westpac Matching Gifts Limited (from August 2011 to December 2013), together known as the Westpac Foundation

• Former Director of Westpac Banking Corporation (from February 2003 to June 2012)

Board Committee membership:

• Chairman of the Remuneration Committee

• Member of the Nomination and Governance Committee

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Lindsay Maxsted

DipBus (Gordon), FCA, FAICD, 64

Independent Non-executive Director

Director of BHP Billiton Limited and BHP Billiton Plc since March 2011.

Skills and experience: Mr Maxsted has over 10 years’ experience in non-executive roles, including as chairman of two global companies. Mr Maxsted is also a corporate recovery specialist who has managed a number of Australia’s largest corporate insolvency and restructuring engagements and, until 2011, continued to undertake consultancy work in the restructuring advisory field. He was the Chief Executive Officer of KPMG Australia between 2001 and 2007.

Mr Maxsted has a breadth of understanding and insight in relation to the creation of shareholder value through cycles, risk, capital discipline and the external environment.

The Board is satisfied that Mr Maxsted meets the criteria for recent and relevant financial experience as outlined in the UK Corporate Code and competence in accounting and auditing as required by the UK Financial Conduct Authority’s Corporate Governance Rules. In addition, he is the Board’s nominated ‘audit committee financial expert’ for the purposes of the SEC Rules.

Other directorships and offices (current and recent):

• Chairman of Westpac Banking Corporation (since December 2011) and a Director (since March 2008)

• Chairman of Transurban Group (since August 2010) and a Director (since March 2008)

• Director and Honorary Treasurer of Baker Heart and Diabetes Institute (since June 2005)

Board Committee membership:

• Chairman of the Risk and Audit Committee

John Mogford

BEng, 65

Independent Non-executive Director

Director of BHP Billiton Limited and BHP Billiton Plc since October 2017.

Skills and experience: Mr Mogford has significant global executive experience, including in oil and gas, capital allocation discipline, commodity value chains and health, safety and environment. Mr Mogford has also held roles as a non-executive director on a number of boards.

Mr Mogford spent the majority of his career in various leadership, technical and operational roles at BP Plc. More recently, he was the Managing Director and an Operating Partner of First Reserve, a large global energy focused private equity firm, from 2009 until 2015, during which he served on the boards of First Reserve’s investee companies, including as Chairman of Amromco Energy LLC and White Rose Energy Ventures LLP. Mr Mogford retired from the boards of Weir Group Plc, and one of First Reserve’s portfolio companies, DOF Subsea AS, in 2018, and is currently on the board of ERM Worldwide Group Limited.

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Other directorships and offices (current and recent):

• Former Non-executive Director of Network Rail Limited (from 2016 to 2017)

• Former Managing Director (from 2012 to 2015) and Operating Partner (from 2009 to 2012) of First Reserve Corporation

• Non-executive Director of ERM Worldwide Group Limited (since 2015)

• Former Non-executive Director of Midstates Petroleum Company Inc. (from 2011 to 2016)

• Former Non-executive Director of CHC Group Limited (from 2014 to 2015) and CHC Helicopters SA (from 2012 to 2015)

• Former Non-executive Director of DOF Subsea AS (from 2009 to 2018)

• Former Non-executive Director of Weir Group Plc (from 2008 to 2018)

Board Committee membership:

• Member of the Sustainability Committee

Wayne Murdy

BSc (Business Administration), CPA, 74

Independent Non-executive Director

Director of BHP Billiton Limited and BHP Billiton Plc since June 2009.

Skills and experience: Mr Murdy has significant executive experience in the mining industry and a background in finance and accounting. Mr Murdy has a deep understanding of strategy over long-term cycles, capital discipline and commodity value chain expertise. As a long-standing member of the BHP Board, he has extensive corporate knowledge and understanding.

Mr Murdy has held executive roles with Getty Oil, Apache Corporation and Newmont Mining Corporation. He served as the Chief Executive Officer of Newmont Mining Corporation from 2001 to 2007 and Chairman from 2002 to 2007, and has been a Director of Extraction Oil and Gas, Inc. since December 2016 and Lead Independent Director since March 2018. Mr Murdy is also a former Chairman of the International Council on Mining and Metals, a former Director of the US National Mining Association and a former member of the Manufacturing Council of the US Department of Commerce.

Other directorships and offices (current and recent):

• Director of Extraction Oil and Gas, Inc. (since December 2016) and Lead Independent Director (since March 2018)

• Former Director of Weyerhaeuser Company (from January 2009 to February 2016)

• Former Director of Qwest Communications International Inc. (from September 2005 to April 2011)

Board Committee membership:

• Member of the Remuneration Committee

• Member of the Risk and Audit Committee

Mr Murdy has decided not to stand for re-election as a Non-executive Director at the 2018 Annual General Meetings of BHP.

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Shriti Vadera

MA, 56

Senior Independent Director, BHP Billiton Plc

Director of BHP Billiton Limited and BHP Billiton Plc since January 2011.

Skills and experience:

Ms Vadera brings wide-ranging and global experience in economics, public policy and strategy, as well as deep understanding and insight in relation to global and emerging markets and the macro-political and economic environment.

Ms Vadera has held executive roles and has broad non-executive experience. She is Chairman of Santander UK Group Holdings Plc and Santander UK Plc, and has been a Director of AstraZeneca Plc since 2011. She was an investment banker with S G Warburg/UBS from 1984 to 1999, on the Council of Economic Advisers, HM Treasury from 1999 to 2007, Minister in the UK Department of International Development in 2007, Minister in the Cabinet Office and Business Department from 2008 to 2009 with responsibility for dealing with the financial crisis and G20 Adviser from 2009 to 2010. Ms Vadera advised governments, banks and investors on the Eurozone crisis, banking sector, debt restructuring and markets from 2010 to 2014.

Other directorships and offices (current and recent):

• Chairman of Santander UK Group Holdings Plc and Santander UK Plc (since March 2015)

• Director of AstraZeneca Plc (since January 2011)

• Former Trustee of Oxfam (from 2000 until 2005)

Board Committee membership:

• Member of the Nomination and Governance Committee

• Member of the Remuneration Committee

Margaret Taylor

BA, LLB, GAICD, FCIS, 58

Group Company Secretary and Chairman of the Disclosure Committee

Ms Taylor was appointed Group Company Secretary of BHP effective June 2015. Previously, she was Group Company Secretary of Commonwealth Bank of Australia, and before joining the Bank, held the position of Group General Counsel and Company Secretary of Boral Limited. Prior to that, Ms Taylor was Regional Counsel Australia/Asia with BHP, and earlier, a partner with law firm Minter Ellison, specialising in corporate and securities laws. She is a Fellow of the Governance Institute of Australia.

2.2.2    Executive Leadership Team

Andrew Mackenzie

BSc (Geology), PhD (Chemistry), 61

Chief Executive Officer

(See section 2.2.1 for biography)

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Arnoud Balhuizen

BBE, 49

Chief Commercial Officer

Mr Balhuizen was appointed Chief Commercial Officer in March 2017. Prior to this, he was President Marketing and Supply from March 2016 and President Marketing from 2013. Mr Balhuizen started his career with Billiton in 1994, working for the Marketing and Trading division in the Netherlands. Since then he has held various marketing roles, including General Manager Marketing for Copper Cathodes, Vice President Iron Ore Marketing and Vice President Petroleum Marketing.

Peter Beaven

BAcc, CA, 51

Chief Financial Officer

Mr Beaven was appointed Chief Financial Officer in October 2014. Previously he was the President of Copper and prior to that appointment in May 2013, President of Base Metals, President of BHP’s Manganese Business, and Vice President and Chief Development Officer for Carbon Steel Materials. He has wide experience across a range of regions and businesses in BHP, UBS Warburg, Kleinwort Benson and PricewaterhouseCoopers.

Geoff Healy

BEc, LLB, 52

Chief External Affairs Officer

Mr Healy joined BHP as Chief Legal Counsel in June 2013 and was appointed Chief External Affairs Officer in February 2016. Prior to joining BHP, Mr Healy was a partner at Herbert Smith Freehills for 16 years and a member of its Global Partnership Council, working widely across its network of Australian and international offices.

Mike Henry

BSc (Chemistry), 52

President Operations, Minerals Australia

Mr Henry joined BHP in 2003. He served as President, Coal from January 2015 to February 2016 when he was appointed President Operations, Minerals Australia. Prior to January 2015, he was President, HSE, Marketing & Technology. His earlier career with BHP included a number of commercial roles covering Minerals and Petroleum, including the role of Chief Marketing Officer.

Diane Jurgens

BSEE, MSEE, MBA, 56

Chief Technology Officer

Ms Jurgens joined BHP in 2015 and was appointed Chief Technology Officer in February 2016. Prior to joining BHP, Ms Jurgens was based in China for nearly 10 years, serving as Board Member and Managing Director of Shanghai OnStar Telematics Company, in addition to prior roles as Chief Information Officer and Strategy Board member for General Motors’ International and China Operations. Ms Jurgens’ early career was with the Boeing Company where she worked for 12 years in engineering, information technology and business development leadership roles.

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Daniel Malchuk

BEng, MBA, 52

President Operations, Minerals Americas

Mr Malchuk was appointed President Operations, Minerals Americas in February 2016 based in Santiago, Chile. Previously he was President of the Copper Business. Mr Malchuk has held a number of roles in BHP, including President Aluminium, Manganese and Nickel, President of Minerals Exploration, and Vice President Strategy and Development Base Metals. He has worked in four countries with BHP, after joining the Company in April 2002.

Steve Pastor

BSc (Mechanical Engineering), MBA, 52

President Operations, Petroleum

Mr Pastor joined BHP in 2001 and was appointed President Operations, Petroleum in February 2016. He is responsible for the Group’s global oil and gas operations and exploration program. Over his career with BHP, Mr Pastor has served as Asset President Conventional and he has held leadership roles in deepwater and shale operations. Prior to joining BHP, Mr Pastor’s experience includes 11 years with Chevron.

Athalie Williams

BA (Hons), FAHRI, 48

Chief People Officer

Ms Williams joined BHP in 2007 and was appointed to the role of President, Human Resources in January 2015. Ms Williams’ title changed to Chief People Officer effective 1 July 2015. She has previously held senior Human Resources positions, including Vice President Human Resources Marketing, Vice President Human Resources for the Uranium business and Group HR Manager, Executive Resourcing & Development. Prior to BHP, Ms Williams was an organisation strategy advisor with Accenture (formerly Andersen Consulting) and National Australia Bank. Ms Williams is a member of Chief Executive Women and a Director of the BHP Billiton Foundation.

2.3    Shareholder engagement

Part of the Board’s commitment to high quality governance is expressed through the approach BHP takes to engaging and communicating with its shareholders. We encourage shareholders to make their views known to us.

Our shareholders are based around the globe. As well as the two AGMs, which are an important part of the governance and investor engagement process, the Board uses a range of formal and informal communication channels to understand the views of shareholders. This ensures the Board represents shareholders in governing BHP. We regularly engage with institutional shareholders and investor representative organisations in Australia, South Africa, the United Kingdom and the United States. The purpose of these meetings is to discuss governance and strategy of BHP. The meetings are an important opportunity to build relationships and to engage directly with governance managers, fund managers and governance advisers. We also meet regularly with retail shareholder representatives, such as the Australian Shareholders’ Association, the UK Shareholders’ Association and the UK Individual Shareholders Society.

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We take a coordinated approach to engagement on corporate governance and during FY2018, we responded to a wide range of shareholders, their representatives and non-governmental organisations. Issues covered included Samarco, non-operated joint ventures, industry associations, tax and transparency, corporate purpose, remuneration, climate change, cybersecurity and diversity. Engagement with other groups, including non-governmental organisations, is outlined in section 1.9.

Investor engagement in FY2018

Topic	Led by	Purpose	FY2018 activity
Strategy, governance and remuneration	Chairman	Discuss proposals and issues with shareholders and other stakeholders. Meetings are scheduled to allow for feedback and for new policies to be developed prior to AGMs.	Meetings held in Australia, the UK and the US in July/August 2017, and the US and the UK in May 2018. Retail shareholder event, held in conjunction with the Australian Shareholders’ Association in July 2018, in line with our intention to make this an annual event.
Strategy, governance and remuneration	Senior Independent Director	Discuss strategy, Board succession and remuneration issues.	Meetings held by the Senior Independent Director in the UK in January and Australia in February.
Strategy, finance and operating performance	CEO, CFO, senior management and Investor Relations	Update shareholders on results or other key announcements. We also engage with other capital providers; for example, through meetings with bondholders.	Live webcasts of important announcements. Face-to-face investor meetings held in Australia, Canada, France, Germany, Hong Kong, Italy, Singapore, South Africa, Sweden, Switzerland, the UK and the US. Debt investor meetings held in London in September. Debt investor teleconferences held in August 2017 and February 2018 were attended by investors in Canada, France, India, Switzerland, Turkey, the UK and the US.
Health, Safety, Environment and Community (HSEC)	Head of Health, Safety and Environment	Update investors on key HSEC issues.	Meetings held in Australia in September. The European ESG roadshow will take place in October 2018 to re-align with the release of the Sustainability Report.

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Topic	Led by	Purpose	FY2018 activity
Governance strategy and briefings	Group Governance	Provides a conduit to enable the Board and its committees to remain abreast of evolving investor expectations and to continuously enhance the governance processes of BHP.	Meetings held in Australia and the UK throughout the year, in Sweden and the US in March, and South Africa in May. Multiple briefings on Samarco, including an update in March covering non-operated joint ventures and a Renova Foundation update.
Climate change	Vice President, Sustainability and Climate Change	Update investors on our strategy on climate change.	Meetings held in Australia and the UK throughout the year, the US in March and South Africa in May.

Shareholder communications

Shareholders can communicate with BHP and our registrar electronically. Shareholders can contact us at any time through our Investor Relations team, with contact details available online at bhp.com. Shareholder and analyst feedback is shared with the Board through the Chairman, the Senior Independent Director, the Chairman of the Remuneration Committee, other Directors, the CEO, the CFO and the Group Company Secretary. In addition, Investor Relations and Group Governance provide regular reports to the Board on shareholder and governance manager feedback and analysis. This approach provides a robust mechanism to ensure that Directors are aware of issues raised and have a good understanding of current shareholder views.

Annual General Meetings

The AGMs provide a forum to facilitate the sharing of shareholder views, and are important events in the BHP calendar. These meetings provide an update for shareholders on our performance and offer an opportunity for shareholders to ask questions and vote.

Key members of management, including the CEO and CFO, are present and available to answer questions. The External Auditor attends the AGMs and is also available to answer questions.

Proceedings at shareholder meetings are webcast live from our website. Copies of the speeches delivered by the Chairman and CEO to the AGMs are released to the stock exchanges and posted on our website. A summary of proceedings and the outcome of voting on the items of business are released to the relevant stock exchanges and posted on our website as soon as they are available following completion of the BHP Billiton Limited AGM.

Information relating to our AGMs is available online at bhp.com/meetings.

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Understanding shareholder views

2.4    Role and responsibilities of the Board

The Board’s role is to represent the shareholders. It is accountable to shareholders for creating and delivering value through the effective governance of BHP. This role requires a high-performing Board, with all Directors contributing to the Board’s collective decision-making processes.

The Board Governance Document is a statement of the practices and processes the Board has adopted to discharge its responsibilities. It includes the processes the Board has implemented to undertake its own tasks and activities; the matters it has reserved for its own consideration and decision-making; the authority it has delegated to the CEO, including the limits on the way in which the CEO can execute that authority; and guidance on the relationship between the Board and the CEO.

The Board Governance Document specifies the role of the Chairman, the membership of the Board and the role and conduct of Non-executive Directors. It also provides that the Group Company Secretary is accountable to the Board and advises the Chairman and, through the Chairman, the Board and individual Directors on all matters of governance process.

The CEO is required to report regularly to the Board in a spirit of openness and trust on the progress being made by BHP. Open dialogue between individual members of the Board and the CEO and other members of the management team is encouraged to enable Directors to gain a better understanding of the Group.

For more information, refer to sections 2.5 to 2.8.

The Board Governance Document is available online at bhp.com/governance.

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Matters reserved for Board decision

Topic	Matter
Succession	Appointment of the CEO and determination of the terms of the appointment. Succession planning for direct reports to the CEO. Approval of the appointment of executives reporting to the CEO and membership of the ELT, and material changes to the organisational structure involving direct reports to the CEO.
Strategic matters	Strategy, annual budgets, balance sheet management and funding strategy. Determination of commitments, capital and non-capital items, acquisitions and divestments above specified thresholds. Setting dividend policy and determining dividends. Market risk management strategy and limits.
Monitoring	Performance assessment of the CEO and the Group and the remuneration of the CEO. Management of Board composition processes and performance. Review and monitoring systems of risk management and internal control. Establishment and assessment of measurable diversity objectives.
Reporting and regulation	Determination and adoption of documents (including the publication of reports and statements to shareholders) that are required by the Group’s constitutional documents, statute or by other external regulation. Determination and approval of matters that are required by the Group’s constitutional documents, statute or by other external regulation to be determined or approved by the Board.

Key Board activities during FY2018

The Board considered a range of matters during FY2018, as outlined below.

Strategic matters	Capital allocation (Capital Allocation Framework, capital prioritisation and development outcomes)	•   Dividend policy and dividend recommendations •   Capital prioritisation and portfolio development options •   Capital expenditure – revised Board process
	Funding (annual budgets, balance sheet management, liquidity management)	•   Two-year budget and annual funding plan •   Euro medium-term note update
	Portfolio (Group scenarios, commodity and asset review, growth options, approving commitments, capital and non-capital items and acquisitions and divestments above a specified threshold, and geopolitical and macro-environmental impacts)	•   Approval of Spence Growth Option •   Petroleum commodity review •   Safety and productivity •   Jansen FY2018 plans and supplementary approval •   Onshore US divestment execution •   Capital Allocation Working Group

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		•   Approval for Samarco funding •   Industry association membership •   Approval of capital investment – South Flank •   Audit tender •   Technology strategy •   Samarco strategy updates •   Review of Dual Listed Company structure •   Portfolio review – commodities and assets •   Divestment of Cerro Colorado
Monitoring and assurance matters	Includes matters and/or documents required by the Group’s constitutional documents, statute or by other external regulation	•   Goonyella fatality ICAM •   Permian Basin fatality ICAM •   Investor relations reports •   CEO reports •   HSEC reports •   Risk and Audit Committee report-outs •   Sustainability Committee report-outs including Site Visit report-outs •   Nomination and Governance Committee report-outs •   Remuneration Committee report-outs •   Approval of the CEO’s remuneration
Chairman’s matters	Board composition, succession planning, performance and culture	•   Committee succession •   Board composition and succession •   Culture update •   Diversity case study •   Inclusion and Diversity Council update and FY2018 targets •   Reviewing Engagement & Perception Survey results •   Director evaluation and independence •   Reviewing and approving the Annual Report suite •   Reviewing the ELT succession and talent pipeline •   Site visits and Board meetings held outside of Melbourne and London

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2.5    Board membership

The Board currently has 10 members. This will reduce to nine following the retirement of Wayne Murdy after the 2018 BHP Billiton Limited AGM. The Non-executive Directors are considered by the Board to be independent of management and free from any business relationship or other circumstance that could materially interfere with the exercise of objective, unfettered or independent judgement. For more information on the process for assessing independence, refer to section 2.10.

The Nomination and Governance Committee retains the services of external recruitment specialists to assist in the identification of potential candidates for the Board.

The Board believes there is an appropriate balance between Executive and Non-executive Directors to promote shareholder interests and govern BHP effectively. While the Board includes a smaller number of Executive Directors than is common for UK-listed companies, its composition is appropriate for the Dual Listed Company structure and is in line with Australian-listed company practice. In addition, the Board has extensive access to members of senior management who frequently attend Board meetings, where they make presentations and engage in discussions with Directors, answer questions and provide input and perspective on their areas of responsibility. The CFO attends all Board meetings. The Board, led by the Chairman, also holds discussions in the absence of management at the beginning and end of Board meetings.

The Directors of BHP, along with their biographical details, are listed in section 2.2.1.

Inclusion and diversity

Our Charter and the Our Requirements for Human Resources standard guide management on all aspects of human resource management, including inclusion and diversity. Underpinning the Our Requirements standards and supporting the achievement of diversity across BHP are principles and measurable objectives that define our approach to diversity and our focus on creating an inclusive work environment.

The Board and management believe many facets of diversity are required, as set out in section 2.13.3, in order to meet the corporate purpose. Diversity is a core consideration in ensuring the Board and its committees have the right blend of perspectives so that the Board oversees BHP effectively for shareholders.

Part of the Board’s role is to consider and approve measurable objectives for workforce diversity each financial year and to assess annually both the objectives and our progress in achieving those objectives. This progress will continue to be disclosed in the Annual Report, along with the proportion of women in our workforce, in senior management positions and on the Board, with our aspirational goal being to achieve gender balance across the business and the Board by FY2025. For more information on inclusion and diversity at BHP, including our progress against our measurable objectives and our employee profile more generally, refer to section 1.7.

2.6    Chairman

Until his retirement on 31 August 2017, the Chairman was Jac Nasser, who was considered by the Board to be independent on his appointment. He was appointed Chairman of the Group with effect from 31 March 2010, and had been a Non-executive Director since 6 June 2006. The Board considered that none of Mr Nasser’s other commitments interfered with the discharge of his responsibilities to BHP during the relevant part of the year under review. Ken MacKenzie succeeded Jac Nasser as Chairman with effect from 1 September 2017.

Mr MacKenzie was considered by the Board to be independent on his appointment as Chairman, and was an independent Non-executive Director from his appointment to the Board effective 22 September 2016. The Board considered that none of Mr MacKenzie’s other commitments (set out in section 2.2.1) interfered with the discharge of his responsibilities to BHP during the year under review. The Board is satisfied that as Chairman, Mr MacKenzie made sufficient time available to serve BHP effectively.

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2.7    Renewal and re-election

Renewal

BHP adopts a structured and rigorous approach to Board succession planning. We consider Board size, tenure and the skills, experience and attributes required to effectively govern and manage risk within BHP. This process is continuous, and planning is based on an expected nine-year tenure, allowing the Board to ensure we have the right balance on the Board between experience and fresh perspectives, noting the value of non-executive and executive experience. It also ensures the Board continues to be fit-for-purpose and evolves to take account of the rapidly changing external environment and BHP’s circumstances. Further information is set out in section 2.13.3 Nomination and Governance Committee Report.

When considering new appointments to the Board, the Nomination and Governance Committee oversees the preparation of a position specification which is then provided to an external search firm retained to conduct a global search. The search firm is instructed to consider a wide range of candidates, including taking into account the criteria and attributes set out in the Board Governance Document.

Once a candidate is identified, the Board, with the assistance of external consultants, conducts appropriate background and reference checks. The candidate is also interviewed by each Board member ahead of the Board deciding whether to appoint the candidate to the Board.

The Board has adopted a letter of appointment that contains the terms on which Non-executive Directors will be appointed, including the basis upon which they will be indemnified by the Group. The letter of appointment clearly defines the role of Directors, including the expectations in terms of independence, participation, time commitment and continuous improvement.

A copy of the terms of appointment for Non-executive Directors is available online at bhp.com/governance.

Director re-election

The Board adopted a policy in 2011, consistent with the UK Corporate Governance Code, under which all Directors must seek re-election by shareholders annually if they wish to remain on the Board. The Board believes annual re-election promotes and supports accountability to shareholders. The combined voting outcome of the BHP Billiton Plc and BHP Billiton Limited 2017 AGMs was that each Director received more than 96 per cent in support of their re-election.

Board support for re-election is not automatic. Directors who are seeking re-election are subject to a performance appraisal overseen by the Nomination and Governance Committee. Annual re-election effectively means all Directors are subject to a performance appraisal annually. The Board, on the recommendation of the Nomination and Governance Committee, makes a determination as to whether it will endorse a retiring Director for re-election. The Board will not endorse a Director for re-election if his or her performance is not considered satisfactory. The Notice of Meeting provides information that is material to a shareholder’s decision whether or not to re-elect a Director, including whether or not re-election is supported by the Board.

2.8    Director skills, experience and attributes

Skills, experience and attributes required

The Board and its Nomination and Governance Committee work to ensure that the Board continues to have the right balance necessary to discharge its responsibilities in accordance with the highest standards of governance. During the year under review, the new Chairman led a review of the Board’s approach to succession planning. The requirements for Board composition are now articulated in an overarching statement, with the desired skills and experience included in an updated skills and experience matrix.

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The overarching statement, skills, experience and attributes take into account, and respond to, the external environment and BHP’s core business characteristics, including:

• BHP’s strategy and the long-term cyclical nature of the business;

• that BHP is a global natural resources company operating in global markets;

• the continued need to focus on financial and HSEC risks;

• the increasing challenge to retain our social licence to operate, and the many stakeholders that will determine whether that licence is retained, including civil society, communities, investors, government, regulators, customers and employees;

• the increasing importance of technology and innovation to the sustainability of BHP;

• ongoing and continued focus on capital allocation, and improving shareholder and capital returns.

Overarching statement of Board requirements

The BHP Board will be diverse in terms of gender, background, nationality, skills, expertise and geographic location. The Board will comprise Directors who have proven past performance and the level of business, executive and non-executive experience required to:

• provide the breadth and depth of understanding necessary to effectively create long-term shareholder value;

• protect and promote the interests of BHP and its social licence to operate;

• ensure the talent, capability and culture of the Group support the long-term delivery of BHP’s strategy.

Attributes

The Board considers that each of the Non-executive Directors has the following attributes: sufficient time to undertake the responsibilities of the role; honesty and integrity; and a preparedness to question, challenge and critique. The Executive Director brings additional perspectives to the Board through a deeper understanding of BHP’s business and day-to-day operations.

Skills matrix

During FY2018, the Nomination and Governance Committee and the Board conducted a review of the Board skills matrix, which took into account the skills and experience the Board requires for the next period of BHP’s development, having regard to BHP’s circumstances and the changing external environment.

The revised matrix now includes an emphasis on technology and commodity value chain expertise. A narrow focus on capital projects has now become a more broadly defined capital allocation and cost efficiency skill, which reflects business imperatives.

In addition, strategy and risk have been separated, and the defined skills around governance, marketing and remuneration are no longer included in the matrix, with a different approach now being taken to these skills. Governance is experience that all Directors should possess, while experience with remuneration is satisfied by having a mix of executive and non-executive experience on the Board, and marketing is now included in commodity value chain expertise. All of the remaining definitions have been updated.

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Fewer Directors meet each of the skills and experience contained in the updated matrix than was the case previously. This is intentional, but all Directors satisfy both the overarching statement and the key attributes. Further information about the skills and attributes of each Director is set out in their biographies.

Skills and experience	Board
Total Directors		10
Mining		3
Senior Executive who has deep operating or technical mining experience with a large company operating in multiple countries; successfully optimised and led a suite of large, global, complex operating assets that have delivered consistent and sustaining levels of high performance (related to cost, returns and throughput); successfully led exploration projects with proven results and performance; delivered large capital projects that have been successful in terms of performance and returns; and a proven record in terms of health, safety and environmental performance and results.
Oil and Gas		2
Senior Executive who has deep technical and operational oil and gas experience with a large company operating in multiple countries; successfully led production operations that have delivered consistent and sustaining levels of high performance (related to cost, returns and throughput); successfully led exploration projects with proven results and performance; delivered large capital projects that have been successful in terms of performance and returns; and a proven record in terms of health, safety and environmental performance and results.
Global experience		6
Global experience working in multiple geographies over an extended period of time, including a deep understanding of and experience with global markets, and the macro-political and economic environment.
Strategy		8
Experience in enterprise-wide strategy development and implementation in industries with long cycles, and developing and leading business transformation strategies.
Risk		10
Experience and deep understanding of systemic risk and monitoring risk management frameworks and controls, and the ability to identify key emerging and existing risks to the organisation.
Commodity value chain expertise		5
End-to-end value or commodity chain experience – understanding of consumers, marketing demand drivers (including specific geographic markets) and other aspects of commodity chain development.
Financial expertise		10/2	(1)
Extensive relevant experience in financial regulation and the capability to evaluate financial statements and understand key financial drivers of the business, bringing a deep understanding of corporate finance, internal financial controls and experience probing the adequacy of financial and risk controls.
Relevant public policy expertise		2
Extensive experience specifically and explicitly focused on public policy or regulatory matters, including ESG (in particular climate change) and community issues, social responsibility and transformation, and economic issues.

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Skills and experience	Board
Health, safety, environment and community		7
Extensive experience with complex workplace health, safety, environmental and community risks and frameworks.
Technology		2
Recent experience and expertise with the development, selection and implementation of leading and business transforming technology and innovation, and responding to digital disruption.
Capital allocation and cost efficiency		6
Extensive direct experience gained through a senior executive role in capital allocation discipline, cost efficiency and cash flow, with proven long-term performance.

⁽¹⁾  Ten Directors meet the criteria of financial expertise outlined above. Two of these Directors also meet the criteria for recent and relevant financial experience as outlined in the UK Corporate Governance Code, competence in accounting and auditing as required by the UK Financial Conduct Authority’s Corporate Governance Rules in DTR7 and the audit committee financial expert requirements under the US Securities and Exchange Commission rules.

Board skills and experience: Climate change

The strategic issues facing the Board change over time. It is important the Board is able to identify these issues and access the best possible advice.

Climate change is a multi-faceted issue that affects investment decisions, our portfolio, oversight of the sustainability of our operations and engagement with government, investors, suppliers and customers. The Board includes an appropriate mix of skills and experience to understand the implications of climate change on our operations, market and society.

Climate change is treated as a Board-level governance issue and is discussed regularly, including during Board strategy discussions, portfolio review and investment decisions, and in the context of scenario triggers and signposts. The Sustainability Committee spends a significant amount of time considering systemic climate change matters relating to the resilience of, and opportunities for, BHP’s portfolio.

As a Board-level governance issue requiring experience of managing in the context of uncertainty and an understanding of the risk environment of the Group, all of the Non-executive Directors bring relevant experience to our climate change discussions.

Board members bring significant sectoral experience, which equips them to consider potential implications of climate change on the Group and its operational capacity. Board members also possess extensive experience in energy, governance and sustainability. There is also wide-ranging experience in finance, economics and public policy, which helps BHP understand the nature of the debate and the international policy response as it develops. In addition, there is a deep understanding of systemic risk and the potential impacts on our portfolio.

Collectively, this means the Board has the experience and skills to assist the Group in the optimal allocation of financial, capital and human resources for the creation of long-term shareholder value. It also means the Board understands the importance of meeting the expectations of stakeholders, including in respect of the natural environment.

To enhance that experience, the Board has taken a number of measures to ensure that its decisions are appropriately informed by climate change science and expert advisers.

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The Board seeks the input of management (including Dr Fiona Wild, our Vice President Sustainability and Climate Change), our Forum on Corporate Responsibility (which advises the Board on sustainability issues and includes Don Henry, former CEO of the Australian Conservation Foundation and Changhua Wu, former Greater China Director, the Climate Group) and other independent advisers.

Board tenure and diversity (as at 30 June 2018)

2.9    Director induction, training and development

The development of industry and Group knowledge is a continuous and ongoing process. The Board’s development activity reflects the diversification of the portfolio through the provision of regular updates to Directors on BHP’s assets, commodities, geographies and markets, and on the changing external environment, to enable the Board to remain up-to-date.

Upon appointment, each new Non-executive Director undertakes an induction program specifically tailored to his or her needs.

A copy of an indicative induction program is available online at bhp.com/governance.

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Following the induction program, Non-executive Directors participate in continuous improvement activities (Training and Development Program), which are overseen by the Nomination and Governance Committee. The Training and Development Program covers a range of matters of a business nature, including environmental, social and governance matters. Programs are designed to maximise the effectiveness of the Directors throughout their tenure and reflect their individual performance evaluations.

Training and development in FY2018

Area	Purpose	FY2018 activity
Briefings	Provide each Director with a deeper understanding of the activities, environment, key issues and direction of the assets along with HSEC and public policy considerations.	Diversity case study Technology strategy Iron Ore market update Petroleum review
Development sessions	Specific topics of relevance.	BHP and China 2035
Site visits	Briefings on the assets, operations and other relevant issues and meetings with key personnel.	Western Australia Iron Ore, Iron Ore, Australia Houston, Petroleum, United States Olympic Dam, Copper, Australia Marketing, Supply and Technology, Singapore Closed sites, Arizona, United States Samarco, Iron Ore, Brazil
External speakers	Addresses by various external experts to provide insight into current geopolitical, economic or social themes.	One Belt One Road initiative Climate change and the impact on developing countries Economic reforms in China Institutional political economy The rate of climate change and its impacts

These sessions and site visits also allow an opportunity to discuss in detail the changing risk environment and the potential for impacts on the achievement of our corporate purpose and business plans. For information on the management of principal risks, refer to sections 1.6.5 and 2.14.

The Chairman throughout the year discusses development areas with each Director. Board committees in turn review and agree their training needs. The benefit of this approach is that induction and learning opportunities can be tailored to Directors’ committee memberships, as well as the Board’s specific areas of focus. This approach also ensures a coordinated process in relation to succession planning, Board renewal, training and development and committee composition, which are all relevant to the Nomination and Governance Committee’s role in securing the supply of talent to the Board.

Each Board committee provides a standing invitation for any Non-executive Director to attend committee meetings (rather than just limiting attendance to committee members). Committee agendas and papers are provided to all Directors to ensure Directors are aware of matters to be considered by the committees and any Director can elect to attend meetings where appropriate.

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2.10    Independence

The Board is committed to ensuring a majority of Directors is independent. The Board considers that all of the current Non-executive Directors, including the Chairman, are independent.

Process to determine independence

The Board has adopted a policy which it uses to determine the independence of its Directors. This determination is carried out upon appointment, annually and at any other time where the changed circumstances of a Director warrant reconsideration.

A copy of the policy on Independence of Directors is available online at bhp.com/governance.

Under the policy, an ‘independent’ Director is one who is: ‘independent of management and any business or other relationship that could materially interfere with the exercise of objective, unfettered or independent judgement by the Director or the Director’s ability to act in the best interests of the BHP Billiton Group’.

Where a Director is considered by the Board to be independent but is affected by circumstances that appear relevant to the Board’s assessment of independence, the Board has undertaken to explain the reasons why it reached its conclusion. In applying the independence test, the Board considers relationships with management, major shareholders, subsidiary and associated companies and other parties with whom BHP transacts business against pre-determined materiality thresholds, all of which are set out in the policy.

Tenure

As at the end of the year under review, only Wayne Murdy, who was appointed on 18 June 2009, had served on the Board for more than nine years. As set out above, Wayne Murdy has decided to retire from the Board after the 2018 AGMs.

Relationships and associations

Lindsay Maxsted was the CEO of KPMG in Australia from 2001 until 2007. The Board believes this prior relationship with KPMG does not materially interfere with Mr Maxsted’s exercise of objective, unfettered or independent judgement, or his ability to act in the best interests of BHP. The Board has determined, consistent with its policy on the independence of Directors, that Mr Maxsted is independent. The Board notes in particular that:

• at the time of his appointment to the Board, more than three years had elapsed since Mr Maxsted’s retirement from KPMG. The Director independence rules and guidelines that apply to the Group – which are a combination of Australian, UK and US rules and guidelines – all use three years as the benchmark ‘cooling off’ period for former audit firm partners;

• Mr Maxsted has no financial (e.g. pension, retainer or advisory fee) or consulting arrangements with KPMG;

• Mr Maxsted was not part of the KPMG audit practice after 1980, and while at KPMG was not in any way involved in, or able to influence, any audit activity associated with BHP.

The Board believes Mr Maxsted’s financial acumen and extensive experience in the corporate restructuring field to be important in the discharge of the Board’s responsibilities. His membership of the Board and Chairmanship of the Risk and Audit Committee are considered by the Board to be appropriate and desirable.

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Some of the Directors hold, or have previously held, positions in companies with which BHP has commercial relationships. Those positions and companies are set out in the Director profiles in section 2.2.1. The Board has assessed all of the relationships between the Group and companies in which Directors hold or held positions, and has concluded that in all cases the relationships do not interfere with the Directors’ exercise of objective, unfettered or independent judgement or their ability to act in the best interests of BHP.

A specific instance is Malcolm Broomhead, who on 1 January 2016 was appointed Chairman of Orica Limited (a company with which BHP has commercial dealings). Orica provides commercial explosives, blasting systems and mineral processing chemicals and services to the mining and resources industry, among others. At the time of Mr Broomhead’s appointment to the Board of Orica, the BHP Board assessed the relationship between BHP and Orica and determined (and remains satisfied) that Mr Broomhead is able to apply objective, unfettered and independent judgement and to act in the best interests of BHP.

Transactions during FY2018 that amounted to related party transactions with Directors or Director-related entities under International Financial Reporting Standards (IFRS) are outlined in note 30 ‘Related party transactions’ in section 5.

Executive Director

The Executive Director, Andrew Mackenzie, is not considered independent because of his executive responsibilities. Mr Mackenzie does not hold directorships in any other company included in the ASX 100 or FTSE 100.

Conflicts of interest

The UK Companies Act 2006 requires that BHP Directors avoid a situation where they have or can have an unauthorised direct or indirect interest that conflicts, or possibly may conflict, with the Group’s interests, unless approved by non-interested Directors. In accordance with the UK Companies Act 2006, BHP Billiton Plc’s Articles of Association allow the Directors to authorise conflicts and potential conflicts where appropriate. A procedure operates to ensure the disclosure of conflicts and for the consideration and, if appropriate, the authorisation of those conflicts by non-conflicted Directors. The Nomination and Governance Committee supports the Board in this process by reviewing requests from Directors for authorisation of situations of actual or potential conflict and making recommendations to the Board, and by regularly reviewing any situations of actual or potential conflict that have previously been authorised by the Board, and making recommendations regarding whether the authorisation remains appropriate. In addition, in accordance with Australian law, if a situation arises for consideration in which a Director has a material personal interest, the affected Director takes no part in decision-making unless authorised by non-interested Directors. Provisions for Directors’ interests are set out in the Constitution of BHP Billiton Limited.

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2.11    Board evaluation

The Board is committed to transparency in assessing the performance of Directors. The Board conducts regular evaluations of its performance, the performance of its committees, the Chairman, individual Directors and the governance processes that support the Board’s work. The Board evaluation process comprises both assessment and review, as summarised in the diagram below.

The evaluation considers the balance of skills, experience, independence and knowledge of the Group and the Board, its overall diversity, including gender diversity, and how the Board works together as a unit.

Evaluation process

 * May be internally or externally facilitated assessment. Our approach is to conduct an externally facilitated assessment of the Board or Directors and committees at least every three years.

Directors provide anonymous feedback on their peers’ performance and individual contributions to the Board, which is passed on to the relevant Director via the Chairman. In respect of the Chairman’s performance, feedback is provided directly to the Senior Independent Director. External independent advisers are engaged to assist with these processes, as necessary. The involvement of an independent third party has assisted in the evaluation processes being rigorous and fair, and ensuring continuous improvement in the operation of the Board and committees, as well as the contributions of individual Directors.

Director assessment

The assessment of individual Directors focuses on the contribution of the Director to the work of the Board and the expectations of Directors as specified in the Group’s governance framework. The performance of individual Directors is assessed against a range of criteria, including the ability of the Director to:

• focus on creating long-term shareholder value;

• contribute to the development of strategy;

• understand the major risks affecting BHP;

• provide clear direction to management;

• contribute to Board effectiveness;

• contribute to discussions relating to organisational culture and behaviour;

• commit the time required to fulfil the role and perform their responsibilities effectively;

• listen to and respect the ideas of fellow Directors and members of management.

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Board effectiveness

The effectiveness of the Board as a whole and of its committees is assessed against the accountabilities set out in the Board Governance Document and each committee’s terms of reference. Matters considered in evaluations include:

• the effectiveness of discussion and debate at Board and committee meetings;

• the effectiveness of the Board’s and committees’ processes and relationship with management;

• the quality and timeliness of meeting agendas, Board and committee papers and secretariat support;

• the composition of the Board and each committee, focusing on the blend of skills, experience, independence and knowledge of the Group and its diversity, including geographic location, nationality and gender.

The process is managed by the Chairman, with feedback on the Chairman’s performance being provided to him by the Senior Independent Director. For information on the performance review process for executives, refer to section 2.15.

Assessments conducted in respect of FY2018

During FY2018, the Board commenced an assessment of the Board committees against their terms of reference, and an internal assessment of the individual directors. These assessments were completed in early FY2019 and have been discussed with the Board.

JCA Group (during FY2016) and Heidrick & Struggles Leadership Assessment (in previous years) have provided services in respect of Director performance assessments. Both companies have also conducted external searches and assisted in the identification of potential candidates for the Board as set out in section 2.13.3. In both cases, the search and assessment services operate independently and neither firm has any other connection with BHP.

Board committee assessment

The Board committee assessment required each committee member to consider the relevant committee’s compliance with its respective terms of reference. The Board considered its compliance with the Board Governance Document.

The outcomes of the assessment for each committee are set out in the relevant section.

Director review

An internal assessment of Directors’ performance was conducted in respect of FY2018. The assessments were undertaken with the assistance of an external service provider (Lintstock Limited) to aid collation, review and produce a report of the findings. As in FY2017, the focus was on consistently taking the perspective of creating shareholder value, contributing to Board cohesion and effective relationships with fellow Directors, and committing the time required to fulfil their role and effectively perform their responsibilities. Directors were specifically asked to comment on areas where their fellow directors contribute the greatest value and on potential areas for development. Feedback on the performance of the Chairman and the Senior Independent Director was also sought.

The overall findings were presented to the Board and discussed. The outcomes of the review supported the Board’s decision to endorse all Directors standing for re-election.

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Committee assessment in action

A number of improvements were agreed and implemented following the FY2017 committee assessment. The key areas of focus agreed for each committee in FY2018 were:

Risk and Audit – streamlining agenda items and providing additional background and context to certain matters as relevant during the year;

Remuneration – prioritising issues for the Committee, more regular briefings about the external environment and a deeper focus on trends;

Nomination and Governance – additional emphasis on the end-to-end process for identifying and assessing potential Board candidates, the skills and experience matrix and the ongoing process for regular review, engagement with potential Non-executive Director candidates, and a review of overall Committee composition and succession;

Sustainability – background briefings in advance of deep dives into material risks and further enhancements to the Director induction and training programs.

2.12    Board meetings and attendance

The Board meets as often as is appropriate to fulfil its role. Directors are required to allocate sufficient time to BHP to perform their responsibilities effectively, including adequate time to prepare for Board meetings. During the reporting year, the Board met 11 times, with five of those meetings held in Australia, four in the United Kingdom, one in New York and one in Singapore. Regularly scheduled Board meetings generally run over two days (including committee meetings and Director training and development sessions).

Members of the Executive Leadership Team and other members of senior management attended meetings of the Board by invitation.

Attendance at Board and standing Board committee meetings during FY2018 is set out in the table below.

Board and Board Committee attendance in FY2018

Board

Risk and Audit

Nomination and Governance

Remuneration

Sustainability

Tenure as at 30 June 2018

A

B

A

B

A

B

A

B

A

B

Terry Bowen

6

6

6

6

–

–

–

–

–

–

9 months

Malcolm Brinded

6

6

–

–

–

–

1

1

2

2

Retired on 18 October 2017

Malcolm Broomhead

11

11

4

4

4

4

–

–

4

4

8 years 3 months

Anita Frew

11

10

(1)

10

10

–

–

1

1

–

–

2 years 10 months

Carolyn Hewson

11

9

(2)

–

–

8

7

2

2

–

–

8 years 3 months

Grant King

4

4

–

–

–

–

–

–

1

1

Retired on 31 August 2017

Andrew Mackenzie

11

11

–

–

–

–

–

–

–

–

5 years 3 months

Ken MacKenzie

11

11

–

–

5

5

–

–

4

4

1 year 10 months

Lindsay Maxsted

11

11

10

10

–

–

–

–

–

–

7 years 3 months

John Mogford

6

6

–

–

–

–

–

–

2

2

9 months

Wayne Murdy

11

10

(3)

10

10

–

–

2

2

–

–

9 years

Jac Nasser

4

4

–

–

3

3

–

–

–

–

Retired on 31 August 2017

Shriti Vadera

11

11

–

–

8

8

2

2

–

–

7 years 5 months

Column A: Scheduled indicates the number of scheduled and ad-hoc meetings held during the period the Director was a member of the Board and/or committee.

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Column B: Attended indicates the number of scheduled and ad-hoc meetings attended by the Director during the period the Director was a member of the Board and/or committee. The following Directors were not able to attend certain meetings:

^1.  Ms Frew was not able to attend the meeting on 1 August due to ill health.

^2.  Ms Hewson was unable to attend the meeting on 20 February and 10 April due to a family illness.

^3.  Mr Murdy was unable to attend the meeting on 7 September due to ill health.

2.13    Board committees

The Board has established committees to assist it in exercising its authority, including monitoring the performance of BHP to gain assurance that progress is being made towards the corporate purpose within the limits imposed by the Board.

Each of the permanent committees has terms of reference under which authority is delegated by the Board.

Group Governance provides secretariat services for each of the committees. Committee meeting agendas, papers and minutes are made available to all members of the Board. Subject to appropriate controls and the overriding scrutiny of the Board, Committee Chairmen are free to use whatever resources they consider necessary to discharge their responsibilities.

Reports from each of the committees follow.

The terms of reference for each committee are available online at bhp.com/governance.

2.13.1    Risk and Audit Committee Report

Role and focus

The role of the Risk and Audit Committee (RAC) is to assist the Board in monitoring the decisions and actions of the CEO and the Group and to gain assurance that progress is being made towards achieving the corporate purpose within the limits imposed by the Board, as set out in the Board Governance Document.

The RAC discharges its responsibilities by overseeing:

• the integrity of BHP’s Financial Statements and Annual Report;

• the appointment, performance and remuneration of the External Auditor and integrity of the external audit process;

• the effectiveness of the systems of risk management and internal control;

• the plans, performance, objectivity and leadership of the Internal Audit function and the integrity of the internal audit process;

• capital management (capital structure and funding, and capital management planning and initiatives) and other matters.

For more information about our approach to risk management, refer to sections 1.4.3, 1.6.4 and 2.14.

The RAC met 10 times during FY2018. Information on meeting attendance by Committee members is included in the table below and information on Committee members’ qualifications is set out in section 2.2.1.

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In addition to the regular business of the year, the Committee discussed matters including non-operated minerals joint venture governance, Onshore US carrying values, US tax reform and the separation of the Risk function from Internal Audit. Further information is set out in the diagram below. The viability statement and the Board’s confirmation that it has carried out a robust risk assessment are in section 1.6.4. Statements relating to tendering of the external audit contract, significant matters relating to the Financial Statements and the process for evaluating the External Auditor are set out below. In addition to those items of business, the RAC spent significant time dealing with matters relating to Samarco. For more information on Samarco, refer to section 1.8.

Risk and Audit Committee members during the year

Name	Independent	Status	Attendance
Lindsay Maxsted (Chairman) (1)	Yes	Member for whole period	10/10
Terry Bowen	Yes	Member from 1 November 2017	6/6
Malcolm Broomhead	Yes	Member until 31 October 2017	4/4
Anita Frew	Yes	Member for whole period	10/10
Wayne Murdy	Yes	Member for whole period	10/10

⁽¹⁾  Mr Maxsted is the Committee’s financial expert nominated by the Board.

Committee activities in FY2018

Integrity of Financial Statements and funding matters

• Accounting matters for consideration, materiality limits, half-year and full-year results

• SOX compliance, reserves and resources

• Capital Allocation Framework

• Funding update, net debt target, Euro medium-term note update and US Form F-3 shelf registration statement update

• US tax reform

External auditor and integrity of the audit process

• External audit report

• External audit fees

• Management and external auditor closed sessions

• Audit plan, review of performance and quality of service

• Business RAC meetings

• Taxation

• Audit tender

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Effectiveness of systems of internal control and risk management

• Creation of a separate Risk function

• Group risk profile

• Regular reports on progress against the internal audit plan

• Matters of note rising from internal audits

• Internal assessments of performance of the internal audit function

• Fraud and misappropriation

• Risk management and internal control review

• Ethics and compliance

• Insurance

Other governance matters

• Induction, training and development program

• Board committee procedures, including closed sessions

• Performance and leadership of the internal audit function

• Non-operated minerals joint venture governance

• New country entry Philippines

• Cybersecurity

• Global Data Protections Regulation

Business Risk and Audit Committees

Business Risk and Audit Committees, covering each asset group, assist management in providing the information necessary to allow the RAC to discharge its responsibilities. They are management committees and perform an important monitoring function in the overall governance of BHP. The meetings take place annually as part of our financial governance framework.

As management committees, the responsible member of the Executive Leadership Team participates, but the committee is chaired by a member of the RAC. Each committee also includes the Group Financial Controller, the Chief Risk Officer and the Group Assurance Officer.

Significant operational and risk matters raised at Business RAC meetings are reported to the RAC by management.

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Activities undertaken by RAC during FY2018

Fair, balanced and understandable

Directors are required to confirm that they consider the Annual Report, taken as a whole, to be fair, balanced and understandable and provides the information necessary for shareholders to assess BHP’s position, performance, business model and strategy.

BHP has a substantial governance framework in place for the Annual Report. This includes management representation letters, certifications, RAC oversight of the Financial Statements and a range of other financial governance procedures focused on the financial section of the Annual Report, together with verification procedures for the narrative reporting section of the Report.

The RAC advises the Board on whether the Annual Report meets the fair, balanced and understandable requirement. The process to support the giving of this confirmation involved the following:

(1) ensuring all individuals involved in the preparation of any part of the Annual Report are briefed on the fair, balanced and understandable requirement through training sessions for each content manager that detail the key attributes of ‘fair, balanced and understandable’;

(2) employees who have been closely involved in the preparation of the Financial Statements review the entire narrative for the fair, balanced and understandable requirement, and sign off an appropriate sub-certification;

(3) key members of the team preparing the Annual Report confirm they have taken the fair, balanced and understandable requirement into account and they have raised, with the Annual Report project team, any concerns they have in relation to meeting this requirement;

(4) the Annual Report suite sub-certification incorporates a fair, balanced and understandable declaration;

(5) in relation to the requirement for the auditor to review parts of the narrative report for consistency with the audited Financial Statements, asking the External Auditor to raise any issues of inconsistency at an early stage.

As a result of the process outlined above, the RAC, and then the Directors, were able to confirm their view that BHP’s Annual Report 2018 taken as a whole is fair, balanced and understandable. For the Board’s statement on the Annual Report, refer to the Directors’ Report in section 4.

Integrity of Financial Statements

The RAC assists the Board in assuring the integrity of the Financial Statements. The RAC evaluates and makes recommendations to the Board about the appropriateness of accounting policies and practices, areas of judgement, compliance with accounting standards, stock exchange and legal requirements and the results of the external audit. It reviews the half-yearly and annual Financial Statements and makes recommendations on specific actions or decisions (including formal adoption of the Financial Statements and reports) the Board should consider in order to maintain the integrity of the Financial Statements.

For the FY2018 full-year and the half-year, the CEO and CFO have certified that BHP’s financial records have been properly maintained and that the FY2018 Financial Statements present a true and fair view, in all material respects, of our financial condition and operating results and are in accordance with accounting standards and applicable regulatory requirements.

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Significant issues

In addition to the Group’s key judgements and estimates disclosed throughout the FY2018 Financial Statements, the Committee also considered the following significant issues relating to financial reporting:

Onshore US divestment

The Committee examined management’s review of impairment triggers and potential impairment charges or reversals for the Group’s Onshore US assets throughout the year. While the divestment process was underway, prior to the receipt of bids, considerations were consistent with the approach to the Group’s other long-term assets as presented below.

Following the receipt of bids, specific consideration was given to the bids received and, subsequently, the agreements reached for the disposal of the Onshore US assets.

The Committee concurred with management’s conclusion that the impairment charges, and the timing of their recognition, in respect of the Group’s Onshore US assets were appropriate.

The Committee reviewed the Financial Statement impacts resulting from the announced divestment of the Group’s Onshore US assets, including their classification and disclosure as assets held for sale and discontinued operations.

Conclusions from these reviews are reflected in note 26 ‘Discontinued operations’ in section 5.

Carrying value of long-term assets (excluding Onshore US)

The assessment of carrying values of long-term assets uses a number of significant judgements and estimates.

The Committee examined management’s review of impairment triggers and potential impairment charges or reversals. Specific consideration was given to the most recent short, medium and long-term price forecasts, geological complexity, expected production volumes and mix, amended development plans, operating and capital costs, discount rates and other market indicators of fair value.

The Committee concurred with management’s conclusion on significant impairments recognised and that no impairment reversals were appropriate.

Conclusions from these reviews are reflected in note 10 ‘Property, plant and equipment’ in section 5.

Samarco dam failure

On 5 November 2015, the Samarco Mineração S.A (Samarco) iron ore operation in Minas Gerais, Brazil experienced a tailings dam failure that resulted in a release of mine tailings, flooding the community of Bento Rodrigues and impacting other communities downstream. Samarco is jointly owned by BHP Billiton Brasil Limitada (BHP Billiton Brasil) and Vale S.A. (Vale). BHP Billiton Brasil’s 50 per cent interest in Samarco is accounted for as an equity accounted joint venture investment.

Samarco’s provisions and contingent liabilities

The Committee reviewed updates to matters relating to the Samarco dam failure, including developments on existing and new legal proceedings and changes to the estimated costs of remediation.

BHP Billiton Brasil has recognised a share of additional losses recorded by Samarco during the year ended 30 June 2018.

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Potential direct financial impacts to BHP Billiton Brasil

The Committee considered:

• the accounting implications of funding provided to the Renova Foundation and Samarco to support activities under the Framework Agreement, carry out remediation and stabilisation work and support Samarco’s operations;

• changes to the estimated cost of remediation and compensation Programs under the Framework Agreement;

• developments in existing and new legal proceedings, including the impact of the Governance Agreement, entered into on 25 June 2018, on the Samarco dam failure provision and related disclosures;

• the provisions recognised and contingent liabilities disclosed by BHP Billiton Brasil or other BHP entities.

Based on currently available information, the Committee concluded that the accounting for the equity investment in Samarco, the provision recognised by BHP Billiton Brasil and contingent liabilities disclosed in the Group’s Financial Statements are appropriate.

For further information refer to note 3 ‘Significant events – Samarco dam failure’ in section 5.

Tax and royalty liabilities

The Group is subject to a range of tax and royalty matters across many jurisdictions. The Committee considered updates on changes to the wider tax landscape, estimates and judgements supporting the measurement and disclosure of tax and royalty provisions and contingent liabilities including the following:

• changes in foreign tax law. In FY2018, the Committee considered the impact of US tax reform, including the re-measurement of deferred tax balances. The Committee also concurred with management’s conclusion that the impact of US tax reform be disclosed as an exceptional item;

• tax risks (including transfer pricing risks) arising from the Group’s cross-border operations and transactions;

• settlement of disputed royalty assessments issued by the Queensland Office of State Revenue to certain Group companies in relation to its share of the BHP Billiton Mitsubishi Alliance (BMA); and

• other matters where uncertainty exists in the application of the law.

The Committee concluded that provisions recognised and contingent liabilities disclosed for these matters were appropriate considering the range of possible outcomes, currently available information and legal advice obtained.

For further information refer to notes 5 ‘Income tax expense’ and 32 ‘Contingent liabilities’ in section 5.

Closure and rehabilitation provisions

Determining the closure and rehabilitation provision is a complex area requiring significant judgement and estimates, particularly given the timing and quantum of future costs, the unique nature of each site and the long timescales involved.

The Committee considered the various changes in estimates for closure and rehabilitation provisions recognised during the year. Consideration was given to the results of the most recently completed surveying data, current cost estimates and appropriate inclusion of contingency in cost estimates to allow for both known and residual risks. The Committee concluded that the assumptions and inputs for closure and rehabilitation cost estimates were reasonable and the related provisions recorded were appropriate.

For further information, refer to note 13 ‘Closure and rehabilitation provisions’ in section 5.

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Impact of new accounting standards

The Committee considered and approved accounting policy changes resulting from the application of new standards commencing 1 July 2018, including IFRS 9/AASB 9 ‘Financial Instruments’ and IFRS 15/AASB 15 ‘Revenue from Contracts with Customers’.

The Committee reviewed management’s analysis of the adoption implications for the Group and concurred with its recommendations. The Committee continued to consider the impact of new and emerging accounting standards and regulatory requirements commencing in future periods.

For further information, refer to note 38 ‘New and amended accounting standards and interpretations’ in section 5.

External Auditor

The RAC manages the relationship with the External Auditor on behalf of the Board. It considers the reappointment of the External Auditor each year, as well as remuneration and other terms of engagement and makes a recommendation to the Board. There are no contractual obligations that restrict the RAC’s capacity to recommend a particular firm for appointment as auditor.

The lead audit engagement partners in both Australia and the United Kingdom have been rotated every five years. The current Australian audit engagement partner was appointed at the start of FY2015. The current UK audit engagement partner took formal responsibility at the start of FY2018 following a transition period.

Audit tender

Consistent with the UK and EU requirements in regard to audit firm tender and rotation, during the March 2017 quarter the Committee commenced a tender process for the appointment of a new External Auditor, as described on page 113 of the Annual Report 2017. In August 2017, the Board announced that it had selected EY, with the planned commencement date of 1 July 2019. This provides adequate time for EY to meet all relevant independence criteria before commencement of this appointment.

Compliance with the Competition and Markets Authority Order

BHP confirms that during FY2018 it was in compliance with the provisions of The Statutory Audit Services for Large Companies Market Investigation (Mandatory Use of Competitive Tender Processes and Audit Committee Responsibilities) Order 2014.

Evaluation of External Auditor and external audit process

The RAC evaluates the performance of the External Auditor during its term of appointment against specified criteria, including delivering value to shareholders and BHP, and also assesses the effectiveness of the external audit process. It does so through a range of means:

• the Committee considers the External Audit Plan, in particular to gain assurance that it is tailored to reflect changes in circumstances from the prior year;

• throughout the year, the Committee meets with the audit partners, particularly the lead Australian and UK audit engagement partners, without management present;

• following the completion of the audit, the Committee considers the quality of the External Auditor’s performance drawing on survey results. The survey is based on a two-way feedback model where the BHP and KPMG teams assess each other against a range of criteria. The criteria against which the BHP team evaluates KPMG’s performance include ethics and integrity, insight, service quality, communication and reporting, and responsiveness;

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• reviewing the terms of engagement of the External Auditor;

• discussing with the audit engagement partners the skills and experience of the broader audit team;

• reviewing audit quality inspection reports on KPMG published by the UK Financial Reporting Council in considering the effectiveness of the audit. The RAC discussed with KPMG the findings of the Audit Quality Review conducted by the UK’s Financial Reporting Council. The Committee is satisfied that the findings of the Audit Quality Review have been incorporated into KPMG’s audit processes as they relate to BHP;

• overseeing (and approving where relevant) non-audit services as described below.

The RAC also reviews the integrity, independence and objectivity of the External Auditor and assesses whether there is any element of the relationship that impairs, or appears to impair, the External Auditor’s judgement or independence. This review includes:

• confirming the External Auditor is, in its judgement, independent of BHP;

• obtaining from the External Auditor an account of all relationships between the External Auditor and BHP;

• monitoring the number of former employees of the External Auditor currently employed in senior positions within BHP;

• considering the various relationships between BHP and the External Auditor;

• determining whether the compensation of individuals employed by the External Auditor who conduct the audit is tied to the provision of non-audit services;

• reviewing the economic importance of BHP to the External Auditor.

The External Auditor also certifies its independence to the RAC.

Non-audit services

Although the External Auditor does provide some non-audit services, the objectivity and independence of the External Auditor are safeguarded through restrictions on the provision of these services. For example, certain types of non-audit services may be undertaken by the External Auditor only with the prior approval of the RAC (as described below), while other services may not be undertaken at all, including services where the External Auditor:

• may be required to audit its own work;

• participates in activities that would normally be undertaken by management;

• is remunerated through a ‘success fee’ structure;

• acts in an advocacy role for BHP.

The RAC has adopted a policy entitled ‘Provision of Audit and Other Services by the External Auditor’ covering the RAC’s pre-approval policies and procedures to maintain the independence of the External Auditor.

Our policy on Provision of Audit and Other Services by the External Auditor is available online at bhp.com/governance.

In addition to audit services, the External Auditor is permitted to provide other (non-audit) services that are not, and are not perceived to be, in conflict with the role of the External Auditor. In accordance with the requirements of the Exchange Act and guidance contained in Public Company Accounting Oversight Board (PCAOB) Release 2004-001, certain specific activities are listed in our detailed policy that have been ‘pre-approved’ by the RAC.

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The categories of ‘pre-approved’ services are as follows:

• Audit and audit-related services – work that constitutes the agreed scope of the statutory audit and includes the statutory audits of BHP and its entities (including interim reviews). This category also includes work that is reasonably related to the performance of an audit or review and is a logical extension of the audit or review scope. The RAC monitors the audit services engagements and if necessary approves any changes in terms and conditions resulting from changes in audit scope, Group structure or other relevant events.

• Other assurance services – work that is outside the required scope of the statutory audit but is consistent with the role of the external statutory auditor, is of an assurance or compliance nature and is work the External Auditor must or is best placed to undertake.

• Other services – work of an advisory nature that does not compromise the independence of the External Auditor.

Activities not listed specifically are therefore not ‘pre-approved’ and must be approved by the RAC prior to engagement, regardless of the dollar value involved. Additionally, any engagement for other services with a value over US$100,000, even if listed as a ‘pre-approved’ service, requires the approval of the RAC. All engagements for other services whether ‘pre-approved’ or not and regardless of the dollar value involved are reported quarterly to the RAC.

While not specifically prohibited by BHP’s policy, any proposed non-audit engagement of the External Auditor relating to internal control (such as a review of internal controls or assistance with implementing the regulatory requirements, including those of the Exchange Act) requires specific prior approval from the RAC. With the exception of the external audit of BHP’s Financial Statements, any engagement identified that contains an internal control-related element is not considered to be pre-approved. In addition, while the categories shown above include a list of certain pre-approved services, the use of the External Auditor to perform such services will always be subject to our overriding governance practices as articulated in the policy.

An exception can be made to the policy where it is in BHP’s interests and appropriate arrangements are put in place to ensure the integrity and independence of the External Auditor. Any such exception requires the specific prior approval of the RAC and must be reported to the Board. No exceptions were approved during the year ended 30 June 2018.

In addition, the RAC approved no services during the year ended 30 June 2018 pursuant to paragraph (c)(7)(i)(C) of Rule 2-01 of SEC Regulation S-X (provision of services other than audit).

Fees paid to BHP’s External Auditor during FY2018 for audit and other services were US$23.9 million, of which 75 per cent comprised audit fees, 22 per cent related to legislative requirements (including US Sarbanes-Oxley Act of 2002 as amended (SOX)) and three per cent was for other services. Details of the fees paid are set out in note 35 ‘Auditor’s remuneration’ in section 5.

Based on the review by the RAC, the Board is satisfied that the External Auditor is independent and that the incoming auditor is also independent.

Risk function

During FY2017, a review and benchmarking of the design of BHP’s Risk Management Framework to industry best practice and standards found that the Framework meets applicable legal and governance requirements in all relevant jurisdictions. The review confirmed that the Group has established a strong foundation in risk management and that the fundamental requirements of a risk management framework are in place.

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The review also identified that BHP’s risk approach could be enhanced by creating a dedicated global Risk function with full responsibility for the risk framework and end-to-end process. This new structure has been implemented, with the new function being led by a Chief Risk Officer. Risk professionals are co-located with the assets and functions. The new Risk function develops policies, procedures, tools, training materials and best practice methodologies, providing expert advice on the risk management framework with a focus on continuous improvement against a rapidly changing external environment.

Additional information about the effectiveness of risk management is set out below.

Internal Audit

The Internal Audit function is carried out by Internal Audit and Advisory (IAA). The role of IAA is to provide assurance as to whether risk management, internal control and governance processes are adequate and functioning. The Internal Audit function is independent of the External Auditor. The RAC evaluates and, if thought fit, approves the terms of reference of IAA, the staffing levels and its scope of work to ensure it is appropriate in light of the key risks we face. It also reviews and approves the annual internal audit plan and monitors and reviews the overall effectiveness of the internal audit activities.

The RAC also approves the appointment and dismissal of the Group Assurance Officer and assesses his or her performance, independence and objectivity. The position was held throughout the year by Kirsty Wallace. Ms Wallace reported directly to the RAC. During the period, functional oversight of IAA was provided by the Chief External Affairs Officer.

Effectiveness of systems of internal control and risk management (RAC and Board)

In delegating authority to the CEO, the Board has established CEO limits set out in the Board Governance Document. Limits on the CEO’s authority require the CEO to ensure there is a system of control in place for identifying and managing risk in BHP. Through the RAC, the Directors review the systems that have been established for this purpose and regularly review their effectiveness. These reviews include assessing whether processes continue to meet evolving external governance requirements.

The RAC oversees and reviews the internal controls and risk management systems. In undertaking this role, the RAC reviews the following:

• procedures for identifying material risks and controlling their impact on the Group, the operational effectiveness of these procedures;

• processes and systems for managing budgeting, forecasting and financial reporting;

• the Group’s strategy and standards in respect of insurance;

• the Group’s standards and procedures in respect of reporting of reserves and resources;

• the Group’s standards and procedures in respect of the closure and rehabilitation provision;

• standards and practices for detecting, reporting and preventing fraud, serious breaches of business conduct, and whistle-blowing procedures supporting reporting to the Committee;

• procedures for ensuring compliance with relevant regulatory and legal requirements;

• arrangements for the protection of the Group’s information and data systems and other non-physical assets;

• operational effectiveness of the Business RAC structures;

• overseeing the adequacy of the internal controls and allocation of responsibilities for monitoring internal financial controls.

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For more information on our approach to risk management, refer to sections 1.4.3 and 2.14. Section 1.6.4 includes a description of the material risks that could affect BHP, including, but not limited to, economic, environment and social sustainability risks to which the Group has a material exposure. Section 1.6.5 also provides an explanation of how those risks are managed.

As previously set out, during FY2017, benchmarking of the design of BHP’s Risk Management Framework to industry best practice and standards found that the Framework meets its legal and governance requirements in all relevant jurisdictions, and continues to be sound. Nonetheless, further refinements were made to the Framework, including the establishment of a separate Risk function. In addition, the Board conducted reviews of the effectiveness of BHP’s systems of risk management and internal controls for the financial year and up to the date of this Annual Report in accordance with the UK Corporate Governance Code, the Guidance on Risk Management, Internal Control and Related Financial and Business Reporting and the Corporate Governance Principles and Recommendations published by the Australian Securities Exchange (ASX) Corporate Governance Council (ASX Principles and Recommendations). These risk management and internal control reviews covered business conduct, compliance, financial, operational and sustainability.

During FY2018, management presented an assessment of the material business risks facing BHP and the level of effectiveness of risk management over the material business risks. The reviews were overseen by the RAC, with findings and recommendations reported to the Board. In addition to considering key risks facing BHP, the Board received an assessment of the effectiveness of internal controls over key risks identified through the work of the Board committees.

The Board is satisfied with the effectiveness of risk management and internal control systems.

Management’s assessment of internal control over financial reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act).

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and, even when determined to be effective, can only provide reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or the degree of compliance with the policies or procedures may deteriorate.

Under the supervision and with the participation of our management, including our CEO and CFO, the effectiveness of BHP’s internal control over financial reporting has been evaluated based on the framework and criteria established in Internal Controls – Integrated Framework (2013), issued by the Committee of the Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation, management has concluded that internal control over financial reporting was effective as at 30 June 2018. There were no material weaknesses in BHP’s internal controls over financial reporting identified by management as at 30 June 2018.

BHP has engaged our independent registered public accounting firms, KPMG and KPMG LLP, to issue an audit report on our internal control over financial reporting for inclusion in the Financial Statements section of the Annual Report and the Annual Report on Form 20-F as filed with the SEC.

There have been no changes in our internal control over financial reporting during FY2018 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

The CEO and CFO have certified to the Board that the Financial Statements for the full-year and half-year are founded on a sound system of risk management and internal control and the system is operating efficiently and effectively.

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During FY2018, the RAC reviewed our compliance with the obligations imposed by SOX, including evaluating and documenting internal controls as required by section 404 of SOX.

Management’s assessment of disclosure controls and procedures

Management, with the participation of our CEO and CFO, performed an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures as at 30 June 2018. Disclosure controls and procedures are designed to provide reasonable assurance that the material financial and non-financial information required to be disclosed by BHP, including in the reports that it files or submits under the Exchange Act, is recorded, processed, summarised and reported on a timely basis and that such information is accumulated and communicated to BHP’s management, including our CEO and CFO, as appropriate, to allow timely decisions regarding required disclosure. Based on the evaluation, management, including the CEO and CFO, has concluded that as at 30 June 2018, our disclosure controls and procedures are effective in providing that reasonable assurance.

There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives.

Further, in the design and evaluation of our disclosure controls and procedures, management was required to apply its judgement in evaluating the cost-benefit relationship of possible controls and procedures.

Committee assessment

Following the committee assessment, the RAC was satisfied that it had continued to meet its terms of reference in FY2018. The terms of reference were updated during the year to reflect the creation of a separate Risk function and certain minor administrative changes.

The terms of reference for the RAC are available online at bhp.com/governance.

2.13.2    Remuneration Committee Report

Role and focus

The role of the Remuneration Committee is to assist the Board in overseeing:

• the remuneration policy and its specific application to the CEO and other Key Management Personnel (those who have authority and responsibility for planning, directing and controlling the activities of the Group directly or indirectly), and its general application to all employees;

• the adoption of annual and longer-term incentive plans;

• the determination of levels of reward for the CEO and approval of reward for other Key Management Personnel;

• the annual evaluation of the performance of the CEO, by giving guidance to the Chairman;

• leaving entitlements;

• the preparation of the Remuneration Report for inclusion in the Annual Report;

• compliance with applicable legal and regulatory requirements associated with remuneration matters;

• the review, at least annually, of remuneration by gender.

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The Sustainability Committee and the Risk and Audit Committee assist the Remuneration Committee in determining appropriate HSEC and financial metrics, respectively, to be included in senior executive scorecards and in assessing performance against those measures.

The Remuneration Committee met twice during FY2018 and also considered some matters out of session. Information on meeting attendance by Committee members is included in the table below.

For full details of the Committee’s work on behalf of the Board, refer to the Remuneration Report in section 3.

Remuneration Committee members during the year

Name	Independent	Status	Attendance
Carolyn Hewson (Chairman)	Yes	Member for whole period	2/2
Malcolm Brinded	Yes	Member until 18 October 2017	1/1
Anita Frew	Yes	Member from 1 March 2018	1/1
Wayne Murdy	Yes	Member for whole period	2/2
Shriti Vadera	Yes	Member for whole period	2/2

Committee activities in FY2018

Remuneration policy review

• Link to strategy

• Alignment between pay and performance

Remuneration of the KMP and the Board

• Remuneration of CEO and other Key Management Personnel

• KPIs, performance levels, award outcomes

• Long-Term Incentive Plan sector peer group review

• Chairman and Non-executive Director fees

Other remuneration matters

• Shareplus, employee incentive outcomes

• Remuneration by gender

• Shareholder engagement

Other

• Induction, training and development program

• Board committee procedures, including closed sessions

Committee assessment

Following the committee assessment, the Remuneration Committee was satisfied that it had continued to meet its terms of reference in FY2018. Minor updates were made to the terms of reference during the year, largely to reflect administrative changes.

The terms of reference for the Remuneration Committee are available online at bhp.com/governance.

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2.13.3    Nomination and Governance Committee Report

Role and focus

The role of the Nomination and Governance Committee is to assist the Board in ensuring that the Board comprises individuals who are best able to discharge the responsibilities of a Director, having regard to the highest standards of governance, the strategic direction of BHP and the diversity aspirations of the Board. It does so by focusing on:

• the succession planning process for the Board and its committees, including the identification of suitable candidates for appointment to the Board taking into account the skills, experience, independence and knowledge required on the Board, as well as the attributes required of potential Directors;

• the succession planning process for the Chairman;

• the succession planning process for the CEO and periodic evaluation of the process;

• Board and Director performance evaluation, including evaluation of Directors seeking re-election prior to their endorsement by the Board as set out in sections 2.7 and 2.11;

• the provision of appropriate training and development opportunities for Directors;

• the independence of Non-executive Directors;

• the time required from Non-executive Directors;

• the assessment and, if appropriate, authorisation of situations of actual and potential conflict notified by Directors;

• BHP’s corporate governance practices.

For details on the Board succession planning process, refer to section 2.8.

The Nomination and Governance Committee met eight times during FY2018. Information on meeting attendance by Committee members is included in the table below. In addition to the regular business of the year, the Committee considered the appointments of Terry Bowen and John Mogford as Non-executive Directors and the retirements of Grant King and Malcolm Brinded, as set out in more detail below.

Board changes

Terry Bowen and John Mogford joined the Board on 1 October 2018. Jac Nasser and Grant King retired from the Board on 31 August 2017, and Malcolm Brinded retired from the Board on 18 October 2017. Further details in respect of each of these appointments and retirements are set out in the Annual Report 2017.

Wayne Murdy has decided to retire from the Board after the 2018 BHP Billiton Limited AGM.

Board policy on inclusion and diversity

Our Charter and the Our Requirements for Human Resources standard guide management on all aspects of human resource management, including inclusion and diversity. Underpinning the Our Requirements standards and supporting the achievement of diversity across BHP are principles and measurable objectives that define our approach to diversity and our focus on creating an inclusive work environment.

The Board and management believe that many facets of diversity are required in order to meet the corporate purpose as set out in section 2.8. Diversity is a core consideration in ensuring the Board and its committees have the right blend of perspectives so that the Board oversees BHP effectively for shareholders.

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The Board believes that critical mass is important for diversity, and diversity of all types remains a priority as the Board continues to be refreshed and renewed, as set out in section 2.8. This is in line with our aspirational goal to achieve gender balance across our workforce – and on our Board – by FY2025. We believe this will help create a more diverse, inclusive, empowered and connected workforce, underpinned by Our Charter values.

Part of the Board’s role is to consider and approve BHP’s measurable objectives for workforce diversity each financial year and to oversee our progress in achieving those objectives. BHP’s progress will continue to be disclosed in the Annual Report, along with the proportion of women in our workforce, in senior management positions and on the Board. For more information on inclusion and diversity at BHP, including our progress against our FY2018 measurable objectives and our employee profile more generally, refer to sections 1.7.2 and 1.7.3.

External recruitment specialists

The Committee retained the services of external recruitment specialists Heidrick & Struggles and JCA Group.

Nomination and Governance Committee members during the year

Name	Independent	Status	Attendance
Ken MacKenzie (Chairman)	Chairman of the Board	Member from 1 September 2017	5/5
Jac Nasser	Former Chairman of the Board	Member until 31 August 2017	3/3
Malcolm Broomhead	Yes	Member from 1 October 2017	4/4
Carolyn Hewson	Yes	Member for whole period	7/8 (1)
Shriti Vadera	Yes	Member for whole period	8/8

⁽¹⁾  Carolyn Hewson was unable to attend the meeting on 10 April due to a family illness.

Committee activities in FY2018

Succession planning processes

• Skills and experience matrix update

• Identification of suitable Non-executive Director candidates

• Committee composition

• Board and committee succession

• Search firm review and tender

Evaluation and training

• Board and Director performance evaluation

• Provision of appropriate training and development opportunities

• Induction

• Committee assessment

Corporate governance practices

• Independence of Non-executive Directors

• Authorisation of situations of actual or potential conflict

• Corporate Governance Statement

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Other governance matters

• Induction, training and development program

• Board committee procedures, including closed sessions

Committee assessment

Following the committee assessment, the Nomination and Governance Committee was satisfied that it had continued to meet its terms of reference in FY2018.

The terms of reference for the Nomination and Governance Committee are available online at bhp.com/governance.

2.13.4    Sustainability Committee Report

Role and focus

The role of the Sustainability Committee is to assist the Board in its oversight of the Group’s health, safety, environment and community (HSEC) performance and the adequacy of the Group’s HSEC Framework, and in relation to various other governance responsibilities related to HSE and Community.

The Group’s HSEC framework consists of:

• the CEO limits set out in the Board Governance Document. The Board Governance Document establishes the remit of the Board and delegates authority to the CEO, including in respect of the HSEC Management System, subject to CEO limits;

• the Sustainability Committee, which is responsible for assisting the Board in overseeing the adequacy of the Group’s HSEC Framework and HSEC Management System (among other things);

• the HSEC Management System, established by management in accordance with the CEO’s delegated authority. The HSEC Management System provides the processes, resources, structures and performance standards for the identification, management and reporting of HSEC risks and the investigation of any HSEC incidents;

• a robust and independent internal audit process overseen by the RAC, in accordance with its terms of reference;

• independent advice on HSEC matters, which may be requested by the Board and its Committees where deemed necessary in order to meet their respective obligations.

Our approach to sustainability is reflected in Our Charter, which defines our values, purpose and how we measure success, and in our sustainability performance targets, which define our public commitments to safety, health, environment and community. More information is available in our Sustainability Report 2018.

A copy of the Sustainability Report is available online at bhp.com.

The Committee provides oversight of the preparation and presentation of the Sustainability Report by management, and reviewed and recommended to the Board the approval of the Report for publication. The Sustainability Report identifies our targets for HSEC matters and our performance against those targets. Our targets rely on fact-based measurement and quality data, and reflect a desire to move BHP to a position of industry leadership.

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The Sustainability Committee met four times during FY2018. Information on meeting attendance by Committee members is included in the table below. In addition, the Committee met with the Forum on Corporate Responsibility and discussed a range of topics, including social licence to operate, corporate purpose and the Forum’s site visit to Port Hedland and engagement with Iron Ore employees and members of the Port Hedland community.

Members of the Sustainability Committee also visited a number of operated and non-operated sites during FY2018 as part of a formal program of committee visits. These included Olympic Dam, closed sites in Arizona and Samarco. During these site visits, Committee members received briefings on relevant HSEC matters and the management of material HSEC risks, and met with key personnel. These visits offer access to a diverse cross-section of the workforce from frontline through to the leadership team, including, where possible, risk and control owners. This provides Directors with a sense of the culture and the risk management processes in place at each site. Some of the visits, such as Samarco and closed sites, included engagement with local communities.

In addition, as part of either the induction process or Chairman’s visits, members of the Committee also visited Petroleum in Houston, Marketing, Supply and Technology in Singapore and Western Australia Iron Ore.

The Sustainability Committee continued to assist the Board in its oversight of HSEC issues and performance during FY2018. For a summary of the main areas discussed, refer below.

Sustainability Committee members during the year

Name	Independent	Status	Attendance
Malcolm Broomhead (Chairman) (1)	Yes	Member for whole period	4/4
Malcolm Brinded	Yes	Member until 18 October 2017	2/2
Grant King	Yes	Member from 1 August 2017 until 31 August 2017	1/1
Ken MacKenzie	Yes	Member for whole period	4/4
John Mogford	Yes	Member from 1 November 2017	2/2

⁽¹⁾  Malcolm Brinded was Chairman of the Committee until 18 October 2017. Malcolm Broomhead assumed the role of Chairman with effect from 19 October 2017.

Committee activities in FY2018

Assurance and adequacy of HSEC framework and HSEC management system

• Key HSEC risks, including process safety, security and high occupancy vehicles

• Audit planning and reporting in relation to HSEC risks and processes

• Rehabilitation update

• Fatality risk management project

• Contractor management

Compliance and reporting

• Compliance with HSEC legal and regulatory requirements

• Updates on key legal and regulatory changes

• Sustainability Report, including consideration of processes for preparation and assurance provided by KPMG

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Performance

• Performance of BHP in relation to HSEC matters

• Considering proposed HSEC KPIs for KMP scorecard and considering performance against such KPIs

• Monitoring against the FY2018–FY2022 HSEC performance targets

• Updates on Samarco remediation and Renova Foundation

• Field leadership

• Goonyella fatality ICAM and Permian Basin fatality ICAM

• Cerrejón (non-operated joint venture) fatality ICAM

• Performance and key issues on sustainable development and community relations, including community issues update

• Water stewardship strategy update

• Global priority on social licence

• Non-operated joint venture HSE risk management update

• Climate change updates

Other governance matters

• Induction, training and development

• HSEC emerging trends

• Site visits and site visit reports to Board

• Board committee procedures including closed sessions

Sustainable development governance

Our approach to HSEC and sustainable development governance is characterised by:

(1) the Sustainability Committee assisting the Board in its oversight of material HSEC matters and risks across BHP, including seeking continuous improvement and policy advocacy as applicable;

(2) management having primary responsibility for the design and implementation of an effective HSEC Management System;

(3) management having accountability for HSEC performance;

(4) the HSE function and Community sub-function providing advice and guidance directly to the Sustainability Committee and the Board;

(5) the Board, Sustainability Committee and management seeking input and insight from external experts, such as the BHP Forum on Corporate Responsibility; and

(6) clear links between executive remuneration and HSEC performance.

The key areas of focus for the Committee, management and the HSE function and Community sub-function are outlined in the Sustainability Report 2018.

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Climate change

Climate change is treated as a Board-level governance issue, with the Sustainability Committee playing a key supporting role. The Committee work during FY2018 included receiving updates on BHP’s climate change target, carbon capture and storage investment and advocacy, low emissions technology, portfolio analysis and disclosure, advocacy and positioning, climate risks and potential implications for BHP, including physical risks and transition risks. In addition, the Committee received an update on product stewardship and Scope 3 emissions, both of which are of major interest to investors. The Product stewardship project aims to improve identification, assessment and management of climate change risks in our value chain and encompasses the measurement and disclosure of Scope 3 emissions and identification of opportunities to work with our customers to reduce their emissions. For more information on our climate change position and how we consider the impacts on our portfolio, refer to section 1.9.8.

Social investment

We also continued to monitor our progress in relation to our social investment and met our target for investments in community programs, with such investments comprising cash towards community development programs and administrative costs. This was the equivalent of not less than one per cent of our pre-tax profit, calculated on the average of the previous three years’ pre-tax profit. Our social investment performance in FY2018 saw BHP deliver projects with a continued focus on good governance, human capability and social inclusion and environment. The total investment of US$77.05 million includes US$7.16 million on community contributions at our non-operated joint ventures, and US$1.54 million to facilitate the operation of the BHP Billiton Foundation.

HSEC matters and remuneration

In order to link HSEC matters to remuneration, 25 per cent of the short-term incentive opportunity for Key Management Personnel was based on HSEC performance during FY2018. The Sustainability Committee assists the Remuneration Committee in determining appropriate HSEC metrics to be included in the KMP scorecard and also assists in relation to assessment of performance against those measures. The Board believes this method of assessment is transparent, rigorous and balanced, and provides an appropriate, objective and comprehensive assessment of performance. For more information on the metrics and their assessment, refer to the Remuneration Report in section 3.

Committee assessment

Following the committee assessment, the Sustainability Committee was satisfied that it had continued to meet its terms of reference in FY2018. Minor updates were made to the terms of reference during the year, largely to reflect administrative changes.

The terms of reference for the Sustainability Committee are available online at bhp.com/governance.

2.13.5    Capital Allocation Working Group

The processes in place for submission of capital expenditure proposals to the Board and for subsequent monitoring and evaluation of approved projects are kept under review. Over the past four years, the amount of capital required annually by the Group has been reduced from over US$20 billion in FY2013 to less than US$8 billion in FY2019 and FY2020.

Although our processes are sound, in line with our approach of ongoing improvement, we established a Capital Allocation Working Group in FY2018 to assist the Board in considering the following:

• the process and requirements for the presentation of capital expenditure decisions to the Board (Board Capital Process); and

• a capital expenditure monitoring and evaluation framework.

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The objectives of the Board Capital Process include improving the Board’s understanding of capital expenditure proposals as they are developed, the variables, changes to metrics and scenarios that may affect the value of capital expenditure proposals or the risk profile, and enabling the Board to assess these proposals within the context of the Capital Allocation Framework. These improvements are designed to facilitate more effective and informed decision-making.

Composition

The Working Group consisted of seven members: Malcolm Broomhead (Working Group Chairman), the Chairman of the Board, Lindsay Maxsted, Terry Bowen, the Chief Executive Officer, the Chief Financial Officer and the President, Minerals Americas. Given the terms of reference, members of senior management, including the Group Portfolio & Strategy Development Officer and the Group Company Secretary, supported the Working Group and attended meetings. The Chairman of the Working Group provided a report to the Board following each meeting of the Working Group. With the review now completed and enhancements approved by the Board and implemented, the Working Group has been disbanded.

Enhancements

Enhancements implemented include:

• the approach to prioritisation and comparison of capital proposals and transactions in the portfolio;

• the Board receiving additional and more project-specific and market outlook information earlier in the study phases, in order to understand the project early in the process and provide feedback, as well as information concerning changes in the risk and reward profile as the project progresses;

• the content in relation to the reporting to the Board on the performance of capital projects;

• the portfolio and project metrics used by the Board in assessing capital expenditure proposals;

• additional reporting in relation to all capital expenditure, and enhancements to reporting on Post Investment Reviews.

2.14    Risk management governance structure

We believe the identification and management of risk are central to achieving the corporate purpose of creating long-term shareholder value. Our approach to risk is set out in section 1.4.3.

The principal aim of BHP’s risk management governance structure and internal control systems is to identify, evaluate and manage business risks with a view to enhancing the value of shareholders’ investments and safeguarding assets. As previously set out, in FY2018, we established a global Risk function headed by the Chief Risk Officer. This function has allowed enhancements to be made, including developments in relation to the risk framework, culture, training, competencies and reporting, incorporating Board-level reporting.

The Board reviews and considers BHP’s risk profile each year, which covers both operational and strategic risks. Our material risk profile is assessed to ensure it supports the achievement of BHP’s strategy while seeking to maintain a strong balance sheet. The Board’s approach to investment decision-making, portfolio management and the consideration of risk in that process is set out in sections 1.4.1 and 1.6, and includes a broad range of scenarios to assess our portfolio. This process allows us to be able to adjust the shape of our portfolio to match energy and commodity demand and meet society’s expectations, while maximising shareholder returns.

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The Risk and Audit Committee (RAC) assists the Board with the oversight of risk management, although the Board retains overall accountability for BHP’s risk profile. In addition, the Board specifically requires the CEO to implement a system of control for identifying and managing risk. The Directors, through the RAC, review the systems that have been established for this purpose, regularly review the effectiveness of those systems and monitor that necessary actions have been taken to remedy any significant failings or weaknesses identified from that review. The RAC regularly reports to the Board to enable the Board to review our risk framework.

The RAC has established review processes for the nature and extent of material risks taken in achieving our corporate purpose. These processes include the application of materiality and tolerance criteria to determine and assess material risks. Materiality criteria include maximum foreseeable loss and residual risk thresholds and are set at the Group level. Tolerance criteria additionally assess the control effectiveness of material risks.

The diagram below outlines the risk reporting process.

Management has put in place a number of key policies, processes, performance requirements and controls to provide assurance to the Board and the RAC as to the integrity of our reporting and effectiveness of our systems of internal control and risk management. Some of the more significant internal control systems include Board and management committees, Business RACs and internal audit.

Business Risk and Audit committees

The Business RACs assist the RAC to monitor BHP’s obligations in relation to financial reporting, internal control structure, risk management processes and the internal and external audit functions.

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Board committees

Directors also monitor risks and controls through the RAC, the Remuneration Committee and the Sustainability Committee.

Management committees

Management committees also perform roles in relation to risk and control. Strategic risks and opportunities arising from changes in our business environment are regularly reviewed by the ELT and discussed by the Board. The Financial Risk Management Committee (FRMC) reviews the effectiveness of internal controls relating to commodity price risk, counterparty credit risk, currency risk, financing risk, interest rate risk and insurance. Minutes of the FRMC meetings are provided to the Board through the RAC. The Investment Review Committee (IRC) provides oversight for investment processes across BHP and coordinates the investment toll-gating process for major investments. Reports are made to the Board on findings by the IRC in relation to major capital projects. The Disclosure Committee oversees BHP’s compliance with securities dealing and continuous and periodic disclosure requirements, including reviewing information that may require disclosure through stock exchanges and overseeing processes to ensure information disclosed is timely, accurate and complete.

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2.15    Management

Below the level of the Board, key management decisions are made by the CEO, the ELT, other management committees and individual members of management to whom authority has been delegated.

The diagram below describes the responsibilities of the CEO and four key management committees.

CEO and management committee responsibilities

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Performance evaluation for executives

The performance of executives and other senior employees is reviewed on an annual basis. For the members of the ELT, this review includes their contribution, engagement and interaction at Board level. The annual performance review process that we employ considers the performance of executives against criteria designed to capture both ‘what’ is achieved and ‘how’ it is achieved. All performance assessments of executives consider how effective they have been in undertaking their role; what they have achieved against their specified key performance indicators; how they match up to the behaviours prescribed in our leadership model; and how those behaviours align with Our Charter values. The assessment is therefore holistic and balances absolute achievement with the way performance has been delivered. Progression within BHP is driven equally by personal leadership behaviours and capability to produce excellent results.

A performance evaluation as outlined above was conducted for all members of the ELT during FY2018. For the CEO, the performance evaluation was led by the Chairman of the Board on behalf of all the Non-executive Directors, drawing on guidance from the Remuneration Committee.

2.16    Our conduct

Our Charter and Our Code of Conduct

Our Charter is central to our business. It articulates the values we uphold, our strategy and how we measure success.

Our Code of Conduct (Our Code) is based on Our Charter values. Our Code sets out standards of behaviour for our people when using BHP resources, in their dealings with governments and communities, third parties, and each other. Our Code describes the behaviours expected to support a safe, respectful and a legally compliant working environment.

Working with integrity is a condition of employment with BHP and in some cases a contractual obligation of many of our contractors and suppliers. All our people are required to undertake annual training on Our Code to promote awareness and understanding of the behaviours expected of them. Demonstration of the values described in Our Charter and Our Code is part of the annual employee performance review process.

Our Code is accessible to all our people and external stakeholders online at bhp.com.

BHP’s EthicsPoint

We have mechanisms in place for anyone to raise a report if they feel Our Code has been breached. Employees and contractors can raise reports through line leaders or Human Resources. Processes for the community to report potential breaches of Our Code are available at the asset level.

Reports can also be raised by anyone through EthicsPoint, a 24-hour, multilingual service for confidential reporting of potential misconduct. This service is accessible online or via the phone and is managed by an independent third party. Reports can be raised anonymously.

We acknowledge, investigate as appropriate and document all matters reported. Where matters are investigated and substantiated, we take appropriate remedial actions, advise the reporter (where possible) and document the outcome.

BHP does not tolerate any form of retaliation against anyone for speaking up about potential misconduct or participating in an investigation.

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Political donations

We maintain a position of impartiality with respect to party politics and do not make political contributions/donations for political purposes to any political party, politician, elected official or candidate for public office. We do, however, contribute to the public debate of policy issues that may affect BHP in the countries in which we operate. As explained in the Directors’ Report, the Australian Electoral Commission (AEC) disclosure requirements are broad such that amounts that are not political donations can be reportable for AEC purposes. For example, where a political party or organisation owns shares in BHP, the AEC filing requires the political party or organisation to disclose the dividend payments received for their shareholding.

2.17    Market disclosure

We are committed to maintaining the highest standards of disclosure, ensuring that all investors and potential investors have the same access to high-quality, relevant information in an accessible and timely manner to assist them in making informed decisions. The Disclosure Committee manages our compliance with market disclosure obligations and is responsible for implementing reporting processes and controls and setting guidelines for the release of information. As part of our commitment to continuous improvement, we continue to ensure alignment with best practice as it develops in the jurisdictions in which BHP is listed.

Disclosure officers have been appointed in BHP’s asset groups, Marketing and Supply, and functions. These officers are responsible for identifying and providing the Disclosure Committee with referral information about the activities of the asset or functional areas using disclosure guidelines developed by the Committee. The Committee then makes the decision whether a particular piece of information is material and therefore needs to be disclosed to the market.

To safeguard the effective dissemination of information, we have developed the Our Requirements for market disclosure standard, which outlines how we identify and distribute information to shareholders and market participants.

A copy of the market disclosure and communications document is available online at bhp.com/governance.

Copies of announcements to the stock exchanges on which BHP is listed, investor briefings, Financial Statements, the Annual Report and other relevant information can be found online at bhp.com. Any person wishing to receive advice by email of news releases can subscribe at bhp.com.

2.18    Remuneration

Details of our remuneration policies and practices, and the remuneration paid to the Directors (Executive and Non-executive) and other members of the KMP, are set out in the Remuneration Report in section 3.

2.19    Directors’ share ownership

Non-executive Directors have agreed to apply at least 25 per cent of their remuneration (base fees plus committee fees) to the purchase of BHP shares until they achieve a shareholding equivalent in value to one year’s remuneration (base fees plus committee fees). Thereafter, they must maintain at least that level of shareholding throughout their tenure. All dealings by Directors are subject to the Our Requirements for Securities Dealing standard and are reported to the Board and to the stock exchanges.

Information on our policy governing the use of hedging arrangements over shares in BHP by Directors and other members of the KMP is set out in section 3.3.19.

Details of the shares held by Directors are set out in section 3.3.18.

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2.20    Conformance with corporate governance standards

Our compliance with the governance standards in our home jurisdictions of Australia and the United Kingdom, and with the governance requirements that apply to us as a result of our New York Stock Exchange (NYSE) listing and our registration with the SEC in the United States, is summarised in this Corporate Governance Statement, the Remuneration Report, the Directors’ Report and the Financial Statements.

The Listing Rules and the Disclosure and Transparency Rules of the UK Financial Conduct Authority require companies listed in the United Kingdom to report how they have applied the Main Principles and the extent to which they have complied with the provisions of the UK Corporate Governance Code (UK Code), and explain the reasons for any non-compliance. The UK Code is available online at frc.org.uk/Our-Work/Corporate-Governance-Reporting/Corporate-governance.aspx.

The Listing Rules of the ASX require ASX-listed companies to report on the extent to which they meet the ASX Principles and Recommendations and explain the reasons for any non-compliance. The ASX Principles and Recommendations are available online at asx.com.au/regulation/corporate-governance-council.htm.

Both the UK Code and the ASX Principles and Recommendations require the Board to consider the application of the relevant corporate governance principles, while recognising that departures from those principles are appropriate in some circumstances. We have applied the Main Principles and complied with the provisions set out in the UK Code and with the ASX Principles and Recommendations during the financial period, with no exceptions.

Appendix 4G, summarising our compliance with the ASX Principles and Recommendations is available online at bhp.com/governance.

BHP Billiton Limited and BHP Billiton Plc are registrants with the SEC in the United States. Each company is classified as a foreign private issuer and each has American Depositary Shares listed on the NYSE.

We have reviewed the governance requirements applicable to foreign private issuers under SOX, including the rules promulgated by the SEC and the rules of the NYSE, and are satisfied that we comply with those requirements.

Section 303A of the NYSE-Listed Company Manual contains a broad regime of corporate governance requirements for NYSE-listed companies. Under the NYSE rules, foreign private issuers, such as BHP, are permitted to follow home country practice in lieu of the requirements of Section 303A, except for the rule relating to compliance with Rule 10A-3 of the Exchange Act (audit committee independence) and certain notification provisions contained in Section 303A of the Listed Company Manual. Section 303A.11 of the Listed Company Manual, however, requires us to disclose any significant ways in which our corporate governance practices differ from those followed by US companies under the NYSE corporate governance standards. After a comparison of our corporate governance practices with the requirements of Section 303A of the Listed Company Manual followed by US companies, the following significant difference was identified:

1 Rule 10A-3 of the Exchange Act requires NYSE-listed companies to ensure their audit committees are directly responsible for the appointment, compensation, retention and oversight of the work of the External Auditor unless the company’s governing law or documents or other home country legal requirements require or permit shareholders to ultimately vote on or approve these matters. While the RAC is directly responsible for remuneration and oversight of the External Auditor, the ultimate responsibility for appointment and retention of the External Auditor rests with our shareholders, in accordance with UK law and our constitutional documents. The RAC does, however, make recommendations to the Board on these matters, which are in turn reported to shareholders.

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While the Board is satisfied with its level of compliance with the governance requirements in Australia, the United Kingdom and the United States, it recognises that practices and procedures can always be improved and there is merit in continuously reviewing its own standards against those in a variety of jurisdictions. The Board’s program of review will continue throughout the year ahead.

2.21    Additional UK disclosure

The information specified in the UK Financial Conduct Authority Disclosure Guidance and Transparency Rules, DTR 7.2.6, is located elsewhere in this Annual Report. The Directors’ Report in section 4 provides cross-references to where the information is located.

This Corporate Governance Statement was current, and approved by the Board, on 6 September 2018 and signed on its behalf by:

Ken MacKenzie

Chairman

6 September 2018

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3    Remuneration Report

In this section

This Remuneration Report describes the remuneration policies, practices, outcomes and governance for the KMP of BHP.

BHP’s DLC structure means that we are subject to remuneration disclosure requirements in both the United Kingdom and Australia. This results in some complexity in our disclosures, as there are some key differences in the requirements and the information that must be disclosed. For example, UK requirements give shareholders the right to a binding vote on remuneration policy every three years, and as a result, the remuneration policy needs to be described in a separate section in the Remuneration Report. Our remuneration policy is set out in section 3.2. In Australia, BHP is required to make certain disclosures for KMP as defined by the Australian Corporations Act 2001, Australian Accounting Standards and IFRS.

The UK requirements focus on the remuneration of executive and non-executive directors. At BHP, this is our Board, including the CEO, who is our sole Executive Director. In contrast, the Australian requirements focus on the remuneration of KMP, defined as those who have authority and responsibility for planning, directing and controlling the activities of the Group directly or indirectly. KMP includes the Board, as well as certain members of our senior executive team.

Consistent with BHP’s continuing efforts to simplify the Company’s activities, the OMC was dissolved during FY2018. As a consequence, the Committee has re-examined the classification of KMP for FY2018 to determine which persons have the authority and responsibility for planning, directing and controlling the activities of BHP. After due consideration, the Committee has determined the KMP for FY2018 comprised: all Non-executive Directors, the CEO, the Chief Financial Officer, the President Operations, Minerals Australia, the President Operations, Minerals Americas, and the President Operations, Petroleum.

The following individuals have held their positions and were KMP for the whole of FY2018, unless stated otherwise:

• CEO and Executive Director, Andrew Mackenzie;

• Non-executive Directors – see section 3.3.11 for details of the Non-executive Directors, including dates of appointment or cessation (where relevant);

• Other Executive KMP, as set out in the table below.

Name	Title
Peter Beaven	Chief Financial Officer
Mike Henry	President Operations, Minerals Australia
Daniel Malchuk	President Operations, Minerals Americas
Steve Pastor	President Operations, Petroleum

Contents
3.1	Annual statement by the Remuneration Committee Chairman
3.2	Remuneration policy report
	Remuneration policy for the Executive Director
	Remuneration policy for Non-executive Directors
3.3	Annual report on remuneration
	Remuneration for the Executive Director (the CEO)
	Remuneration for other Executive KMP (excluding the CEO)
	Remuneration for Non-executive Directors
	Remuneration governance
	Other statutory disclosures

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Abbreviation	Item
AASB	Australian Accounting Standards Board
AGM	Annual General Meeting
CEO	Chief Executive Officer
DEP	Dividend Equivalent Payment
DLC	Dual Listed Company
ELT	Executive Leadership Team
GSTIP	Group Short-Term Incentive Plan
HSEC	Health, Safety, Environment and Community
IFRS	International Financial Reporting Standards
KMP	Key Management Personnel
KPI	Key Performance Indicator
LTI	Long-Term Incentive
LTIP	Long-Term Incentive Plan
MAP	Management Award Plan
MSR	Minimum Shareholding Requirement
OMC	Operations Management Committee
STI	Short-Term Incentive
STIP	Short-Term Incentive Plan
TRIF	Total Recordable Injury Frequency
TSR	Total Shareholder Return
UAP	Underlying Attributable Profit

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3.1    Annual statement by the Remuneration Committee Chairman

Dear Shareholders,

I am pleased to introduce BHP’s Remuneration Report for the financial year to 30 June 2018. During the year, the Committee has continued its work to achieve remuneration outcomes that fairly reflect the performance of BHP, its businesses and individuals. FY2018 has seen continued improvement in performance in comparison with recent years, and the remuneration outcomes for FY2018 reflect this.

The Board and Committee believe our remuneration policy has served stakeholders well over prior years, a view supported by discussions with shareholders and reflected in the voting outcomes at our AGMs. However, we also believe it is appropriate we remain open to arrangements that differ from ours, provided that they support the attraction and motivation of talented executives and, at the same time, align business performance and remuneration outcomes.

Link to strategy

Our Charter sets out our values, placing health and safety first, upon which the Remuneration Committee places great weight in the determination of performance-based remuneration outcomes for BHP executives. Our Charter also sets out our purpose, our strategy and how we measure success. The Committee is guided by Our Charter and aims to support our executives in taking a long-term approach to decision-making in order to build a sustainable and value-adding business.

Our approach

Our policy and approach to remuneration remains unchanged; however, we continue to strive for simplification in our programs. We were pleased to again receive strong support for our remuneration policy at the 2017 AGMs, with over 97 per cent voting ‘for’ the Remuneration Report, and over 96 per cent support in each of the prior five years. The Committee and the Board continue to incorporate shareholder feedback into our deliberations on pay to ensure it supports the Company’s strategy.

The Committee strives to implement the remuneration policy in a considered way. The exercise of reasonable downward discretion has been a feature of BHP’s approach over many years where the status quo or a formulaic outcome does not align with the overall shareholder experience, and this remains unchanged. As a result, remuneration outcomes for our executives continue to appropriately reflect Company, business and individual performance.

We are aware of various proposals put forward by some shareholders and other groups to consider alternative remuneration arrangements, and while there is not yet a fully aligned view on the way forward, positive steps have been observed in the last 12 months. We will continue to monitor the debate, as our shareholders would expect. We are keen to consider any alternate arrangements that simplify remuneration, drive a balanced short- and long-term focus, align outcomes and business performance, limit the potential for extreme and / or excessive outcomes, and yet still deliver on the primary purpose: to attract, retain and appropriately reward talented executives. We will continue to have discussions with our shareholders and assess these matters.

Remuneration outcomes for the CEO

Since his appointment as CEO in 2013, Andrew Mackenzie has not received a base salary increase and, after review in 2018, the Committee has again determined his salary will remain unchanged at US$1.700 million per annum. In addition, the other components of his total target remuneration (pension contributions, benefits and short-term and long-term incentive targets) also remain unchanged since 2013. Mr Mackenzie is BHP’s only Executive Director.

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Mr Mackenzie’s annual STI is focussed on motivating high levels of performance during the financial year and is at-risk. The target level of STI is worth 160 per cent of base salary but, importantly, there is a significant amount of stretch incorporated into the levels of performance required for a ‘target’ outcome. The maximum STI is worth 240 per cent of base salary but is only realisable in circumstances of significant outperformance. The minimum STI outcome is zero.

The scorecard against which Mr Mackenzie’s short-term performance is assessed comprises stretching performance measures, including HSEC, financial and individual performance elements. For FY2018, the Remuneration Committee has assessed Mr Mackenzie’s performance and determined an STI outcome of 90 per cent against the target of 100 per cent (which represents an outcome of 60 per cent against the maximum STI opportunity available to him or 144 per cent of base salary).

This outcome took into account HSEC performance, which primarily reflected the tragic fatalities that occurred at the Goonyella Riverside mine in August 2017 and at our Permian Basin Shale operations in November 2017, with the Committee, after taking advice from the Sustainability Committee, giving the Group’s safety performance the greatest weighting in the HSEC category.

Controllable financial performance was below the stretching financial target set at the commencement of the year, mainly due to variable production performance across the Group, with overall volumes of coal, iron ore and copper being lower than expectations, partly offset by higher than expected production of petroleum products.

The Committee also considered the CEO’s strong performance against individual objectives, including significant work to finalise the divestment of Onshore US assets, the Board approvals of the Spence copper growth option and South Flank iron ore project, a continued strong focus on safety and productivity across the Company, progress on BHP’s Capital Allocation Framework, and further advancement against BHP’s inclusion and diversity objectives.

Mr Mackenzie’s LTI is also at-risk, and forms an important part of recognising long-term performance, including the impacts of long-dated capital allocation and portfolio decisions. In relation to the LTI awards granted in 2013, BHP’s TSR performance was negative 9.3 per cent over the five-year period from 1 July 2013 to 30 June 2018. This is below the weighted median TSR of peer companies of positive 9.6 per cent and below the TSR of the MSCI World index of positive 67.6 per cent. This level of performance results in zero vesting for the 2013 LTIP awards, and accordingly the awards have lapsed.

Overall, Mr Mackenzie’s actual total remuneration for FY2018 was US$4.657 million, compared with US$4.554 million for FY2017, with the slight increase due to a marginally higher STI outcome this year compared to FY2017. The LTI outcome was zero in both years.

In line with the approach for Mr Mackenzie, the base salaries and total target remuneration packages for all other Executive KMP will also be held constant in FY2019.

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FY2018 CEO remuneration

FY2019 CEO remuneration

Fixed remuneration	STI	LTI
•   Base salary of US$1.700 million per annum. •   Pension contributions of 25 per cent of base salary. •   No change to either base salary or pension contribution for FY2019.	•   Target STI of 160 per cent of base salary (maximum 240 per cent of base salary). •   No change to either target or maximum percentages for FY2019. •   Three performance categories: –   HSEC – 25 per cent –   Financial – 45 per cent –   Individual performance – 30 per cent.	•   The normal LTI grant is based on a face value of 400 per cent of base salary. •   Our LTI awards have rigorous relative TSR performance hurdles measured over five years.

Remuneration outcomes for the Chairman and Non-executive Directors

Fee levels for the Chairman and Non-executive Directors are reviewed annually, including benchmarking against peer companies. No changes to the Chairman’s fee will be made for FY2019. This follows a review in 2017, where a decision was made to reduce the Chairman’s annual fee by approximately eight per cent from US$0.960 million to US$0.880 million with effect from 1 July 2017, which followed an earlier reduction, effective 1 July 2015, of approximately 13 per cent from US$1.100 million to US$0.960 million.

Base fee levels for Non-executive Directors will also remain unchanged, after they were also reduced effective 1 July 2015 by approximately six per cent, from US$0.170 million to US$0.160 million per annum. Prior to the above reductions in fee levels for the Chairman and Non-executive Directors, their fees had remained unchanged since 2011.

In recognition of the increasing workload of BHP’s Nomination and Governance Committee, a fee for members of that Committee was introduced with effect from 1 July 2018. The fee is US$18,000 per annum. There is no fee for the role of Chairman of the Nomination and Governance Committee as the Group Chairman fills that role and his fee is all-inclusive.

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Summary

The remuneration outcomes for FY2018 reflect an appropriate alignment between pay and performance during the year. We remain confident our philosophy, framework and remuneration policy can continue to support long-term value creation; however, we continue to look for opportunities to improve our approach. We look forward to ongoing dialogue with, and the support of, our shareholders, and welcome your feedback and comments on any aspect of this Report.

Carolyn Hewson

Chairman, Remuneration Committee

6 September 2018

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3.2    Remuneration policy report

BHP has an overarching remuneration policy that guides the Remuneration Committee’s decisions. Under UK legislation, shareholders have the opportunity to vote on our remuneration policy every three years, with binding effect in regard to the Directors (including the CEO). Our remuneration policy, which was approved by shareholders at the 2017 AGMs, has not changed and is repeated below. Under Australian legislation, shareholders also have the opportunity to vote on our remuneration policy, in conjunction with the broader Remuneration Report, each year at the AGMs as it applies to all KMP under a non-binding advisory vote.

3.2.1    Framework

BHP’s remuneration policy is designed to reward and recognise the delivery of our strategy, promote long-term success, align management and shareholder interests and encourage behaviours to be aligned to the values in Our Charter, as set out in the framework below.

Strategic driver	Remuneration principles	Mechanisms
Productivity: operational excellence	•  Provide competitive rewards to attract and retain highly skilled executives. •  Reflect the level of responsibility for delivering business strategy and results. •  Stretching performance targets.	•  Salary and benefits positioned competitively against key global markets and peer comparator companies. •  STIP and LITP performance measures support operational excellence, risk management and strategy execution.
Sustainability: long-term growth and success	•  Balance performance and risk. •  Significant portion of pay at-risk. •  Encourage long-term, sustainable growth aligned to the interests of shareholders.	•  Sustainable HSEC and financial performance measures are built into incentive plans. •  STIP awards delivered half in cash and half in deferred equity. •  Long-term strategic plans and market expectations are taken into account when setting performance criteria and goals. •  Five-year performance period of LTI and use of relative TSR performance condition.
Corporate planning: shareholder value creation	•  Align performance-related pay to delivery of shareholder value. •  Ensure appropriate executive, Non-executive Director and management shareholdings.	•  Retention through long-term share exposure over five-year performance period. •  Stretch goals, balance business objectives and market conditions, and align performance and shareholder experience. •  Relative TSR performance condition. •  Prohibition on hedging of incentive instruments. •  Significant MSRs.

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Strategic driver	Remuneration principles	Mechanisms
Capital management: capital discipline and governance	•  Ensure rewards are appropriate for actual performance and avoid windfalls •  Control cost to shareholders by paying competitive but not excessive remuneration	•  Annual review of remuneration against relevant markets. •  Board discretion to reduce incentive outcomes. •  Deferred STI equity component. •  Malus and clawback provisions. •  Severance payments limited to contractual agreements.
Our Charter values: Sustainability, Integrity, Respect, Performance, Simplicity, Accountability

3.2.2    How remuneration policy is set

The Remuneration Committee sets the remuneration policy for the CEO and other Executive KMP based on the principles and framework outlined above. The Committee is briefed on and considers prevailing market conditions, the competitive environment and the positioning and relativities of pay and employment conditions across the wider BHP workforce. The Committee takes into account the annual base salary increases for our employee population when determining any change in the CEO’s base salary. Salary increases in Australia, where the CEO is located, are particularly relevant, as they reflect the local economic conditions.

Although BHP does not consult directly with employees on CEO and other Executive KMP remuneration, the Group conducts regular employee engagement surveys that give employees an opportunity to provide feedback on a wide range of employee matters. Further, many employees are ordinary shareholders through our all-employee share purchase plan, Shareplus, and therefore have the opportunity to vote on AGM resolutions.

As part of the Board’s commitment to good governance, the Committee also considers shareholder views when setting the remuneration policy for the CEO and other Executive KMP. We are committed to engaging and communicating with shareholders regularly and, as our shareholders are spread across the globe, we are proactive with our engagement on remuneration and governance matters with institutional shareholders and investor representative organisations. Feedback from shareholders and investors is shared with, and used as input into decision-making by, the Board and Remuneration Committee in respect of our remuneration policy and its application. The Committee considers that this approach provides a robust mechanism to ensure Directors are aware of matters raised, have a good understanding of current shareholder views, and can formulate policy and make decisions as appropriate. We encourage shareholders to always make their views known to us by directly contacting our Investor Relations team (contact details available on our website at bhp.com).

Remuneration policy for the Executive Director

This section only refers to the remuneration policy for our CEO, who is our sole Executive Director. If any other executive were to be appointed an Executive Director, this remuneration policy would apply to that new role. The principles that underpin the remuneration policy for the CEO are the same as those that apply to other employees, although the CEO’s arrangements have a greater emphasis on, and a higher proportion of remuneration in the form of, performance-related variable pay. Similarly, the performance measures used to determine STI outcomes for the CEO and all other employees are linked to the delivery of our strategy and behaviours that are aligned to the values in Our Charter.

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3.2.3    Components of remuneration

The following table shows the components of total remuneration, the link to strategy, the applicable operation and performance frameworks, and the maximum opportunity for each component. The Remuneration Committee’s discretion in respect of each remuneration component applies up to the maximum shown. Any remuneration elements awarded or granted under the previous remuneration policy approved by shareholders in 2014, but which have not yet vested or been paid, shall continue to be capable of vesting and payment on their existing terms.

Remuneration component and link to strategy	Operation and performance framework	Maximum (1)
Base salary A competitive base salary is paid in order to attract and retain a high-quality and experienced CEO, and to provide appropriate remuneration for this important role in the Group.	•  Base salary, denominated in US dollars, is broadly aligned with salaries for comparable roles in global companies of similar global complexity, size, reach and industry, and reflects the CEO’s responsibilities, location, skills, performance, qualifications and experience. •  Base salary is reviewed annually with effect from 1 September. Reviews are informed, but not led, by benchmarking to comparable roles (as above), changes in responsibility and general economic conditions. Substantial weight is also given to the general base salary increases for employees. •  Base salary is not subject to separate performance conditions.	8% increase per annum (annualised), or inflation if higher in Australia.
Pension contributions Provides a market-competitive level of post-employment benefits provided to attract and retain a high-quality and experienced CEO.	•  Pension contributions are benchmarked to comparable roles in global companies and have been determined after considering the pension contributions provided to the wider workforce. •  A choice of funding vehicles is offered, including a defined contribution plan, an unfunded retirement savings plan, an international retirement plan or a self-managed superannuation fund. Alternatively, a cash payment may be provided in lieu.	25% of base salary.
Benefits Provides personal insurances, relocation benefits and tax assistance where BHP’s structure gives rise to tax obligations across multiple jurisdictions, and a market-competitive level of benefits to attract and retain a high-quality and experienced CEO.	•  Benefits may be provided, as determined by the Committee, and currently include costs of private family health insurance, death and disability insurance, car parking, and personal tax return preparation in the required countries where BHP has requested the CEO relocate internationally, or where BHP’s DLC structure requires personal tax returns in multiple jurisdictions. •  Costs associated with business-related travel for the CEO’s spouse/partner, including for Board meetings, may be covered. Where these costs are deemed to be taxable benefits for the CEO, BHP may reimburse the CEO for these tax costs. •  The CEO is eligible to participate in Shareplus, BHP’s all-employee share purchase plan. •  A relocation allowance and assistance is provided only where a change of location is made at BHP’s request. The Group’s mobility policies provide ‘one-off’ payments with no trailing entitlements.	Benefits as determined by the Committee but to a limit not exceeding 10% of base salary and (if applicable) a one-off taxable relocation allowance up to US$700,000.

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Remuneration component and link to strategy	Operation and performance framework	Maximum (1)
STI The purpose of STI is to encourage and focus the CEO’s efforts on the delivery of the Group’s strategic priorities for the relevant financial year, and to motivate the CEO to strive to achieve stretch performance objectives. The performance measures for each year are chosen on the basis that they are expected to have a significant short-and long-term impact on the success of the Group. Deferral of a portion of STI awards in deferred equity over BHP shares encourages a longer-term focus aligned to that of shareholders.	Setting performance measures and targets •  The Committee sets a balanced scorecard of HSEC, financial and individual performance measures, with targets and relative weightings, at the beginning of the financial year in order to appropriately motivate the CEO to achieve outperformance that contributes to the long-term sustainability of the Group and shareholder wealth creation. •  Specific financial measures will constitute the largest weighting and are derived from the annual budget as approved by the Board for the relevant financial year. •  Appropriate HSEC measures and weightings are determined by the Remuneration Committee with the assistance of the Sustainability Committee. •  For HSEC and for individual measures the target is ordinarily expressed in narrative form and will be disclosed near the beginning of the performance period. However, the target for each financial measure will be disclosed retrospectively. In the rare instances where this may not be prudent on grounds of commercial sensitivity, we will seek to explain why and give an indication of when the target may be disclosed. •  Should any other performance measures be added at the discretion of the Committee, we will determine the timing of disclosure of the relevant target with due consideration of commercial sensitivity. Assessment of performance •  At the conclusion of the financial year, the CEO’s achievement against each measure is assessed by the Remuneration Committee and the Board, with guidance provided by other relevant Board Committees in respect of HSEC and other measures, and an STI award determined. If performance is below the Threshold level for any measure, no STI will be provided in respect of that portion of the STI opportunity. •  The Board believes this method of assessment is transparent, rigorous and balanced, and provides an appropriate, objective and comprehensive assessment of performance. •  In the event that the Remuneration Committee does not consider the outcome that would otherwise apply to be a true reflection of the performance of the Group or should it consider that individual performance or other circumstances makes this an inappropriate outcome, it retains the discretion to not provide all or a part of any STI award. This is an important mitigation against the risk of unintended award outcomes.	Maximum award 240% of base salary (cash 120% and 120% in deferred equity). Target performance 160% of base salary (cash 80% and 80% in deferred equity). Threshold performance 80% of base salary (cash 40% and 40% in deferred equity). Minimum award Zero.

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Remuneration component and link to strategy	Operation and performance framework	Maximum (1)
	Delivery of award •  STI awards are provided under the STIP and the value is delivered half in cash and half in an award of the equivalent value of BHP equity, which is deferred for two years and may be forfeited if the CEO leaves the Group within the deferral period. •  The award of deferred equity comprises rights to receive ordinary BHP shares in the future at the end of the deferral period. Before the awards vest (or are exercised), these rights are not ordinary shares and do not carry entitlements to ordinary dividends or other shareholder rights; however, a DEP is provided on vested awards. The Committee also has a discretion to settle STI awards in cash. •  Both cash and equity STI awards are subject to malus and clawback as described below.
LTI The purpose of the LTI is to focus the CEO’s efforts on the achievement of sustainable long-term value creation and success of the Group (including appropriate management of business risks). It also encourages retention through long-term share exposure for the CEO over the five-year performance period (consistent with the long-term nature of resources), and aligns the long-term interests of the CEO and shareholders. The LTI aligns the CEO’s reward with sustained shareholder wealth creation in excess of that of relevant comparator group(s), through the relative TSR performance condition. Relative TSR has been chosen as an appropriate measure as it allows for an objective external assessment over a sustained period on a basis that is familiar to shareholders.	Relative TSR performance condition •  The LTIP award is conditional on achieving five-year relative TSR (2) performance conditions as set out below. •  The relevant comparator group(s) and the weighting between relevant comparator group(s) will be determined by the Committee in relation to each LTIP grant. Level of performance required for vesting •  Vesting of the award is dependent on BHP’s TSR relative to the TSR of relevant comparator group(s) over a five-year performance period. •  25% of the award will vest where BHP’s TSR is equal to the median TSR of the relevant comparator group(s), as measured over the performance period. Where TSR is below the median, awards will not vest. •  Vesting occurs on a sliding scale between the median TSR of the relevant comparator group(s) up to a nominated level of TSR outperformance(4) over the relevant comparator group(s), as determined by the Committee, above which 100% of the award will vest. •  Where the TSR performance condition is not met, there is no retesting and awards will lapse. The Committee also retains discretion to lapse any portion or all of the award where it considers the vesting outcome is not appropriate given Group or individual performance. This is an important mitigation against the risk of unintended outcomes. Further performance measures •  The Committee may add further performance conditions, in which case the vesting of a portion of any LTI award may instead be linked to performance against the new condition(s). However, the Committee expects that in the event of introducing an additional performance condition(s), the weighting on relative TSR would remain the majority weighting.	Normal Maximum Award Face value of 400% of base salary. Exceptional Maximum Award (3) Face value of 488% of base salary.

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Remuneration component and link to strategy	Operation and performance framework	Maximum (1)
	Delivery of award •  LTI awards are provided under the LTIP approved by shareholders at the 2013 AGMs. When considering the value of the award to be provided, the Committee primarily considers the face value of the award, and also considers its fair value which includes consideration of the performance conditions.(5) •  LTI awards consist of rights to receive ordinary BHP shares in the future if the performance and service conditions are met. Before vesting (or exercise), these rights are not ordinary shares and do not carry entitlements to ordinary dividends or other shareholder rights; however, a DEP is provided on vested awards. The Committee has a discretion to settle LTI awards in cash. •  LTI awards are subject to malus and clawback as described below.

⁽¹⁾  UK regulations require the disclosure of the maximum that may be paid in respect of each remuneration component. Where that is expressed as a maximum annual percentage increase which is annualised it should not be interpreted that it is BHP’s current intention to award an increase of that size in total in any one year, or in each year, and instead it is a maximum required to be disclosed under the regulations.

⁽²⁾  BHP’s TSR is a weighted average of the TSRs of BHP Billiton Limited and BHP Billiton Plc.

⁽³⁾  The Exceptional Maximum Award permitted under the LTIP rules is expressed as a fair value equal to 200 per cent of base salary which represents 41 per cent of face value (200 per cent divided by 41 per cent = 488 per cent). All LTI awards to the CEO will only be provided with prior approval by shareholders in the relevant AGMs.

⁽⁴⁾  Maximum vesting is determined with reference to a position against each comparator group.

⁽⁵⁾  Fair value is calculated by the Committee’s independent adviser and is different to fair value used for IFRS disclosures (which do not take into account forfeiture conditions on the awards). It reflects outcomes weighted by probability, taking into account the difficulty of achieving the performance conditions and the correlation between these and share price appreciation, together with other factors, including volatility and forfeiture risks. The current fair value is 41 per cent of the face value of an award, which may change should the Committee vary elements (such as adding a performance measure or altering the level of relative TSR outperformance).

3.2.4    Malus and clawback

The STIP and LTIP provisions allow the Committee to reduce or clawback awards in the following circumstances:

• the participant acting fraudulently or dishonestly or being in material breach of their obligations to the Group;

• where BHP becomes aware of a material misstatement or omission in the Financial Statements of a Group company or the Group; or

• any circumstances occur that the Committee determines in good faith to have resulted in an unfair benefit to the participant.

These malus and clawback provisions apply whether or not awards are made in the form of cash or equity, and whether or not the equity has vested.

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3.2.5    Potential remuneration outcomes

The Remuneration Committee recognises that market forces necessarily influence remuneration practices and it strongly believes the fundamental driver of remuneration outcomes should be business performance. It also believes that overall remuneration should be both fair to the individual, such that remuneration levels accurately reflect the CEO’s responsibilities and contributions, and align with the expectations of our shareholders, while considering the positioning and relativities of pay and employment conditions across the wider BHP workforce.

The amount of remuneration actually received each year depends on the achievement of superior business and individual performance generating sustained shareholder value. Before deciding on the final incentive outcomes for the CEO, the Committee first considers the achievement against the pre-determined performance conditions. The Committee then applies its overarching discretion on the basis of what it considers to be a fair and commensurate remuneration level to decide if the outcome should be reduced. When the CEO was appointed in May 2013, the Board advised him that the Committee would exercise its discretion on the basis of what it considered to be a fair and commensurate remuneration level to decide if the outcome should be reduced.

In this way, the Committee believes it can set a remuneration level for the CEO that is sufficient to incentivise him and that is also fair to him and commensurate with shareholder expectations and prevailing market conditions.

The diagram below provides the scenario for the potential total remuneration of the CEO at different levels of performance.

Remuneration mix for the CEO

Minimum: consists of fixed remuneration, which comprises base salary (US$1.700 million), pension contributions (25 per cent of base salary) and other benefits (US$0.084 million).

Target: consists of fixed remuneration, target STI (160 per cent of base salary) and target LTI. The LTI target value is based on the fair value of the award, which is 41 per cent of the face value of 400 per cent of base salary. The potential impact of future share price movements is not included in the value of deferred STI awards or LTI awards.

Maximum: consists of fixed remuneration, maximum STI (240 per cent of base salary), and maximum LTI (face value of 400 per cent of base salary). This is lower than the maximum permissible award size under the plan rules. The potential impact of future share price movements is not included in the value of deferred STI awards or LTI awards.

The maximum opportunity represented above is the most that could potentially be paid of each remuneration component, as required by UK regulations. It does not reflect any intention by the Group to award that amount. The Remuneration Committee reviews relevant benchmarking data and industry practices, and believes the maximum remuneration opportunity is appropriate and in line with our remuneration principles.

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3.2.6    Approach to recruitment and promotion remuneration

The remuneration policy as set out in section 3.2 of this Report will apply to the remuneration arrangements for a newly recruited or promoted CEO, or for another Executive Director should one be appointed. A market-competitive level of remuneration comprising base salary, pension contributions, benefits, STI and LTI will be provided. Having considered views expressed by shareholders, the Committee has determined it will review the maximum pension contributions for any newly recruited or promoted CEO, or for another Executive Director should one be appointed, based on market practice at the time. The same maximum STI and LTI opportunity will continue to apply as detailed in the remuneration policy.

For external appointments, the Remuneration Committee may determine that it is appropriate to provide additional cash and/or equity components to replace any remuneration forfeited from a former employer. It is anticipated that any foregone equity awards would be replaced by equity. The value of the replacement remuneration would not be any greater than the fair value of the awards foregone (as determined by the Committee’s independent adviser). The Committee would determine appropriate service conditions and performance conditions within BHP’s framework, taking into account the conditions attached to the foregone awards. The Committee is mindful of limiting such payments and not providing any more compensation than is necessary. For any internal CEO (or another Executive Director) appointment, any entitlements provided under former arrangements will be honoured according to their existing terms.

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3.2.7    Service contracts and policy on loss of office

The terms of employment for the CEO are formalised in his employment contract. Key terms of the current contract and relevant payments on loss of office are shown below. If a new CEO or another Executive Director was appointed, similar contractual terms would apply, other than where the Remuneration Committee determines that different terms should apply for reasons specific to the individual.

The CEO’s current contract has no fixed term. It can be terminated by BHP on 12 months’ notice. BHP can terminate the contract immediately by paying base salary plus pension contributions for the notice period. The CEO must give six months’ notice for voluntary resignation. The table below sets out the basis on which payments on loss of office may be made.

	Leaving reason (1)(2)
	Voluntary resignation	Termination for cause	Death, serious injury, illness, disability or total and permanent disablement	Cessation of employment as agreed with the Board (3)
Base salary	•  Paid as a lump sum for the notice period or progressively over the notice period.	•  No payment will be made.	•  Paid for a period of up to four months, after which time employment may cease.	•  Paid as a lump sum for the notice period or progressively over the notice period.
Pension contributions	•  Paid as a lump sum for the notice period or progressively over the notice period.	•  No contributions will be provided.	•  Paid for a period of up to four months, after which time employment may cease.	•  Paid as a lump sum for the notice period or progressively over the notice period.
Benefits	•  May continue to be provided during the notice period. •  Accumulated annual leave entitlements and any statutory payments will be paid. •  May pay repatriation expenses to the home location where a relocation was at the request of BHP. •  Any unvested Shareplus Matched Shares held will lapse.	•  No benefits will be provided. •  Accumulated annual leave entitlements and any statutory payments will be paid. •  May pay repatriation expenses to the home location where a relocation was at the request of BHP. •  Any unvested Shareplus Matched Shares held will lapse.	•  May continue to be provided during the notice period. •  Accumulated annual leave entitlements and any statutory payments will be paid. •  May pay repatriation expenses to the home location where a relocation was at the request of BHP. •  Any unvested Shareplus Matched Shares held will vest in full.	•  May continue to be provided for year in which employment ceases. •  Accumulated annual leave entitlements and any statutory payments will be paid. •  May pay repatriation expenses to the home location where a relocation was at the request of BHP. •  Any unvested Shareplus Matched Shares held will vest in full.

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	Leaving reason (1)(2)
	Voluntary resignation	Termination for cause	Death, serious injury, illness, disability or total and permanent disablement	Cessation of employment as agreed with the Board (3)
STI – cash and deferred equity Where CEO leaves either during or after the end of the financial year, but before an award is provided.	•  No cash STI will be paid. •  Unvested STIP will lapse. •  Vested but unexercised STIP will remain exercisable for the remaining exercise period unless the Committee determines they will lapse.	•  No cash STI will be paid. •  Unvested STIP will lapse. •  Vested but unexercised STIP will remain exercisable for the remaining exercise period unless the Committee determines they will lapse.	•  The Committee has discretion to pay and/or award an amount in respect of the CEO’s performance for that year. •  Unvested STIP will vest in full and, where applicable become exercisable. •  Vested but unexercised STIP will remain exercisable for the remaining exercise period.	•  The Committee has discretion to pay and/or award an amount in respect of the CEO’s performance for that year. •  Unvested STIP continue to be held on the existing terms for the deferral period before vesting (subject to Committee discretion to lapse some or all of the award). •  Vested but unexercised STIP remain exercisable for the remaining exercise period, or a reduced period, or may lapse, as determined by the Committee. •  Unvested and vested but unexercised awards remain subject to malus and clawback.

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	Leaving reason (1)(2)
	Voluntary resignation	Termination for cause	Death, serious injury, illness, disability or total and permanent disablement	Cessation of employment as agreed with the Board (3)
LTI – unvested and vested but unexercised awards	•  Unvested awards will lapse. •  Vested but unexercised awards will remain exercisable for the remaining exercise period, or for a reduced period, or may lapse, as determined by the Committee.	•  Unvested awards will lapse. •  Vested but unexercised awards will remain exercisable for the remaining exercise period, or for a reduced period, or may lapse, as determined by the Committee.	•  Unvested awards will vest in full. •  Vested but unexercised awards will remain exercisable for remaining exercise period.	•  A pro-rata portion of unvested awards (based on the proportion of the performance period served) will continue to be held subject to the LTIP rules and terms of grant. The balance will lapse. •  Vested but unexercised awards will remain exercisable for the remaining exercise period, or for a reduced period, or may lapse, as determined by the Committee. •  Unvested and vested but unexercised awards remain subject to malus and clawback.

⁽¹⁾  If the Committee deems it necessary, BHP may enter into agreements with a CEO, which may include the settlement of liabilities in return for payment(s), including reimbursement of legal fees subject to appropriate conditions; or to enter into new arrangements with the departing CEO (for example, entering into consultancy arrangements).

⁽²⁾  In the event of a change in control event (for example, takeover, compromise or arrangement, winding up of the Group) as defined in the STIP and LTIP rules:

• base salary, pension contributions and benefits will be paid until the date of the change of control event;

• the Committee may determine that a cash payment be made in respect of performance during the current financial year and all unvested STI equity awards would vest in full;

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• the Committee may determine that unvested LTI awards will either (i) be pro-rated (based on the proportion of the performance period served up to the date of the change of control event) and vest to the extent the Committee determines appropriate (with reference to performance against the performance condition up to the date of the change of control event and expectations regarding future performance) or (ii) be lapsed if the Committee determines the holders will participate in an acceptable alternative employee equity plan as a term of the change of control event.

⁽³⁾  Defined as occurring when a participant leaves BHP due to forced early retirement, retrenchment or redundancy, termination by mutual agreement or retirement with the agreement of the Group, or such other circumstances that do not constitute resignation or termination for cause.

Remuneration policy for Non-executive Directors

Our Non-executive Directors are paid in line with the UK Corporate Governance Code (April 2016) and the Australian Securities Exchange Corporate Governance Council’s Principles and Recommendations (3rd Edition).

3.2.8    Components of remuneration

The following table shows the components of total remuneration, the link to strategy, the applicable operation and performance frameworks, and the maximum opportunity for each component.

Remuneration component and link to strategy	Operation and performance framework	Maximum (1)
Fees Competitive base fees are paid in order to attract and retain high-quality individuals, and to provide appropriate remuneration for the role undertaken. Committee fees are provided to recognise the additional responsibilities, time and commitment required.	•  The Chairman is paid a single fee for all responsibilities. •  Non-executive Directors are paid a base fee and relevant committee membership fees. •  Committee Chairmen and the Senior Independent Director are paid an additional fee to reflect their extra responsibilities. •  All fee levels are reviewed annually and any changes are effective from 1 July. •  Fees are set at a competitive level based on benchmarks and advice provided by external advisers. Fee levels reflect the size and complexity of the Group, the multi-jurisdictional environment arising from the DLC structure, the multiple stock exchange listings and the geographies in which the Group operates. The economic environment and the financial performance of the Group are taken into account. Consideration is also given to salary reviews across the rest of the Group. •  Where the payment of pension contributions is required by law, these contributions are deducted from the Director’s overall fee entitlements.	8% increase per annum (annualised), or inflation if higher in the location in which duties are primarily performed, on a per fee basis.

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Remuneration component and link to strategy	Operation and performance framework	Maximum (1)
Benefits Competitive benefits are paid in order to attract and retain high-quality individuals and adequately remunerate them for the role undertaken, including the considerable travel burden.	•  Travel allowances are paid on a per-trip basis reflecting the considerable travel burden imposed on members of the Board as a consequence of the global nature of the organisation and apply when a Director needs to travel internationally to attend a Board meeting or site visits at our multiple geographic locations. •  As a consequence of the DLC structure, Non-executive Directors are required to prepare personal tax returns in both Australia and the UK, regardless of whether they reside in one or neither of those countries. They are accordingly reimbursed for the costs of personal tax return preparation in whichever of the UK and/or Australia is not their place of residence (including payment of the tax cost associated with the provision of the benefit).	8% increase per annum (annualised), or inflation if higher in the location in which duties are primarily performed, on a per-trip basis. Up to a limit not exceeding 20% of fees.
STI and LTI	•  Non-executive Directors are not eligible to participate in any STI or LTI arrangements.
Payments on early termination	•  There are no provisions in any of the Non-executive Directors’ appointment arrangements for compensation payable on early termination of their directorship.

⁽¹⁾  UK regulations require the disclosure of the maximum that may be paid in respect of each remuneration component. Where that is expressed as a maximum annual percentage increase which is annualised it should not be interpreted that it is BHP’s current intention to award an increase of that size in total in any one year, or in each year, and instead it is a maximum required to be disclosed under the regulations.

Approach to recruitment remuneration

The ongoing remuneration arrangements for a newly recruited Non-executive Director will reflect the remuneration policy in place for other Non-executive Directors, comprising fees and benefits as set out in the table above. No variable remuneration (STI and LTI) will be provided to newly recruited Non-executive Directors.

Letters of appointment and policy on loss of office

The standard letter of appointment for Non-executive Directors is available on our website. The Board has adopted a policy consistent with the UK Corporate Governance Code, under which all Non-executive Directors must seek re-election by shareholders annually if they wish to remain on the Board. As such, no Non-executive Directors seeking re-election have an unexpired term in their letter of appointment. A Non-executive Director may resign on reasonable notice. No payments are made to Non-executive Directors on loss of office.

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3.3    Annual report on remuneration

This section of the Report shows the impact of the remuneration policy in FY2018 and how remuneration outcomes are linked to actual performance.

Remuneration for the Executive Director (the CEO)

3.3.1    Single total figure of remuneration

This section shows a single total figure of remuneration as prescribed under UK requirements. It is a measure of actual remuneration, rather than a figure calculated in accordance with IFRS (which is detailed in section 5.1.6 note 22). The components of remuneration are detailed in the remuneration policy table in section 3.2.3.

US$(’000)		Base salary		Benefits (1)		STI (2)		LTI		Pension		Total
Andrew Mackenzie	FY2018		1,700		84		2,448		0		425		4,657
	FY2017		1,700		90		2,339		0		425		4,554

⁽¹⁾  Includes private family health insurance, spouse business-related travel, car parking and personal tax return preparation in required countries.

⁽²⁾  Provided half in cash and half in deferred equity (on the terms set out in section 3.2.3) as shown in the table below.

For the CEO, the single total figure of remuneration is calculated on the same basis as at his appointment in 2013. There have been no changes to his base salary, benefit entitlements or pension since that date. Changes from prior year outcomes of STI and LTI are set out below.

	FY2018	FY2017
STI	STI awarded for FY2018 performance. Half was provided in cash in September 2018, and half deferred in an equity award that is due to vest in FY2021.	STI awarded for FY2017 performance. Half was provided in cash in September 2017, and half deferred in an equity award that is due to vest in FY2020.
LTI	Based on performance during the five-year period to 30 June 2018, all of Andrew Mackenzie’s 213,701 awards from the 2013 LTIP did not vest and have lapsed. The value of the awards is zero and no DEP has been paid in respect of these awards.	Based on performance during the five-year period to 30 June 2017, all of Andrew Mackenzie’s 151,609 awards from the 2012 LTIP did not vest and have lapsed. The value of the awards is zero and no DEP has been paid in respect of these awards.

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3.3.2    FY2018 STI performance outcomes

The Board and Remuneration Committee assessed the CEO’s STI outcome in light of the Group’s performance in FY2018, taking into account the CEO’s performance against the KPIs in his STI scorecard. The Board and Committee determined that the STI outcome for the CEO for FY2018 is 90 per cent against the target of 100 per cent (which represents an outcome of 60 per cent against maximum), and believe this outcome is appropriately aligned with the shareholder experience and the interests of the Group’s other stakeholders.

The CEO’s STI scorecard outcomes for FY2018 are summarised in the following tables, including a narrative description of each performance measure and the CEO’s level of achievement, as determined by the Remuneration Committee. The level of performance for each measure is determined based on a range of threshold (the minimum necessary to qualify for any reward outcome), target (where the performance requirements are met), and stretch (where the performance requirements are significantly exceeded).

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HSEC

The HSEC targets for the CEO are aligned to the Group’s suite of HSEC five-year public targets as set out in BHP’s Sustainability Report. As it has done for several years, the Remuneration Committee seeks guidance each year from the Sustainability Committee when assessing HSEC performance against scorecard targets. The Remuneration Committee has taken a holistic view of Group performance in critical areas, including any matters outside the scorecard targets which the Sustainability Committee considers relevant.

The performance commentary below is provided against the scorecard targets, which were set on the basis of operated assets only.

HSEC Scorecard Targets

Performance against Scorecard Targets

Fatalities, environmental and community incidents: Nil fatalities and nil actual significant environmental and community incidents at operated assets. Year-on-year improvement in trends for events with potential for such outcomes. TRIF and occupational illness: Improved performance compared with FY2017 results, with severity and trends to be considered as a moderating influence on the overall HSEC assessment. Risk management: For all material risks, operated assets to have all critical control execution and critical control verification tasks evaluated and recorded with controls in place as part of Field Leadership activities. Year-on-year improvement in trends for potential events associated with identified material risks. Health, environmental and community initiatives: All assets to achieve 100% of planned targets in respect of occupational exposure reduction, water and greenhouse gas, social investment, quality of life, community perceptions and community complaints.

Fatalities, environmental and community incidents: In what is clearly a tragic and unacceptable outcome, we lost two of our colleagues during FY2018, one in August 2017 at Goonyella Riverside, and another in November 2017 at Permian Basin Operations. These events have the greatest weighting and impact when determining the performance outcomes under the HSEC category. Our imperative as a Company is to continue to build our focus on fatality prevention and safety through leadership, verification and effective risk management. No significant environment or community incidents occurred during FY2018. TRIF and occupational illness: Our TRIF performance in FY2018 (including Onshore US) of 4.4 is slightly higher than the 4.2 recorded in FY2017, following an improvement of 2% in the prior year. Importantly, we have continued to significantly reduce the number of high potential injury events, which is a critical element of fatality prevention. While we have experienced an increase in occupational illnesses during FY2018, this will be a continuing key focus area for improvement in future years.. Risk management: All operated assets completed reviews of critical control execution and verification tasks for all material HSEC risks and met, or exceeded, targets for compliance of critical control execution and verification tasks, and deployment and improvement of Field Leadership activities. Health, environmental and community initiatives: Greenhouse gas reduction targets set at the commencement of the year were met at all operated assets. Water management projects were completed and fresh water usage reduction achievements from projects implemented were on target. In addition, the assets met or exceeded all occupational exposure reduction and community targets.

The outcome against the HSEC KPI for FY2018 was 16 per cent against the target of 25 per cent.

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Underlying attributable profit

UAP is the profit after taxation attributable to members of the Group, excluding exceptional items (see section 1.11.5 for a more detailed explanation of UAP). UAP is the key KPI against which STI outcomes for our senior executives are measured and is, in our view, the most relevant measure to assess the financial performance of the Group for this purpose. At the commencement of the financial year when the target is approved, attributable profit is usually equal to UAP as there are usually no exceptional items.

During the assessment of management’s performance, adjustments to the UAP result are made to allow for changes in commodity prices, foreign exchange movements and other material items to ensure the assessment appropriately measures outcomes that are within the control and influence of the Group and its executives. Of these, changes in commodity prices has historically been the most material due to volatility in prices and the impact on Group revenue. The Remuneration Committee reviews each exceptional item to assess if it should be included in the result for the purposes of deriving the UAP STI outcome.

Financial Scorecard Targets

Performance against Scorecard Targets

In respect of FY2018, the Board determined a Target for UAP of US$5.4 billion, with a Threshold of US$4.0 billion and a Stretch of US$5.7 billion. The Target UAP is based on the Group’s approved annual budget. It is the Group’s practice to build a material element of stretch performance into the budget, to include a high level of operational integrity with assets typically assumed to run at full design capacity, and to not make allowance for material unforeseen downside events. Achievement of this stretching UAP budget will result in a target STI outcome. The Threshold and Stretch are a fair range of UAP outcomes which represent a lower limit of underperformance below which no STI award should be made, and an upper limit of outperformance which would represent the maximum STI award. For the reasons set out above, the performance range around Target is subject to a greater level of downside risk than there is upside opportunity, and accordingly, the range between Threshold and Target is greater than that between Target and Stretch. For Stretch, the Committee takes care not to create leveraged incentives that encourage executives to push for short-term performance that goes beyond our risk appetite and current operational capacity. Using the mid-point of the Threshold and Stretch range as Target would provide a symmetrical distribution; however, this would not provide sufficient stretch for management to achieve a target STI outcome. The Committee retains, and has a track record of applying, downward discretion to ensure that the STI outcome is appropriately aligned with the overall performance of the Group for the year, and is fair to management and shareholders.

UAP of US$8.9 billion was reported by BHP for FY2018. Adjusted for the factors outlined below, UAP is US$4.9 billion, which is between Threshold and Target as determined by the Board. The following adjustments were made to ensure the outcomes appropriately reflect the performance of management for the year: •   Adjustments for movements in prices of commodities and exchange rates for operated assets reduced UAP by US$3.9 billion. •   Adjustments for other material items ordinarily made to ensure the outcomes reflect the performance of management for the year reduced UAP by US$0.1 billion, mainly due to the exclusion of the commodity price impacts on non-controlled equity accounted investments. Having reviewed the FY2018 exceptional items (as described in section 5.1.6 note 2), the Committee determined that they should not be considered for the purposes of determining the UAP STI outcome. One item given particular consideration was the impairment related to Onshore US. The Committee noted that this was triggered by a successful divestment process for those assets that maximises value, returns and certainty for shareholders, and also that action has already been taken by the Committee in prior periods in relation to managerial accountability for the acquisitions and investments in Onshore US. The Committee concluded that no further action was appropriate. The key driver of the UAP performance being below Target at US$4.9 billion was variable production performance across the different operated assets, with volumes of coal, iron ore and copper being lower than expectations, partly offset by higher than expected production of petroleum products. Cost performance, excluding the impact of exchange rates, was generally aligned with the targets set for the Group at the commencement of the year.

The outcome against the UAP KPI for FY2018 was 37 per cent against the target of 45 per cent.

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Individual performance measures for the CEO

Individual measures for the CEO are determined at the commencement of the financial year. The application of personal, qualitative measures remains an important element of effective performance management. These measures seek to provide a balance between the financial and non-financial performance requirements that maintain our position as a leader in our industry. The CEO’s individual measures for FY2018 included contribution to BHP’s overall performance and the management team, and also the delivery of projects and initiatives within the scope of the CEO role as specified by the Board, as set out in the table below.

Measures	Individual Scorecard Targets	Performance against Scorecard Targets	Assessment
Strategy	•   Strategy implementation. •   Execution of growth aspirations. •   Onshore US divestment. •   Delivery of latent capacity enhancement projects.	•   Strategic initiatives on track, including the future Petroleum strategy; advancement of the Olympic Dam expansion; and the review of Potash and Coal strategies. •   Successful development of the Spence copper growth option saw the Board approve the project. •   Significant work on the divestment of Onshore US assets will result in a transaction that maximises value and returns for shareholders, and provides certainty to investors and our employees. •   The Board approved the South Flank iron ore project, which will replace production from the Yandi mine that is reaching the end of its economic life. •   Continued progress on BHP’s rigorous Capital Allocation Framework. •   Latent capacity projects on track to meet expected milestones and benefits. •   BHP’s value increased consistent with the plan outlined previously, driven not only by commodity price appreciation, but also by management actions on strategic initiatives.	Between Target and Stretch, with a bias towards the latter.

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Measures	Individual Scorecard Targets	Performance against Scorecard Targets	Assessment
Productivity	•   Delivery of productivity initiatives.	•   Delivered a strategy for a step change in safety and productivity outcomes and culture, within which the BHP Operating System will standardise work to increase safety and efficiency at operations across the Company. •   Achieved lower functional costs than targeted, with plans developed to realise more cost reductions in future years. •   Plans developed to target circa US$1 billion in productivity gains in FY2019, on top of the more than US$12 billion achieved since 2012.	Marginally above Target.
Sustainability	•   Positive progress on the Samarco Framework Agreement. •   Enhanced reputation of BHP.	•   Fundação Renova activity and spend has met the defined schedule. •   Continued strong representation on key issues such as inclusion and diversity, transparency, taxation and Samarco. •   Shareholder engagement strengthened through close communication, regular updates and relationship building. •   Global brand strategy has enhanced BHP’s reputation in key markets with the next phase of global brand positioning underway.	Midway between Target and Stretch.
People and culture	•   Achievement of culture initiatives (improvement in Company-wide leadership capabilities, employee engagement, diversity and inclusion). •   ELT member development and succession.	•   Year-on-year improvement in workforce leadership capabilities, employee engagement and the inclusion index, as measured by the annual employee perception survey, with improvement in nine of the 10 broad categories, with one unchanged. •   Strong leadership on inclusion and diversity, with solid progress on the goal to increase female representation in the workforce globally, and increased uptake of flexible working arrangements across BHP.	Marginally above Target.

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Measures	Individual Scorecard Targets	Performance against Scorecard Targets	Assessment
		•   Development and implementation of a Company-wide culture plan led to significant improvement in trust and teamwork, which has supported the success of Field Leadership, the Maintenance Centre of Excellence and our General Manager Leadership programs. •   Continued focus on development of a strong long-term talent pool of candidates for Asset President and ELT roles, including additional coaching and development opportunities.

It was considered that the performance of the CEO against the personal measures KPI has been strong and warranted an outcome for FY2018 of 37 per cent against the target of 30 per cent.

3.3.3    LTI performance outcomes

LTI vesting based on performance to June 2018

The five-year performance period for the 2013 LTIP ended on 30 June 2018. The CEO’s 2013 LTI comprised 213,701 awards (inclusive of an uplift of 15,187 awards due to the demerger of South32), subject to achievement of the relative TSR performance conditions and any discretion applied by the Remuneration Committee.

Testing the performance condition

For the award to vest in full, TSR must exceed the Peer Group TSR (for 67 per cent of the award) and the Index TSR (for 33 per cent of the award) by an average of 5.5 per cent per year for five years, being 30.7 per cent in total compounded over the performance period from 1 July 2013 to 30 June 2018. TSR includes returns to BHP shareholders in the form of share price movements along with dividends paid and reinvested in BHP (including cash and in-specie dividends).

BHP’s TSR performance was negative 9.3 per cent over the five-year period from 1 July 2013 to 30 June 2018. This is below the weighted median Peer Group TSR of positive 9.6 per cent and below the Index TSR of positive 67.6 per cent over the same period. This level of performance results in zero vesting for the 2013 LTIP awards, and accordingly all of the CEO’s awards have lapsed. No compensation or DEP was paid in relation to the lapsed awards.

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The graph below shows BHP’s performance relative to comparator groups.

BHP vs. Peer Group and Index TSR

Overarching discretion

The rules of the LTIP and the terms and conditions of the award give the Committee an overarching discretion to reduce the number of awards that will vest, notwithstanding the fact that the performance condition for partial or full vesting, as tested following the end of the performance period, has been met. This qualitative judgement, which is applied before final vesting is confirmed, is an important risk management aspect to ensure that vesting is not simply driven by a formula that may give unexpected or unintended remuneration outcomes. The Committee considers its discretion carefully each year. It considers performance holistically over the five-year period, including a five-year view on HSEC statistics, profitability, cash flow, balance sheet health, returns to shareholders, production volumes and unit costs. The Committee believes that this is the most appropriate process of measurement for the LTI performance condition.

As the formulaic outcome of the 2013 LTIP was a zero vesting, there is no discretion available to the Remuneration Committee, as the overarching discretion may only reduce the number of awards that may vest.

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3.3.4    LTI allocated during FY2018

Following shareholder approval at the 2017 AGMs, an LTI award (in the form of performance rights) was granted to the CEO on 24 November 2017. The face value and fair value of the award are shown in the table below.

The face value of the award is ordinarily determined as 400 per cent of the CEO’s base salary of US$1.700 million. The fair value of the award is ordinarily calculated by multiplying the face value of the award by the fair value factor of 41 per cent (for the current plan design, as determined by the independent adviser to the Committee). Using the average share price and US$/A$ exchange rate over the 12 months up to and including 30 June 2017, the number of LTI awards derived from a grant of 400 per cent of base salary with a face value of US$6.800 million was 385,075 LTI awards.

Number of LTI awards	Face value US$(‘000)	Face value % of salary	Fair value US$(‘000)	Fair value % of salary	% of max (1)
385,075	6,800	400	2,788	164	82

⁽¹⁾  The allocation is 82 per cent of the maximum award that may be provided under the LTIP rules. The maximum is a fair value of 200 per cent of base salary or face value of 488 per cent of base salary, based on the fair value of 41 per cent for the current plan design (488 per cent x 41 per cent = 200 per cent).

Terms of the LTI award

In addition to those LTI terms set in the remuneration policy for the CEO, the Remuneration Committee has determined:

Performance period	•   1 July 2017 to 30 June 2022.
Performance conditions	•   An averaging period of six months will be used in the TSR calculations. •   BHP’s TSR relative to the weighted median TSR of sector peer companies selected by the Committee (Peer Group TSR) and the MSCI World index (Index TSR) will determine the vesting of 67% and 33% of the award, respectively. •   Each company in the peer group is weighted by market capitalisation. The maximum weighting for any one company is 20% and the minimum is set at 0.67% to reduce sensitivity to any single peer company. •   For the whole of either portion of the award to vest, BHP’s TSR must be at or exceed the weighted 80th percentile of the Peer Group TSR or the Index TSR (as applicable). Threshold vesting (25% of each portion of the award) occurs where BHP’s TSR equals the weighted 50th percentile of the Peer Group TSR or the Index TSR (as applicable).
Sector Peer Group Companies (1)(2)	•   Resources (75%): Anglo American, CONSOL Energy and Fortescue Metals (from December 2013), Freeport-McMoRan, Glencore(3), Rio Tinto, Southern Copper, Teck Resources, Vale. •   Oil and Gas (25%): Apache, BP, Devon Energy, ExxonMobil, Royal Dutch Shell, Woodside Petroleum, and from December 2013, Anadarko Petroleum, Canadian Natural Res., Chevron, ConocoPhillips, EOG Resources, Occidental Petroleum.

⁽¹⁾  From December 2016, BG Group and Peabody Energy were removed from the comparator group. BG Group was acquired by Royal Dutch Shell and Peabody Energy has become a significantly less comparable peer.

⁽²⁾  From December 2015, Alcoa, Cameco and MMC Norilsk Nickel were removed from the sector peer group following the demerger of South32 as they are less relevant comparator companies.

⁽³⁾  Glencore Xstrata was included in the sector peer group for grants made from December 2013 onwards and was renamed Glencore in May 2014.

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3.3.5    CEO remuneration and returns to shareholders

Nine-year CEO remuneration

The table below shows the total remuneration earned by Andrew Mackenzie and Marius Kloppers over the last nine years along with the proportion of maximum opportunity earned for each type of incentive.

Financial year	FY2010		FY2011		FY2012		FY2013 (1)		FY2014		FY2015		FY2016		FY2017		FY2018
Andrew Mackenzie
Total single figure remuneration, US$(‘000)		–		–		–		2,468		7,988		4,582		2,241		4,554		4,657
STI (% of maximum)		–		–		–		47		77		57		0		57		60
LTI (% of maximum)		–		–		–		65		58		0		0		0		0
Marius Kloppers
Total single figure remuneration, US$(‘000)		14,789		15,755		16,092		15,991		–		–		–		–		–
STI (% of maximum)		71		69		0		47		–		–		–		–		–
LTI (% of maximum)		100		100		100		65		–		–		–		–		–

⁽¹⁾  As Mr Mackenzie assumed the role of CEO in May 2013, the FY2013 total remuneration shown relates only to the period 10 May to 30 June 2013. The FY2013 total remuneration for Mr Kloppers relates only to the period 1 July 2012 to 10 May 2013.

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Nine-year TSR

The graph below shows BHP’s TSR against the performance of relevant indices over the same nine-year period. The indices shown in the graph were chosen as being broad market indices, which include companies of a comparable size and complexity to BHP.

Value of US$100 invested over the nine-year period to 30 June 2018 (with dividends reinvested)

3.3.6    Changes in the CEO’s remuneration in FY2018

The table below sets out the CEO’s base salary, benefits and STI amounts earned in respect of FY2018, with the percentage change from FY2017. The table also shows the average change in each element for current employees in Australia (being approximately 16,500 employees) during FY2018. This has been chosen by the Committee as the most appropriate comparison, as the CEO is located in Australia.

		Base salary		Benefits			STI
CEO	US$(‘000)		1,700		84			2,448
	% change		0.0		(6.7	)		4.7
Australian employees	% change (average)		2.6		9.9			(7.0	)

The ratio of the total remuneration of the CEO to the median total remuneration of all BHP employees for FY2018 was 37:1 (2017: 38:1).

3.3.7    Remuneration for the CEO in FY2019

The remuneration for the CEO in FY2019 will be set in accordance with the remuneration policy approved by shareholders at the AGMs in 2017.

Base salary review

Base salary is reviewed annually and increases are applicable from 1 September. The CEO will not receive a base salary increase in September 2018 and it will remain unchanged at US$1.700 million per annum for FY2019.

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FY2019 STI performance measures

For FY2019, the Remuneration Committee has set the following STI scorecard performance measures:

Performance measure	Weighting		Target performance
HSEC		25%	Fatalities, environmental and community incidents: Nil fatalities and nil actual significant environmental and community incidents. Year-on-year improvement in trends for events with potential for such outcomes. Significant safety events, TRIF and occupational illness: Improved performance compared with FY2018 results, with severity and trends to also be considered as a moderating influence on the overall HSEC assessment. Risk management: Operated assets to have controls for fatal risks verified as part of Field Leadership activities with fatal risk control improvement plans developed and executed and increased levels of in-field coaching. Achieve 90% compliance for critical control verification and execution tasks. Health, environmental and community initiatives: All operated assets to achieve 100% of planned targets in respect of occupational exposure reduction, water and greenhouse gas, social investment, quality of life, community perceptions and community complaints.
UAP		45%	UAP is profit after taxation attributable to members of the BHP Group, excluding exceptional items. When we are assessing management’s performance, we make adjustments to the UAP result to allow for changes in commodity prices, foreign exchange movements and other material items to ensure the assessment appropriately measures outcomes that are within the control and influence of the Group and its executives. For reasons of commercial sensitivity, the target for UAP will not be disclosed in advance; however, we plan to disclose targets and outcomes retrospectively in our next Remuneration Report, following the end of each performance year. In the rare instances where this may not be prudent on grounds of commercial sensitivity, we will explain why and give an indication of when they will be disclosed.

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Performance measure	Weighting		Target performance
Individual performance		30%	The CEO’s individual measures for FY2019 comprise contribution to BHP’s overall performance and the management team and the delivery of projects and initiatives within the scope of the CEO role as set out by the Board. These include strategy, productivity initiatives, transformation programs, latent capacity enhancement projects, focus on the returns of BHP and those expected of future major capital projects, exploration, continued enhancement of BHP’s global brand, culture initiatives (including improvement in Group-wide leadership capabilities, employee engagement, diversity and inclusion) and ELT member development and succession.

FY2019 LTI award

The normal maximum face value of the CEO’s award is US$6.800 million, being 400 per cent of the CEO’s base salary. The number of LTI awards in FY2019 has been determined using the share price and US$/A$ exchange rate over the 12 months up to and including 30 June 2018. Based on this, an FY2019 grant of 304,523 LTI awards is proposed and approval for this LTI grant will be sought from shareholders at the 2018 AGMs. If approved, the award will be granted following the AGMs (i.e., in or around November/December 2018).

The FY2019 LTI award will use the same performance, service conditions and peer groups as the FY2018 LTI award except that CONSOL Energy has been removed from the sector peer group of companies due to the demerger of CONSOL Energy and CNX Resources resulting in two significantly smaller companies, and the split between Resources and Oil and Gas peers has been adjusted from 75 per cent / 25 per cent to 85 per cent / 15 per cent to reflect the continuing shift in the future commodity mix of BHP, mainly as a consequence of the exit from Onshore US.

Remuneration for other Executive KMP (excluding the CEO)

The information in this section contains details of the remuneration policy that guided the Remuneration Committee’s decisions and resulted in the remuneration outcomes for other Executive KMP (excluding the CEO).

The remuneration policy and structures for other Executive KMP are essentially the same as those already described for the CEO in previous sections of the Remuneration Report, including the treatment of remuneration on loss of office as detailed in section 3.2.7.

3.3.8    Components of remuneration

The components of remuneration for other Executive KMP are the same as for the CEO, with any differences described below.

STI

STI performance measures for other Executive KMP are similar to those of the CEO which are outlined at section 3.3.2; however, the weighting of each performance measure will vary to reflect the focus required from each Executive KMP role.

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Individual performance measures are determined at the start of the financial year. These include the other Executive KMP’s contribution to the delivery of projects and initiatives within the scope of their role and the overall performance of the Group. Individual performance of other Executive KMP was reviewed against these measures by the Committee and, on average, was considered slightly above target.

The diagram below represents the STI outcomes against the original scorecard.

LTI

LTI awards granted to other Executive KMP have a maximum face value of 350 per cent of base salary, which is a fair value of 143.5 per cent of base salary under the current plan design (with a fair value of 41 per cent, taking into account the performance condition: 350 per cent x 41 per cent = 143.5 per cent).

Transitional Executive KMP awards

Transitional Executive KMP awards were granted to certain new Executive KMP recruited from within BHP to bridge the gap created by the different timeframes of BHP’s LTIP, for Executive KMP, and MAP, for senior management. Peter Beaven and Daniel Malchuk are the only Executive KMP who held Transitional Executive KMP awards at the commencement of FY2018, as set out in section 3.3.16.

Equity awards provided for pre-KMP service

Other Executive KMP who were promoted from executive roles within BHP may hold GSTIP and MAP awards that were granted to them in respect of their service in non-Executive KMP roles.

Shareplus

Other Executive KMP are eligible to participate in Shareplus. For administrative simplicity, Executive KMP, including the CEO, do not currently participate in Shareplus. No Executive KMP, including the CEO, had any holdings under the Shareplus program during FY2018.

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3.3.9    Remuneration mix

A significant portion of other Executive KMP remuneration is at-risk, in order to provide strong alignment between remuneration outcomes and the interests of BHP shareholders.

The diagram below sets out the relative mix of each remuneration component for the other Executive KMP. Each component is determined as a percentage of base salary (at the minimum, target and maximum levels of performance-based remuneration).

⁽¹⁾  Base salary earned by each Executive KMP is set out in section 3.3.15.

⁽²⁾  Retirement benefits are 25 per cent of base salary.

⁽³⁾  Other benefits is based on a notional 10 per cent of base salary.

⁽⁴⁾  As for the CEO, the minimum STI award is zero, with an award of 80 per cent of base salary in cash and 80 per cent of salary in deferred equity for target performance, and a maximum award of 120 per cent cash and 120 per cent deferred equity for exceptional performance against KPIs.

⁽⁵⁾  Other Executive KMP have a maximum LTI award with a face value of 350 per cent of base salary as shown in the chart.

3.3.10    Employment contracts

The terms of employment for other Executive KMP are formalised in employment contracts, which have no fixed term. They typically outline the components of remuneration paid to the individual, but do not prescribe how remuneration levels are to be modified from year-to-year. An Executive KMP employment contract may be terminated by BHP on up to 12 months’ notice or can be terminated immediately by BHP making a payment of up to 12 months’ base salary plus pension contributions for the relevant period. An Executive KMP must give six months’ notice for voluntary resignation.

Remuneration for Non-executive Directors

The remuneration outcomes described below have been provided in accordance with the remuneration policy approved by shareholders at the 2017 AGMs. The maximum aggregate fees payable to Non-executive Directors (including the Chairman) were approved by shareholders at the 2008 AGMs at US$3.800 million per annum. This sum includes base fees, Committee fees and pension contributions. Travel allowances and non-monetary benefits are not included in this limit.

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3.3.11    Single total figure of remuneration

This section shows a single total figure of remuneration as prescribed under UK requirements. It is a measure of actual remuneration. Fees include the annual base fee, plus additional fees as applicable for the Senior Independent Director, Committee Chairmen and Committee memberships. Non-executive Directors do not have any at-risk remuneration or receive any equity awards as part of their remuneration. This table also meets the requirements of the Australian Corporations Act 2001 and relevant accounting standards.

US$(‘000)	Financial year		Fees		Benefits  (1)		Pensions  (2)		Total
Terry Bowen (3)		FY2018		135		37		7		179
Malcolm Brinded (4)		FY2018		70		17		–		87
		FY2017		229		101		–		330
Malcolm Broomhead		FY2018		200		33		11		244
		FY2017		209		70		11		290
Anita Frew		FY2018		202		62		–		264
		FY2017		193		68		–		261
Carolyn Hewson		FY2018		195		32		10		237
		FY2017		195		54		10		259
Grant King (4) (5)		FY2018		28		7		1		36
		FY2017		51		37		2		90
Ken MacKenzie (5)		FY2018		749		61		16		826
		FY2017		138		81		8		227
Lindsay Maxsted		FY2018		209		47		11		267
		FY2017		209		36		11		256
John Mogford (3)		FY2018		138		60		–		198
Wayne Murdy		FY2018		220		80		–		300
		FY2017		199		93		–		292
Jac Nasser (4)		FY2018		147		19		–		166
		FY2017		960		93		–		1,053
Shriti Vadera		FY2018		235		63		–		298
		FY2017		236		69		–		305

⁽¹⁾  The majority of the amounts disclosed for benefits are travel allowances for each Non-executive Director: amounts of between US$7,000 and US$75,000. In addition, amounts of between US$ nil and US$3,000 are included in respect of tax return preparation; and amounts of between US$ nil and US$2,000 are included in respect of reimbursement of the tax cost associated with the provision of taxable benefits.

⁽²⁾ BHP Billiton Limited made minimum superannuation contributions of 9.5 per cent of fees for FY2018 in accordance with Australian superannuation legislation.

⁽³⁾ The FY2018 remuneration for Terry Bowen and John Mogford relates to part of the year only, as they both joined the Board on 1 October 2017.

⁽⁴⁾ The FY2018 remuneration for Jac Nasser, Malcolm Brinded and Grant King relates to part of the year only as they each retired from the Board during FY2018. Jac Nasser retired from the Board as Non-executive Director and Chairman on 31 August 2017. Grant King retired from the Board on 31 August 2017. Malcolm Brinded retired from the Board on 18 October 2017.

⁽⁵⁾ The FY2017 remuneration for Ken MacKenzie and Grant King relates to part of the year only, as they joined the Board on 22 September 2016 and 1 March 2017, respectively. Ken MacKenzie became Chairman on 1 September 2017.

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3.3.12    Non-executive Directors’ remuneration in FY2019

In FY2019, the remuneration for the Non-executive Directors will be paid in accordance with the remuneration policy approved by shareholders at the 2017 AGMs. Fee levels for the Non-executive Directors and the Chairman are reviewed annually. The review includes benchmarking, with the assistance of external advisers, against peer companies.

From 1 July 2017, the Chairman’s annual fee was reduced by approximately eight per cent from US$0.960 million to US$0.880 million, and will remain at that level for FY2019. This fee reduction was in addition to the reduction of approximately 13 per cent from US$1.100 million to US$0.960 million effective 1 July 2015. Base fee levels for Non-executive Directors will remain at the reduced levels that took effect from 1 July 2015, at which time they were reduced by approximately six per cent from US$0.170 million to US$0.160 million per annum.

In recognition of the increasing workload of BHP’s Nomination and Governance Committee, a fee for members of that Committee was introduced with effect from 1 July 2018. The fee is US$18,000 per annum. There is no additional fee for the Chairman of that Committee as the role is performed by the Board Chairman who is paid a single fee for all responsibilities.

The adjacent table sets out the annualised fee levels for FY2019.

Levels of fees and travel allowances for Non-executive Directors (in US$)	From 1 July 2018
Base annual fee		160,000
Plus additional fees for:
Senior Independent Director of BHP Billiton Plc		48,000
Committee Chair:
Risk and Audit		60,000
Remuneration		45,000
Sustainability		45,000
Nomination and Governance		No additional fee
Committee membership:
Risk and Audit		32,500
Remuneration		27,500
Sustainability		27,500
Nomination and Governance		18,000
Travel allowance: (1)
Greater than 3 but less than 10 hours		7,000
10 hours or more		15,000
Chairman’s fee		880,000

⁽¹⁾  In relation to travel for Board business, the time thresholds relate to the flight time to travel to the meeting location (i.e. one way flight time).

240

Remuneration governance

3.3.13    Board oversight and the Remuneration Committee

Board

The Board is responsible for ensuring the Group’s remuneration arrangements are equitable and aligned with the long-term interests of BHP and its shareholders. In performing this function, it is critical that the Board is independent of management when making decisions affecting remuneration of the CEO, other Executive KMP and the Group’s employees.

The Board has therefore established a Remuneration Committee to assist it in making such decisions. The Committee is comprised solely of Non-executive Directors, all of whom are independent. To ensure that it is fully informed, the Committee regularly invites members of management to attend meetings to provide reports and updates. The Committee can draw on services from a range of external sources, including remuneration advisers.

Remuneration Committee

The activities of the Remuneration Committee are governed by Terms of Reference (approved by the Board in June 2018), which are available on our website. The current members of the Remuneration Committee are Carolyn Hewson (Chairman), Anita Frew, Wayne Murdy and Shriti Vadera. The role and focus of the Committee and details of meeting attendances can be found in section 2.13.2. Other Directors and employees who regularly attended meetings were: Ken MacKenzie (Chairman from 1 September 2017); Jac Nasser (Chairman to 31 August 2017); Andrew Mackenzie (CEO); Athalie Williams (Chief People Officer); Andrew Fitzgerald (Vice President Reward); Margaret Taylor (Group Company Secretary); and Geof Stapledon (Vice President Governance). These individuals were not present when matters associated with their own remuneration were considered.

Engagement of independent remuneration advisers

The Committee seeks and considers advice from independent remuneration advisers where appropriate. Remuneration consultants are engaged by, and report directly to, the Committee. Potential conflicts of interest are taken into account when remuneration consultants are selected and their terms of engagement regulate their level of access to, and require their independence from, BHP’s management.

PricewaterhouseCoopers was appointed by the Committee in March 2016 to act as an independent remuneration adviser.

The PricewaterhouseCoopers team that advises the Remuneration Committee does not provide any other services to the Group. Other parts of PricewaterhouseCoopers provide services to the Group in the areas of forensic and general technology, internal audit and international assignment solutions. Processes and arrangements are in place to protect independence (for example, ring-fencing of teams) and to manage any conflicts of interest that may arise.

PricewaterhouseCoopers is currently the only remuneration adviser appointed by the Committee. In that capacity, they may provide remuneration recommendations in relation to KMP, however they did not do so in FY2018.

Total fees paid to the PricewaterhouseCoopers team advising the Committee on remuneration-related matters for FY2018 were £128,100. These fees are based on an agreed fee for regular items with additional work charged at agreed rates. Total fees paid to PricewaterhouseCoopers for other services rendered to the Group for FY2018 were approximately US$19 million.

241

3.3.14    Statement of voting at the 2017 AGMs

BHP’s remuneration resolutions have attracted a high level of support by shareholders. Voting in regard to those resolutions put to shareholders at the 2017 AGMs is shown below.

AGM resolution	Requirement		% vote ‘for’		% vote ‘against’		Votes withheld (1)
Remuneration Report (remuneration policy)		UK		97.1		2.9		9,658,674
Remuneration Report (excluding remuneration policy)		UK		97.7		2.3		8,163,117
Remuneration Report (whole report)		Australia		96.9		3.1		8,442,607
Leaving entitlements		Australia		98.4		1.6		8,153,740
Approval of grants to Executive Director		Australia		95.7		4.3		74,099,923

⁽¹⁾  The sum of votes marked ‘Vote Withheld’ at BHP Billiton Plc’s AGM and votes marked ‘Abstain’ at BHP Billiton Limited’s AGM.

Other statutory disclosures

This section provides details of any additional statutory disclosures required by Australian or UK regulations that have not been included in the previous sections of the Remuneration Report.

3.3.15    Executive KMP remuneration table

The following table has been prepared in accordance with relevant accounting standards and remuneration data for Executive KMP are for the periods of FY2017 and FY2018 that they were KMP. More information on the policy and operation of each element of remuneration is provided in prior sections of this Report.

242

Share-based payments

The figures included in the shaded columns of the statutory table below for share-based payments were not actually provided to the KMP during FY2017 or FY2018. These amounts are calculated in accordance with accounting standards and are the amortised IFRS fair values of equity and equity-related instruments that have been granted to the executives. For information on awards that were allocated and vested during FY2017 and FY2018, refer to section 3.3.16.

					Short-term benefits						Post- employment benefits		Share-based payments				Total
US$(‘000)	Financial year		Base salary (1)		Annual cash incentive (2)		Non-monetary benefits (3)		Other benefits (4)		Retirement benefits (5)		Value of STI awards (2)(6)		Value of LTI awards (6)
Executive Director
Andrew Mackenzie		FY2018		1,700		1,224		84		–		425		779		3,894		8,106
		FY2017		1,700		1,170		90		–		425		752		2,955		7,092
Other Executive KMP (7)
Peter Beaven		FY2018		1,000		728		8		–		250		549		1,792		4,327
		FY2017		1,000		752		11		–		250		531		1,383		3,927
Mike Henry		FY2018		1,100		722		13		–		275		546		1,971		4,627
		FY2017		1,100		757		12		26		275		555		1,751		4,476
Daniel Malchuk		FY2018		1,000		792		13		19		250		507		1,751		4,332
		FY2017		1,000		584		12		39		250		468		1,326		3,679
Steve Pastor		FY2018		1,000		720		–		21		250		493		1,076		3,560
		FY2017		848		638		–		33		212		360		776		2,867

243

(1) Base salaries shown in this table reflect the amounts paid over the 12-month period from 1 July 2017 to 30 June 2018 for each executive. There were no changes to Executive KMP base salaries during the year.

(2) Annual cash incentive is the cash portion of STI awards earned in respect of performance during each financial year for each executive. STI is provided half in cash and half in deferred equity (which are included in the share-based payments columns of the table). The cash portion of STI awards is paid to Executive KMP in September of the year following the relevant financial year. The minimum possible value awarded to each individual is nil and the maximum is 240 per cent of base salary (120 per cent in cash and 120 per cent in deferred equity). For FY2018, Executive KMP earned the following STI awards as a percentage of the maximum (the remaining portion has been forfeited): Andrew Mackenzie 60 per cent, Peter Beaven 61 per cent, Mike Henry 55 per cent, Daniel Malchuk 66 per cent and Steve Pastor 60 per cent.

(3) Non-monetary benefits are non-pensionable and include such items as health and other insurances, fees for tax return preparation (if required in multiple jurisdictions), car parking and travel costs.

(4) Other benefits are non-pensionable and for FY2018 include an international relocation benefit for Daniel Malchuk and an encashment of annual leave entitlements under the US Annual Leave policy for Steve Pastor.

(5) Retirement benefits are 25 per cent of base salary for each Executive KMP.

(6) The IFRS fair value of both STI and LTI awards is estimated at grant date. Refer to section 5.1.6 note 22 for further details. The FY2018 LTI amount for Andrew Mackenzie includes a DEP and any change in fair value associated with FY2008 phantom LTI awards that vested in FY2013 and were cash settled in FY2018. Full details of the award were provided in the FY2013 Remuneration Report.

(7) Following the dissolution of the OMC in FY2018, the Committee re-examined the classification of KMP for FY2018 and determined that the roles that have the authority and responsibility for planning, directing and controlling the activities of BHP include all Non-executive Directors, the CEO, the Chief Financial Officer, the President Operations, Minerals Australia, the President Operations, Minerals Americas, and the President Operations, Petroleum. The Committee also determined that, effective 1 July 2017, the Chief External Affairs Officer and Chief People Officer roles (held by Geoff Healy and Athalie Williams respectively) were no longer considered KMP and therefore, there is no requirement to disclose their remuneration for FY2017 or FY2018.

3.3.16    Equity awards

The interests held by Executive KMP under the Group’s employee equity plans are set out below. Each equity award is a right to acquire one ordinary share in BHP Billiton Limited or in BHP Billiton Plc upon satisfaction of the vesting conditions. BHP Billiton Limited share awards are shown in Australian dollars. BHP Billiton Plc awards are shown in Pounds Sterling. The Our Requirements for Securities Dealing standard governs and restricts dealing arrangements and the provision of shares on vesting or exercise of awards. No interests under the Group’s employee equity plans are held by related parties of Executive KMP.

Dividend Equivalent Payments

DEP applies to awards provided to Executive KMP under the STIP and LTIP as detailed in section 3.2.3. No DEP is payable on Transitional Executive KMP awards, GSTIP awards or MAP awards.

Equity awards provided for Executive KMP service

STI awards under the STIP

Executive KMP receive their STI awards under the STIP. The terms and conditions of STIP awards, including the performance conditions, are described in sections 3.2.3 and 3.2.7 of this Report.

244

LTI awards under the LTIP

Executive KMP receive their LTI awards under the LTIP. The terms and conditions of LTIP awards, including the performance conditions, are described in sections 3.2.3 and 3.2.7 of this Report and the LTIP rules are available on our website.

Transitional Executive KMP awards

The Remuneration Committee is able to determine that new Executive KMP members recruited from within BHP receive Transitional Executive KMP awards to bridge the gap between MAP awards, which ordinarily have a three-year service condition and the LTIP awards, which have a five-year service and performance condition.

No Transitional Executive KMP awards were granted to Executive KMP in FY2018. Peter Beaven and Daniel Malchuk are the only Executive KMP who held Transitional Executive KMP awards at the commencement of FY2018.

Equity awards provided for pre-Executive KMP service

STI awards under the GSTIP and LTI awards under the MAP

BHP senior management who are not KMP receive their STI awards under the GSTIP and their LTI awards under the MAP. While no GSTIP or MAP awards were granted to Executive KMP during FY2018, Steve Pastor still holds GSTIP and MAP awards that were allocated to him prior to his Executive KMP service.

245

Award type

Date of grant

At 1 July 2017

Granted

Vested

Lapsed

At 30 June 2018

Award vesting date (1)

Market price on date of:

Gain on awards (‘000)  (4)

DEP on awards (‘000)

Grant (2)

Vesting (3)

Andrew Mackenzie

STIP

24 Nov 2017

–

56,217

–

–

56,217

Aug 19

A$27.97

–

–

–

STIP

4 Dec 2015

69,566

–

69,566

–

–

23 Aug 17

A$17.93

A$26.04

A$1,811

A$116

LTIP

24 Nov 2017

–

385,075

–

–

385,075

Aug 22

A$27.97

–

–

–

LTIP

9 Dec 2016

339,753

–

–

–

339,753

Aug 21

A$25.98

–

–

–

LTIP

4 Dec 2015

339,753

–

–

–

339,753

Aug 20

A$17.93

–

–

–

LTIP

19 Dec 2014

224,859

–

–

–

224,859

Aug 19

A$28.98

–

–

–

LTIP

18 Dec 2013

213,701

–

–

–

213,701

Aug 18

A$35.79

–

–

–

LTIP

5 Dec 2012

151,609

–

–

151,609

–

23 Aug 17

£19.98

–

–

–

Peter Beaven

STIP

24 Nov 2017

–

36,145

–

–

36,145

Aug 19

A$27.97

–

–

–

STIP

9 Dec 2016

10,958

–

–

–

10,958

Aug 18

A$25.98

–

–

–

STIP

4 Dec 2015

40,921

–

40,921

–

–

23 Aug 17

A$17.93

A$26.04

A$1,066

A$68

LTIP

24 Nov 2017

–

198,200

–

–

198,200

Aug 22

A$27.97

–

–

–

LTIP

9 Dec 2016

174,873

–

–

–

174,873

Aug 21

A$25.98

–

–

–

LTIP

4 Dec 2015

174,873

–

–

–

174,873

Aug 20

A$17.93

–

–

–

LTIP

19 Dec 2014

115,736

–

–

–

115,736

Aug 19

A$28.98

–

–

–

LTIP

18 Dec 2013

109,993

–

–

–

109,993

Aug 18

A$35.79

–

–

–

Transitional

18 Dec 2013

19,641

–

13,552

6,089

–

23 Aug 17

A$35.79

A$26.04

A$353

–

Mike Henry

STIP

24 Nov 2017

–

36,376

–

–

36,376

Aug 19

A$27.97

–

–

–

STIP

9 Dec 2016

10,663

–

–

–

10,663

Aug 18

A$25.98

–

–

–

STIP

4 Dec 2015

45,542

–

45,542

–

–

23 Aug 17

A$17.93

A$26.04

A$1,186

A$76

LTIP

24 Nov 2017

–

218,020

–

–

218,020

Aug 22

A$27.97

–

–

–

LTIP

9 Dec 2016

192,360

–

–

–

192,360

Aug 21

A$25.98

–

–

–

LTIP

4 Dec 2015

192,360

–

–

–

192,360

Aug 20

A$17.93

–

–

–

LTIP

19 Dec 2014

127,310

–

–

–

127,310

Aug 19

A$28.98

–

–

–

LTIP

18 Dec 2013

120,993

–

–

–

120,993

Aug 18

A$35.79

–

–

–

LTIP

5 Dec 2012

130,922

–

–

130,922

–

23 Aug 17

£19.98

–

–

–

Daniel Malchuk

STIP

24 Nov 2017

–

28,070

–

–

28,070

Aug 19

A$27.97

–

–

–

STIP

9 Dec 2016

9,694

–

–

–

9,694

Aug 18

A$25.98

–

–

–

STIP

4 Dec 2015

40,921

–

40,921

–

–

23 Aug 17

A$17.93

A$26.04

A$1,066

A$68

LTIP

24 Nov 2017

–

198,200

–

–

198,200

Aug 22

A$27.97

–

–

–

LTIP

9 Dec 2016

174,873

–

–

–

174,873

Aug 21

A$25.98

–

–

–

LTIP

4 Dec 2015

174,873

–

–

–

174,873

Aug 20

A$17.93

–

–

–

LTIP

19 Dec 2014

115,736

–

–

–

115,736

Aug 19

A$28.98

–

–

–

LTIP

18 Dec 2013

93,495

–

–

–

93,495

Aug 18

A$35.79

–

–

–

Transitional

18 Dec 2013

16,695

–

11,520

5,175

–

23 Aug 17

A$35.79

A$26.04

A$300

–

246

Award type

Date of grant

At 1 July 2017

Granted

Vested

Lapsed

At 30 June 2018

Award vesting date (1)

Market price on date of:

Gain on awards (‘000)  (4)

DEP on awards (‘000)

Grant (2)

Vesting (3)

Steve Pastor

STIP

24 Nov 2017

–

30,659

–

–

30,659

Aug 19

A$27.97

–

–

–

STIP

9 Dec 2016

2,697

–

–

–

2,697

Aug 18

A$25.98

–

–

–

LTIP

24 Nov 2017

–

198,200

–

–

198,200

Aug 22

A$27.97

–

–

–

LTIP

9 Dec 2016

139,898

–

–

–

139,898

Aug 21

A$25.98

–

–

–

GSTIP

9 Dec 2016

5,435

–

–

–

5,435

Aug 18

A$25.98

–

–

–

GSTIP

30 Oct 2015

20,124

–

20,124

–

–

23 Aug 17

A$23.02

A$26.04

A$524

–

MAP

24 Feb 2016

21,775

–

–

–

21,775

Aug 20

A$16.18

–

–

–

MAP

24 Feb 2016

21,775

–

–

–

21,775

Aug 19

A$16.18

–

–

–

MAP

30 Oct 2015

21,775

–

–

–

21,775

Aug 18

A$23.02

–

–

–

MAP

3 Nov 2014

23,441

–

23,441

–

–

23 Aug 17

A$33.71

A$26.04

A$610

–

247

⁽¹⁾  Where the vesting date is not yet known, the estimated vesting month is shown. Where awards lapse, the lapse date is shown. If the vesting conditions are met, awards will vest on, or as soon as practicable after, the first non-prohibited period date occurring after 30 June of the preceding year of vest. The year of vest is the second (STIP and GSTIP), third (MAP), fourth (Transitional) or fifth (LTIP) financial year after grant. Except for the LTIP awards granted on 5 December 2012, all awards are conditional awards and have no exercise period, exercise price or expiry date; instead ordinary fully paid shares are automatically delivered upon the vesting conditions being met. Where vesting conditions are not met, the conditional awards will immediately lapse. The LTIP awards granted on 5 December 2012 were non-conditional awards which had an exercise period and an expiry date of the day prior to the fifth anniversary of the vesting date, but have now lapsed in full. None of these awards had vested and were exercisable or had vested but were not exercisable at the end of the reporting period.

⁽²⁾  The market price shown is the closing price of BHP shares on the relevant date of grant. No price is payable by the individual to receive a grant of awards. The IFRS fair value of the STIP and LTIP awards granted in FY2018 is at the grant date of 24 November 2017, and are as follows: STIP – A$27.97 and LTIP – A$17.21.

⁽³⁾  The market price shown is the closing price of BHP shares on the relevant date of vest.

⁽⁴⁾  The gain on awards is calculated using the market price on date of vesting or exercise (as applicable) less any exercise price payable. The amounts that vested and were lapsed for the awards during FY2018 are as follows: STIP – 100 per cent vested; LTIP – 100 per cent lapsed; Transitional (Peter Beaven) – 69 per cent vested, 31 per cent lapsed; Transitional (Daniel Malchuk) – 69 per cent vested, 31 per cent lapsed; GSTIP – 100 per cent vested; MAP – 100 per cent vested.

3.3.17    Estimated value range of equity awards

The current face value (and estimate of the maximum possible total value) of equity awards allocated during FY2018 and yet to vest are the awards as set out in the previous table multiplied by the current share price of BHP Billiton Limited or BHP Billiton Plc as applicable. The minimum possible total value of the awards is nil.

The actual value that may be received by participants in the future cannot be determined as it is dependent on and therefore fluctuates with the share prices of BHP Billiton Limited and BHP Billiton Plc at the date that any particular award vests or is exercised. The table below provides five-year share price history for BHP Billiton Limited and BHP Billiton Plc, history of dividends paid and the Group’s earnings.

Five-year share price, dividend and earnings history

		FY2018		FY2017		FY2016			FY2015			FY2014
BHP Billiton Limited	Share price at beginning of year		A$23.23		A$19.09		A$26.58			A$36.00			A$30.94
	Share price at end of year		A$33.91		A$23.28		A$18.65			A$27.05			A$35.90
	Dividends paid		A$1.24		A$0.72		A$1.09			A$3.72	(1)		A$1.29
BHP Billiton Plc	Share price at beginning of year		£12.15		£9.40		£12.58			£19.45			£17.15
	Share price at end of year		£17.06		£11.76		£9.43			£12.49			£18.90
	Dividends paid		£0.72		£0.44		£0.51			£1.95	(1)		£0.73
BHP	Attributable profit /(loss) (US$M, as reported)		3,705		5,890		(6,385	)		1,910			13,832

⁽¹⁾  The FY2015 dividends paid includes A$2.25 or £1.15 in respect of the in-specie dividend associated with the demerger of South32.

The highest share prices during FY2018 were A$34.44 for BHP Billiton Limited shares and £17.79 for BHP Billiton Plc shares. The lowest share prices during FY2018 were A$23.23 and £12.15, respectively.

248

3.3.18    Ordinary share holdings and transactions

The number of ordinary shares in BHP Billiton Limited or in BHP Billiton Plc held directly, indirectly or beneficially, by each individual (including shares held in the name of all close members of the Director’s or Executive KMP’s family and entities over which either the Director or Executive KMP or the family member has, directly or indirectly, control, joint control or significant influence) are shown below. In addition, there have been no changes in the interests of any Directors in the period to 6 September 2018 (being not less than one month prior to the date of the notice of the 2018 AGMs). These are ordinary shares held without performance conditions or restrictions and are included in MSR calculations for each individual.

The interests of Directors and Executive KMP in the ordinary shares of each of BHP Billiton Limited and BHP Billiton Plc as at 30 June 2018 did not exceed on an individual basis or in the aggregate one per cent of BHP Billiton Limited’s or BHP Billiton Plc’s issued ordinary shares.

BHP Billiton Limited Shares

BHP Billiton Plc Shares

Held at 1 July 2017

Purchased

Received as remuneration (1)

Sold

Held at 30 June 2018

Held at 1 July 2017

Purchased

Received as remuneration (1)

Sold

Held at 30 June 2018

Executive Director

Andrew Mackenzie

55,200

–

74,072

36,221

93,051

266,205

–

–

–

266,205

Other Executive KMP

Peter Beaven

266,359

–

57,124

26,793

296,690

–

–

–

–

–

Mike Henry

65,278

–

48,492

21,777

91,993

196,262

–

–

–

196,262

Daniel Malchuk

126,530

–

55,092

17,568

164,054

–

–

–

–

–

Steve Pastor (2)

27,681

–

43,565

18,293

52,953

–

–

–

–

–

Non-executive Directors

Terry Bowen (3)

11,000

–

–

–

11,000

–

–

–

–

–

Malcolm Brinded (4)

–

–

–

–

–

60,000

–

–

–

60,000

Malcolm Broomhead

19,000

–

–

–

19,000

–

–

–

–

–

Anita Frew

–

–

–

–

–

15,000

–

–

–

15,000

Carolyn Hewson

19,000

–

–

–

19,000

–

–

–

–

–

Grant King (4)

20,000

–

–

–

20,000

–

–

–

–

–

Ken MacKenzie

15,000

32,856

–

–

47,856

–

–

–

–

–

Lindsay Maxsted

18,000

–

–

–

18,000

–

–

–

–

–

John Mogford (3)

–

–

–

–

–

12,000

–

–

–

12,000

Wayne Murdy (2)

8,000

–

–

–

8,000

24,000

–

–

–

24,000

Jac Nasser (2) (4)

20,400

–

–

–

20,400

81,200

–

–

–

81,200

Shriti Vadera

–

–

–

–

–

25,000

–

–

–

25,000

⁽¹⁾  Includes DEP in the form of shares on equity awards vesting as disclosed in section 3.3.16.

⁽²⁾  The following BHP Billiton Limited shares and BHP Billiton Plc shares are held in the form of American Depositary Shares: Wayne Murdy (4,000 BHP Billiton Limited; 12,000 BHP Billiton Plc), Jac Nasser (5,200 BHP Billiton Limited; 40,600 BHP Billiton Plc) and Steve Pastor (1,574 BHP Billiton Limited).

⁽³⁾  The opening balances for Terry Bowen and John Mogford reflect their shareholdings on the date that each became KMP being 1 October 2017 for both.

⁽⁴⁾  The closing balances for Malcolm Brinded, Grant King and Jac Nasser reflect their shareholdings on the date that each ceased being KMP being 18 October 2017, 31 August 2017 and 31 August 2017, respectively.

3.3.19    Prohibition on hedging of shares and equity instruments

The CEO and other Executive KMP may not use unvested BHP equity awards as collateral, or protect the value of any unvested BHP equity awards or the value of shares and securities held as part of meeting the MSR.

249

Any securities that have vested and are no longer subject to restrictions may be subject to hedging arrangements or used as collateral, provided that prior consent is obtained.

3.3.20    Share ownership guidelines and the MSR

The share ownership guidelines and the MSR help to ensure the interests of Directors, executives and shareholders remain aligned.

The CEO and other Executive KMP are expected to grow their holdings to the MSR from the scheduled vesting of their employee awards over time. The MSR is tested at the time that shares are to be sold. Shares may be sold to satisfy tax obligations arising from the granting, holding, vesting, exercise or sale of the employee awards or the underlying shares whether the MSR is satisfied at that time or not.

For FY2018:

• the MSR for the CEO was five times annual pre-tax base salary and while he has met this requirement in the past, subsequent movements in foreign exchange rates and share prices have resulted in Andrew Mackenzie’s shareholding being 4.3 times his annual pre-tax base salary at the end of FY2018;

• the MSR for other Executive KMP was three times annual pre-tax base salary. At the end of FY2018, Peter Beaven, Mike Henry and Daniel Malchuk met the MSR, while Steve Pastor did not. No Executive KMP sold shares during FY2018, other than to satisfy taxation obligations.

Subject to securities dealing constraints, Non-executive Directors have agreed to apply at least 25 per cent of their remuneration (base fees plus Committee fees) to the purchase of BHP shares until they achieve an MSR equivalent in value to one year’s remuneration (base fees plus Committee fees). Thereafter, they must maintain at least that level of shareholding throughout their tenure. At the end of FY2018, each Non-executive Director met the MSR.

3.3.21    Payments to past Directors and for loss of office

UK regulations require the inclusion in the Remuneration Report of certain payments to past Directors and payments made for loss of office. There is nothing to disclose for these payments for FY2018. The Remuneration Committee has adopted a de minimis threshold of US$7,500 for disclosure of payments to past Directors under UK requirements.

3.3.22    Relative importance of spend on pay

The table below sets out the total spend for continuing operations on employee remuneration during FY2018 (and the prior year) compared with other significant expenditure items, and includes items as prescribed in the UK requirements. BHP has included tax payments and purchases of property, plant and equipment being the most significant other outgoings in monetary terms.

US$ million	FY2018		FY2017 (1)
Aggregate employee benefits expense		4,072		3,773
Dividends paid to BHP shareholders		5,220		2,921
Share buy-backs		–		–
Income tax paid and royalty-related taxation paid (net of refunds)		4,918		2,248
Purchases of property, plant and equipment		4,979		3,697

⁽¹⁾  The financial information for FY2017 has been restated for the effects of the application of IFRS 5/AASB 5 ‘Non-current Assets Held for Sale and Discontinued Operations’ following the announcement of the agreements for the sale of the Onshore US oil and gas assets.

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3.3.23    Transactions with KMP

During the financial year, there were no transactions between the Group and its subsidiaries and KMP (including their related parties) (2017: US$ nil; 2016: US$ nil). There were no amounts payable at 30 June 2018 (2017: US$ nil). There were US$ nil loans (2017: US$ nil) with KMP (including their related parties).

A number of KMP hold or have held positions in other companies (i.e. personally related entities), where it is considered they control or significantly influence the financial or operating policies of those entities. There have been no transactions with those entities and no amounts were owed by the Group to personally related entities or any other related parties (2017: US$ nil).

This Remuneration Report was approved by the Board on 6 September 2018 and signed on its behalf by:

Carolyn Hewson

Chairman, Remuneration Committee

6 September 2018

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4    Directors’ Report

The information presented by the Directors in this Directors’ Report relates to BHP Billiton Limited, BHP Billiton Plc and their respective subsidiaries. Section 1 ‘Strategic Report’ (which includes the Chairman’s Review in section 1.1 and the Chief Executive Officer’s Report in section 1.2, and incorporates the operating and financial review), section 2 ‘Governance at BHP’, section 3 ‘Remuneration Report’, section 5.5 ‘Lead Auditor’s Independence Declaration’ and section 7 ‘Shareholder information’ are each incorporated by reference into, and form part of, this Directors’ Report. In addition, for the purposes of UK law, the Strategic Report in section 1 and the Remuneration Report in section 3 form separate reports and have been separately approved by the Board for that purpose.

For the purpose of the UK Listing Authority’s (UKLA) Listing Rule 9.8.4C R, the applicable information required to be disclosed in accordance with UKLA Listing Rule 9.8.4 R is set out in the sections below.

Applicable information required by UKLA Listing Rule 9.8.4 R	Section in this Annual Report
(1)  Interest capitalised by the Group	Section 5, note 19
(6)  Waiver of future emoluments	Section 3.3.1
(12) Shareholder waivers of dividends	Section 5, note 22
(13) Shareholder waivers of future dividends	Section 5, note 22

Paragraphs (2), (4), (5), (7), (8), (9), (10), (11) and (14) of Listing Rule 9.8.4 R are not applicable.

The Directors confirm, on the advice of the Risk and Audit Committee, that they consider the Annual Report (including the Financial Statements), taken as a whole, is fair, balanced and understandable, and provides the information necessary for shareholders to assess BHP’s position, performance, business model and strategy.

4.1    Review of operations, principal activities and state of affairs

A review of the operations of BHP during FY2018, the results of those operations during FY2018 and the expected results of those operations in future financial years are set out in section 1, in particular in 1.1 to 1.8, 1.11 and 1.12 and in other material in this Annual Report. Information on the development of BHP and likely developments in future years also appears in those sections.

Our principal activities during FY2018 are disclosed in section 1. We are among the world’s top producers of major commodities, including iron ore, metallurgical coal and copper. We also have substantial interests in oil, gas and energy coal. No significant changes in the nature of BHP’s principal activities occurred during FY2018 other than as disclosed in section 1.

There were no significant changes in BHP’s state of affairs that occurred during FY2018 and no significant post balance date events other than as disclosed in section 1.

No other matter or circumstance has arisen since the end of FY2018 that has significantly affected or is expected to significantly affect the operations, the results of operations or state of affairs of BHP in future years.

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4.2    Share capital and buy-back programs

At the Annual General Meetings held in 2016 and 2017, shareholders authorised BHP Billiton Plc to make on-market purchases of up to 211,207,180 of its ordinary shares, representing 10 per cent of BHP Billiton Plc’s issued share capital at that time. During FY2018, we did not make any on-market or off-market purchases of BHP Billiton Limited shares or BHP Billiton Plc shares under any share buy-back program. As at the date of this Directors’ Report, there were no current on-market buy-backs. Shareholders will be asked at the 2018 Annual General Meetings to renew this authority. As at the date of this Directors’ Report, there is currently no intention to exercise this authority. However, as advised to the market on 27 July 2018, BHP expects to return to shareholders the net proceeds from the sale of BHP’s Onshore US assets, the form and timing of that return to be confirmed at the time of completion of the sale. If shareholders renew the buy-back authority, it is possible that the Directors may use the authority in connection with the return of the Onshore US sale proceeds to shareholders.

Some of our executives receive rights over BHP shares as part of their remuneration arrangements. Entitlements may be satisfied by the transfer of existing shares, which are acquired on-market by the Employee Share Ownership Plan (ESOP) Trusts or, in respect of some entitlements, by the issue of shares.

The number of shares referred to in column ‘A’ below were purchased to satisfy awards made under the various BHP Billiton Limited and BHP Billiton Plc employee share schemes during FY2018.

Period	A Total number of shares purchased		B Average price paid per share (1) US$		C Total number of shares purchased as part of publicly announced plans or programs		D Maximum number of shares that may yet be purchased under the plans or programs
							BHP Billiton Limited (2)		BHP Billiton Plc
1 Jul 2017 to 31 Jul 2017		4,071,150		19.64		–		–		211,207,180	(3)
1 Aug 2017 to 31 Aug 2017		794,182		20.17		–		–		211,207,180	(3)
1 Sep 2017 to 30 Sep 2017		–		–		–		–		211,207,180	(3)
1 Oct 2017 to 31 Oct 2017		8,185		18.19		–		–		211,207,180	(3)
1 Nov 2017 to 30 Nov 2017		–		–		–		–		211,207,180	(3)
1 Dec 2017 to 31 Dec 2017		–		–		–		–		211,207,180	(3)
1 Jan 2018 to 31 Jan 2018		–		–		–		–		211,207,180	(3)
1 Feb 2018 to 28 Feb 2018		–		–		–		–		211,207,180	(3)
1 Mar 2018 to 31 Mar 2018		3,254,516		23.02		–		–		211,207,180	(3)
1 Apr 2018 to 30 Apr 2018		4,766		23.96		–		–		211,207,180	(3)
1 May 2018 to 31 May 2018		–		–		–		–		211,207,180	(3)
1 Jun 2018 to 30 Jun 2018		–		–		–		–		211,207,180	(3)
Total		8,132,799		21.04		–		–		211,207,180	(3)

⁽¹⁾  The shares were purchased in the currency of the stock exchange on which the purchase took place and the sale price has been converted into US dollars at the exchange rate on the day of purchase.

⁽²⁾  BHP Billiton Limited is able to buy-back and cancel BHP Billiton Limited shares within the ‘10/12 limit’ without shareholder approval in accordance with section 257B of the Australian Corporations Act 2001. Any future on-market share buy-back program would be conducted in accordance with the Australian Corporations Act 2001 and with the ASX Listing Rules.

⁽³⁾  At the Annual General Meetings held during 2016 and 2017, shareholders authorised BHP Billiton Plc to make on-market purchases of up to 211,207,180 of its ordinary shares, representing 10 per cent of BHP Billiton Plc’s issued capital at the time.

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4.3    Results, financial instruments and going concern

Information about the Group’s financial position and financial results is included in the Financial Statements in this Annual Report. The Consolidated Income Statement shows profit attributable to BHP members of US$3.7 billion in FY2018, compared with a profit of US$5.9 billion in FY2017.

BHP’s business activities, together with the factors likely to affect its future development, performance and position, are discussed in section 1. In addition, sections 1.3 to 1.6 and 2.14, and note 20 ‘Financial risk management’ in section 5 outline BHP’s capital management objectives, its approach to financial risk management and exposure to financial risks, liquidity and borrowing facilities.

The Directors, having made appropriate enquiries, have a reasonable expectation that BHP has adequate resources to continue in operational existence for the foreseeable future. Therefore, they continue to adopt the going concern basis of accounting in preparing the annual Financial Statements.

4.4    Directors

The Directors who served at any time during FY2018 or up until the date of this Directors’ Report were Jac Nasser, Andrew Mackenzie, Terry Bowen, Malcolm Brinded, Malcolm Broomhead, Anita Frew, Carolyn Hewson, Grant King, Ken MacKenzie, Lindsay Maxsted, John Mogford, Wayne Murdy and Shriti Vadera. Further details of the current Directors of BHP Billiton Limited and BHP Billiton Plc are set out in section 2.2. These details include the period for which each Director held office up to the date of this Directors’ Report, their qualifications, experience and particular responsibilities, the directorships held in other listed companies since 1 July 2015 and the period for which each directorship has been held.

Grant King was appointed as a Non-executive Director of BHP Billiton Limited and BHP Billiton Plc with effect from 1 March 2017. Mr King decided not to stand for election at the 2017 Annual General Meetings and retired as a Non-executive Director on 31 August 2017.

Jac Nasser retired as Chairman and a Director of BHP Billiton Limited and BHP Billiton Plc on 31 August 2017, having been a Director of BHP Billiton Limited and BHP Billiton Plc since June 2006 and Chairman of BHP Billiton Limited and BHP Billiton Plc since March 2010. Ken MacKenzie assumed the role of Chairman of BHP Billiton Limited and BHP Billiton Plc from 1 September 2017.

Malcolm Brinded served as a Non-executive Director of BHP Billiton Limited and BHP Billiton Plc from April 2014. Mr Brinded decided not to stand for re-election at the 2017 Annual General Meetings and retired as a Non-executive Director of BHP Billiton Limited and BHP Billiton Plc on 18 October 2017.

Terry Bowen was appointed as a Non-executive Director of BHP Billiton Limited and BHP Billiton Plc with effect from 1 October 2017. In accordance with the BHP Billiton Limited Constitution and BHP Billiton Plc Articles of Association, he stood for election and was elected at the 2017 Annual General Meetings.

John Mogford was appointed as a Non-executive Director of BHP Billiton Limited and BHP Billiton Plc with effect from 1 October 2017. In accordance with the BHP Billiton Limited Constitution and BHP Billiton Plc Articles of Association, he stood for election and was elected at the 2017 Annual General Meetings.

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Wayne Murdy has announced that he will retire as a Non-executive Director of BHP Billiton Limited and BHP Billiton Plc at the conclusion of the BHP Billiton Limited Annual General Meeting in November 2018.

The number of meetings of the Board and its Committees held during the year and each Director’s attendance at those meetings are set out in section 2.12.

4.5    Remuneration and share interests

4.5.1    Remuneration

The policy for determining the nature and amount of emoluments of the Executive Key Management Personnel (KMP) (including the Executive Director) and the Non-executive Directors, and information about the relationship between that policy and BHP’s performance, are set out in sections 3.2 and 3.3.

The remuneration tables contained in section 3.3 set out the remuneration of members of the Executive KMP (including the Executive Director) and the Non-executive Directors.

4.5.2    Directors

Section 3.3.18 sets out the relevant interests in shares in BHP Billiton Limited and BHP Billiton Plc of the Directors who held office during FY2018, at the beginning and end of FY2018. No rights or options over shares in BHP Billiton Limited and BHP Billiton Plc are held by any of the Non-executive Directors. Interests held by the Executive Director under employee equity plans as at 30 June 2018 are set out in the tables showing interests in incentive plans contained in section 3.3.16. Except for Andrew Mackenzie, as at the date of this Directors’ Report, the information pertaining to shares in BHP Billiton Limited and BHP Billiton Plc held directly, indirectly or beneficially by Directors is the same as set out in the table in section 3.3.18. Where applicable, the information includes shares held in the name of a spouse, superannuation fund, nominee and/or other controlled entities.

As at the date of this Directors’ Report, Andrew Mackenzie holds:

• (either directly, indirectly or beneficially) 266,205 shares in BHP Billiton Plc and 93,051 shares in BHP Billiton Limited;

• rights and options over nil shares in BHP Billiton Plc and 1,345,657 shares in BHP Billiton Limited.

We have not made available to any Director any interest in a registered scheme.

4.5.3    Key Management Personnel

Section 3.3.18 sets out the relevant interests in shares in BHP Billiton Limited and BHP Billiton Plc held directly, indirectly or beneficially at the beginning and end of FY2018 by those senior executives who were Executive KMP (other than the Executive Director) during FY2018. Where applicable, the information includes shares held in the name of a spouse, superannuation fund, nominee and/or other controlled entities. Interests held by members of the Executive KMP under employee equity plans as at 30 June 2018 are set out in the tables contained in section 3.3.16.

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The table below sets out the relevant interests in shares in BHP Billiton Limited and BHP Billiton Plc held directly, indirectly or beneficially, as at the date of this Directors’ Report by those senior executives who were Executive KMP (other than the Executive Director) on that date. Where applicable, the information also includes shares held in the name of a spouse, superannuation fund, nominee and/or other controlled entities.

Executive KMP member	BHP Billiton entity	As at date of Directors’ Report
Peter Beaven	BHP Billiton Limited BHP Billiton Plc		240,262 –
Mike Henry	BHP Billiton Limited BHP Billiton Plc		98,062 196,262
Daniel Malchuk	BHP Billiton Limited BHP Billiton Plc		174,355 –
Steve Pastor	BHP Billiton Limited BHP Billiton Plc		70,795 –

4.6    Secretaries

Margaret Taylor is the Group Company Secretary. Details of her qualifications and experience are set out in section 2.2. The following people also act, or have acted during FY2018, as company secretaries of BHP Billiton Limited, BHP Billiton Plc or both (as indicated): Rachel Agnew, BComm (Economics), LLB (Hons) (BHP Billiton Limited and BHP Billiton Plc), Kathryn Griffiths, BA, LLB (Hons), GDipACG, FCIS, FGIA, GAICD (BHP Billiton Limited), Megan Pepper, BA (Hons), LLB (Hons), GDipACG, FCIS, FGIA, GAICD (BHP Billiton Limited) and Geof Stapledon, BEc, LLB (Hons), DPhil, FCIS (BHP Billiton Plc). Each such individual has experience in a company secretariat role or other relevant fields arising from time spent in such roles within BHP, other large listed companies or other relevant entities.

4.7    Indemnities and insurance

Rule 146 of the BHP Billiton Limited Constitution and Article 146 of the BHP Billiton Plc Articles of Association require each Company to indemnify, to the extent permitted by law, each Officer of BHP Billiton Limited and BHP Billiton Plc, respectively, against liability incurred in, or arising out of, the conduct of the business of BHP or the discharge of the duties of the Officer. The Directors named in section 2.2, the Company Secretaries and other Officers of BHP Billiton Limited and BHP Billiton Plc have the benefit of this requirement, as do individuals who formerly held one of those positions.

In accordance with this requirement, BHP Billiton Limited and BHP Billiton Plc have entered into Deeds of Indemnity, Access and Insurance (Deeds of Indemnity) with each of their respective Directors. The Deeds of Indemnity are qualifying third party indemnity provisions for the purposes of the UK Companies Act 2006 and each of these qualifying third party indemnities was in force as at the date of this Directors’ Report.

We have a policy that BHP will, as a general rule, support and hold harmless an employee, including an employee appointed as a Director of a subsidiary who, while acting in good faith, incurs personal liability to others as a result of working for BHP.

In addition, as part of the arrangements to effect the demerger of South32, we agreed to indemnify certain former Officers of BHP who transitioned to South32 from certain claims and liabilities incurred in their capacity as Directors or Officers of South32.

From time to time, we engage our External Auditor, KPMG, to conduct non-statutory audit work and provide other services in accordance with our policy on the provision of other services by the External Auditor. The terms of engagement in the United Kingdom include that we must compensate and reimburse KPMG LLP for, and protect KPMG LLP against, any loss, damage, expense, or liability incurred by KPMG LLP in respect of third party claims arising from a breach by BHP of any obligation under the engagement terms.

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We have insured against amounts that we may be liable to pay to Directors, Company Secretaries or certain employees (including former Officers) pursuant to Rule 146 of the Constitution of BHP Billiton Limited and Article 146 of the Articles of Association of BHP Billiton Plc or that we otherwise agree to pay by way of indemnity. The insurance policy also insures Directors, Company Secretaries and some employees (including former Officers) against certain liabilities (including legal costs) they may incur in carrying out their duties. For this Directors’ and Officers’ insurance, we paid premiums of US$3,197,137 net during FY2018.

During FY2018, BHP paid defence costs for:

• certain employees and former employees of BHP Billiton Brasil (Affected Individuals) in relation to the charges filed by the Federal Prosecutors’ Office against BHP Billiton Brasil and the Affected Individuals;

• certain employees and former employees of BHP in relation to the putative class action complaint that was filed in the US District Court for the Southern District of New York on behalf of purchasers of American Depositary Receipts of BHP Billiton Limited and BHP Billiton Plc between 25 September 2014 and 30 November 2015;

• certain employees and former employees of BHP in relation to a putative class action complaint filed in the US District Court for the Southern District of New York on behalf of all purchasers of Samarco’s ten-year bond notes due 2022–2024 between 31 October 2012 and 30 November 2015.

Other than as set out above, no indemnity in favour of a current or former officer of BHP Billiton Limited or BHP Billiton Plc, or in favour of the External Auditor, was called on during FY2018.

4.8    Employee policies

Our people are fundamental to our success. We are committed to shaping a culture where our employees are provided with opportunities to develop, are valued and are encouraged to contribute towards making work safer, simpler and more productive. We strongly believe that having employees who are engaged and connected to BHP reinforces our shared purpose aligned to Our Charter and will result in a more productive workplace.

For more information on employee engagement and employee policies, including communications and regarding disabilities, refer to section 1.7.

4.9    Corporate governance

The UK Financial Conduct Authority’s Disclosure and Transparency Rules (DTR 7.2) require that certain information be included in a corporate governance statement. BHP has an existing practice of issuing a corporate governance statement as part of our Annual Report that is incorporated into the Directors’ Report by reference. The information required by the Disclosure and Transparency Rules and the UK Financial Conduct Authority’s Listing Rules (LR 9.8.6) is located in section 2, with the exception of the information referred to in LR 9.8.6 (1), (3) and (4) and DTR 7.2.6, which is located in sections 4.2, 4.3, 4.5.2 and 4.18.

4.10    Dividends

A final dividend of 63 US cents per share will be paid on 25 September 2018, resulting in total dividends determined in respect of FY2018 of 118 US cents per share. Details of the dividends paid are set out in notes 14 ‘Share capital’ and 16 ‘Dividends’ in section 5, and details of the Group’s dividend policy are set out in sections 1.4.3, 1.5.1 and 7.7.

4.11    Auditors

A resolution to reappoint KPMG LLP as the auditor of BHP Billiton Plc will be proposed at the 2018 Annual General Meetings in accordance with section 489 of the UK Companies Act 2006.

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Consistent with the UK and EU requirements in regard to audit firm tender and rotation, BHP conducted an audit tender during FY2017. After a comprehensive tender process, the Board selected EY to be appointed as the Group’s auditor from the financial year beginning 1 July 2019, subject to shareholder approval. The Board intends to seek shareholder approval at the Annual General Meetings in 2019 for the appointment of EY as the auditor for BHP Billiton Plc. KPMG, BHP’s current External Auditor, did not participate in the tender due to UK and EU requirements which require a new External Auditor to be in place by 1 July 2023. KPMG will continue in its role and will undertake the audit of BHP for the 2018 and 2019 financial years, subject to reappointment by shareholders at the 2018 Annual General Meetings.

During FY2018, Lindsay Maxsted was the only officer of BHP who previously held the role of director or partner of the Group’s External Auditor at a time when the Group’s External Auditor conducted an audit of BHP. His prior relationship with KPMG is outlined in section 2.10. Lindsay Maxsted was not part of the KPMG audit practice after 1980 and, while at KPMG, was not in any way involved in, or able to influence, any audit activity associated with BHP.

Each person who held the office of Director at the date the Board approved this Directors’ Report made the following statements:

• so far as the Director is aware, there is no relevant audit information of which BHP’s External Auditor is unaware;

• the Director has taken all steps that he or she ought to have taken as a Director to make him or herself aware of any relevant audit information and to establish that BHP’s External Auditor is aware of that information.

This confirmation is given pursuant to section 418 of the UK Companies Act 2006 and should be interpreted in accordance with, and subject to, those provisions.

4.12    Non-audit services

Details of the non-audit services undertaken by BHP’s External Auditor, including the amounts paid for non-audit services, are set out in 35 ‘Auditor’s remuneration’ in section 5. All non-audit services were approved in accordance with the process set out in the Policy on Provision of Audit and Other Services by the External Auditor. No non-audit services were carried out that were specifically excluded by the Policy on Provision of Audit and Other Services by the External Auditor. Based on advice provided by the Risk and Audit Committee, the Directors have formed the view that the provision of non-audit services is compatible with the general standard of independence for auditors, and that the nature of non-audit services means that auditor independence was not compromised. For more information about our policy in relation to the provision of non-audit services by the auditor, refer to section 2.13.1.

4.13    Political donations

No political contributions/donations for political purposes were made by BHP to any political party, politician, elected official or candidate for public office during FY2018.⁽¹⁾

4.14    Exploration, research and development

Companies within the Group carry out exploration and research and development necessary to support their activities. Details are provided in sections 1.6.3, 1.10 to 1.12 and 6.3.

⁽¹⁾  Note that Australian Electoral Commission (AEC) disclosure requirements are broad, such that amounts that are not political donations can be reportable for AEC purposes. For example, where a political party or organisation owns shares in BHP, the AEC filing requires the political party or organisation to disclose the dividend payments received in respect of their shareholding.

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4.15    ASIC Instrument 2016/191

BHP Billiton Limited is an entity to which Australian Securities and Investments Commission (ASIC) Corporations (Rounding in Financial/Directors’ Reports) Instrument 2016/191 dated 24 March 2016 applies. Amounts in this Directors’ Report and the Financial Statements, except estimates of future expenditure or where otherwise indicated, have been rounded to the nearest million dollars in accordance with ASIC Instrument 2016/191.

4.16    Proceedings on behalf of BHP Billiton Limited

No proceedings have been brought on behalf of BHP Billiton Limited, nor has any application been made, under section 237 of the Australian Corporations Act 2001.

4.17    Performance in relation to environmental regulation

BHP seeks to be compliant with all applicable environmental laws and regulations relevant to its operations. We monitor compliance on a regular basis, including through external and internal means, to minimise the risk of non-compliance. For more information on BHP’s performance in relation to health, safety and the environment, refer to section 1.9.

Fines and prosecutions

For the purposes of section 299 (1)(f) of the Australian Corporations Act 2001, in FY2018 BHP received eight fines in relation to Australian environmental laws and regulations at our operated assets, the total amount payable being US$68,186. Three fines were received at Saraji: unauthorised release of mine affected water (US$9,021), maintenance of hydrocarbon measures (US$9,020) and failure to comply with Plan of Operations – Hakea Diversion (US$2,333). Three fines were received at Caval Ridge: contaminated release of water (US$9,335), unauthorised release point ($9,335) and lack of monitoring data to show compliance with site erosion and sediment control plan (US$9,021). One fine was received at Daunia: unauthorised release point (US$9,021), and one fine was received at Mt Arthur Coal: failing to comply with an environmental protection notice (US$11,100).

Greenhouse gas emissions

The UK Companies Act 2006 requires BHP, to the extent practicable, to obtain relevant information on the Group’s annual quantity of greenhouse gas emissions, which is reported in tonnes of carbon dioxide equivalent. In accordance with those UK requirements, information on BHP’s total FY2018 greenhouse gas emissions and intensity has been included in sections 1.5.2 and 1.9.8.

For more information on environmental performance, including environmental regulation, refer to section 1.9 and the Sustainability Report 2018, which is available online at bhp.com.

4.18    Share capital, restrictions on transfer of shares and other additional information

Information relating to BHP Billiton Plc’s share capital structure, restrictions on the holding or transfer of its securities or on the exercise of voting rights attaching to such securities, certain agreements triggered on a change of control and the existence of branches of BHP outside of the United Kingdom, is set out in the following sections:

• Section 1.4.4 (Our locations)

• Section 4.2 (Share capital and buy-back programs)

• Section 7.3 (Organisational structure)

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• Section 7.4 (Material contracts)

• Section 7.5 (Constitution)

• Section 7.6 (Share ownership)

• Section 7.11 (Government regulations)

• Note 14 ‘Share capital’ and note 22 ‘Employee share ownership plans’ in section 5.

As at the date of this Directors’ Report, there were 19,935,506 unvested equity awards outstanding in relation to BHP Billiton Limited ordinary shares and 536,077 unvested equity awards outstanding in relation to BHP Billiton Plc ordinary shares. The expiry dates of these unvested equity awards range between August 2019 and August 2022 and there is no exercise price. No options over unissued shares or unissued interests in BHP have been granted since the end of FY2018 and no shares or interests were issued as a result of the exercise of an option over unissued shares or interests since the end of FY2018. Further details are set out in note 22 ‘Employee share ownership plans’ in section 5. Details of movements in share capital during and since the end of FY2018 are set out in note 14 ‘Share capital’ in section 5.

The Directors’ Report is approved in accordance with a resolution of the Board.

Ken MacKenzie	Andrew Mackenzie
Chairman	Chief Executive Officer
Dated: 6 September 2018

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5    Financial Statements

Refer to the pages beginning on page F-1 in this annual report.

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Section 6

Additional information

In this section

6.1 Information on mining operations

6.2 Production

6.3 Reserves

6.4 Major projects

6.5 Legal proceedings

6.6 Glossary

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6.1    Information on mining operations

Minerals Australia

Copper mining operations

The following table contains additional details of our mining operations. This table should be read in conjunction with the production table (refer to section 6.2.1) and reserves table (refer to section 6.3.2).

Mine & location	Means of access	Ownership	Operator	Title, leases or options	History	Mine type & mineralisation style	Power source	Facilities, use & condition
Olympic Dam
560 km northwest of Adelaide, South Australia	Public road Copper cathode trucked to ports Uranium oxide transported by road to ports	BHP 100%	BHP	Mining lease granted by South Australian Government expires in 2036 Right of extension for 50 years (subject to remaining mine life)	Acquired in 2005 as part of WMC acquisition Copper production began in 1988 Nominal milling capacity raised to 9 Mtpa in 1999 Optimisation project completed in 2002 New copper solvent extraction plant commissioned in 2004 Major smelter maintenance campaign completed in 2018	Underground Large poly-metallic deposit of iron oxide-copper-uranium-gold mineralisation	Electricity transmitted via (i) BHP’s 275 kV power line from Port Augusta and (ii) ElectraNet’s system upstream of Port Augusta. Energy purchased via Retail Agreement	Underground automated train and trucking network feeding crushing, storage and ore hoisting facilities 2 grinding circuits Nominal milling capacity: 10.3 Mtpa Flash furnace produces copper anodes, then refined to produce copper cathodes Electrowon copper cathode and uranium oxide concentrate produced by leaching and solvent extracting flotation tailings

263

Iron ore mining operations

The following table contains additional details of our iron ore mining operations. This table should be read in conjunction with the production table (refer to section 6.2.1) and reserves table (refer to section 6.3.2).

Mine & location	Means of access	Ownership	Operator	Title, leases or options	History	Mine type & mineralisation style	Power source	Facilities, use & condition
WAIO
Mt Newman joint venture
Pilbara region, Western Australia Mt Whaleback Orebodies 18, 24, 25, 29, 30, 31, 32 and 35	Private road Ore transported by Mt Newman JV-owned rail to Port Hedland (427 km)	BHP 85% Mitsui-ITOCHU Iron 10% ITOCHU Minerals and Energy of Australia 5%	BHP	Mineral lease granted and held under the Iron Ore (Mount Newman) Agreement Act 1964 expires in 2030 with right to successive renewals of 21 years each	Production began at Mt Whaleback in 1969 Production from Orebodies 18, 24, 25, 29, 30, 31, 32 and 35 complements production from Mt Whaleback Production from Orebodies 31 and 32 started in 2015 and 2017 respectively	Open-cut Bedded ore types classified as per host Archaean or Proterozoic iron formation, which are Brockman and Marra Mamba	Power for all mine operations both in the Central and Eastern Pilbara is supplied by BHP’s natural gas fired Yarnima power station. Power consumed in port operations is supplied via a contract with Alinta	Newman Hub: primary crusher, ore handling plant, heavy media beneficiation plant, stockyard blending facility, single cell rotary car dumper, train load out (nominal capacity 73 Mtpa) Orebody 25 Ore processing plant (nominal capacity 12 Mtpa)

264

Mine & location	Means of access	Ownership	Operator	Title, leases or options	History	Mine type & mineralisation style	Power source	Facilities, use & condition
Yandi joint venture
Pilbara region, Western Australia	Private road Ore transported by Mt Newman JV-owned rail to Port Hedland (316 km) Yandi JV’s railway spur links Yandi hub to Mt Newman JV main line	BHP 85% ITOCHU Minerals and Energy of Australia 8% Mitsui Iron Ore Corporation 7%	BHP	Mining lease granted pursuant to the Iron Ore (Marillana Creek) Agreement Act 1991 expires in 2033 with 1 renewal right to a further 21 years	Production began at the Yandi mine in 1992 Capacity of Yandi hub expanded between 1994 and 2013	Open-cut Channel Iron Deposits are Cainozoic fluvial sediments	Power for all mine operations both in the Central and Eastern Pilbara is supplied by BHP’s natural gas fired Yarnima power station. Power consumed in port operations is supplied via a contract with Alinta	3 primary crushers, 3 ore handling plants, stockyard blending facility, and 2 train load outs (nominal capacity 80 Mtpa)

265

Mine & location	Means of access	Ownership	Operator	Title, leases or options	History	Mine type & mineralisation style	Power source	Facilities, use & condition
Jimblebar operation*
Pilbara region, Western Australia	Private road Ore is transported via overland conveyor (12.4 km)	BHP 85% ITOCHU Minerals and Energy of Australia 8% Mitsui & Co. Iron Ore Exploration & Mining 7% *Jimblebar is an ‘incorporated’ venture, with the above companies holding A Class Shares in BHP Iron Ore Jimblebar Pty Ltd (BHPIOJ) BHP holds 100% of the B Class Shares, which has rights to all other BHPIOJ assets	BHP	Mining lease granted pursuant to the Iron Ore (McCamey’s Monster) Agreement Authorisation Act 1972 expires in 2030 with rights to successive renewals of 21 years each	Production began in March 1989 From 2004, production was transferred to Wheelarra JV as part of the Wheelarra sublease agreement Ore was first produced from the newly commissioned Jimblebar hub in late 2013 Jimblebar sells ore to the Newman JV proximate to the Jimblebar hub	Open-cut Bedded ore types classified as per host Archaean or Proterozoic banded iron formation, which are Brockman and Marra Mamba	Power for all mine operations both in the Central and Eastern Pilbara is supplied by BHP’s natural gas fired Yarnima power station. Power consumed in port operations is supplied via a contract with Alinta	3 primary crushers, ore handling plant, train loadout, stockyard blending facility and supporting mining hub infrastructure (nominal capacity 65 Mtpa)

266

Mine & location	Means of access	Ownership	Operator	Title, leases or options	History	Mine type & mineralisation style	Power source	Facilities, use & condition
Wheelarra joint venture
Pilbara region, Western Australia	Private road Ore is transported via overland conveyor (12.4 km)	BHP 51% ITOCHU Minerals and Energy of Australia 4.8% Mitsui Iron Ore Corporation 4.2% Maanshan Iron & Steel Australia 10% Shagang Australia 10% Hesteel Australia 10% Wugang Australia 10%	BHP	Sublease over part of the Jimblebar mining lease that expired in March 2018	Production began in 2004 Wheelarra JV sells all ore to the Mt Newman JV at the Jimblebar hub	Open-cut Bedded ore types classified as per host Archaean or Proterozoic banded iron formation, which is Brockman	Power for all mine operations both in the Central and Eastern Pilbara is supplied by BHP’s natural gas fired Yarnima power station. Power consumed in port operations is supplied via a contract with Alinta	All Wheelarra JV ore is processed at the Jimblebar hub

267

Mine & location	Means of access	Ownership	Operator	Title, leases or options	History	Mine type & mineralisation style	Power source	Facilities, use & condition
Mt Goldsworthy joint venture
Pilbara region, Western Australia Yarrie Nimingarra Mining Area C	Private road Yarrie and Nimingarra iron ore transported by Mt Goldsworthy JV-owned rail to Port Hedland (218 km) Mining Area C iron ore transported by Mt Newman JV-owned rail to Port Hedland (360 km) Mt Goldsworthy JV railway spur links Mining Area C to Yandi railway spur	BHP 85% Mitsui Iron Ore Corporation 7% ITOCHU Minerals and Energy of Australia 8%	BHP	1 mineral lease and 1 mining lease both granted pursuant to the Iron Ore (Goldsworthy – Nimingarra) Agreement Act 1972, which expire 2035, with rights to successive renewals of 21 years 3 mineral leases granted under the Iron Ore (Mount Goldsworthy) Agreement Act 1964, which expire 2028, with rights to successive renewals of 21 years each	Operations commenced at Mt Goldsworthy in 1966 and at Shay Gap in 1973 Original Goldsworthy mine closed in 1982 Associated Shay Gap mine closed in 1993 Mining at Nimingarra mine ceased in 2007, then continued from adjacent Yarrie area Production commenced at Mining Area C mine in 2003 Yarrie mine operations were suspended in February 2014	Mining Area C, Yarrie and Nimingarra all open-cut Bedded ore types classified as per host Archaean or Proterozoic iron formation, which are Brockman, Marra Mamba and Nimingarra	Power for Yarrie and Shay Gap is supplied by their own small diesel generating stations. Power for all remaining mine operations both in the Central and Eastern Pilbara is supplied by BHP’s natural gas fired Yarnima power station. Power consumed in port operations is supplied via a contract with Alinta	2 primary crushers, 2 ore handling plants, stockyard blending facility and train load out (nominal capacity 60 Mtpa)

268

Mine & location	Means of access	Ownership	Operator	Title, leases or options	History	Mine type & mineralisation style	Power source	Facilities, use & condition
POSMAC joint venture
Pilbara Region, Western Australia	Private road POSMAC JV sells ore to Mt Goldsworthy JV at Mining Area C	BHP 65% ITOCHU Minerals and Energy of Australia 8%, Mitsui Iron Ore Corporation 7% POS-Ore 20%	BHP	Sublease over part of Mt Goldsworthy Mining Area C mineral lease that expires on the earlier of termination of the mineral lease or the end of the POSMAC JV	Production commenced in October 2003 POSMAC JV sells all ore to Mt Goldsworthy JV at Mining Area C	Open-cut Bedded ore types classified as per host Archaean or Proterozoic iron formation, which is Marra Mamba	Power for all mine operations both in the Central and Eastern Pilbara is supplied by BHP’s natural gas fired Yarnima power station. Power consumed in port operations is supplied via a contract with Alinta	POSMAC sells all ore to Mt Goldsworthy JV, which is then processed at Mining Area C

269

Coal mining operations

The following table contains additional details of our mining operations. This table should be read in conjunction with the production table (refer to section 6.2.1) and reserves table (refer to section 6.3.2).

Mine & location	Means of access	Ownership	Operator	Title, leases or options	History	Mine type & mineralisation style	Power source	Facilities, use & condition
Queensland Coal
Central Queensland Coal Associates joint venture
Bowen Basin, Queensland, Australia Goonyella Riverside, Broadmeadow Daunia Caval Ridge Peak Downs Saraji Blackwater and Norwich Park mines	Public road Coal transported by rail to Hay Point, Gladstone, Dalrymple Bay and Abbot Point ports Distances between the mines and port are between 160 km and 315 km	BHP 50% Mitsubishi Development 50%	BMA	Mining leases, including undeveloped tenements, expire in 2031, renewable for further periods as Queensland Government legislation allows Mining is permitted to continue under the legislation during the renewal application period	Goonyella mine commenced in 1971, merged with adjoining Riverside mine in 1989 Operates as Goonyella Riverside Production commenced at: Peak Downs in 1972 Saraji in 1974 Norwich Park in 1979 Blackwater in 1967 Broadmeadow (longwall operations) in 2005 Daunia in 2013 and Caval Ridge in 2014 Production at Norwich Park ceased in May 2012	All open-cut except Broadmeadow: longwall underground Bituminous coal is mined from the Permian Moranbah and Rangal Coal measures Products range from premium quality, low volatile, high vitrinite, hard coking coal to medium volatile hard coking coal, to weak coking coal, some pulverised coal injection (PCI) coal and medium ash thermal coal as a secondary product	Queensland electricity grid connection is under long-term contracts and energy purchased via Retail Agreements	On-site beneficiation processing facilities Combined nominal capacity: in excess of 65 Mtpa

270

Mine & location	Means of access	Ownership	Operator	Title, leases or options	History	Mine type & mineralisation style	Power source	Facilities, use & condition
Gregory joint venture
Bowen Basin, Queensland, Australia Gregory and Crinum mines	Public road Coal transported by rail to Hay Point and Gladstone ports Distances between the mines and port are between 310 km and 370 km	BHP 50% Mitsubishi Development 50%	BMA	Mining leases, including undeveloped tenements, expire between 2019 and 2039, renewable for further periods as Queensland Government legislation allows Mining is permitted to continue under the legislation during the renewal application period	Gregory commenced in 1979 Crinum mine (longwall) commenced in 1997 Production at Gregory open-cut mine ceased in October 2012 Production at Crinum underground mine ceased in November 2015 Agreement entered for sale of our entire 50 per cent interest in Gregory Joint Venture	Gregory: open-cut Crinum: longwall underground Bituminous coal is mined from the Permian German Creek Coal measures Product is a high volatile, low ash hard coking coal	Queensland electricity grid connection is under long-term contracts and energy purchased via Retail Agreements	On-site beneficiation processing facility Facilities under care and maintenance

271

Mine & location	Means of access	Ownership	Operator	Title, leases or options	History	Mine type & mineralisation style	Power source	Facilities, use & condition
BHP Billiton Mitsui Coal
Bowen Basin, Queensland, Australia South Walker Creek and Poitrel mines	Public road Coal transported by rail to Hay Point and Dalrymple Bay ports Distances between the mines and port are between 135 km and 165 km	BHP 80% Mitsui and Co 20%	BMC	Mining leases, including undeveloped tenements expire between 2020 and 2034, and are renewable for further periods as Queensland Government legislation allows Mining is permitted to continue under the legislation during the renewal application period	South Walker Creek commenced in 1996 Poitrel commenced in 2006 BMC purchased remaining 50% share of Red Mountain processing facility in 2018 to secure 100% ownership	Open-cut Bituminous coal is mined from the Permian Rangal Coal measures Produces a range of coking coal and pulverised coal injection (PCI) coal	Queensland electricity grid connection is under long-term contracts and energy purchased via Retail Agreements	South Walker Creek coal beneficiated on-site Nominal capacity: in excess of 5 Mtpa Poitrel mine utilises Red Mountain for processing and rail loading facilities Nominal capacity: in excess of 3 Mtpa

272

Mine & location	Means of access	Ownership	Operator	Title, leases or options	History	Mine type & mineralisation style	Power source	Facilities, use & condition
New South Wales Energy Coal
Mt Arthur Coal
Approximately 126 km northwest of Newcastle, New South Wales, Australia	Public road Domestic coal transported by conveyor to Bayswater and Liddell Power Stations Export coal transported by third party rail to Newcastle port	BHP 100%	BHP	Current Development Consent expires in 2026, an extension will be sought within the next few years MAC holds 10 mining leases and 3 exploration licences MAC’s primary exploration licence is currently being renewed	Production commenced in 2002 Government approval permits extraction of up to 36 Mtpa of run of mine coal from underground and open-cut operations, with open-cut extraction limited to 32 Mtpa	Open-cut Produces a medium rank bituminous thermal coal	NSW electricity grid connection under a deemed long-term contract and energy purchased via a Retail Agreement	Beneficiation facilities: coal handling, preparation, washing plants Nominal capacity: in excess of 23 Mtpa

273

Nickel mining operations

The following table contains additional details of our mining operations. This table should be read in conjunction with the production table (refer to section 6.2.1) and reserves tables (refer to section 6.3.2).

Mine & location	Means of access	Ownership	Operator	Title, leases or options	History	Mine type & mineralisation style	Power source	Facilities, use & condition
Nickel West
Mt Keith mine and concentrator
485 km north of Kalgoorlie, Western Australia	Private road Nickel concentrate transported by road to Leinster nickel operations for drying and on- shipping	BHP 100%	BHP	Mining leases granted by Western Australian Government Key leases expire between 2029 and 2036 Renewals at government discretion	Commissioned in 1995 by WMC Acquired in 2005 as part of WMC acquisition	Open-cut Disseminated textured magmatic nickel-sulphide mineralisation associated with a metamorphosed ultramafic intrusion	On-site third party gas-fired turbines Contracts expire in December 2023 Natural gas sourced and transported under separate long-term contracts	Concentration plant with a nominal capacity: 11 Mtpa of ore
Leinster mine complex and concentrator
375 km north of Kalgoorlie, Western Australia	Public road Nickel concentrate shipped by road and rail to Kalgoorlie nickel smelter	BHP 100%	BHP	Mining leases granted by Western Australian Government Key leases expire between 2019 and 2034 Renewals of principal mineral lease in accordance with Nickel (agnew) Agreement	Production commenced in 1979 Acquired in 2005 as part of WMC acquisition Perseverance underground mine ceased operations during 2013	Open-cut and underground Steeply dipping disseminated and massive textured nickel-sulphide mineralisation associated with metamorphosed ultramafic lava flows and intrusions	On-site third party gas-fired turbines Contracts expire in December 2023 Natural gas sourced and transported under separate long-term contracts	Concentration plant with a nominal capacity: 3 Mtpa of ore
Cliffs mine
481 km north of Kalgoorlie, Western Australia	Private road Nickel ore transported by road to Leinster nickel operations for further processing	BHP 100%	BHP	Mining leases granted by Western Australian Government Key leases expire between 2025 and 2028 Renewals at government discretion	Production commenced in 2008 Acquired in 2005 as part of WMC acquisition	Underground Steeply dipping massive textured nickel-sulphide mineralisation associated with metamorphosed ultramafic lava flows	Supplied from Mt Keith	Mine site

274

Nickel smelters, refineries and processing plants

Smelter, refinery or processing plant	Location	Ownership	Operator	Title, leases or options	Product	Nominal production capacity	Power source
Nickel West
Kambalda
Nickel concentrator	56 km south of Kalgoorlie, Western Australia	BHP 100%	BHP	Mining leases granted by Western Australian Government Key leases expire in 2028 Renewals at government discretion	Concentrate containing approximately 13% nickel	1.6 Mtpa ore Ore sourced through tolling and concentrate purchase arrangements with third parties in Kambalda region	On-site third party gas-fired turbines supplemented by access to grid power Contracts expire in December 2023 Natural gas sourced and transported under separate long-term contracts
Kalgoorlie
Nickel smelter	Kalgoorlie, Western Australia	BHP 100%	BHP	Freehold title over the property	Matte containing approximately 65% nickel	110 ktpa matte	On-site third party gas-fired turbines supplemented by access to grid power Contracts expire in December 2023 Natural gas sourced and transported under separate long-term contracts
Kwinana
Nickel refinery	30 km south of Perth, Western Australia	BHP 100%	BHP	Freehold title over the property	LME grade nickel briquettes, nickel powder Also intermediate products, including copper sulphide, cobalt-nickel-sulphide, ammonium-sulphate	75 ktpa nickel matte	Power is sourced from the local grid, which is supplied under a retail contract

275

Minerals Americas

Copper mining operations

The following table contains additional details of our mining operations. This table should be read in conjunction with the production table (refer to section 6.2.1) and reserves table (refer to section 6.3.2).

Mine & location	Means of access	Ownership	Operator	Title, leases or options	History	Mine type & mineralisation style	Power source	Facilities, use & condition
Escondida
Atacama Desert 170 km southeast of Antofagasta, Chile	Private road available for public use Copper cathode transported by privately owned rail to ports at Antofagasta and Mejillones Copper concentrate transported by Escondida-owned pipelines to its Coloso port facilities	BHP 57.5% Rio Tinto 30% JECO Corporation consortium comprising Mitsubishi, JX Nippon Mining and Metals 10% JECO2 Ltd 2.5%	BHP	Mining concession from Chilean Government valid indefinitely (subject to payment of annual fees)	Original construction completed in 1990 Sulphide leach copper production commenced in 2006	2 open-cut pits: Escondida and Escondida Norte Escondida and Escondida Norte mineral deposits are adjacent but distinct supergene enriched porphyry copper deposits	Escondida-owned transmission lines connect to Chile’s northern power grid Electricity sourced from a combination of contracts with external vendors expiring in 2029 and Tamakaya SpA (100% owned by BHP), which generates power from the recently commissioned Kelar gas-fired power plant	3 concentrator plants extract copper concentrate from sulphide ore by flotation extraction process 2 solvent extraction plants produce copper cathode Nominal capacity: 153.7 Mtpa (nominal milling capacity) and 350 ktpa copper cathode (nominal capacity of tank house) 2 x 168 km concentrate pipelines 167 km water pipeline Port facilities at Coloso, Antofagasta Desalinated water plant (Nominal capacity 2,500 litre per second)

276

Mine & location	Means of access	Ownership	Operator	Title, leases or options	History	Mine type & mineralisation style	Power source	Facilities, use & condition
Pampa Norte Spence
Atacama Desert 162 km northeast of Antofagasta, Chile	Public road Copper cathode transported by rail to ports at Mejillones and Antofagasta	BHP 100%	BHP	Mining concession from Chilean Government valid indefinitely (subject to payment of annual fees)	Development cost of US$1.1 billion approved in 2004 First copper produced in 2006	Open-cut Enriched and oxidised porphyry copper deposit containing in situ copper oxide mineralisation that overlies a near-horizontal sequence of supergene sulphides, transitional sulphides, and finally primary (hypogene) sulphide mineralisation	Spence-owned transmission lines connect to Chile’s northern power grid Electricity purchased under contract	Processing and crushing facilities, separate dynamic (on-off) leach pads, solvent extraction plant, electrowinning plant Nominal capacity of tank house: 200 ktpa copper cathode

277

Mine & location	Means of access	Ownership	Operator	Title, leases or options	History	Mine type & mineralisation style	Power source	Facilities, use & condition
Pampa Norte Cerro Colorado
Atacama Desert 120 km east of Iquique, Chile	Public road Copper cathode trucked to port at Iquique	BHP 100%	BHP	Mining concession from Chilean Government valid indefinitely (subject to payment of annual fees)	Commercial production commenced in 1994 Expansions in 1996 and 1998 On 19 June 2018, BHP entered into an agreement to sell Cerro Colorado to EMR Capital. The transaction is expected to close during the December 2018 quarter, subject to financing and customary closing conditions	Open-cut Enriched and oxidised porphyry copper deposit containing in situ copper oxide mineralisation that overlies a near-horizontal sequence of supergene sulphides, transitional sulphides, and finally primary (hypogene) sulphide mineralisation	Long-term contracts with northern Chile power grid	2 primary, secondary and tertiary crushers, dynamic leaching pads, solvent extraction plant, electrowinning plant Nominal capacity of tank house: 130 ktpa copper cathode

278

Mine & location	Means of access	Ownership	Operator	Title, leases or options	History	Mine type & mineralisation style	Power source	Facilities, use & condition
Antamina
Andes mountain range 270 km north of Lima, north central Peru	Public road Copper and zinc concentrates transported by pipeline to port of Huarmey Molybdenum and lead/bismuth concentrates transported by truck	BHP 33.75% Glencore 33.75% Teck 22.5% Mitsubishi 10%	Compañía Minera Antamina S.A.	Mining rights from Peruvian Government held indefinitely, subject to payment of annual fees and supply of information on investment and production	Commercial production commenced in 2001	Open-cut Zoned porphyry and skarn deposit with central copper dominated ores and an outer band of copper-zinc dominated ores	Long-term contracts with individual power producers	Primary crusher, concentrator, copper and zinc flotation circuits, bismuth/moly cleaning circuit Nominal milling capacity: 53 Mtpa 300 km concentrate pipeline Port facilities at Huarmey

279

Iron ore mining operations

The following table contains additional details of our mining operations. This table should be read in conjunction with the production table (refer to section 6.2.1) and reserves table (refer to section 6.3.2).

Mine & location	Means of access	Ownership	Operator	Title, leases or options	History	Mine type & mineralisation style	Power source	Facilities, use & condition
Samarco
Southeast Brazil	Public road Conveyor belts were used to transport iron ore to beneficiation plant 3 slurry pipelines used to transport concentrate to pellet plants on coast Iron pellets were exported via port facilities	BHP Billiton Brasil Limitada 50% of Samarco Mineração S.A. Vale S.A. 50%	Samarco	The mining facilities are currently under administrative embargoes and judicial injunction given the Fundão dam failure	Production began at Germano mine in 1977 and at Alegria complex in 1992 Second pellet plant built in 1997 Third pellet plant, second concentrator and second pipeline built in 2008 Fourth pellet plant, third concentrator and third pipeline built in 2014	Open-cut Itabirites (metamorphic quartz-hematite rock) and friable hematite ores	Samarco holds interests in 2 hydroelectric power plants, which supply part of its electricity Power supply contract with Cemig Geração e Transmissão expires in 2022	Samarco mining activities are currently suspended after the failure of Fundão dam The beneficiation plants, pipelines, pellet plants and port facilities are intact

280

Coal mining operations

The following table contains additional details of our mining operations. This table should be read in conjunction with the production table (refer to section 6.2.1) and reserves table (refer to section 6.3.2).

Mine & location	Means of access	Ownership	Operator	Title, leases or options	History	Mine type & mineralisation style	Power source	Facilities, use & condition
Cerrejón
La Guajira province, Colombia	Public road Coal exported by company-owned rail to Puerto Bolivar (150 km)	BHP 33.33% Anglo American 33.33% Glencore 33.33%	Cerrejón	Mining leases expire progressively from 2028 to early 2034 Production not scheduled after 2033	Original mine began producing in 1976 BHP interest acquired in 2000	Open-cut Produces a medium rank bituminous thermal coal (non-coking, suitable for the export market)	Local Colombian power system	Beneficiation facilities: crushing plant with capacity in excess of 40 Mtpa and washing plant Nominal capacity in excess of 3 Mtpa
Navajo
40 km southwest of Farmington, New Mexico, United States	Public road Coal transported by rail to Four Corners Power Plant	BHP 0% Navajo Transitional Energy Company 100%	BHP	Lease held by Navajo Transitional Energy Company	Production commenced in 1963 Divested in FY2014 BHP continued to manage and operate the mine until the Mine Management Agreement with Navajo Transitional Energy Company (NTEC) ended on 31 December 2016	Open-cut Produces a medium rank bituminous thermal coal (non-coking suitable for the domestic market only)	Four Corners Power Plant	Stackers and reclaimers used to size and blend coal to meet contract quantities and specification Nominal capacity in excess of 4 Mtpa

281

Petroleum

Petroleum operations

The following table contains additional details of our petroleum operations. This table should be read in conjunction with the production table (refer to section 6.2.2) and reserves table (refer to section 6.3.1).

Operation & location	Product	Ownership	Operator	Title, leases or options	Nominal production capacity	Facilities, use & condition
United States
Offshore Gulf of Mexico
Neptune (Green Canyon 613)
Offshore deepwater Gulf of Mexico (1,300m)	Oil and gas	BHP 35% EnVen Energy 30% W&T Offshore 20% 31 Offshore 15%	BHP	Lease from US Government as long as oil and gas produced in paying quantities	50 Mbbl/d oil 50 MMcf/d gas	Stand-alone tension leg platform (TLP)
Shenzi (Green Canyon 653)
Offshore deepwater Gulf of Mexico (1,310m)	Oil and gas	BHP 44% Hess 28% Repsol 28%	BHP	Lease from US Government as long as oil and gas produced in paying quantities	100 Mbbl/d oil 50 MMcf/d gas	Stand-alone TLP Genghis Khan field (part of same geological structure) tied back to Marco Polo TLP
Atlantis (Green Canyon 743)
Offshore deepwater Gulf of Mexico (2,155m)	Oil and gas	BHP 44% BP 56%	BP	Lease from US Government as long as oil and gas produced in paying quantities	200 Mbbl/d oil 180 MMcf/d gas	Moored semi-submersible platform
Mad Dog (Green Canyon 782)
Offshore deepwater Gulf of Mexico (1,310m)	Oil and gas	BHP 23.9% BP 60.5% Chevron 15.6%	BP	Lease from US Government as long as oil and gas produced in paying quantities	100 Mbbl/d oil 60 MMcf/d gas	Moored integrated truss spar, facilities for simultaneous production and drilling operations

282

Operation & location	Product	Ownership	Operator	Title, leases or options	Nominal production capacity	Facilities, use & condition
Genesis (Green Canyon 205)
Offshore deepwater Gulf of Mexico (approximately 790m)	Oil and gas	BHP 4.95% Chevron 56.67% ExxonMobil 38.38%	Chevron	Lease from US Government as long as oil and gas produced in paying quantities	55 Mbbl/d oil 72 MMcf/d gas	Floating cylindrical hull (spar) moored to seabed with integrated drilling facilities BHP has withdrawn from Genesis effective 1 January 2017
Australia
Bass Strait
Offshore and onshore Victoria	Oil and gas	Gippsland Basin joint venture (GBJV): BHP 50% Esso Australia (Exxon Mobil subsidiary) 50% Kipper Unit joint venture (KUJV): BHP 32.5% Esso Australia 32.5% MEPAU A Pty Ltd 35%	Esso Australia	20 production licences and 2 retention leases issued by Australian Government Expire between 2018 and end of life of field 1 production licence held with MEPAU A Pty Ltd	65 Mbbl/d oil 1,040 TJ/d 5,150 tpd LPG 850 tpd Ethane	21 producing fields with 23 offshore developments (15 steel jacket platforms, 4 subsea developments, 2 steel gravity based mono towers, 2 concrete gravity based platforms) Onshore infrastructure: – Longford facility (gas conditioning/processing and liquids processing facilities) – Interconnecting pipelines – Long Island Point (LPG processing and liquids storage/offtake) – Ethane pipeline

283

Operation & location	Product	Ownership	Operator	Title, leases or options	Nominal production capacity	Facilities, use & condition
North West Shelf
Offshore and onshore Western Australia North Rankin Goodwyn Perseus Angel and Searipple fields	Domestic gas, LPG, condensate, LNG	North West Shelf Project is an unincorporated JV BHP: 16.67% of Incremental Pipeline Gas (IPG) domestic gas JV 16.67% of original LNG JV 12.5% of China LNG JV 16.67% of LPG JV Other participants: subsidiaries of Woodside, Chevron, BP, Shell, Mitsubishi/Mitsui and China National Offshore Oil Corporation	Woodside Petroleum Ltd	9 production licences issued by Australian Government 6 expire in 2022 and 3 expire 5 years from end of production	North Rankin Complex: 3,010 MMcf/d gas 53 Mbbl/d condensate Goodwyn A platform: 1,746 MMcf/d gas 100 Mbbl/d condensate Angel platform: 960 MMcf/d gas 51 Mbbl/d condensate Withnell Bay gas plant: 630 MMcf/d gas 5-train LNG plant: 52,000 tpd LNG	Production from North Rankin, Persephone and Perseus processed through the interconnected North Rankin A and North Rankin B platforms Production from Goodwyn and Searipple processed through Goodwyn A platform 3 subsea wells in Perseus field, 3 subsea wells in Tidepole field and 2 subsea wells in Goodwyn field tied into Goodwyn A platform Production from Angel field processed through Angel platform Onshore gas treatment plant at Withnell Bay processes gas for domestic market 5-train LNG plant
North West Shelf
Offshore Western Australia Wanaea Cossack Lambert and Hermes fields	Oil	BHP 16.67% Woodside 33.34%, BP, Chevron, Japan Australia LNG (MIMI) 16.67% each	Woodside Petroleum Ltd	3 production licences issued by Australian Government in September 2014 expire in 2033, 2035 and 2039 respectively	Production: 60 Mbbl/d Storage: 1 MMbbl	FPSO unit

284

Operation & location	Product	Ownership	Operator	Title, leases or options	Nominal production capacity	Facilities, use & condition
Pyrenees
Offshore Western Australia Crosby Moondyne Wild Bull Tanglehead Stickle and Ravensworth fields	Oil	WA-42-L permit: BHP 71.43% Quadrant PVG P/L 28.57% WA-43-L permit: BHP 39.999% Quadrant PVG P/L 31.501% Inpex Alpha Ltd 28.5%	BHP	Production licence issued by Australian Government expires 5 years after production ceases	Production: 96 Mbbl/d oil Storage: 920 Mbbl	26 subsea well completions (21 producers, 4 water injectors, 1 gas injector), FPSO
Macedon
Offshore and onshore Western Australia	Gas and condensate	WA-42-L permit BHP 71.43% Quadrant PVG P/L 28.57%	BHP	Production licence issued by Australian Government expires 5 years after production ceases	Production: 220 MMcf/d gas 20 bbl/d condensate	4 well completions Single flow line transports gas to onshore gas processing facility Gas plant located approximately 17 km southwest of Onslow
Minerva
Offshore and onshore Victoria	Gas and condensate	BHP 90% Cooper Energy (MF) Pty Ltd 10%	BHP	Production licence issued by Australian Government expires 5 years after production ceases	150 TJ/d gas 600 bbl/d condensate	2 subsea well completions (2 producing wells) Single flow line transports gas to onshore gas processing facility Gas plant located approximately 4 km inland from Port Campbell

285

Operation & location	Product	Ownership	Operator	Title, leases or options	Nominal production capacity	Facilities, use & condition
Other production operations
Trinidad and Tobago
Greater Angostura
Offshore Trinidad and Tobago	Oil and gas	BHP 45% National Gas Company 30% Chaoyang 25%	BHP	Production sharing contract with the Trinidad and Tobago Government entitles us to operate Greater Angostura until 2026	100 Mbbl/d oil 340 MMcf/d gas	Integrated oil and gas development: central processing platform connected to the Kairi-2 platform and gas export platform 31 wells completed for production and injection including: 17 oil producers, 7 gas producers (3 subsea) and 7 gas injectors
Algeria
ROD Integrated Development
Onshore Berkine Basin 900 km southeast of Algiers, Algeria	Oil	BHP 45% interest in 401a/402a production sharing contract ENI 55% BHP effective 29.3% interest in ROD unitised integrated development ENI 70.7%	Joint Sonatrach/ENI entity	Production sharing contract with Sonatrach (title holder)	Approximately 80 Mbbl/d oil	Development and production of 6 oil fields 2 largest fields (ROD and SFNE) extend into neighbouring blocks 403a, 403d Production through dedicated processing train on block 403

286

Operation & location	Product	Ownership	Operator	Title, leases or options	Nominal production capacity	Facilities, use & condition
Greater Angostura
Algeria
ROD Integrated Development
United Kingdom
Bruce/Keith
Offshore North Sea, UK	Oil and gas	Bruce: BHP 16% BP 37% Total SA 43.25% Marubeni 3.75% Keith: BHP 31.83% BP 34.84% Total SA 25% Marubeni 8.33%	Bruce – BP Keith – BP	3 production licences issued by UK Government expiring at end of life of field	920 MMcf/d gas	Integrated oil and gas platform Keith developed as tie-back to Bruce facilities
Unconventional petroleum operations The following table contains details of our Onshore US production operations, which are presented in this Report as Discontinued operations. BHP announced on 27 July 2018 that we had entered into an agreement to divest our Onshore US business (see section 1.10.3 for further information). This table should be read in conjunction with the production table (refer to section 6.2.2) and reserves table (refer to section 6.3.1).
Operation & location	Product	Ownership	Operator	Title, leases or options	Nominal production capacity	Facilities, use & condition
Onshore US
Eagle Ford
Black Hawk/Hawkville southern Texas	Condensate, gas and NGL	BHP working interest in wells ranges from less than 1% to 100% BHP average net working interest is approximately 62% Largest partners include Devon Energy and Statoil (Equinor)	BHP operated approximately 34% of approximately 1,539 gross wells	We currently own leasehold interests in approximately 236,000 net acres Leases associated with producing wells remain in place as long as oil and gas are produced in paying quantities	Average daily production during FY2018 150 MMcf/d gas 38 Mbbl/d condensate 20 Mbbl/d NGL	Producing condensate and gas wells and associated pipeline and compression facilities

287

Operation & location	Product	Ownership	Operator	Title, leases or options	Nominal production capacity	Facilities, use & condition
Permian
Permian western Texas	Oil, condensate, gas and NGL	BHP working interest in wells ranges from less than 1% to 100% BHP average net working interest is approximately 84% Largest partners include Resolute Natural Resources and RKI Exploration	BHP operated approximately 83% of approximately 184 gross wells	We currently own leasehold interests in approximately 83,000 net acres Leases associated with producing wells remain in place as long as oil and gas are produced in paying quantities	Average daily production during FY2018 51 MMcf/d gas 15 Mbbl/d oil 6 Mbbl/d NGL	Producing oil and gas wells with associated gathering systems to third party processing plant and compression facilities
Haynesville
Haynesville northern Louisiana and eastern Texas	Gas	BHP working interest in wells ranges from less than 1% to 100% BHP average net working interest is approximately 37% Largest partners include Chesapeake Energy and Aethon Energy	BHP operated approximately 38% of approximately 1,055 gross wells	We currently own leasehold interests in approximately 193,000 net acres Leases associated with producing wells remain in place as long as gas is produced in paying quantities	Average daily production during FY2018 288 MMcf/d gas	Producing gas wells with an associated pipeline owned by a third party and compression infrastructure
Fayetteville
Fayetteville northern central Arkansas	Gas	BHP working interest in wells ranges from less than 1% to 100% BHP average net working interest is approximately 21% Largest partners include Southwestern Energy and Exxon Mobil (XTO)	BHP operated approximately 19% of approximately 4,853 gross wells	We currently own leasehold interests in approximately 258,000 net acres Leases associated with producing wells remain in place as long as gas is produced in paying quantities	Average daily production during FY2018 219 MMcf/d gas	Producing gas wells with associated pipeline and compression infrastructure

288

6.2    Production

6.2.1    Production – Minerals

The table below details our mineral and derivative product production for all operations (except Petroleum) for the three years ended 30 June 2018, 2017 and 2016. Unless otherwise stated, the production numbers represent our share of production and include BHP’s share of production from which profit is derived from our equity accounted investments. Production information for equity accounted investments is included to provide insight into the operational performance of these entities. For discussion of minerals pricing during the past three years, refer to 1.6.2.

	BHP Group interest %		BHP Group share of production (1) Year ended 30 June
			2018		2017		2016
Copper (2)
Payable metal in concentrate (‘000 tonnes)
Escondida, Chile (3)		57.5		925.8		539.6		648.9
Antamina, Peru (4)		33.75		139.5		133.8		146.4
Total copper concentrate				1,065.3		673.4		795.3
Copper cathode (‘000 tonnes)
Escondida, Chile (3)		57.5		287.5		232.0		330.3
Pampa Norte, Chile (5)		100		263.8		254.3		251.4
Olympic Dam, Australia		100		136.7		166.3		202.8
Total copper cathode				688.0		652.6		784.5
Total copper concentrate and cathode				1,753.3		1,326.0		1,579.8
Lead
Payable metal in concentrate (‘000 tonnes)
Antamina, Peru (4)		33.75		3.4		5.5		3.7
Total lead				3.4		5.5		3.7
Zinc
Payable metal in concentrate (‘000 tonnes)
Antamina, Peru (4)		33.75		119.8		87.5		55.4
Total zinc				119.8		87.5		55.4
Gold
Payable metal in concentrate (‘000 ounces)
Escondida, Chile (3)		57.5		229.1		110.9		109.0
Olympic Dam, Australia (refined gold)		100		91.6		104.1		117.7
Total gold				320.7		215.0		226.7
Silver
Payable metal in concentrate (‘000 ounces)
Escondida, Chile (3)		57.5		8,796		4,326		5,561
Antamina, Peru (4)		33.75		5,437		5,783		6,711
Olympic Dam, Australia (refined silver)		100		792		768		917
Total silver				15,025		10,877		13,189
Uranium
Payable metal in concentrate (tonnes)
Olympic Dam, Australia		100		3,364		3,661		4,363
Total uranium				3,364		3,661		4,363
Molybdenum
Payable metal in concentrate (tonnes)
Antamina, Peru (4)		33.75		1,662		1,144		1,113
Total molybdenum				1,662		1,144		1,113

289

	BHP Group interest %		BHP Group share of production (1) Year ended 30 June
			2018		2017		2016
Iron ore
Western Australia Iron Ore
Production (‘000 tonnes) (6)
Newman, Australia		85		67,071		68,283		65,941
Area C Joint Venture, Australia		85		51,517		48,744		46,799
Yandi Joint Venture, Australia		85		64,048		65,355		67,375
Jimblebar, Australia (7)		85		30,627		21,950		18,890
Wheelarra, Australia (8)		85		25,158		27,020		22,549
Total Western Australia Iron Ore				238,421		231,352		221,554
Samarco, Brazil (4)		50		–		–		5,404
Total iron ore				238,421		231,352		226,958
Coal
Metallurgical coal
Production (‘000 tonnes) (9)
Blackwater, Australia		50		6,688		7,296		7,626
Goonyella Riverside, Australia		50		7,961		7,355		8,996
Peak Downs, Australia		50		6,350		6,055		5,031
Saraji, Australia		50		5,053		4,734		4,206
Gregory Joint Venture, Australia		50		–		–		1,329
Daunia, Australia		50		2,556		2,560		2,624
Caval Ridge, Australia		50		4,285		3,458		3,601
Total BHP Billiton Mitsubishi Alliance				32,893		31,458		33,413
South Walker Creek, Australia (10)		80		6,029		5,123		5,436
Poitrel, Australia (10)		80		3,718		3,189		3,462
Total BHP Billiton Mitsui Coal				9,747		8,312		8,898
Total Queensland Coal				42,640		39,770		42,311
IndoMet, Haju, Indonesia (11)		75		–		129		529
Total metallurgical coal				42,640		39,899		42,840
Energy coal
Production (‘000 tonnes)
Navajo, United States (12)		100		–		451		3,999
San Juan, United States		100		–		–		3,053
Total New Mexico Coal				–		451		7,052
New South Wales Energy Coal, Australia		100		18,541		18,176		17,101
Cerrejón, Colombia (4)		33.3		10,617		10,959		10,094
Total energy coal				29,158		29,586		34,247

290

	BHP Group interest %		BHP Group share of production (1) Year ended 30 June
			2018		2017		2016
Other assets
Nickel
Saleable production (‘000 tonnes)
Nickel West, Australia		100		90.6		85.1		80.7
Total nickel				90.6		85.1		80.7

⁽¹⁾  BHP share of production includes the Group’s share of production for which profit is derived from our equity accounted investments, unless otherwise stated.

⁽²⁾ Metal production is reported on the basis of payable metal.

⁽³⁾  Shown on 100 per cent basis following the application of IFRS 10. BHP interest in saleable production is 57.5 per cent.

⁽⁴⁾  For statutory financial reporting purposes, this is an equity accounted investment. We have included production numbers from our equity accounted investments as the level of production and operating performance from these operations impacts Underlying EBITDA of the Group. Our use of Underlying EBITDA is explained in 1.11. Samarco operations are currently suspended following the Samarco dam failure as explained in section 1.8.

⁽⁵⁾  Includes Cerro Colorado and Spence.

⁽⁶⁾  Iron ore production is reported on a wet tonnes basis

⁽⁷⁾  Shown on 100 per cent basis. BHP interest in saleable production is 85 per cent.

⁽⁸⁾  All production from Wheelarra is now processed via the Jimblebar processing hub.

⁽⁹⁾  Metallurgical coal production is reported on the basis of saleable product. Production figures include some thermal coal.

⁽¹⁰⁾  Shown on 100 per cent basis. BHP interest in saleable production is 80 per cent.

⁽¹¹⁾  Shown on 100 per cent basis. BHP interest in saleable production is 75 per cent.

⁽¹²⁾  BHP completed the sale of Navajo Mine on 30 December 2013. As BHP retained control of the mine until 29 July 2016, production has been reported through such date.

291

6.2.2    Production – Petroleum

The table below details Petroleum’s historical net crude oil and condensate, natural gas and natural gas liquids production, primarily by geographic segment, for each of the three years ended 30 June 2018, 2017 and 2016. We have shown volumes of marketable production after deduction of applicable royalties, fuel and flare. We have included in the table average production costs per unit of production and average sales prices for oil and condensate and natural gas for each of those periods.

	BHP Group share of production Year ended 30 June
	2018		2017		2016
Production volumes
Crude oil and condensate (‘000 of barrels)
Australia		16,545		18,658		20,307
United States – Conventional		27,476		29,933		32,990
United States – Onshore US		19,464		22,944		32,568
Other (4)		4,616		4,850		4,714
Total crude oil and condensate		68,101		76,385		90,579
Natural gas (billion cubic feet)
Australia		325.0		345.7		325.6
United States – Conventional		9.5		10.3		11.4
United States – Onshore US		258.5		275.0		364.5
Other (4)		42.5		36.8		43.2
Total natural gas		635.5		667.8		744.7
Natural gas liquids (1) (‘000 of barrels)
Australia		6,955		7,423		7,646
United States – Conventional		1,725		1,725		2,158
United States – Onshore US		9,560		11,427		15,613
Other (4)		88		119		43
Total NGL (1)		18,328		20,694		25,460
Total production of petroleum products (million barrels of oil equivalent) (2)
Australia		77.7		83.7		82.2
United States – Conventional		30.8		33.4		37.1
United States – Onshore US		72.1		80.2		108.9
Other (4)		11.8		11.1		12.0
Total production of petroleum products		192.4		208.4		240.2
Average sales price
Crude oil and condensate (US$ per barrel)
Australia		63.69		50.59		43.55
United States – Conventional		58.55		45.45		38.55
United States – Onshore US		59.03		47.91		37.66
Other (4)		61.73		47.96		41.00
Total crude oil and condensate		60.12		47.61		39.48
Natural gas (US$ per thousand cubic feet)
Australia		5.97		5.06		5.22
United States – Conventional		3.12		4.39		2.33
United States – Onshore US		2.79		2.82		2.16
Other (4)		3.19		2.72		3.20
Total natural gas		4.44		4.00		3.57

292

	BHP Group share of production Year ended 30 June
	2018		2017		2016
Natural gas liquids (US$ per barrel)
Australia		35.99		27.76		24.86
United States – Conventional		27.52		21.29		16.16
United States – Onshore US		22.15		15.14		10.60
Other (4)		25.85		21.10		20.90
Total NGL		27.95		20.37		15.31
Total average production cost (US$ per barrel of oil equivalent) (3)
Australia		8.06		5.78		6.12
United States – Conventional		7.43		6.62		3.21
United States – Onshore US		6.43		7.87		7.06
Other (4)(5)		9.31		13.55		14.39
Total average production cost (5)		7.43		7.14		6.51

⁽¹⁾  LPG and ethane are reported as natural gas liquids (NGL).

⁽²⁾  Total barrels of oil equivalent (boe) conversion is based on the following: 6,000 standard cubic feet (scf) of natural gas equals one boe.

⁽³⁾  Average production costs include direct and indirect costs relating to the production of hydrocarbons and the foreign exchange effect of translating local currency denominated costs into US dollars, but excludes ad valorem and severance taxes, and the cost to transport our produced hydrocarbons to the point of sale.

⁽⁴⁾  Other comprises Algeria, Mexico, Pakistan (divested 31 December 2015), Trinidad and Tobago, and the United Kingdom.

⁽⁵⁾  30 June 2017 and 30 June 2016 have been restated to be consistent with the 30 June 2018 total average production cost calculation which excludes the impacts of non-production related costs.

6.3    Reserves

Resources are the estimated quantities of material that can potentially be commercially recovered from the Group’s properties. Reserves are a subset of resources that can be demonstrated to be able to be economically and legally extracted. In order to estimate reserves, assumptions are required about a range of technical and economic factors, including quantities, qualities, production techniques, recovery efficiency, production and transport costs, commodity supply and demand, commodity prices and exchange rates.

Estimating the quantity and/or quality of reserves requires the size, shape and depth of ore bodies or oil and gas reservoirs to be determined by analysing geological data, such as drilling samples and geophysical survey interpretations. Economic assumptions used to estimate reserves change from period-to-period as additional technical and operational data is generated.

6.3.1     Petroleum reserves

Estimates of oil and gas reserves involve some degree of uncertainty, are inherently imprecise, require the application of judgement and are subject to future revision. Accordingly, financial and accounting measures (such as the standardised measure of discounted cash flows, depreciation, depletion and amortisation charges, the assessment of impairments and the assessment of valuation allowances against deferred tax assets) that are based on reserve estimates are also subject to change.

293

How we estimate and report reserves

Petroleum’s reserves are estimated as of 30 June 2018. Reported reserves include both Conventional Petroleum reserves and Onshore US reserves. Footnotes have been included where appropriate so that the contribution of the discontinued Onshore US operations can be separated out from the continuing Conventional operations.

Our proved reserves are estimated and reported according to SEC regulations and have been determined in accordance with SEC Rule 4-10(a) of Regulation S-X.

Proved oil and gas reserves

Proved oil and gas reserves are those quantities of crude oil, natural gas and natural gas liquids (NGL) that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs and under existing economic conditions, operating methods, operating contracts and government regulations. Unless evidence indicates that renewal of existing operating contracts is reasonably certain, estimates of economically producible reserves reflect only the period before the contracts expire. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence within a reasonable time. As specified in SEC Rule 4-10(a) of Regulation S-X, oil and gas prices are taken as the unweighted average of the corresponding first day of the month prices for the 12 months prior to the ending date of the period covered.

Proved reserves were estimated by reference to available well and reservoir information, including but not limited to well logs, well test data, core data, production and pressure data, geologic data, seismic data and in some cases, to similar data from analogous, producing reservoirs. A wide range of engineering and geoscience methods, including performance analysis, well analogues and geologic studies were used to estimate high confidence proved developed and undeveloped reserves in accordance with SEC regulations.

Proved reserve estimates were attributed to future development projects only where there is a significant commitment to project funding and execution and for which applicable government and regulatory approvals have been secured or are reasonably certain to be secured. Furthermore, estimates of proved reserves include only volumes for which access to market is assured with reasonable certainty. All proved reserve estimates are subject to revision (either upward or downward) based on new information, such as from development drilling and production activities or from changes in economic factors, including product prices, contract terms or development plans.

Developed oil and gas reserves

Proved developed oil and gas reserves are reserves that can be expected to be recovered through:

• existing wells with existing equipment and operating methods;

• installed extraction equipment and infrastructure operational at the time of the reserve estimate if the extraction is by means not involving a well.

Performance-derived reserve assessments for producing wells were primarily based in the following manner:

• for our conventional operations, reserves were estimated using rate and pressure decline methods, including material balance, supplemented by reservoir simulation models where appropriate;

• for our Onshore US operations, rate-transient analysis and decline curve analysis methods;

• for wells that lacked sufficient production history, reserves were estimated using performance-based type curves and offset location analogues with similar geologic and reservoir characteristics.

294

Proved undeveloped reserves

Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage where commitment has been made to commence development within five years from first reporting or from existing wells where a relatively major expenditure is required for recompletion.

A combination of geologic and engineering data and where appropriate, statistical analysis was used to support the assignment of proved undeveloped reserves when assessing planned drilling locations. Performance data along with log and core data was used to delineate consistent, continuous reservoir characteristics in core areas of the development. Proved undeveloped locations were included in core areas between known data and adjacent to productive wells using performance-based type curves and offset location analogues with similar geologic and reservoir characteristics. Locations where a high degree of certainty could not be demonstrated using the above technologies and techniques were not categorised as proved.

Methodology used to estimate reserves

Reserve estimates have been estimated with deterministic methodology, with the exception of the North West Shelf gas operation in Australia, where probabilistic methodology has been used to estimate and aggregate reserves for the reservoirs dedicated to the gas project only. The probabilistic based portion of these reserves totals 23 million barrels of oil equivalent (MMboe) (total boe conversion is based on the following: 6,000 standard cubic feet (scf) of natural gas equals 1 boe) and represents approximately two per cent of our total reported proved reserves. Aggregation of proved reserves beyond the field/project level has been performed by arithmetic summation. Due to portfolio effects, aggregates of proved reserves may be conservative. The custody transfer point(s) or point(s) of sale applicable for each field or project are the reference point for reserves. The reserves replacement ratio is the reserves change during the year before production, divided by the production during the year stated as a percentage.

Governance

The Petroleum Reserves Group (PRG) is a dedicated group that provides oversight of the reserves’ assessment and reporting processes. It is independent of the various operation teams directly responsible for development and production activities. The PRG is staffed by individuals averaging more than 20 years’ experience in the oil and gas industry. The manager of the PRG, Abhijit Gadgil, is a full-time employee of BHP and is responsible for overseeing the preparation of the reserve estimates and compiling the information for inclusion in this Annual Report. He has an advanced degree in engineering and more than 35 years of diversified industry experience in reservoir engineering, reserves assessment, field development and technical management. He is a 35-year member of the Society of Petroleum Engineers (SPE). He has also served on the Society of Petroleum Engineers Oil and Gas Reserves Committee. Mr Gadgil has the qualifications and experience required to act as a qualified petroleum reserves evaluator under the Australian Securities Exchange (ASX) Listing Rules. The estimates of petroleum reserves are based on and fairly represent information and supporting documentation prepared under the supervision of Mr Gadgil. He has reviewed and agrees with the information included in section 6.3.1 and has given his prior written consent for its publication. No part of the individual compensation for members of the PRG is dependent on reported reserves.

Reserve assessments for all Petroleum operations were conducted by technical staff within the operating organisation. These individuals meet the professional qualifications outlined by the SPE, are trained in the fundamentals of SEC reserves reporting and the reserves processes and are endorsed by the PRG. Each reserve assessment is reviewed annually by the PRG to ensure technical quality, adherence to internally published Petroleum guidelines and compliance with SEC reporting requirements. Once endorsed by the PRG, all reserves receive final endorsement by senior management and the Risk and Audit Committee prior to public reporting. Our Internal Audit and Assurance function provides secondary assurance of the oil and gas reserve reporting processes through audits of the key controls that have been implemented, as required by the U.S. Sarbanes-Oxley Act of 2002. For more information on our risk management governance, refer to section 2.13.1.

295

FY2018 reserves

Production for FY2018 totalled 192 MMboe in sales, which is a decrease of 16 MMboe from FY2017 (refer to section 6.2.2 for more information). There was an additional 5 MMboe in non-sales production, primarily for fuel consumed in our Petroleum operations. The combined sales and non-sales production totalled 198 MMboe. The natural decline of production in our Onshore US fields and mature fields in other locations was the reason for the lower amount produced.

As of 30 June 2018, our proved reserves totalled 1,400 MMboe and reflect a net increase of 62 MMboe (before total production) from the 1535 MMboe reported at FY2017. This increase was primarily the result of continued strong performance in our Offshore US fields in the Gulf of Mexico and Offshore Trinidad and Tobago along with better performance and improved liquid product prices for our North American shale operations. These increases were partially offset by reductions in the North West Shelf (Australia) and reduced gas prices received for production from our Onshore US fields. Net additions to reserves resulted in a reserves replacement of 32 per cent overall, (Conventional: 25 per cent reserves replacement, Onshore US: 43 per cent reserves replacement). As of 30 June 2018, approximately 65 per cent of our proved reserves were in conventional fields, while about 35 per cent of our proved reserves were in unconventional fields.

Discoveries and extensions

Discoveries and extensions added 75 MMboe to proved reserves during FY2018. This comprised of 69 MMboe of extensions related to planned drilling in new locations in our Onshore US operations within the next five years and an additional 4 MMboe in the Mad Dog field and 2 MMboe in the Shenzi field, both of which are in the US Gulf of Mexico.

Revisions

Overall, net revisions decreased proved reserves by 7 MMboe during FY2018. In our Australian operations, reductions of 21 MMboe occurred, primarily in the North West Shelf, due to revisions related to updated technical assessments. In the United States, net revisions increased reserves by approximately 4 MMboe. This was a result of additions of 36 MMboe, primarily for strong performance in the Atlantis field in the Offshore US Gulf of Mexico and better performance in our Onshore US Eagle Ford and Permian assets. These additions were partially offset by reductions of 33 MMboe, mainly in our Onshore US fields as a result of lower planned drilling activity in light of our previously announced plan to exit our shale operations and the effect of lower gas prices. In Other areas outside of Australia and the United States, revisions increased reserves by 10 MMboe, primarily for strong performance in the Angostura Phase 3 project in Offshore Trinidad and Tobago.

Of the overall decrease in proved reserves of 7 MMboe through revisions, the impact of commodity prices using the required SEC price-basis represented a decrease of 4 MMboe while well performance, interest changes and other revisions resulted in a net decrease of 3 MMboe. Virtually all of the price-related decrease occurred in our Onshore US fields where increases of 26 MMboe occurred in the Eagle Ford and Permian fields as a result of higher liquids prices, but these additions were more than offset by 31 MMboe in reductions in Haynesville and Fayetteville due to lower gas prices.

Sales

The sale of acreage in our Eagle Ford field accounted for our reported sales of approximately 5 MMboe. There were no purchases during FY2018.

These results are summarised in the following tables, which detail estimated oil, condensate, NGL and natural gas reserves at 30 June 2018, 30 June 2017 and 30 June 2016, with a reconciliation of the changes in each year. Reserves have been calculated using the economic interest method and represent net interest volumes after deduction of applicable royalty. Reserves of 77 MMboe are in two production and risk-sharing arrangements that involve BHP in upstream risks and rewards without transfer of ownership of the products. At 30 June 2018, approximately five per cent of the proved reserves were attributable to such arrangements.

296

Millions of barrels	Australia			United States			Other  (b)			Total
Proved developed and undeveloped oil and condensate reserves (a)
Reserves at 30 June 2015		124.0			383.3	(c)		17.1			524.3	(c)
Improved recovery		–			–			–			–
Revisions of previous estimates		9.1			(67.0	)		14.4			(43.5	)
Extensions and discoveries		0.4			2.9			–			3.4
Purchase/sales of reserves		–			–			(0.3	)		(0.3	)
Production		(20.3	)		(65.6	)		(4.7	)		(90.6	)
Total changes		(10.8	)		(129.6	)		9.4			(130.9	)
Reserves at 30 June 2016		113.2			253.7	(c)		26.5			393.4	(c)
Improved recovery		–			–			–			–
Revisions of previous estimates		(5.9	)		17.0			4.4			15.4
Extensions and discoveries		–			123.3			–			123.3
Purchase/sales of reserves		–			(0.4	)		–			(0.4	)
Production		(18.7	)		(52.9	)		(4.8	)		(76.4	)
Total changes		(24.6	)		87.0			(0.5	)		61.9
Reserves at 30 June 2017		88.6			340.7	(c)		26.0			455.3	(c)
Improved recovery		–			–			–			–
Revisions of previous estimates		(1.6	)		41.2			0.6			40.1
Extensions and discoveries		–			27.6			–			27.6
Purchase/sales of reserves		–			(0.7	)		–			(0.7	)
Production		(16.5	)		(46.9	)		(4.6	)		(68.1	)
Total changes		(18.2	)		21.1			(4.0	)		(1.1	)
Reserves at 30 June 2018		70.5			361.8	(c)		21.9			454.2	(c)
Developed
Proved developed oil and condensate reserves
as of 30 June 2015		81.2			225.4			11.7			318.3
as of 30 June 2016		82.2			187.3			20.0			289.5
as of 30 June 2017		76.2			162.3			21.9			260.5
Developed reserves as of 30 June 2018		60.5			181.1			19.2			260.8
Undeveloped
Proved undeveloped oil and condensate reserves
as of 30 June 2015		42.7			157.9			5.4			206.0
as of 30 June 2016		31.0			66.4			6.5			103.9
as of 30 June 2017		12.4			178.4			4.0			194.8
Undeveloped reserves as of 30 June 2018		10.0			180.7			2.8			193.4

^(a)  Small differences are due to rounding to first decimal place.

^(b)  ‘Other’ comprises Algeria. Pakistan (divested in December 2015), Trinidad and Tobago, and the United Kingdom.

^(c)  For FY2015, FY2016, FY2017 and FY2018 amounts include 161.7, 62.9, 73.0 and 86.1 million barrels respectively attributable to discontinued operations of Onshore US.

297

Millions of barrels	Australia			United States			Other  (c)			Total
Proved developed and undeveloped NGL reserves (a)
Reserves at 30 June 2015		76.6			108.6	(d)(e)		–			185.2	(d)(e)
Improved recovery		–			–			–			–
Revisions of previous estimates		1.8			(57.0	)		–			(55.2	)
Extensions and discoveries		0.6			1.8			–			2.4
Purchase/sales of reserves		–			–			–			–
Production (b)		(7.6	)		(17.8	)		–			(25.5	)
Total changes		(5.3	)		(73.0	)		–			(78.2	)
Reserves at 30 June 2016		71.3			35.6	(d)(e)		–			107.0	(d)(e)
Improved recovery		–			–			–			–
Revisions of previous estimates		1.2			23.4			0.1			24.8
Extensions and discoveries		–			13.1			–			13.1
Purchase/sales of reserves		–			(0.1	)		–			(0.1	)
Production (b)		(7.4	)		(13.2	)		(0.1	)		(20.7	)
Total changes		(6.2	)		23.2			–			17.0
Reserves at 30 June 2017		65.2			58.9	(d)(e)		–			124.0	(d)(e)
Improved recovery		–			–			–			–
Revisions of previous estimates		(1.7	)		12.7			0.1			11.0
Extensions and discoveries		–			13.4			–			13.4
Purchase/sales of reserves		–			(1.7	)		–			(1.7	)
Production (b)		(7.0	)		(11.3	)		(0.1	)		(18.3	)
Total changes		(8.7	)		13.1			–			4.4
Reserves at 30 June 2018		56.5			72.0	(d)(e)		–			128.4	(d)(e)
Developed
Proved developed NGL reserves
as of 30 June 2015		40.1			59.7			–			99.8
as of 30 June 2016		38.0			30.7			–			68.7
as of 30 June 2017		56.6			31.4			–			88.0
Developed reserves as of 30 June 2018		49.8			37.0			–			86.8
Undeveloped
Proved undeveloped NGL reserves
as of 30 June 2015		36.5			48.9			–			85.4
as of 30 June 2016		33.3			4.9			–			38.2
as of 30 June 2017		8.6			27.5			–			36.1
Undeveloped reserves as of 30 June 2018		6.6			35.0			–			41.6

^(a)  Small differences are due to rounding to first decimal place.

^(b)  Production includes volumes consumed by operations.

^(c)  ‘Other’ comprises Algeria, Pakistan (divested in December 2015), Trinidad and Tobago, and the United Kingdom.

^(d)  For FY2015, FY2016, FY2017 and FY2018 amounts include 4.2, 0.2, 2.1 and 2.5 million barrels respectively, which are anticipated to be consumed as fuel in operations in the United States.

^(e)  For FY2015, FY2016, FY2017 and FY2018 amounts include 100.5, 28.3, 51.0 and 62.2 million barrels respectively attributable to discontinued operations of Onshore US.

298

Billions of cubic feet	Australia  (c)			United States			Other  (d)			Total
Proved developed and undeveloped natural gas reserves (a)
Reserves at 30 June 2015		3,483.4	(e)		3,296.1	(f)(i)		410.6	(g)		7,190.2	(h)(i)
Improved recovery		–			–			–			–
Revisions of previous estimates		48.9			(1,643.9	)		17.4			(1,577.6	)
Extensions and discoveries		9.7			37.3			–			47.0
Purchase/sales of reserves		–			–			(71.3	)		(71.3	)
Production (b)		(350.0	)		(378.5	)		(45.9	)		(774.4	)
Total changes		(291.4	)		(1,985.0	)		(99.8	)		(2,376.4	)
Reserves at 30 June 2016		3,192.0	(e)		1,311.1	(f)(i)		310.8	(g)		4,813.8	(h)(i)
Improved recovery		–			–			–			–
Revisions of previous estimates		49.9			1,307.4			43.5			1,400.7
Extensions and discoveries		–			216.5			–			216.5
Purchase/sales of reserves		–			(0.7	)		–			(0.7	)
Production (b)		(372.1	)		(287.9	)		(38.3	)		(698.4	)
Total changes		(322.3	)		1,235.3			5.1			918.1
Reserves at 30 June 2017		2,869.7	(e)		2,546.3	(f)(i)		315.9	(g)		5,731.9	(h)(i)
Improved recovery		–			–			–			–
Revisions of previous estimates		(105.3	)		(302.0	)		57.0			(350.2	)
Extensions and discoveries		–			204.1			–			204.1
Purchase/sales of reserves		–			(17.8	)		–			(17.8	)
Production (b)		(351.9	)		(270.7	)		(44.3	)		(666.9	)
Total changes		(457.2	)		(386.3	)		12.7			(830.7	)
Reserves at 30 June 2018		2,412.5	(e)		2,160.1	(f)(i)		328.6	(g)		4,901.2	(h)(i)
Developed
Proved developed natural gas reserves
as of 30 June 2015		2,400.7			2,499.0			281.1			5,180.7
as of 30 June 2016		2,204.6			1,268.1			182.9			3,655.6
as of 30 June 2017		2,346.3			1,556.4			315.9			4,218.5
Developed reserves as of 30 June 2018		1,975.9			1,479.4			328.6			3,783.8
Undeveloped
Proved undeveloped natural gas reserves
as of 30 June 2015		1,082.7			797.1			129.6			2,009.4
as of 30 June 2016		987.4			43.0			127.8			1,158.2
as of 30 June 2017		523.4			989.9			–			1,513.3
Undeveloped reserves as of 30 June 2018		436.6			680.7			–			1,117.3

^(a)  Small differences are due to rounding to first decimal place.

^(b)  Production includes volumes consumed by operations.

^(c)  Production for Australia includes gas sold as LNG.

^(d)  ‘Other’ comprises Algeria, Pakistan (divested in December 2015), Trinidad and Tobago, and the United Kingdom.

^(e)  For FY2015, FY2016, FY2017 and FY2018 amounts include 343, 321, 295 and 295 billion cubic feet respectively, which are anticipated to be consumed as fuel in operations in Australia.

^(f)  For FY2015, FY2016, FY2017 and FY2018 amounts include 154, 75, 155 and 160 billion cubic feet respectively, which are anticipated to be consumed as fuel in operations in the United States.

^(g)  For FY2015, FY2016, FY2017 and FY2018 amounts include 27, 17, 17 and 16 billion cubic feet respectively, which are anticipated to be consumed as fuel in operations in Other areas.

^(h)  For FY2015, FY2016, FY2017 and 2018 amounts include 524, 413, 467 and 472 billion cubic feet respectively, which are anticipated to be consumed as fuel in operations.

⁽ⁱ⁾  For FY2015, FY2016, FY2017 and FY2018 amounts include 3,209, 1,238, 2,444 and 2,049 billion cubic feet respectively attributable to discontinued operations of Onshore US.

299

Millions of barrels of oil equivalent (a)	Australia			United States			Other  (d)			Total
Proved developed and undeveloped oil, condensate, natural gas and NGL reserves (b)
Reserves at 30 June 2015		781.1	(a)		1,041.3	(f)(i)		85.5	(g)		1,907.9	(h)(i)
Improved recovery		–			–			–			–
Revisions of previous estimates		19.0			(397.9	)		17.3			(361.6	)
Extensions and discoveries		2.7			10.9			–			13.6
Purchase/sales of reserves		–			–			(12.2	)		(12.2	)
Production (c)		(86.3	)		(146.4	)		(12.4	)		(245.1	)
Total changes		(64.6	)		(533.4	)		(7.3	)		(605.2	)
Reserves at 30 June 2016		716.5	(e)		507.9	(f)(j)		78.2	(g)		1,302.7	(h)(j)
Improved recovery		–			–			–			–
Revisions of previous estimates		3.6			258.3			11.7			273.6
Extensions and discoveries		–			172.4			–			172.4
Purchase/sales of reserves		–			(0.6	)		–			(0.6	)
Production (e)		(88.1	)		(114.0	)		(11.4	)		(213.5	)
Total changes		(84.5	)		316.1			0.4			232.0
Reserves at 30 June 2017		632.1	(e)		824.0	(f)(j)		78.6	(g)		1,534.6	(h)(j)
Improved recovery		–			–			–			–
Revisions of previous estimates		(20.9	)		3.5			10.2			(7.3	)
Extensions and discoveries		–			75.0			–			75.0
Purchase/sales of reserves		–			(5.3	)		–			(5.3	)
Production (c)		(82.2	)		(103.3	)		(12.1	)		(197.6	)
Total changes		(103.1	)		(30.1	)		(1.9	)		(135.1	)
Reserves at 30 June 2018		529.0	(e)		793.8	(f)(i)		76.7	(g)		1,399.5	(h)(i)
Developed
Proved developed oil, condensate, natural gas and NGL reserves
as of 30 June 2015		521.5			701.6			58.5			1,281.6
as of 30 June 2016		487.6			429.4			50.5			967.5
as of 30 June 2017		523.8			453.1			74.6			1,051.6
Developed reserves as of 30 June 2018		439.6			464.7			73.9			978.2
Undeveloped
Proved undeveloped oil, condensate, natural gas and NGL reserves
as of 30 June 2015		259.6			339.7			27.0			626.3
as of 30 June 2016		228.9			78.5			27.8			335.2
as of 30 June 2017		108.2			370.8			4.0			483.1
Undeveloped reserves as of 30 June 2018		89.4			329.2			2.8			421.3

^(a)  Barrel oil equivalent conversion based on 6,000 scf of natural gas equals 1 boe.

^(b)  Small differences are due to rounding to first decimal place.

^(c)  Production includes volumes consumed by operations.

^(d)  ‘Other’ comprises Algeria, Pakistan (divested in December 2015), Trinidad and Tobago, and the United Kingdom.

^(e)  For FY2015, FY2016, FY2017 and FY2018 amounts include 57, 53, 49 and 49 million barrels equivalent respectively, which are anticipated to be consumed as fuel in operations in Australia.

^(f)  FY2015, FY2016, FY2017 and FY2018 amounts include 30, 13, 28 and 29 million barrels equivalent respectively, which are anticipated to be consumed as fuel in operations in the United States.

^(g)  For FY2015, FY2016, FY2017 and FY2018 amounts include 4, 3, 3 and 3 million barrels equivalent respectively, which are anticipated to be consumed as fuel in operations in Other areas.

^(h)  For FY2015, FY2016, FY2017 and FY2018 amounts include 91, 69, 80 and 81 million barrels equivalent respectively, which are anticipated to be consumed as fuel in operations.

⁽ⁱ⁾  FY2015, FY2016, FY2017 and FY2018 amounts include 797, 298, 531 and 490 million barrels equivalent respectively attributable to discontinued operations of Onshore US.

300

Proved undeveloped reserves

At 30 June 2018, Petroleum had 421 MMboe of proved undeveloped reserves, which represented 30 per cent of year-end 2018 proved reserves of 1400 MMboe. Approximately 237 MMboe or 56 per cent of the proved undeveloped reserves reside in our conventional offshore fields in Australia, the Gulf of Mexico and Algeria, while 185 MMboe or 44 per cent resides in our Onshore US fields. The current proved undeveloped reserves reflect a net decrease of 62 MMboe from the 483 MMboe reported at 30 June 2017. This decrease was primarily the result of the conversion of 48 MMboe from proved undeveloped to proved developed through drilling and development activities. The largest component of this conversion occurred in our Onshore US fields where 26 MMboe was moved to proved developed status. An additional 11 MMboe was converted in the North West Shelf Persephone development in Australia, while 10 MMboe was converted in the Atlantis field in the Offshore US Gulf of Mexico. An additional 1 MMboe was also converted as a result of drilling in the Rod field in Algeria.

The reduction in planned drilling in our Onshore US fields, in light of our planned exit from Onshore US operations also resulted in a net reduction of 9 MMboe from proved undeveloped, while a further reduction of 7 MMboe occurred in the Offshore Australia Barracouta field as a result of an updated technical assessment.

Of the 421 MMboe currently classified as proved undeveloped at 30 June 2018, 48 MMboe has been reported for five or more years. All of these reserves are in our offshore conventional fields that are currently producing, have significant development in place or are scheduled to start producing within the next five years. The largest components of the proved undeveloped that has been reported for more than five years are in the Kipper/Turrum project (14 MMboe) and in the Macedon field (10 MMboe) both in Offshore Australia and in the Atlantis field (8 MMboe) and the Mad Dog field (6 MMboe), both of which are in the Offshore US Gulf of Mexico with active drilling programs. The remainder resides in other Australian offshore fields that have active development plans. Our Onshore US fields do not contain any undrilled proved undeveloped reserves that have been reported for more than five years or that will not be drilled within five years.

Over the past three years, the conversion of proved undeveloped reserves to developed has totalled 319 MMboe, averaging 106 MMboe per year. In currently producing conventional fields, the remaining proved undeveloped reserves will be developed and brought on stream in a phased manner to best optimise the use of production facilities and to meet sales commitments. During FY2018, Petroleum spent US$1.8 billion on development activities worldwide.

301

6.3.2    Ore Reserves

Ore Reserves are estimates of the amount of ore that can be economically and legally extracted and processed from our mining properties. In order to estimate reserves, assumptions are required about a range of technical and economic factors, including quantities, qualities, production techniques, recovery efficiency, production and transport costs, commodity supply and demand, commodity prices and exchange rates. Estimating the quantity and/or quality of Ore Reserves requires the size, shape and depth of ore bodies to be determined by analysing geological data such as drilling samples and geophysical survey interpretations. Economic assumptions used to estimate reserves may change from period to period as additional technical, financial and operational data is generated. All of the Ore Reserves presented are reported in 100 per cent terms and represent estimates at 30 June 2018 (unless otherwise stated). All tonnes and grade information has been rounded, hence small differences may be present in the totals. Tonnes are reported as dry metric tonnes (unless otherwise stated).

Our mineral leases are of sufficient duration (or convey a legal right to renew for sufficient duration) to enable all Ore Reserves on the leased properties to be mined in accordance with current production schedules. Our Ore Reserves may include areas where some additional approvals remain outstanding but where, based on the technical investigations we carry out as part of our mine planning process, and our knowledge and experience of the approvals process, we expect that such approvals will be obtained as part of the normal course of business and within the timeframe required by the current life of mine schedule.

The reported Ore Reserves contained in this document do not exceed the quantities that we estimate and could be extracted economically if future prices for each commodity were equal to the average historical prices for the three years to 31 December 2017, using current operating costs. In some cases where commodities are produced as by-products (or co-products) with other metals, we use the three-year average historical prices for the combination of commodities produced at the relevant mine in order to verify that each Ore Reserve is economic. The three-year historical average prices used for each traded commodity to test for impairment of the Ore Reserves contained in this Annual Report are as follows:

Commodity Price (1)	US$
Copper	2.50/lb
Gold	1,222/ozt
Molybdenum	7.11/lb
Nickel	4.81/lb
Silver	16.62/ozt
Zinc	1.05/lb
Uranium (2)	28.24/lb
Iron Ore – Fines	55.93/dmt
Iron Ore – Lump	66.51/dmt
Metallurgical Hard Coking Coal	139.63/t
Metallurgical Weak Coking Coal	87.77/t
Thermal Coal Newcastle (2)	71.25/t
Thermal Coal Colombia (2)	62.47/t

⁽¹⁾  Some commodities are traded on a contractual basis for which we are unable to disclose prices due to commercial sensitivity.

⁽²⁾  The Uranium price reported is sourced from NEUXCO spot U₃O_8. Thermal coal prices reported are sourced from the McCloskey Report FOB by region, Newcastle and Colombia 6,000 kcal/t Net As Received. These are comparable to realised prices used to test for impairment.

The reported Ore Reserves may differ in some respects from the Ore Reserves we report in home jurisdictions of Australia and the UK. Those jurisdictions require the use of the Australasian Code for reporting of Exploration Results, Mineral Resources and Ore Reserves, December 2012 (the JORC Code), which provides guidance on the use of reasonable investment assumptions in calculating Ore Reserves estimates.

302

Copper

Ore Reserves in accordance with Industry Guide 7

As at 30 June 2018																																					As at 30 June 2017
Commodity Deposit (1)(2)(3)(4)	Ore Type		Proven Reserves										Probable Reserves										Total Reserves										Reserve Life (years)		BHP Interest %		Total Reserves										Reserve Life (years)
			Mt		%TCu		%SCu		ppmMo				Mt		%TCu		%SCu		ppmMo				Mt		%TCu		%SCu		ppmMo								Mt		%TCu		%SCu		ppmMo
Copper
Escondida (5)		Oxide		93		0.66		–		–				157		0.60		–		–				250		0.62		–		–				58		57.5		298		0.63		–		–				53
		Sulphide		3,700		0.71		–		–				1,910		0.57		–		–				5,610		0.66		–		–								5,260		0.70		–		–
		Sulphide Leach		1,340		0.41		–		–				399		0.39		–		–				1,740		0.41		–		–								2,140		0.40		–		–
Cerro Colorado (6)		Oxide		34		0.60		0.43		–				23		0.59		0.42		–				57		0.60		0.43		–				5.3		100		76		0.59		0.40		–				6.0
		Supergene Sulphide		21		0.60		0.15		–				15		0.62		0.16		–				36		0.61		0.15		–								39		0.67		0.12		–
		Transitional Sulphide		11		0.54		0.09		–				5.6		0.51		0.11		–				17		0.53		0.10		–								–		–		–		–
Spence (7)		Oxide		29		0.63		0.42		–				0.15		0.76		0.57		–				29		0.63		0.42		–				32		100		35		0.65		0.45		–				7.8
		Oxide Low Solubility		15		0.76		0.32		–				2.5		0.49		0.17		–				18		0.72		0.30		–								25		0.77		0.33		–
		Supergene Sulphide		109		0.75		0.10		–				12		0.52		0.10		–				121		0.73		0.10		–								112		0.79		0.11		–
		Transitional Sulphide		19		0.69		0.06		100				0.92		0.57		0.05		70				20		0.68		0.06		100								–		–		–		–
		Hypogene Sulphide		443		0.52		0.02		220				511		0.51		0.02		140				954		0.51		0.02		180								–		–		–		–
		ROM		–		–		–		–				3.4		0.53		0.12		–				3.4		0.53		0.12		–								9.4		0.37		0.14		–
			Mt		%Cu		kg/t U3O8		g/tAu		g/tAg		Mt		%Cu		kg/t U3O8		g/tAu		g/tAg		Mt		%Cu		kg/t U3O8		g/tAu		g/tAg						Mt		%Cu		kg/t U3O8		g/tAu		g/tAg
Copper Uranium Gold
Olympic Dam (8)		UG Sulphide		154		2.06		0.63		0.68		5		346		1.95		0.56		0.74		4		500		1.98		0.58		0.72		4		51		100		–		–		–		–		–		52
		Sulphide		–		–		–		–		–		–		–		–		–		–		–		–		–		–		–						508		1.99		0.58		0.72		4
		Low-grade		8.4		1.20		0.39		0.50		4		27		1.12		0.36		0.51		3		35		1.15		0.37		0.51		3						37		1.13		0.36		0.51		3
			Mt		%Cu		%Zn		g/tAg		ppmMo		Mt		%Cu		%Zn		g/tAg		ppmMo		Mt		%Cu		%Zn		g/tAg		ppmMo						Mt		%Cu		%Zn		g/tAg		ppmMo
Copper Zinc
Antamina (9)		Sulphide Cu only		107		1.02		0.15		7		380		191		0.97		0.18		8		340		298		0.99		0.17		8		350		9.7		33.75		297		1.03		0.17		8		350		10
		Sulphide Cu-Zn		62		0.87		2.14		18		70		154		0.81		2.01		13		80		216		0.83		2.05		14		80						240		0.85		2.03		14		80

303

⁽¹⁾  Cut-off criteria:

Deposit	Ore Type	Ore Reserves
Escondida	Oxide	³ 0.20%SCu
	Sulphide	³ 0.30%TCu and greater than variable cut-off (V_COG) of concentrator. Sulphide ore is processed in the concentrator plants as a result of optimised mine plan with consideration of technical and economical parameters in order to maximise Net Present Value.
	Sulphide Leach	³ 0.30%TCu and lower than V_COG. Sulphide Leach ore is processed by dump leaching as an alternative to the concentrator process.
Cerro Colorado	Oxide, Supergene Sulphide & Transitional Sulphide	³ 0.30%TCu
Spence	Oxide & Oxide Low Solubility	³ 0.30%TCu
	Supergene Sulphide, Transitional Sulphide & Hypogene Sulphide	³ 0.20%TCu
	ROM	³ 0.10%TCu
Olympic Dam	UG Sulphide	Variable between 1.00%Cu and 1.20%Cu
	Low-grade	³ 0.18%Cu
Antamina	Sulphide Cu only	Net value per concentrator hour incorporating all material revenue and cost factors and includes metallurgical recovery (see footnote 4 for averages). Mineralisation at the US$6,000/hr limit averages 0.16% Cu, 2.0 g/t Ag, 141 ppm Mo and 6,700 t/hr mill throughput.
	Sulphide Cu-Zn	Net value per concentrator hour incorporating all material revenue and cost factors and includes metallurgical recovery (see footnote 4 for averages). Mineralisation at the US$6,000/hr limit averages 0.08% Cu, 0.71% Zn, 11.7 g/t Ag and 6,500t/hr mill throughput.

Antamina – All metals used in net value calculations for the reserves were recovered into concentrate (see footnote 4 for averages) and sold.

⁽²⁾  Approximate drill hole spacings used to classify the reserves were:

Deposit	Proven Reserves	Probable Reserves
Escondida	Oxide: 30m × 30m Sulphide: 50m × 50m Sulphide Leach: 60m × 60m	Oxide: 45m × 45m Sulphide: 90m × 90m Sulphide Leach: 115m × 115m
Cerro Colorado	40m to 50m	100m
Spence	Oxide & Oxide Low Solubility: maximum 50m × 50m Supergene Sulphide, Transitional Sulphide & Hypogene Sulphide: maximum 70m × 70m	100m × 100m for all Ore Types
Olympic Dam	20m to 35m	35m to 70m
Antamina	25m to 40m	40m to 75m

⁽³⁾  Ore delivered to process plant.

304

⁽⁴⁾  Metallurgical recoveries for the operations were:

Deposit	Metallurgical Recovery
Escondida	Oxide: 62% Sulphide: 85% Sulphide Leach: 38%
Cerro Colorado	Oxide & Supergene Sulphide: 72% Transitional Sulphide: 64%
Spence	Oxide & Oxide Low Solubility: 80% Supergene Sulphide: 82% Transitional Sulphide & Hypogene Sulphide: 84% ROM: 30%
Olympic Dam	Cu 94%, U3O8 69%, Au 69%, Ag 64%
Antamina	Sulphide Cu only: Cu 93%, Zn 0%, Ag 80%, Mo 65% Sulphide Cu-Zn: Cu 78%, Zn 80%, Ag 64%, Mo 0%

⁽⁵⁾  Escondida – Reserve Life increase by five years was mainly due to a reallocation of Sulphide Leach Ore Reserves to Sulphide Ore Reserves. Inherent within the Reserve Life calculation were Oxide and Sulphide Leach, which have a Reserve Life of 11 years and 16 years respectively. Escondida continues to advance studies to assess the Ore Reserves under the Hamburgo tailings and along the property limit with the Zaldivar deposit.

⁽⁶⁾  Cerro Colorado – Divestment of Cerro Colorado is in progress. Lower grade Oxide and Sulphide material was reallocated to the new Transition Sulphide ore type. The decrease in Reserve Life was due to an increase in nominated production rate from 19.5Mtpa to 20.7Mtpa.

⁽⁷⁾  Spence – Ore Reserves have increased due to the first time declaration of the Hypogene Sulphide ore type, published on 18 October 2017 in BHP Operational Review available to view at www.bhp.com. Transitional Sulphide and Hypogene Sulphide ore type recoveries are based on metallurgical testwork.

⁽⁸⁾  Olympic Dam – Change in ore type from Sulphide to UG Sulphide providing consistency with the underground mining method.

⁽⁹⁾  Antamina – The decrease in the Ore Reserves was mainly due to depletion, partially offset by revision of the tailings storage capacity surveyed in 2017.

305

Iron Ore ⁽¹⁾

Ore Reserves in accordance with Industry Guide 7

As at 30 June 2018																																										As at 30 June 2017
		Proven Reserves												Probable Reserves												Total Reserves												Reserve Life (years)		BHP Interest %		Total Reserves												Reserve Life (years)
Commodity Deposit	Ore Type	Mt		%Fe		%P		%SiO2		%Al2O3		%LOI		Mt		%Fe		%P		%SiO2		%Al2O3		%LOI		Mt		%Fe		%P		%SiO2		%Al2O3		%LOI						Mt		%Fe		%P		%SiO2		%Al2O3		%LOI
Australia
WAIO (2)(3)(4)(5)(6)(7)(8)(9)	BKM		1,060		62.9		0.12		3.0		2.1		4.2		1,550		62.0		0.13		3.7		2.2		4.8		2,600		62.4		0.12		3.4		2.2		4.5		16		88		2,890		61.8		0.12		3.9		2.3		4.7		14
	BKM Bene		20		58.1		0.12		9.3		3.4		2.1		30		57.6		0.11		10.6		3.2		2.0		50		57.8		0.11		10.1		3.3		2.1						50		58.0		0.11		9.9		3.3		2.0
	CID		340		56.6		0.05		6.1		1.6		10.8		60		57.1		0.04		6.1		1.4		10.3		400		56.7		0.04		6.1		1.6		10.7						460		56.9		0.04		6.1		1.5		10.6
	MM		360		62.4		0.06		2.7		1.6		5.9		1,320		61.5		0.06		3.3		1.8		6.5		1,680		61.7		0.06		3.2		1.7		6.3						720		61.3		0.07		3.6		1.9		6.2

⁽¹⁾  Samarco - Following the failure of the Fundão tailings dam in November 2015 and the continued shutdown of its operations, Samarco is reviewing the operation’s reserves. Under these circumstances, BHP is currently not in a position to report reserves for Samarco as of 30 June 2018. However, developments in the future may provide additional information and operating approvals for which a different conclusion might be reached.

⁽²⁾  Approximate drill hole spacings used to classify the reserves were:

Deposit	Proven Reserves	Probable Reserves
WAIO	50m x 50m	150m x 50m

⁽³⁾  WAIO recovery was 100%, except for BKM Bene where Whaleback beneficiation plant recovery was 88% (tonnage basis).

⁽⁴⁾  The reserves grades listed refer to in situ mass percentage on a dry weight basis. Wet tonnes are reported for WAIO deposits based on the following moisture contents: BKM – Brockman 3%, BKM Bene – Brockman Beneficiation 3%, CID – Channel Iron Deposits 8%, MM – Marra Mamba 4%. Iron ore is marketed for WAIO as Lump (direct blast furnace feed) and Fines (sinter plant feed).

⁽⁵⁾  Cut-off grades used to estimate reserves range from 50–62%Fe for all material types. Ore delivered to process plant.

⁽⁶⁾  Reserves are reported on a Pilbara basis by ore type to align with our production of the Newman Blend lump product which comprises of BKM, BKM Bene and MM ore types, in addition to other lump and fines products including CID. This also reflects our single logistics chain and associated management system.

⁽⁷⁾  BHP interest is reported as Pilbara reserve tonnes weighted average across all joint ventures which can vary from year to year. BHP ownership varies between 85% and 100%.

⁽⁸⁾  Reserves are all located on State Agreement mining leases that guarantee the right to mine. Across WAIO, State Government approvals (including environmental and heritage clearances) are required before commencing mining operations in a particular area. Included in the Ore Reserves are select areas where one or more approvals remain outstanding, but where, based on the technical investigations carried out as part of the mine planning process and company knowledge and experience of the approvals process, it is expected that such approvals will be obtained as part of the normal course of business and within the time frame required by the current mine schedule.

⁽⁹⁾  MM ore type has increased due to inclusion of the South Flank project Ore Reserves. The increase was published on 14 June 2018 in an exchange release available to view at www.bhp.com. BKM Ore Reserves have decreased due to depletion and the application of a higher cut-off grade for Mining Area C Ore Reserves due to operational optimisation.

306

Metallurgical Coal

Coal Reserves in accordance with Industry Guide 7

As at 30 June 2018																																					As at 30 June 2017
			Proven Reserve		Probable Reserve		Total Reserve		Proven Marketable Reserves								Probable Marketable Reserves								Total Marketable Reserves								Reserve Life (years)		BHP Interest %		Total Marketable Reserves								Reserve Life (years)
Commodity Deposit (1)(2)(3)(4)(5)	Mining Method	Coal Type	Mt		Mt		Mt		Mt		%Ash		%VM		%S		Mt		%Ash		%VM		%S		Mt		%Ash		%VM		%S						Mt		%Ash		%VM		%S
Metallurgical Coal
Queensland Coal
CQCA JV
Goonyella Riverside (6)	OC	Met		546		19		565		430		9.1		22.8		0.53		14		10.9		23.1		0.57		444		9.2		22.8		0.53		40		50		457		9.2		22.8		0.53		41
Broadmeadow (6)	UG	Met		77		114		191		55		8.0		23.7		0.53		73		9.9		23.5		0.55		128		9.1		23.6		0.54						129		9.1		23.5		0.54
Peak Downs (7)	OC	Met/Th		401		339		740		248		10.6		22.3		0.60		208		10.6		22.7		0.65		456		10.6		22.5		0.62		26		50		–		–		–		–		27
	OC	Met		–		–		–		–		–		–		–		–		–		–		–		–		–		–		–						469		10.6		22.5		0.62
Caval Ridge	OC	Met		266		95		361		159		11.0		22.4		0.57		52		11.0		22.0		0.58		211		11.0		22.3		0.58		29		50		220		11.0		22.3		0.58		30
Saraji (8)	OC	Met		418		48		466		247		10.1		17.8		0.65		23		11.3		18.9		0.77		270		10.2		17.9		0.66		25		50		257		10.3		18.0		0.66		24
Norwich Park (9)(10)	OC	Met		159		70		229		116		10.3		16.8		0.70		49		10.2		16.6		0.70		165		10.3		16.7		0.70		65		50		107		10.3		16.7		0.68		42
Blackwater	OC	Met/Th		158		141		299		140		8.1		26.6		0.43		126		8.8		26.9		0.44		266		8.4		26.7		0.43		15		50		278		8.4		26.7		0.43		15
Daunia	OC	Met		72		47		119		59		8.0		20.8		0.35		40		9.1		19.9		0.34		99		8.4		20.4		0.35		22		50		104		8.4		20.4		0.35		23
Gregory JV
Gregory (10)(11)	OC	Met		6.6		0.3		6.9		5.4		7.0		34.8		0.60		0.2		7.0		35.3		0.60		5.6		7.0		34.8		0.60		4.0		50		2.6		7.4		36.3		0.59		1.0
BHP Mitsui Coal
South Walker Creek (12)	OC	Met/PCI		108		37		145		85		9.2		13.6		0.29		29		9.2		13.2		0.29		114		9.2		13.5		0.30		18		80		–		–		–		–		19
	OC	Met		–		–		–		–		–		–		–		–		–		–		–		–		–		–		–						120		9.2		13.4		0.30
Poitrel (13)	OC	Met		32		31		62		25		8.7		23.5		0.33		25		8.6		23.8		0.33		49		8.7		23.6		0.33		11		80		43		8.8		23.8		0.34		11

⁽¹⁾  Cut-off criteria applied were: Goonyella Riverside, Peak Downs, Caval Ridge, Norwich Park, Gregory, South Walker Creek ³ 0.5m seam thickness; Saraji ³ 0.4m seam thickness; Blackwater, Daunia, Poitrel ³ 0.3m seam thickness; Broadmeadow ³ 2.5m seam thickness.

⁽²⁾  Only geophysically logged, fully analysed cored holes with greater than 95% recovery (or <± 10% expected error at 95% confidence for Goonyella Riverside Broadmeadow) were used to classify reserves. Drill hole spacings vary between seams and geological domains and were determined in conjunction with geostatistical analysis where applicable. The range of maximum drill hole spacings used to classify the Coal Reserves were:

Deposit	Proven Reserves	Probable Reserves
Goonyella Riverside Broadmeadow	900m to 1,300m plus 3D seismic coverage for UG	1,750m to 2,400m
Peak Downs, Caval Ridge	500m to 1,050m	500m to 2,100m
Saraji	450m to 1,800m	800m to 2,600m
Norwich Park	500m to 1,400m	1,000m to 2,800m
Blackwater	450m to 1,000m	900m to 1,850m
Daunia	650m	1,200m
Gregory	850m	850m to 1,700m
South Walker Creek	400m to 800m	650m to 1,500m
Poitrel	300m to 550m	600m to 1,050m

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⁽³⁾  Product recoveries for the operations were:

Deposit	Product Recovery
Goonyella Riverside Broadmeadow	74%
Peak Downs	61%
Caval Ridge	58%
Saraji	57%
Norwich Park	71%
Blackwater	92%
Daunia	83%
Gregory	81%
South Walker Creek	78%
Poitrel	79%

⁽⁴⁾  Total Coal Reserves were at the moisture content when mined (4% CQCA JV, Gregory JV, BHP Mitsui Coal). Total Marketable Reserves were at a product specification moisture content (9.5-10% Goonyella Riverside Broadmeadow; 9.5% Peak Downs; 10% Caval Ridge; 10% Saraji; 10-11% Norwich Park; 7.5-11.5% Blackwater; 9.5-10% Daunia; 8.5% Gregory; 9% South Walker Creek; 10-12% Poitrel) and at an air-dried quality basis, for sale after the beneficiation of the Total Coal Reserves.

⁽⁵⁾  Coal delivered to handling plant.

⁽⁶⁾  Goonyella Riverside and Broadmeadow deposits use the same infrastructure hence Reserve Life applies to both.

⁽⁷⁾  Peak Downs – Change in the Coal Type from Met to Met/Th due to the use of Caval Ridge wash plant to process some coal and produce a thermal product.

⁽⁸⁾  Saraji – The increase in Coal Reserves was due to a higher three year historical average coal price.

⁽⁹⁾  Norwich Park – The increase in Coal Reserves and Reserve Life was due to a higher three year historical average coal price.

⁽¹⁰⁾  Norwich Park and Gregory – Remain on care and maintenance.

⁽¹¹⁾  Gregory – Divestment of Gregory is in progress. The increase in Coal Reserves and Reserve Life is mainly due to updated economic assumptions (changes in prices) and a reduction in nominated production rate from 2.5Mtpa to 2Mtpa.

⁽¹²⁾  South Walker Creek – Change in Coal Type from Met to Met/PCI based on an internal review.

⁽¹³⁾  Poitrel – The increase in Coal Reserves was mainly due to updated economic assumptions (changes in prices) partially offset by changes in the structural model and revised classification.

308

Energy Coal

Coal Reserves in accordance with Industry Guide 7

As at 30 June 2018																																													As at 30 June 2017
Commodity Deposit (1)(2)(3)(4)	Mining Method		Coal Type		Proven Reserves		Probable Reserves		Total Reserves		Proven Marketable Reserves										Marketable Reserves - Probable										Total Marketable Reserves										Reserve Life (years)		BHP Interest %		Total Marketable Reserves										Reserve Life (years)
					Mt		Mt		Mt		Mt		%Ash		%VM		%S		KCal/kg CV		Mt		%Ash		%VM		%S		KCal/kg CV		Mt		%Ash		%VM		%S		KCal/kg CV						Mt		%Ash		%VM		%S		KCal/kg CV
Energy Coal
Australia
Mt Arthur Coal (5)(6)		OC		Th		416		341		757		314		17.7		31.1		0.57		6,320		260		17.7		30.9		0.55		6,330		574		17.7		31.0		0.56		6,320		27		100		480		17.6		31.1		0.56		6,200		22
Colombia
Cerrejón (7)(8)		OC		Th		416		42		458		404		9.4		32.6		0.58		6,141		41		8.6		32.7		0.52		6,168		445		9.3		32.6		0.57		6,144		16		33.33		528		9.2		32.7		0.57		6,072		16

⁽¹⁾  Cut-off criteria:

Deposit	Coal Reserves
Mt Arthur Coal	³ 0.3m seam thickness, £ 26.5% ash, ³ 40% coal washery yield
Cerrejón	³ 0.65m seam thickness

⁽²⁾  Approximate drill hole spacings used to classify the reserves were:

Deposit	Proven Reserves	Probable Reserves
Mt Arthur Coal	200m to 800m	400m to 1,550m
Cerrejón	>6 drill holes per 100ha	2 to 6 drill holes per 100ha

⁽³⁾  Product recoveries for the operations were:

Deposit	Product Recovery
Mt Arthur Coal	76%
Cerrejón	97%

⁽⁴⁾  Total Coal Reserves were at the moisture content when mined (8.7% Mt Arthur Coal; 13% Cerrejón). Total Marketable Coal Reserves were at a product specific moisture content (10.1% Mt Arthur Coal; 13.2% Cerrejón) and at an air-dried quality basis for Mt Arthur Coal and at a total moisture quality basis for Cerrejón.

⁽⁵⁾  Mt Arthur Coal – Coal delivered to handling plant.

⁽⁶⁾  Mt Arthur Coal – The Total Marketable Coal Reserves increased due to the inclusion of an extraction limit inside mining lease as the approval process has begun.

⁽⁷⁾  Cerrejón – The Total Marketable Coal Reserves decreased due to the reduction in the nominated production rate from 33Mtpa to 29.5Mtpa and mining duration constrained to lease expiry in 2034. Coal is delivered to handling plant by exception.

⁽⁸⁾  Cerrejón – While there have been delays in some permits as at 30 June 2018 in response to ongoing local community legal challenges, replacement reserves have been identified within the mine plan utilitising existing fleet capacity. BHP continues to monitor the situation for potential impact on mining.

309

Other Assets

Ore Reserves in accordance with Industry Guide 7

As at 30 June 2018

As at 30 June 2017

Proven Reserves

Probable Reserves

Total Reserves

Reserve Life (years)

BHP Interest %

Total Reserves

Reserve Life (years)

Commodity Deposit (1)(2)(3)(4)

Ore Type

Mt

%Ni

Mt

%Ni

Mt

%Ni

Mt

%Ni

Nickel West Operations

Leinster (5)

OC

–

–

–

–

–

–

–

100

1.9

1.2

2.0

SP

–

–

–

–

–

–

0.16

1.2

Mt Keith (6)

OC

11

0.61

0.13

0.50

11

0.61

2.0

100

21

0.65

3.0

SP

7.3

0.49

3.9

0.45

11

0.48

10

0.48

⁽¹⁾  Cut-off criteria – Mt Keith: Variable between 0.35%Ni and 0.40%Ni and ³ 0.18% recoverable Ni for all Ore Types.

⁽²⁾  Approximate drill hole spacings used to classify the reserve was:

Deposit	Proven Reserves	Probable Reserves
Mt Keith	40m × 40m	80m × 80m

⁽³⁾  Ore delivered to the process plant.

⁽⁴⁾  Metallurgical recovery for the operation was:

Deposit	Metallurgical Recovery
Mt Keith	64%

⁽⁵⁾  Leinster – Reserves were not reported due to being uneconomic after testing with the three year historical average nickel price.

⁽⁶⁾  Mt Keith - The decrease in Ore Reserves was mainly due to depletion, partially offset by upgrade in classification supported by additional drilling.

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6.4    Major projects

At the end of FY2018, BHP had five major projects under development in petroleum, copper, iron ore and potash, with a combined budget of US$10.6 billion over the life of the projects.

Capital and exploration expenditure increased to US$6.8 billion and is expected to further increase to approximately US$8 billion per annum for FY2019.

Projects in execution at the end of FY2018

Commodity	Project and ownership	Capacity (1)	Date of initial production			Capital expenditure (US$M) (1)
				Target		Budget
Projects under development
Petroleum	North West Shelf Greater Western Flank-B (Australia) 16.67% (non-operator)	To maintain LNG plant throughput from the North West Shelf operations. On schedule and on budget, overall project is 87% complete			CY2019		216
Petroleum	Mad Dog Phase 2 (US Gulf of Mexico) 23.9% (non-operator)	New floating production facility with the capacity to produce up to 140,000 gross barrels of crude oil per day. On schedule and on budget, overall project is 23% complete			CY2022		2,154
Iron Ore	South Flank (Australia) 85% (Operator)	Sustaining iron ore mine to replace production from the 80 Mtpa Yandi Mine. Project approved on 14 June 2018			CY2021		3,061	(2)
Copper	Spence Growth Option	New 95 ktpd concentrator is expected to increase Spence’s payable copper in concentrate production by approximately 185 ktpa in the first 10 years of operation and extend the mining operations by more than 50 years. Overall project is 14% complete. Project approved on 17 August 2017			FY2021		2,460
							7,891

311

Other projects in progress at the end of FY2018

			Capital expenditure (US$M) (1)
Commodity	Project and ownership	Scope	Budget
Projects under development
Potash	Jansen Potash (Canada) 100%	Investment to finish the excavation and lining of the production and service shafts, and to continue the installation of essential surface infrastructure and utilities		2,700
				2,700

⁽¹⁾  Unless noted otherwise, references to capacity are on a 100 per cent basis, references to capital expenditure from subsidiaries are reported on a 100 per cent basis and references to capital expenditure from joint operations reflect BHP’s share.

⁽²⁾  Includes initial funding of US$184 million announced on 26 June 2017.

6.5    Legal proceedings

We are involved from time to time in legal proceedings and governmental investigations of a character normally incidental to our business, including claims and pending actions against us seeking damages or clarification of legal rights and regulatory inquiries regarding business practices. Insurance or other indemnification protection may offset the financial impact on the Group of a successful claim.

This section summarises the significant legal proceedings and investigations and associated matters in which we are currently involved or have finalised since the last Annual Report.

Legal proceedings relating to the failure of the Fundão tailings dam at the iron ore operations of Samarco in Minas Gerais and Espírito Santo (Samarco dam failure)

BHP Billiton Brasil is engaged in numerous legal proceedings relating to the Samarco dam failure. Given all of these proceedings are in early stages, it is not possible at this time to provide a range of possible outcomes or a reliable estimate of potential future exposures for BHP Billiton Brasil. The most significant of these proceedings are summarised below. As described below, many of these proceedings involve claims for compensation for the similar or possibly the same damages. There are numerous additional lawsuits against Samarco relating to the Samarco dam failure to which BHP Billiton Brasil is not a party.

R$20 billion public civil claim commenced by the Federal Government of Brazil, states of Espírito Santo and Minas Gerais and other authorities (R$20 billion Public Civil Claim)

On 30 November 2015, the Federal Government of Brazil, states of Espírito Santo and Minas Gerais and other public authorities collectively filed a public civil claim before the 12th Federal Court of Belo Horizonte against Samarco and its shareholders, BHP Billiton Brasil and Vale, seeking the establishment of a fund of up to R$20 billion (approximately US$5.2 billion) in aggregate for clean-up costs and damages.

The plaintiffs also requested certain interim injunctions in connection with the public civil claim. On 18 December 2015, the Federal Court granted the injunctions and, among other things, ordered Samarco to deposit R$2 billion (approximately US$605 million) in to a court-managed bank account for use towards community and environmental rehabilitation. BHP Billiton Brasil, Vale and Samarco immediately appealed against the injunction.

312

On 2 March 2016, BHP Billiton Brasil, together with Vale and Samarco, entered into a Framework Agreement with the plaintiffs (Federal Government of Brazil, states of Espírito Santo and Minas Gerais and certain other authorities) to establish a foundation (Fundação Renova) that will develop and execute environmental and socio-economic programs (Programs) to remediate and provide compensation for damage caused by the Samarco dam failure.

The term of the Framework Agreement is 15 years, renewable for periods of one year successively until all obligations under the Framework Agreement have been performed. Under the Framework Agreement, Samarco is responsible for funding Fundação Renova’s annual calendar year budget for the duration of the Framework Agreement. The amount of funding for each calendar year will be dependent on the remediation and compensation projects to be undertaken in a particular year. To the extent that Samarco does not meet its funding obligations under the Framework Agreement, each of Vale and BHP Billiton Brasil has funding obligations under the Framework Agreement in proportion to its 50 per cent shareholding in Samarco.

On 29 June 2018, BHP Billiton Brasil announced funding of US$158 million to support Fundação Renova for the six months to 31 December 2018, in the event Samarco does not meet its funding obligations under the Framework Agreement.

On 25 June 2018, a Governance Agreement (summarised below), was entered into providing for the settlement of this public civil claim, suspension of the US$155 billion (approximately US$40 billion) Federal Public Prosecution Office claim for 24 months, partial ratification of the Framework Agreement and a formal declaration that the Framework Agreement remains valid for the signing parties. On 8 August 2018, the 12th Federal Court of Minas Gerais ratified the Governance Agreement.

Ratification of the Governance Agreement on 8 August 2018 settled this public civil claim, including the R$1.2 billion (approximately US$365 million) injunction order.

Preliminary Agreement

On 18 January 2017, BHP Billiton Brasil, together with Vale and Samarco, entered into a Preliminary Agreement with the Federal Prosecutors’ Office in Brazil, which outlines the process and timeline for further negotiations towards a final settlement regarding the R$20 billion (approximately US$5.2 billion) public civil claim and the R$155 billion (approximately US$40 billion) Federal Public Prosecution Office claim relating to the dam failure.

Under the Preliminary Agreement, BHP Billiton Brasil, Vale and Samarco agreed interim security (Interim Security) comprising:

• R$1.3 billion (approximately US$335 million) in insurance bonds;

• R$100 million (approximately US$20 million) in liquid assets;

• A charge of R$800 million (approximately US$210 million) over Samarco’s assets;

• R$200 million (approximately US$50 million) to be allocated within the next four years through existing Framework Agreement programs in the Municipalities of Barra Longa, Rio Doce, Santa Cruz do Escalvado and Ponte Nova.

On 24 January 2017, BHP Billiton Brasil, Vale and Samarco provided the Interim Security to the 12th Federal Court of Belo Horizonte, which was to remain in place until the earlier of 30 June 2017 and the date that a final settlement arrangement was agreed between the Federal Prosecutors, and BHP Billiton Brasil, Vale and Samarco. Following, a series of extensions, on 25 June 2018, the parties reached an agreement in the form of the Governance Agreement (summarised below).

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Governance Agreement

On 25 June 2018, BHP Billiton Brasil, Vale, Samarco, the other parties to the Framework Agreement, the Public Prosecutors Office and the Public Defence Office entered into a Governance Agreement (summarised below) which settles the R$20 billion (approximately US$5.2 billion) public civil claim, enhances community participation in decisions related to Programs under the Framework Agreement and establishes a process to renegotiate the Programs over two years to progress settlement of the R$155 billion (approximately US$40 billion) Federal Public Prosecution Office claim (Governance Agreement).

Renegotiation of the Programs will be based on certain agreed principles such as full reparation consistent with Brazilian law, the requirement for a technical basis for any proposed changes, consideration of findings from experts appointed by BHP Billiton Brasil, Samarco and Vale, consideration of findings from experts appointed by Prosecutors and consideration of feedback from impacted communities. During the renegotiation period and up until revisions to the Programs are agreed, the Renova Foundation will continue to implement the Programs in accordance with the terms of the Framework Agreement and the Governance Agreement.

The Governance Agreement was ratified by the 12th Federal Court of Minas Gerais on 8 August 2018, settling the R$20 billion (approximately US$5.2 billion) public civil claim and suspending the R$155 billion (approximately US$40 billion) Federal Public Prosecution Office claim for a period of two years from the date of ratification.

Interim Security provided under the Preliminary Agreement is maintained for a period of 30 months under the Governance Agreement, after which BHP Billiton Brasil, Vale and Samarco will be required to provide security of an amount equal to the Fundação Renova’s annual budget up to a limit of R$2.2 billion (approximately US$570 million).

R$155 billion public civil claim commenced by the Federal Public Prosecution Service (R$155 billion Federal Public Prosecution Office claim).

On 3 May 2016, the Federal Public Prosecution Office filed a public civil claim before the 12th Federal Court of Belo Horizonte against BHP Billiton Brasil, Vale and Samarco – as well as 18 other public entities (which has since been reduced to five defendants²² by the Court) – seeking R$155 billion (approximately US$40 billion) for reparation, compensation and collective moral damages in relation to the Samarco dam failure.

In addition, the claim includes a number of preliminary injunction requests, seeking orders that BHP Billiton Brasil, Vale and Samarco deposit R$7.7 billion (approximately US$2 billion) in a special company account and provide guarantees equivalent to R$155 billion (approximately US$40 billion). The injunctions also seek to prohibit BHP Billiton Brasil, Vale and Samarco from distributing dividends and selling certain assets (among other things).

The 12th Federal Court previously suspended this public civil claim, including the R$7.7 billion (approximately US$2 billion) injunction request. Suspension of the claim continues for a period of two years from the date of ratification of the Governance Agreement on 8 August 2018.

Public civil claims commenced by the State Prosecutors’ Office in the state of Minas Gerais

On 10 December 2015, the State Prosecutors’ Office in the state of Minas Gerais filed a public civil claim against BHP Billiton Brasil, Vale and Samarco before the State Court in Mariana claiming indemnification (amount not specified) for moral and material damages to an unspecified group of individuals affected by the Samarco dam failure, including the payment of costs for housing and social and economic assistance.

²²  Currently, solely the companies, the Federal Government and the State of Minas Gerais are defendants.

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The State Prosecutors’ Office also requested certain interim injunctions in connection with this claim, including orders for BHP Billiton Brasil, Vale and Samarco to provide housing, health care, financial assistance and education facilities to the people affected by the Samarco dam failure. The plaintiff also sought an order to freeze R$300 million (approximately US$80 million) in Samarco’s bank accounts. The Court granted the injunction freezing R$300 million (approximately US$80 million) in Samarco’s bank accounts for use towards the compensation and remediation measures requested under this public civil claim. At a Court hearing on 20 January 2016, the parties agreed that Samarco should unilaterally provide:

• flexible housing solutions for 271 displaced families;

• monthly salaries to the displaced families for at least 12 months;

• a R$20,000 (approximately US$5,000) payment to each displaced family;

• a R$100,000 (approximately US$25,000) payment to each of the families of those deceased, as advance compensation.

There have been multiple hearings, injunctions and enforcement petitions of previous settlements requested in this public civil claim. Samarco has requested the Court to release part of the frozen amount to pay for (i) the technical entity hired to assist the impacted community; and (ii) payments related to the Preliminary Agreement. This public civil claim is ongoing and no final decision has been issued.

On 2 February 2016, the State Prosecutors’ Office in the state of Minas Gerais filed another public civil claim against BHP Billiton Brasil, Vale and Samarco before the State Court in Ponte Nova claiming compensation of R$7.5 billion (approximately US$2.3 billion) for moral and material damages suffered by 1,350 individuals in Ponte Nova and collective moral damages allegedly suffered by the community in Ponte Nova. The claim also sought a number of preliminary injunctions, including orders to:

• freeze R$1 billion (approximately US$305 million) of cash in the defendants’ bank accounts in order to secure the compensation requested under the public civil claim;

• require the defendants to pay minimum wages and basic food supplies to the families in Ponte Nova affected by the Samarco dam failure;

• require the defendants to pay R$30,000 (approximately US$8,000) per affected family and compensation to provide dignified and adequate housing for the affected families.

On 5 February 2016, the Court granted an injunction to freeze R$475 million (approximately US$145 million) from bank accounts of BHP Billiton Brasil, Vale and Samarco and ordered them to pay preliminary amounts to families in Ponte Nova affected by the Samarco dam failure. This injunction was revoked on 9 November 2016 and the Court, on 8 May 2018, also ordered the frozen funds to be returned to BHP Billiton Brasil (R$2 million). Samarco and BHP Billiton Brasil have filed their defences, respectively on 6 December 2016 and 9 March 2017. This case has been remitted to the 12th Federal Court in Belo Horizonte and is currently suspended.

Public civil claim commenced by the Public Defender Department in Minas Gerais

On 25 April 2016, the Public Defender Department filed a public civil claim against BHP Billiton Brasil, Vale and Samarco in the State Court in Belo Horizonte, Minas Gerais, Brazil claiming R$10 billion (approximately US$2.6 billion) for collective moral damages to be deposited in the State Human Rights Defense Fund. The Public Defender Department is also seeking a number of social and environmental remediation measures in relation to the Samarco dam failure, including orders requiring the reparation of the environmental damage and the reconstruction of properties and populations, including historical, religious, cultural, social, environmental and immaterial heritages affected by the dam failure. On 16 March 2016, the Court denied the remediation measures requested as an injunction by the Public Defender Department. The public civil claim was remitted to the 12th Federal Court in Belo Horizonte and is currently suspended.

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Public civil claim commenced by the State Prosecutors’ Office in the state of Espírito Santo

On 15 January 2016, the State Prosecutors’ Office of Espírito Santo filed a public civil claim before the State Court in Espírito Santo against BHP Billiton Brasil, Vale and Samarco seeking compensation for collective moral damages in relation to the suspension of the water supply of the Municipality of Colatina as a result of the Samarco dam failure. As part of the public civil claim, the State Prosecutors’ Office sought a number of injunctions, including an order to freeze R$2 billion (approximately US$520 million) in the defendants’ bank accounts in order to secure the requested compensation. On 11 February 2016, the Court denied all of the injunction requests made by the State Prosecutors’ Office. The State Prosecutors’ Office appealed the decision and on 2 August 2016 the State Court of Appeal decided to remit the case to the 12th Federal Court in Belo Horizonte. This public civil claim is suspended.

Public civil claim commenced by the state of Espírito Santo

On 8 January 2016, the state of Espírito Santo filed a public civil claim against BHP Billiton Brasil, Vale and Samarco before the State Court in Colatina (later remitted to the 12th Federal Court in Belo Horizonte) seeking the remediation and restoration of the water supply of the residents of Baixo Guandu, Linhares, Colatina and Marilândia. In addition, the claim sought injunctions ordering, among other things, the execution of several works and improvements in public equipment in order to repair and upgrade the sewage system and water network in Colatina and Linhares, and an order to freeze R$1 billion (approximately US$260 million) of the defendants’ assets. On 4 February 2016, the Court ordered Samarco to deposit approximately R$7 million (approximately US$2 million) in a fund of the state of Espírito Santo to be created and granted certain injunctions relating to remediation measures. At the same time it denied the injunction request to freeze assets of R$1 billion (approximately US$260 million). On 6 April 2016 the Court of Appeals suspended the injunctions granted. BHP Billiton Brasil, Vale and Samarco filed their defences in March 2016 and also requested the suspension of this public civil claim. On 18 December 2017, the case was remitted to the 12th Federal Court.

Public civil claim commenced by the Association for the Defense of Collective Interests – ADIC

On 17 November 2015, ADIC, a NGO in Brazil, filed a public civil claim solely against Samarco before the 12th Federal Court in Belo Horizonte claiming at least R$10 billion (approximately US$2.6 billion) for environmental and social damages in relation to the Samarco dam failure, in addition to collective moral damages and reparation measures. The NGO also requested preliminary injunctions ordering the deposit of R$1 billion (approximately US$260 million) and prohibiting Samarco from distributing dividends to its shareholders. Samarco presented its defence on 12 February 2016. The Court did not decide on the injunction request and on 27 March 2017, the Court suspended this public civil claim.

Other proceedings

As noted above, BHP Billiton Brasil has been named as a defendant in numerous other lawsuits that are at early stages of proceedings. The lawsuits seek various remedies, including rehabilitation costs, compensation to injured individuals and families of the deceased, recovery of personal and property losses and injunctive relief. In addition, government inquiries and investigations relating to the Samarco dam failure have been commenced by numerous agencies of the Brazilian Government and are ongoing, including criminal investigations by the federal and state police, and by federal prosecutors.

Our potential liabilities, if any, resulting from other pending and future claims, lawsuits and enforcement actions relating to the Samarco dam failure, together with the potential cost of implementing remedies sought in the various proceedings, cannot be reliably estimated at this time and therefore a provision has not been recognised and nor has any contingent liability been quantified for these matters. Ultimately these could have a material adverse impact on BHP’s business, competitive position, cash flows, prospects, liquidity and shareholder returns. For more information on the Samarco dam failure, refer to section 1.8.

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As at June 2018, Samarco has been named as a defendant in more than 50,255 small claims in which people had their water service interrupted for between five and 10 days, and courts have awarded damages, which generally range from R$1,000 (approximately US$260) to R$10,000 (approximately US$2,600) per impacted person. Currently, the majority of such small claims are suspended due to a recourse presented by Samarco before the Minas Gerais State Court. Given the number of people affected by the Samarco dam failure, the number of potential claimants may continue to increase. BHP Billiton Brasil is a defendant in more than 15,500 of these cases.

Criminal charges

On 20 October 2016, the Federal Prosecutors’ Office filed criminal charges against BHP Billiton Brasil, Vale and Samarco and certain employees and former employees of BHP Billiton Brasil (Affected Individuals) in the Federal Court of Ponte Nova, Minas Gerais. On 3 March 2017, BHP Billiton Brasil and the Affected Individuals filed their preliminary defences. BHP Billiton Brasil rejects outright the charges against the company and the Affected Individuals and will defend the charges and fully support each of the Affected Individuals in their defence of the charges.

United States class action complaint – shareholders

In February 2016, a putative class action complaint (Complaint) was filed in the U.S. District Court for the Southern District of New York on behalf of purchasers of American Depositary Receipts of BHP Billiton Limited and BHP Billiton Plc between 25 September 2014 and 30 November 2015 against BHP Billiton Limited and BHP Billiton Plc and certain of its current and former executive officers and directors. The Complaint asserts claims under US federal securities laws and indicates that the plaintiff will seek certification to proceed as a class action.

On 14 October 2016, the defendants moved to dismiss the Complaint. In a decision of the District Court dated 28 August 2017, the claims were dismissed in part, including the claims against the current and former executive officers and directors.

On 6 August 2018, the parties reached an in-principle settlement agreement of US$50 million to resolve all claims with no admission of liability by the Defendants. The agreement is subject to Court approval. BHP expects to recover the majority of the settlement payment under its external insurance arrangements.

United States class action complaint – bondholders

On 14 November 2016, a putative class action complaint (Complaint) was filed in the U.S. District Court for the Southern District of New York on behalf of all purchasers of Samarco’s ten-year bond notes due 2022-2024 between 31 October 2012 and 30 November 2015 against Samarco and the former chief executive officer of Samarco. The Complaint asserts claims under the U.S. federal securities laws and indicates that the plaintiff will seek certification to proceed as a class action.

On 6 March 2017, the Complaint was amended to include BHP Billiton Limited, BHP Billiton Plc, BHP Billiton Brasil Ltda and Vale S.A. and officers of Samarco, including four of Vale S.A. and BHP Billiton Brasil Ltda’s nominees to the Samarco Board. On 5 April 2017, the plaintiff dismissed the claims against the individuals. The remaining corporate defendants filed a joint motion to dismiss the plaintiff’s Complaint on 26 June 2017.

On 7 March 2018, the District Court granted the defendants’ motion to dismiss the Complaint; however, the District Court granted the plaintiff leave to file a second amended Complaint, which it did on 21 March 2018. On 21 May 2018, the defendants’ moved to dismiss the Complaint. The defendants’ motion is pending before the District Court.

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The amount of damages sought by the plaintiff on behalf of the putative class is unspecified. Given the preliminary status of this matter, it is not possible at this time to provide a range of possible outcomes or a reliable estimate of potential future exposures to BHP Billiton Limited, BHP Billiton Plc and BHP Billiton Brasil Ltda.

Australian class action complaints

On 31 May 2018, a shareholder class action was filed in the Federal Court of Australia (Melbourne) against BHP Billiton Ltd on behalf of persons who, during the period from 21 October 2013 to 9 November 2015, acquired BHP Billiton Ltd shares on the Australian Securities Exchange or BHP Billiton Plc shares on the London Stock Exchange or Johannesburg Stock Exchange.

On 31 August 2018 an additional shareholder class action that makes similar allegations was filed in the Federal Court of Australia against BHP Billiton Ltd on behalf of persons who, during the period from 27 August 2014 to 9 November 2015, entered into a contract to acquire BHP Billiton Ltd shares on the Australian Securities Exchange or BHP Billiton Plc shares on the London Stock Exchange or Johannesburg Stock Exchange.

Orders have been made for the Court to consider how to manage the competing shareholder class actions on 29 October 2018.

The amount of damages sought by the plaintiff on behalf of the class is unspecified.

Tax and royalty matters

The Group presently has unresolved tax and royalty matters for which the timing of resolution and potential economic outflow is uncertain. For details of those matters, refer to note 5 ‘Income and tax expense’ in section 5.

6.6    Glossary

6.6.1    Mining, oil and gas-related terms

2D

Two dimensional.

3D

Three dimensional.

AIG

The Australian Institute of Geoscientists.

AusIMM

The Australasian Institute of Mining and Metallurgy.

Beneficiation

The process of physically separating ore from waste material prior to subsequent processing of the improved ore.

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Brownfield

The development or exploration located inside the area of influence of existing mine operations which can share infrastructure/management.

Butane

A component of natural gas. Where sold separately, is largely butane gas that has been liquefied through pressurisation. One tonne of butane is approximately equivalent to 14,000 cubic feet of gas.

Coal Reserves

Equivalent to Ore Reserves, but specifically concerning coal.

Coking coal

Used in the manufacture of coke, which is used in the steelmaking process by virtue of its carbonisation properties. Coking coal may also be referred to as metallurgical coal.

Condensate

A mixture of hydrocarbons that exist in gaseous form in natural underground reservoirs, but which condense to form a liquid at atmospheric conditions.

Conventional Petroleum Resources

Hydrocarbon accumulations that can be produced by a well drilled into a geologic formation in which the reservoir and fluid characteristics permit the hydrocarbons to readily flow to the wellbore without the use of specialised extraction technologies.

Copper cathode

Electrolytically refined copper that has been deposited on the cathode of an electrolytic bath of acidified copper sulphate solution. The refined copper may also be produced through leaching and electrowinning.

Crude oil

A mixture of hydrocarbons that exist in liquid form in natural underground reservoirs, and remain liquid at atmospheric pressure after being produced at the well head and passing through surface separating facilities.

Cut-off grade

A nominated grade above which an Ore Reserve is defined. For example, the lowest grade of mineralised material that qualifies as economic for estimating an Ore Reserve.

Dated Brent

A benchmark price assessment of the spot market value of physical cargoes of North Sea light sweet crude oil.

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Electrowinning/electrowon

An electrochemical process in which metal is recovered by dissolving a metal within an electrolyte and plating it onto an electrode.

Energy coal

Used as a fuel source in electrical power generation, cement manufacture and various industrial applications. Energy coal may also be referred to as steaming or thermal coal.

Ethane

A component of natural gas. Where sold separately, is largely ethane gas that has been liquefied through pressurisation. One tonne of ethane is approximately equivalent to 28,000 cubic feet of gas.

FAusIMM

Fellow of the Australasian Institute of Mining and Metallurgy.

Field

An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field.

The geological terms ‘structural feature’ and ‘stratigraphic condition’ are intended to identify localised geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc. (per SEC Regulation S-X, Rule 4-10).

Flotation

A method of selectively recovering minerals from finely ground ore using a froth created in water by specific reagents. In the flotation process, certain mineral particles are induced to float by becoming attached to bubbles of froth and the unwanted mineral particles sink.

FPSO (Floating, production, storage and off-take)

A floating vessel used by the offshore oil and gas industry for the processing of hydrocarbons and for storage of oil. An FPSO vessel is designed to receive hydrocarbons produced from nearby platforms or subsea templates, process them and store oil until it can be offloaded onto a tanker.

Grade or Quality

Any physical or chemical measurement of the characteristics of the material of interest in samples or product.

Greenfield

The development or exploration located outside the area of influence of existing mine operations/infrastructure.

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Heap leach(ing)

A process used for the recovery of metals such as copper, nickel, uranium and gold from low-grade ores. The crushed material is laid on a slightly sloping, impermeable pad and leached by uniformly trickling (gravity fed) a chemical solution through the beds to ponds. The metals are recovered from the solution.

Hypogene Sulphide

Hypogene mineralisation is formed by fluids at high temperature and pressure derived from magmatic activity. Hypogene sulphide consists predominantly of chalcopyrite.

International Centre for Settlement of Investment Disputes (ICSID)

ICSID is an autonomous international institution that provides facilities and services to support conciliation and arbitration of international investment disputes between investors and States. ICSID was established under the Convention on the Settlement of Investment Disputes between States and Nationals of Other States (the ICSID Convention), with over 140 member States.

Joint Ore Reserves Committee (JORC) Code

A set of minimum standards, recommendations and guidelines for public reporting in Australasia of Exploration Results, Mineral Resources and Ore Reserves. The guidelines are defined by the Australasian Joint Ore Reserves Committee (JORC), which is sponsored by the Australian mining industry and its professional organisations.

Leaching

The process by which a soluble metal can be economically recovered from minerals in ore by dissolution.

LNG (liquefied natural gas)

Consists largely of methane that has been liquefied through chilling and pressurisation. One tonne of LNG is approximately equivalent to 46,000 cubic feet of natural gas.

LOI (loss on ignition)

A measure of the percentage of volatile matter (liquid or gas) contained within a mineral or rock. LOI is determined to calculate loss in mass when subjected to high temperatures.

LPG (liquefied petroleum gas)

Consists of propane and butane and a small amount (less than two per cent) of ethane that has been liquefied through pressurisation. One tonne of LPG is approximately equivalent to 12 barrels of oil.

MAIG

Member of the Australian Institute of Geoscientists.

Marketable Coal Reserves

Tonnes of coal available, at specified moisture content and air-dried qualities, for sale after the beneficiation of Coal Reserves.

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MAusIMM

Member of the Australasian Institute of Mining and Metallurgy.

Metallurgical coal

A broader term than coking coal, which includes all coals used in steelmaking, such as coal used for the pulverised coal injection process.

Metocean

A term that is commonly used in the offshore oil and gas industry to describe the physical environment and surrounds (i.e. an environment near an offshore oil and gas working platform).

MGSSA

Member of the Geological Society of South Africa.

Mineralisation

Any single mineral or combination of minerals occurring in a mass, or deposit, of economic interest.

NGL (natural gas liquids)

Consists of propane, butane and ethane – individually or as a mixture.

Nominated production rate

The approved average production rate for the remainder of the life-of-asset plan or five-year plan production rate if significantly different to life-of-asset production rate.

OC/OP (open-cut/open-pit)

Surface working in which the working area is kept open to the sky.

Ore Reserves

That part of a mineral deposit that can be economically and legally extracted or produced at the time of the reserves determination. To establish this, studies appropriate to this type of mineral deposit involved have been carried out to estimate the quantity, grade and value of the ore mineral(s) present. In addition, technical studies have been completed to determine realistic assumptions for the extraction of minerals including estimates of mining, processing, economic, marketing, legal, environmental, social and governmental factors. The degree of these studies is sufficient to demonstrate the technical and economic feasibility of the project and depends on whether or not the project is an extension of an existing project or operation. The estimates of minerals to be produced include allowances for ore losses and the treatment of unmineralised materials which may occur as part of the mining and processing activities. Ore Reserves are sub-divided in order of increasing confidence into Probable Ore Reserves and Proven Ore Reserves.

Such studies demonstrate that, at the time of reporting, extraction could reasonably be justified (JORC Code, 2012).

PCI

Pulverised coal injection.

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P. Eng. PEGNL

Professional Engineer of the Association of Professional Engineers and Geoscientists of Newfoundland and Labrador.

Probable Ore Reserves

Ore Reserves for which quantity and grade and/or quality are estimated for information similar to that used for Proven Ore Reserves, that the sites for inspection, sampling, and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for Proven Ore Reserves, is high enough to assume continuity between points of observation.

Propane

A component of natural gas. Where sold separately, is largely propane gas that has been liquefied through pressurisation. One tonne of propane is approximately equivalent to 19,000 cubic feet of gas.

Proved oil and gas reserves

Those quantities of oil, gas and natural gas liquids, which by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation (from SEC Modernization of Oil and Gas Reporting, 2009, 17 CFR Parts 210, 211, 229 and 249).

Proven Ore Reserves

Ore Reserves for which (a) quantity is estimated from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement are paced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well established.

Qualified petroleum reserves and resources evaluator

A qualified petroleum reserves and resources evaluator, as defined in Chapter 19 of the ASX Listing Rules.

Reserve Life

Current stated Ore Reserves estimate divided by the current approved nominated production rate as at the end of the financial year.

ROM (run of mine)

Run of mine product mined in the course of regular mining activities. Tonnes include allowances for diluting materials and for losses that occur when the material is mined.

Solvent extraction

A method of separating one or more metals from a leach solution by treating with a solvent that will extract the required metal, leaving the others. The metal is recovered from the solvent by further treatment.

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SP (stockpile)

An accumulation of ore or mineral built up when demand slackens or when the treatment plant or beneficiation equipment is incomplete or temporarily unable to process the mine output; any heap of material formed to create a buffer for loading or other purposes or material dug and piled for future use.

Spud

Commence drilling of an oil or gas well.

Supergene Sulphide

Supergene is a term used to describe near-surface processes and their products, formed at low temperature and pressure by the activity of descending water. Supergene sulphide is mainly formed of chalcocite and covellite and is amenable to heap leaching.

Tailings

Those portions of washed or milled ore that are too poor to be treated further or remain after the required metals and minerals have been extracted.

TLP (tension leg platform)

A vertically moored floating facility for production of oil and gas.

Total Ore Reserves

The sum of Proven and Probable Ore Reserves.

UG (underground)

Below the surface mining activities.

Unconventional Petroleum Resources

Hydrocarbon accumulations that are generally pervasive in nature and may be continuous throughout a large area requiring specialised extraction technologies to produce or recover. Examples include, but are not limited to coalbed methane, basin-centred gas, shale gas, gas hydrates, natural bitumen (tar sands), and oil shale deposits.

Examples of specialised technologies include: dewatering of coalbed methane, massive fracturing programs for shale gas, steam and/or solvents to mobilise bitumen for in situ recovery, and, in some cases, mining activities.

Wet tonnes

Production is usually quoted in terms of wet metric tonnes (wmt). To adjust from wmt to dry metric tonnes (dmt) a factor is applied based on moisture content.

WTI (West Texas Intermediate)

A mixture of hydrocarbons that exists in liquid phase in natural underground reservoirs and remains liquid at atmospheric pressure after passing through surface separating facilities. Crude oil is refined to produce a wide array of petroleum products, including heating oils; gasoline, diesel and jet fuels; lubricants; asphalt; ethane, propane, and butane; and many other products used for their energy or chemical content.

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West Texas Intermediate refers to a crude stream produced in Texas and southern Oklahoma that serves as a reference or ‘marker’ for pricing a number of other crude streams and which is traded in the domestic spot market at Cushing, Oklahoma.

6.6.2    Other terms

AASB (Australian Accounting Standards Board)

Accounting standards as issued by the Australian Accounting Standards Board.

ADR (American Depositary Receipt)

An instrument evidencing American Depository Shares or ADSs, which trades on a stock exchange in the United States.

ADS (American Depositary Share)

A share issued under a deposit agreement that has been created to permit US-resident investors to hold shares in non-US companies and trade them on the stock exchanges in the United States.

ADSs are evidenced by American Depositary Receipts, or ADRs, which are the instruments that trade on a stock exchange in the United States.

ASIC (Australian Securities and Investments Commission)

The Australian Government agency that enforces laws relating to companies, securities, financial services and credit in order to protect consumers, investors and creditors.

Assets

Assets are a set of one or more geographically proximate operations (including open-cut mines, underground mines, and onshore and offshore oil and gas production and production facilities). Assets include our operated and non-operated assets.

Asset groups

We group our assets into geographic regions in order to provide effective governance and accelerate performance improvement. Minerals assets are grouped under Minerals Australia or Minerals Americas based on their geographic location. Oil, gas and petroleum assets are grouped together as Petroleum.

ASX (Australian Securities Exchange)

ASX is a multi-asset class vertically integrated exchange group that functions as a market operator, clearing house and payments system facilitator. It oversees compliance with its operating rules, promotes standards of corporate governance among Australia’s listed companies and helps educate retail investors.

BHP

Both companies in the DLC structure, being BHP Billiton Limited and BHP Billiton Plc and their respective subsidiaries.

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BHP Billiton Limited Group

BHP Billiton Limited and its subsidiaries.

BHP Billiton Limited share

A fully paid ordinary share in the capital of BHP Billiton Limited.

BHP Billiton Limited shareholders

The holders of BHP Billiton Limited shares.

BHP Billiton Limited Special Voting Share

A single voting share issued to facilitate joint voting by shareholders of BHP Billiton Limited on Joint Electorate Actions.

BHP Billiton Plc Group

BHP Billiton Plc and its subsidiaries.

BHP Billiton Plc share

A fully paid ordinary share in the capital of BHP Billiton Plc.

BHP Billiton Plc shareholders

The holders of BHP Billiton Plc shares.

BHP Billiton Plc Special Voting Share

A single voting share issued to facilitate joint voting by shareholders of BHP Billiton Plc on Joint Electorate Actions.

BHP shareholders

In the context of BHP’s financial results, BHP shareholders refers to the holders of shares in BHP Billiton Limited and BHP Billiton Plc.

Board

The Board of Directors of BHP.

Company

BHP Billiton Limited, BHP Billiton Plc and their respective subsidiaries.

Continuing operations

Assets/operations/entities that are owned and/or operated by BHP, excluding Onshore US and assets/operations/entities included in the demerger of South32.

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Discontinued operations

For FY2014 to FY2018, Discontinued operations includes assets/operations/entities that are owned by and/or operated by BHP during FY2018 and held for sale as part of our Onshore US sale, which was announced on 27 July 2018. For FY2014 and FY2015, Discontinued operations also includes assets/operations/entities that were owned and/or operated by BHP during FY2015 and demerged into a new company (South32) on 25 May 2015.

Dividend record date

The date, determined by a company’s board of directors, by when an investor must be recorded as an owner of shares in order to qualify for a forthcoming dividend.

DLC Dividend Share

A share to enable a dividend to be paid by BHP Billiton Plc to BHP Billiton Limited or by BHP Billiton Limited to BHP Billiton Plc (as applicable).

DLC (Dual Listed Company)

BHP’s Dual Listed Company structure has two parent companies (BHP Billiton Ltd and BHP Billiton Plc) operating as a single economic entity as a result of the DLC merger.

DLC merger

The Dual Listed Company merger between BHP Billiton Limited and BHP Billiton Plc on 29 June 2001.

ELT (Executive Leadership Team)

The Executive Leadership Team directly reports to the Chief Executive Officer and is responsible for the day-to-day management of BHP and leading the delivery of our strategic objectives.

Executive KMP

Executive KMP includes the Executive Director (our CEO), the Chief Financial Officer, the President Operations, Minerals Australia, the President Operations, Minerals Americas, and the President Operations, Petroleum. It does not include the Non-executive Directors (our Board).

Functions

Functions operate along global reporting lines to provide support to all areas of the organisation. Functions have specific accountabilities and deep expertise in areas such as finance, legal, governance, technology, human resources, corporate affairs, health, safety and community.

Gearing ratio

The ratio of net debt to net debt plus net assets.

GHG (greenhouse gas)

For BHP reporting purposes, these are the aggregate anthropogenic carbon dioxide equivalent emissions of carbon dioxide (CO₂), methane (CH₄), nitrous oxide (N₂O), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs) and sulphur hexafluoride (SF₆).

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Group

BHP Billiton Limited, BHP Billiton Plc and their respective subsidiaries.

Henry Hub

A natural gas pipeline located in Erath, Louisiana that serves as the official delivery location for futures contracts on the New York Mercantile Exchange.

HPI (high potential injuries)

High potential injuries (HPI) are recordable injuries and first aid cases where there was the potential for a fatality.

IFRS (International Financial Reporting Standards)

Accounting standards as issued by the International Accounting Standards Board.

KMP (Key Management Personnel)

Persons having authority and responsibility for planning, directing and controlling the activities of the Group, directly or indirectly.

For BHP, KMP includes the Executive Director (our CEO), the Non-Executive Directors (our Board), as well as the Chief Financial Officer, the President Operations, Minerals Australia, the President Operations, Minerals Americas, and the President Operations, Petroleum.

KPI (Key performance indicator)

Used to measure the performance of the Group, individual businesses and executives in any one year.

LME (London Metal Exchange)

A major futures exchange for the trading of industrial metals.

Marketing and Supply

BHP’s commercial businesses that optimise our working capital and manage our inward and outward supply chains. Our Marketing business sells our products, gets our commodities to market and supports strategic decision-making through market insights. Supply sources the goods and services we need for our business, sustainably and cost effectively.

Minerals Americas

A group of assets located in Brazil, Canada, Chile, Colombia, Peru and the United States (see ‘Asset groups’) focusing on copper, zinc, iron ore, energy coal and potash.

Minerals Australia

A group of assets located in Australia (see ‘Asset groups’). Minerals Australia includes operations in Western Australia, Queensland, New South Wales and South Australia, focusing on iron ore, copper, metallurgical and energy coal, and nickel.

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Non-operated asset / Non-operated joint venture (NOJV)

Non-operated assets / non-operated joint ventures include interests in assets that are owned as a joint venture but not operated by BHP. References in this Annual Report to a ‘joint venture’ are used for convenience to collectively describe assets that are not wholly owned by BHP. Such references are not intended to characterise the legal relationship between the owners of the asset.

Occupational illness

An illness that occurs as a consequence of work-related activities or exposure. It includes acute or chronic illnesses or diseases, which may be caused by inhalation, absorption, ingestion or direct contact.

OMC (Operations Management Committee)

Prior to FY2018, the Operations Management Committee had responsibility for planning, directing and controlling the activities of BHP under the authorities that have been delegated to it by the Board. This included key strategic, investment and operational decisions, and recommendations to the Board.

During FY2018 the OMC was dissolved and the Remuneration Committee re-examined the classification of KMP for FY2018 to determine which persons have the authority and responsibility for planning, directing and controlling the activities of BHP. After due consideration, the Remuneration Committee determined the KMP for FY2018 comprised of all Non-executive Directors (the Board), the Executive Director (the CEO), the Chief Financial Officer, the President Operations, Minerals Australia, the President Operations, Minerals Americas, and the President Operations, Petroleum. The Committee also determined that, effective 1 July 2017, the Chief External Affairs Officer and Chief People Officer roles are no longer considered KMP.

Onshore US

BHP’s Petroleum asset in four US shale areas (Eagle Ford, Permian, Haynesville and Fayetteville), where we produce oil, condensate, gas and natural gas liquids.

Operated assets

Operated assets include assets that are wholly owned and operated by BHP and assets that are owned as a joint venture and operated by BHP. References in this Annual Report to a ‘joint venture’ are used for convenience to collectively describe assets that are not wholly owned by BHP. Such references are not intended to characterise the legal relationship between the owners of the asset.

Operating Model

The Operating Model outlines how BHP is organised, works and measures performance and includes mandatory performance requirements and common systems, processes and planning. The Operating Model has been simplified and BHP is organised by assets, asset groups, Marketing and Supply, and functions.

Operations

Open-cut mines, underground mines, onshore and offshore oil and gas production and processing facilities.

Our Requirements

The standards that give effect to the mandatory requirements arising from the BHP Operating Model as approved by the Executive Leadership Team (ELT). They describe the mandatory minimum performance requirements and accountabilities for definitive business obligations, processes, functions and activities across BHP.

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Previously called Group Level Documents (GLDs), the Our Requirements standards reflect a simpler organisation with the purpose of being more user-friendly and easier to read.

Petroleum (asset group)

A group of conventional and non-conventional oil and gas assets (see ‘Asset groups’). Petroleum’s core production operations are located in the US Gulf of Mexico, Australia, Trinidad and Tobago and onshore United States. Petroleum produces crude oil and condensate, gas and natural gas liquids.

Platts

Platts is a global provider of energy, petrochemicals, metals and agriculture information and a premier source of benchmark price assessments for those commodity markets.

Quoted

In the context of American Depositary Shares (ADS) and listed investments, the term ‘quoted’ means ‘traded’ on the relevant exchange.

SEC (United States Securities and Exchange Commission)

The US regulatory commission that aims to protect investors, maintain fair, orderly and efficient markets and facilitate capital formation.

Senior manager

An employee who has responsibility for planning, directing or controlling the activities of the entity or a strategically significant part of it. In the Strategic Report, senior manager includes senior leaders and any persons who are directors of any subsidiary company even if they are not senior leaders.

Shareplus

All-employee share purchase plan.

Social investment

Voluntary contributions to support communities through cash donations to community programs and associated administrative costs. BHP’s targeted level of contribution is one per cent of pre-tax profit calculated on the average of the previous three years’ pre-tax profit as reported.

South32

During FY2015, BHP demerged a selection of our alumina, aluminium, coal, manganese, nickel, silver, lead and zinc assets into a new company – South32 Limited.

Strate

South Africa’s Central Securities Depositary for the electronic settlement of financial instruments.

TRIF (total recordable injury frequency)

The sum of (fatalities + lost-time cases + restricted work cases + medical treatment cases) x 1,000,000 ÷ actual hours worked.

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Stated in units of per million hours worked. BHP adopts the US Government Occupational Safety and Health Administration guidelines for the recording and reporting of occupational injury and illnesses. TRIF statistics exclude non-operated assets.

TSR (total shareholder return)

TSR measures the return delivered to shareholders over a certain period through the movements in share price and dividends paid (which are assumed to be reinvested). It is the measure used to compare BHP’s performance to that of other relevant companies under the Long-Term Incentive Plan.

UKLA (United Kingdom Listing Authority)

Term used when the UK Financial Conduct Authority (FCA) acts as the competent authority under Part VI of the UK Financial Services and Markets Act (FSMA).

Underlying attributable profit

Profit/(loss) after taxation attributable to BHP shareholders excluding any exceptional items attributable to BHP shareholders as described in note 2 ‘Exceptional items’ in section 5. Refer to section 1.11 for further information.

Underlying EBIT

Underlying EBITDA, including depreciation, amortisation and impairments. Refer to section 1.11 for further information.

Underlying EBITDA

Earnings before net finance costs, depreciation, amortisation and impairments, taxation expense, Discontinued operations and exceptional items. Refer to section 1.11 for further information.

Unit costs

One of the financial measures BHP uses to monitor the performance of individual assets. Unit costs are calculated as revenue less Underlying EBITDA excluding third party. Conventional petroleum unit costs exclude inventory movements, freight, exploration and development and evaluation expense; WAIO, Queensland Coal and New South Wales Energy Coal unit costs exclude freight and royalties; Escondida unit costs exclude freight and treatment and refining charges and are net of by-product credits. FY2019 and medium-term unit cost guidance are based on exchange rates of AUD/USD 0.75 and USD/CLP 663. Other forward looking guidance is based on internal exchange rate assumptions.

6.6.3    Terms used in reserves

Ag

silver

AI₂O₃

alumina

Anth

anthracite

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Ash

inorganic material remaining after combustion

Au

gold

Cu

copper

CV

calorific value

Fe

iron

Insol.

insolubles

K₂O

potassium oxide

KCl

potassium chloride

LOI

loss on ignition

Met

metallurgical coal

MgO

magnesium oxide

Mo

molybdenum

Ni

nickel

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P

phosphorous

Pc

phosphorous in concentrate

PCI

pulverised coal injection

S

sulphur

SCu

soluble copper

SiO₂

silica

TCu

total copper

Th

thermal coal

U₃O₈

uranium oxide

VM

volatile matter

Yield

the percentage of material of interest that is extracted during mining and/or processing

Zn

zinc

6.6.4    Units of measure

%

percentage or per cent

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bbl

barrel (containing 42 US gallons)

bbl/d

barrels per day

Bcf

billion cubic feet (measured at the pressure bases set by the regulator)

bcm

bank cubic metres

boe

barrels of oil equivalent – 6,000 scf of natural gas equals 1 boe

dmt

dry metric tonne

dmtu

dry metric tonne unit

g/t

grams per tonne

ha

hectare

kcal/kg

kilocalories per kilogram

kg/tonne or kg/t

kilograms per tonne

km

kilometre

kt

kilotonnes

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ktpa

kilotonnes per annum

ktpd

kilotonnes per day

kV

kilovolt

m

metre

Mbbl/d

thousand barrels per day

ML

megalitre

mm

millimetre

MMbbl/d

million barrels per day

MMboe

million barrels of oil equivalent

MMBtu

million British thermal units – 1 scf of natural gas equals 1,010 Btu

MMcf/d

million cubic feet per day

MMcm/d

million cubic metres per day

Mscf

thousand standard cubic feet

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Mt

million tonnes

Mtpa

million tonnes per annum

MW

megawatt

ppm

parts per million

psi

pounds per square inch

scf

standard cubic feet

t

tonne

TJ

terajoule

TJ/d

terajoules per day

tpa

tonnes per annum

tpd

tonnes per day

t/h

tonnes per hour

wmt

wet metric tonnes

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7    Shareholder information

7.1    History and development

BHP Billiton Limited (formerly BHP Limited and, before that, The Broken Hill Proprietary Company Limited) was incorporated in 1885 and is registered in Australia with ABN 49 004 028 077. BHP Billiton Plc (formerly Billiton Plc) was incorporated in 1996 and is registered in England and Wales with registration number 3196209. Successive predecessor entities to BHP Billiton Plc have operated since 1860.

We have operated under a Dual Listed Company (DLC) structure since 29 June 2001. Under the DLC structure, the two parent companies, BHP Billiton Limited and BHP Billiton Plc, operate as a single economic entity, run by a unified Board and senior executive management team. For more information on the DLC structure, refer to section 7.3.

7.2    Markets

As at the date of this Annual Report, BHP Billiton Limited has a primary listing on the Australian Securities Exchange (ASX) in Australia and BHP Billiton Plc has a premium listing on the UK Listing Authority’s Official List and its ordinary shares are admitted to trading on the London Stock Exchange (LSE). BHP Billiton Plc also has a secondary listing on the Johannesburg Stock Exchange (JSE) in South Africa.

In addition, BHP Billiton Limited and BHP Billiton Plc are listed on the New York Stock Exchange (NYSE) in the United States. Trading on the NYSE is via American Depositary Receipts (ADRs) evidencing American Depositary Shares (ADSs), with each ADS representing two ordinary shares of BHP Billiton Limited or BHP Billiton Plc. Citibank N.A. (Citibank) is the Depositary for both ADS programs. BHP Billiton Limited’s ADSs have been listed for trading on the NYSE (ticker BHP) since 28 May 1987 and BHP Billiton Plc’s since 25 June 2003 (ticker BBL).

7.3    Organisational structure

7.3.1    General

BHP consists of the BHP Billiton Limited Group and the BHP Billiton Plc Group, operating as a single unified economic entity, following the completion of the DLC merger in June 2001 (the DLC merger). For a full list of BHP Billiton Limited and BHP Billiton Plc subsidiaries, refer to section 5.2 note 13.

7.3.2    DLC Structure

BHP shareholders approved the DLC merger in 2001, which was designed to place ordinary shareholders of both companies in a position where they have economic and voting interests in a single group.

The principles of the BHP DLC structure are reflected in the DLC Structure Sharing Agreement and include the following:

The two companies must operate as if they are a single unified economic entity, through Boards of Directors that comprise the same individuals and a unified senior executive management team.

The Directors of both companies will, in addition to their duties to the company concerned, have regard to the interests of the ordinary shareholders in the two companies as if the two companies were a single unified economic entity and, for that purpose, the Directors of each company take into account in the exercise of their powers the interests of the shareholders of the other.

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Certain DLC equalisation principles must be observed. These are designed to ensure that for so long as the Equalisation Ratio between a BHP Billiton Limited ordinary share and a BHP Billiton Plc ordinary share is 1:1, the economic and voting interests resulting from holding one BHP Billiton Limited ordinary share and one BHP Billiton Plc ordinary share are, so far as practicable, equivalent. For more information, refer to sub-section ‘Equalisation of economic and voting rights’ below.

Australian Foreign Investment Review Board conditions

The Treasurer of Australia approved the DLC merger subject to certain conditions, the effect of which was to require that, among other things, BHP Billiton Limited continues to:

be an Australian company, which is headquartered in Australia;

ultimately manage and control the companies that conducted the businesses that were conducted by its subsidiaries at the time of the DLC merger for as long as those businesses form part of BHP.

The conditions also require the global headquarters of BHP to be in Australia.

The conditions have effect indefinitely, subject to amendment of the Australian Foreign Acquisitions and Takeovers Act 1975 (FATA) or any revocation or amendment by the Treasurer of Australia. If BHP Billiton Limited no longer wishes to comply with these conditions, it must obtain the prior approval of the Treasurer. Failure to comply with the conditions results in substantial penalties under the FATA.

Equalisation of economic and voting rights

The economic and voting interests attached to each BHP Billiton Limited ordinary share relative to each BHP Billiton Plc ordinary share are determined by a ratio known as the Equalisation Ratio.

The Equalisation Ratio is currently 1:1, meaning one BHP Billiton Limited ordinary share currently has the same economic and voting interests as one BHP Billiton Plc ordinary share.

The Equalisation Ratio governs the proportions in which dividends and capital distributions are paid on the ordinary shares in each company relative to the other. Given the current Equalisation Ratio of 1:1, the amount of any cash dividend paid by BHP Billiton Limited on each BHP Billiton Limited ordinary share must be matched by an equivalent cash dividend by BHP Billiton Plc on each BHP Billiton Plc ordinary share, and vice versa. If one company is prohibited by applicable law or is otherwise unable to pay a matching dividend, the DLC Structure Sharing Agreement requires that BHP Billiton Limited and BHP Billiton Plc will, as far as practicable, enter into such transactions with each other as their Boards agree to be necessary or desirable to enable both companies to pay matching dividends at the same time. These transactions may include BHP Billiton Limited or BHP Billiton Plc making a payment to the other company or paying a dividend on the DLC Dividend Share held by the other company (or a subsidiary of it). The DLC Dividend Share may be used to ensure that the need to trigger the matching dividend mechanism does not arise. BHP Billiton Limited issued a DLC Dividend Share on 23 February 2016. No DLC Dividend Share has been issued by BHP Billiton Plc. For more information on the DLC Dividend Share, refer to section ‘DLC Dividend Share’ below and section 7.5.

The Equalisation Ratio may be adjusted to maintain economic equivalence between an ordinary share in each of the two companies where, broadly speaking (and subject to certain exceptions):

a distribution or action affecting the amount or nature of issued share capital is proposed by one of BHP Billiton Limited and BHP Billiton Plc and that distribution or action would result in the ratio of economic returns on, or voting rights in relation to Joint Electorate Actions (see below) of, a BHP Billiton Limited ordinary share to a BHP Billiton Plc ordinary share not being the same, or would benefit the holders of ordinary shares in one company relative to the holders of ordinary shares in the other company;

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no ‘matching action’ is taken by the other company. A matching action is a distribution or action affecting the amount or nature of issued share capital in relation to the holders of ordinary shares in the other company which ensures that the economic and voting rights of a BHP Billiton Limited ordinary share and BHP Billiton Plc ordinary share are maintained in proportion to the Equalisation Ratio.

For example, an adjustment would be required if there were to be a capital issue or distribution by one company to its ordinary shareholders that does not give equivalent value (before tax) on a per share basis to the ordinary shareholders of the other company and no matching action was undertaken. Since the establishment of the DLC structure in 2001, no adjustment to the Equalisation Ratio has ever been made.

DLC Dividend Share

Each of BHP Billiton Limited and BHP Billiton Plc is authorised to issue a DLC Dividend Share to the other company or a wholly owned subsidiary of it. In effect, only that other company or a wholly owned subsidiary of it may be the holder of the share. The share is redeemable.

The holder of the share is entitled to be paid such dividends as the Board may decide to pay on that DLC Dividend Share provided that:

the amount of the dividend does not exceed the cap mentioned below;

the Board of the issuing company in good faith considers paying the dividend to be in furtherance of any of the DLC principles, including the principle of BHP Billiton Limited and BHP Billiton Plc operating as a single unified economic entity.

The amounts that may be paid as dividends on a DLC Dividend Share are capped. Broadly speaking, the cap is the total amount of the preceding ordinary cash dividend (whether interim or final) paid on BHP Billiton Limited ordinary shares or BHP Billiton Plc ordinary shares, whichever is greater. The cap will not apply to any dividend paid on a DLC Dividend Share if the proceeds of that dividend are to be used to pay a special cash dividend on ordinary shares.

A DLC Dividend Share otherwise has limited rights and does not carry a right to vote. DLC Dividend Shares cannot be used to transfer funds outside of BHP as the terms of issue contain structural safeguards to ensure that a DLC Dividend Share may only be used to pay dividends within the Group. For more information on the rights attaching to and terms of DLC Dividend Shares, refer to section 7.5, the Constitution of BHP Billiton Limited and the Articles of Association of BHP Billiton Plc.

Joint Electorate Actions

Under the terms of the DLC agreements, BHP Billiton Limited and BHP Billiton Plc have implemented special voting arrangements so that the ordinary shareholders of both companies vote together as a single decision-making body on matters that affect the ordinary shareholders of each company in similar ways. These are referred to as Joint Electorate Actions. For so long as the Equalisation Ratio remains 1:1, each BHP Billiton Limited ordinary share will effectively have the same voting rights as each BHP Billiton Plc ordinary share on Joint Electorate Actions.

A Joint Electorate Action requires approval by ordinary resolution (or special resolution if required by statute, regulation, applicable listing rules or other applicable requirements) of BHP Billiton Limited and BHP Billiton Plc. In the case of BHP Billiton Limited, both the BHP Billiton Limited ordinary shareholders and the holder of the BHP Billiton Limited Special Voting Share vote as a single class and, in the case of BHP Billiton Plc, the BHP Billiton Plc ordinary shareholders and the holder of the BHP Billiton Plc Special Voting Share vote as a single class.

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Class Rights Actions

Matters on which ordinary shareholders of BHP Billiton Limited may have divergent interests from the ordinary shareholders of BHP Billiton Plc are referred to as Class Rights Actions. The company wishing to carry out the Class Rights Action requires the prior approval of the ordinary shareholders in the other company voting separately and, where appropriate, the approval of its own ordinary shareholders voting separately. Depending on the type of Class Rights Action undertaken, the approval required is either an ordinary or special resolution of the relevant company.

The Joint Electorate Action and Class Rights Action voting arrangements are secured through the constitutional documents of the two companies, the DLC Structure Sharing Agreement, the BHP Special Voting Shares Deed and rights attaching to a specially created Special Voting Share issued by each company and held in each case by a special voting company. The shares in the special voting companies are held legally and beneficially by Law Debenture Trust Corporation Plc.

Cross guarantees

BHP Billiton Limited and BHP Billiton Plc have each executed a Deed Poll Guarantee in favour of the creditors of the other company. Under the Deed Poll Guarantees, each company has guaranteed certain contractual obligations of the other company. This means that creditors entitled to the benefit of the BHP Billiton Limited Deed Poll Guarantee and the BHP Billiton Plc Deed Poll Guarantee will, to the extent possible, be placed in the same position as if the relevant debts were owed by both BHP Billiton Limited and BHP Billiton Plc on a combined basis.

Restrictions on takeovers of one company only

The BHP Billiton Limited Constitution and the BHP Billiton Plc Articles of Association have been drafted to ensure that, except with the consent of the Board, a person cannot gain control of one company without having made an equivalent offer to the ordinary shareholders of both companies on equivalent terms. Sanctions for breach of these provisions would include withholding of dividends, voting restrictions and the compulsory divestment of shares to the extent a shareholder and its associates exceed the relevant threshold.

7.4    Material contracts

DLC structure agreements

BHP Billiton Limited (then known as BHP Limited) and BHP Billiton Plc (then known as Billiton Plc) merged by way of a DLC structure on 29 June 2001. To effect the DLC structure, BHP Limited and Billiton Plc (as they were then known) entered into the following contractual agreements:

BHP Billiton DLC Structure Sharing Agreement

BHP Billiton Special Voting Shares Deed

BHP Billiton Limited Deed Poll Guarantee

BHP Billiton Plc Deed Poll Guarantee.

For information on the effect of each of these agreements, refer to section 7.3.

Framework Agreement

On 2 March 2016, BHP Billiton Brasil together with Vale and Samarco, entered into a Framework Agreement with the Federal Government of Brazil, states of Espírito Santo and Minas Gerais and certain other authorities to establish a foundation (Fundação Renova) that will develop and execute environmental and socio-economic programs to remediate and provide compensation for damage caused by the Samarco dam failure. For a description of the terms of the Framework Agreement, refer to section 6.5.

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7.5    Constitution

This section sets out a summary of the Constitution of BHP Billiton Limited and the Articles of Association of BHP Billiton Plc. Where the term ‘BHP’ is used in this section, it can mean either BHP Billiton Limited or BHP Billiton Plc.

Provisions of the Constitution of BHP Billiton Limited and the Articles of Association of BHP Billiton Plc can be amended only where such amendment is approved by special resolution either:

by approval as a Class Rights Action, where the amendment results in a change to an ‘Entrenched Provision’; or

otherwise, as a Joint Electorate Action.

In 2015, shareholders approved a number of amendments to our constitutional documents to amend the terms of the Equalisation Shares (which were renamed as DLC Dividend Shares) and to facilitate the more streamlined conduct of simultaneous general meetings.

For a description of Joint Electorate Actions and Class Rights Actions, refer to section 7.3.2.

7.5.1    Directors

The Board may exercise all powers of BHP, other than those that are reserved for BHP shareholders to exercise in a general meeting.

7.5.2    Power to issue securities

Under the Constitution and Articles of Association, the Board of Directors has the power to issue any BHP shares or other securities (including redeemable shares) with preferred, deferred or other special rights, obligations or restrictions. The Board may issue shares on any terms it considers appropriate, provided that:

• the issue does not affect any special rights of shareholders;

• if required, the issue is approved by shareholders; and

• if the issue is of a class other than ordinary shares, the rights attaching to the class are expressed at the date of issue.

7.5.3    Restrictions on voting by Directors

A Director may not vote in respect of any contract or arrangement or any other proposal in which they have a material personal interest except in certain prescribed circumstances, including (subject to applicable laws) where the material personal interest:

arises because the Director is a shareholder of BHP and is held in common with the other shareholders of BHP;

arises in relation to the Director’s remuneration as a Director of BHP;

relates to a contract BHP is proposing to enter into that is subject to approval by the shareholders and will not impose any obligation on BHP if it is not approved by the shareholders;

arises merely because the Director is a guarantor or has given an indemnity or security for all or part of a loan, or proposed loan, to BHP;

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arises merely because the Director has a right of subrogation in relation to a guarantee or indemnity referred to above;

relates to a contract that insures, or would insure, the Director against liabilities the Director incurs as an officer of BHP, but only if the contract does not make BHP or a related body corporate the insurer;

relates to any payment by BHP or a related body corporate in respect of an indemnity permitted by law, or any contract relating to such an indemnity; or

is in a contract, or proposed contract with, or for the benefit of, or on behalf of, a related body corporate and arises merely because the Director is a director of a related body corporate.

If a Director has a material personal interest and is not entitled to vote on a proposal, they will not be counted in the quorum for any vote on a resolution concerning the material personal interest.

In addition, under the UK Companies Act 2006, a Director has a duty to avoid conflicts of interest between their interests and the interests of the company. The duty is not breached if, among other things, the conflict of interest is authorised by non-interested Directors. The Articles of Association of BHP Billiton Plc enable the Board to authorise a matter that might otherwise involve a Director breaching their duty to avoid conflicts of interest. An interested Director may not vote or be counted towards a quorum for a resolution authorising a conflict of interest. Where the Board authorises a conflict of interest, the Board may prohibit the relevant Director from voting on any matter relating to the conflict. The Board has adopted procedures to manage these voting restrictions.

7.5.4    Loans by Directors

Any Director may lend money to BHP at interest with or without security or may, for a commission or profit, guarantee the repayment of any money borrowed by BHP and underwrite or guarantee the subscription of shares or securities of BHP or of any corporation in which BHP may be interested without being disqualified as a Director and without being liable to account to BHP for any commission or profit.

7.5.5    Appointment and retirement of Directors

Appointment of Directors

The Constitution and Articles of Association provide that a person may be appointed as a Director of BHP by the existing Directors of BHP or may be elected by the shareholders in a general meeting.

Any person appointed as a Director of BHP by the existing Directors will hold office only until the next general meeting that includes an election of Directors.

A person may be nominated by shareholders as a Director of BHP if:

a shareholder provides a valid written notice of the nomination;

the person nominated by the shareholder satisfies candidature for the office and consents in writing to his or her nomination as a Director,

in each case, at least 40 business days before the earlier of the date of the general meeting of BHP Billiton Plc and the corresponding general meeting of BHP Billiton Limited. The person nominated as a Director may be elected to the Board by ordinary resolution passed in a general meeting.

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Under the Articles of Association, if a person is validly nominated for election as a Director at a general meeting of BHP Billiton Limited, the Directors of BHP Billiton Plc must nominate that person as a Director at the corresponding general meeting of BHP Billiton Plc. An equivalent requirement is included in the Constitution, which requires any person validly nominated for election as a Director of BHP Billiton Plc to be nominated as a Director of BHP Billiton Limited.

Retirement of Directors

The Board has a policy consistent with the UK Corporate Governance Code under which all Directors must, if they wish to remain on the Board, seek re-election by shareholders annually. This policy took effect from the 2011 Annual General Meetings (AGMs) and replaced the previous system that required Directors to submit themselves to shareholders for re-election at least every three years.

A Director may be removed by BHP in accordance with applicable law and must vacate his or her office as a Director in certain circumstances set out in the Constitution and Articles of Association. There is no requirement for a Director to retire on reaching a certain age.

7.5.6    Rights attaching to shares

Dividend rights

Under English law, dividends on shares may only be paid out of profits available for distribution. Under Australian law, dividends on shares may be paid only if the company’s assets exceed its liabilities immediately before the dividend is determined and the excess is sufficient for payment of the dividend, the payment of the dividend is fair and reasonable to the company’s shareholders as a whole and the payment of the dividend does not materially prejudice the company’s ability to pay its creditors.

The Constitution and Articles of Association provide that payment of any dividend may be made in any manner, by any means and in any currency determined by the Board.

All unclaimed dividends may be invested or otherwise used by the Board for the benefit of whichever of BHP Billiton Limited or BHP Billiton Plc determined that dividend, until claimed or, in the case of BHP Billiton Limited, otherwise disposed of according to law. BHP Billiton Limited is governed by the Victorian unclaimed monies legislation, which requires BHP Billiton Limited to pay to the State Revenue Office any unclaimed dividend payments of A$20 or more that have remained unclaimed for over 12 months.

In the case of BHP Billiton Plc, any dividend unclaimed after a period of 12 years from the date the dividend was determined or became due for payment will be forfeited and returned to BHP Billiton Plc.

Voting rights

Voting at any general meeting of BHP shareholders can, in the first instance, be conducted by a show of hands unless a poll is demanded in accordance with the Constitution or Articles of Association (as applicable) or is otherwise required (as outlined below).

Generally, matters considered by shareholders at an AGM of BHP Billiton Limited or BHP Billiton Plc constitute Joint Electorate Actions or Class Rights Actions and must be decided on a poll and in the manner described under the headings ‘Joint Electorate Actions’ and ‘Class Rights Actions’ in section 7.3.2. This means that, in practice, most items of business at AGMs are decided by way of a poll.

In addition, at any general meeting a resolution, other than a procedural resolution, put to the vote of the meeting on which the holder of the relevant BHP Special Voting Share is entitled to vote must be decided on a poll.

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For the purposes of determining which shareholders are entitled to attend or vote at a meeting of BHP Billiton Plc or BHP Billiton Limited, and how many votes such shareholder may cast, the Notice of Meeting will specify when a shareholder must be entered on the Register of Shareholders in order to have the right to attend or vote at the meeting. The specified time must be not more than 48 hours before the time of the meeting.

Shareholders who wish to appoint a proxy to attend, vote or speak at a meeting of BHP Billiton Plc or BHP Billiton Limited (as appropriate) on their behalf must deposit the relevant form appointing a proxy so that it is received by that company not less than 48 hours before the time of the meeting.

Rights to share in BHP Billiton Limited’s profits

The rights attached to the ordinary shares of BHP Billiton Limited, as regards the participation in the profits available for distribution, are as follows:

The holders of any preference shares will be entitled, in priority to any payment of dividend to the holders of any other class of shares, to a preferred right to participate as regards dividends up to but not beyond a specified amount in distribution.

Subject to the special rights attaching to any preference shares, but in priority to any payment of dividends on all other classes of shares, the holder of the DLC Dividend Share (if any) will be entitled to be paid such non-cumulative dividends as the Board may, subject to the cap referred to in section 7.3 and the DLC Dividend Share being held by BHP Billiton Plc or a wholly owned member of its group, decide to pay on that DLC Dividend Share.

Any surplus remaining after payment of the distributions above will be payable to the holders of BHP Billiton Limited ordinary shares and the BHP Billiton Limited Special Voting Share in equal amounts per share.

Rights to share in BHP Billiton Plc’s profits

The rights attached to the ordinary shares of BHP Billiton Plc, in relation to the participation in the profits available for distribution, are as follows:

The holders of the cumulative preference shares will be entitled, in priority to any payment of dividend to the holders of any other class of shares, to be paid a fixed cumulative preferential dividend (Preferential Dividend) at a rate of 5.5 per cent per annum, to be paid annually in arrears on 31 July in each year or, if any such date will be a Saturday, Sunday or public holiday in England, on the first business day following such date in each year. Payments of Preferential Dividends will be made to holders on the register at any date selected by the Directors up to 42 days prior to the relevant fixed dividend date.

Subject to the rights attaching to the cumulative preference shares, but in priority to any payment of dividends on all other classes of shares, the holder of the BHP Billiton Plc Special Voting Share will be entitled to be paid a fixed dividend of US$0.01 per annum, payable annually in arrears on 31 July.

Subject to the rights attaching to the cumulative preference shares and the BHP Billiton Plc Special Voting Share, but in priority to any payment of dividends on all other classes of shares, the holder of the DLC Dividend Share will be entitled to be paid such non-cumulative dividends as the Board may, subject to the cap referred to in section 7.3 of this Annual Report and the DLC Dividend Share being held by BHP Billiton Limited or a wholly owned member of its group, decide to pay on that DLC Dividend Share.

Any surplus remaining after payment of the distributions above will be payable to the holders of the BHP Billiton Plc ordinary shares in equal amounts per BHP Billiton Plc ordinary share.

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DLC Dividend Share

As set out in section 7.3.2, each of BHP Billiton Limited and BHP Billiton Plc is authorised to issue a DLC Dividend Share to the other company or a wholly owned subsidiary of it.

The dividend rights attaching to a DLC Dividend Share are described above and in section 7.3. The DLC Dividend Share issued by BHP Billiton Limited (BHP Billiton Limited DLC Dividend Share) and the DLC Dividend Share that may be issued by BHP Billiton Plc (BHP Billiton Plc DLC Dividend Share) have no voting rights and, as set out in section 7.5.7 below, very limited rights to a return of capital on a winding-up. A DLC Dividend Share may be redeemed at any time, and must be redeemed if a person other than:

in the case of the BHP Billiton Limited DLC Dividend Share, BHP Billiton Plc or a wholly owned member of its group;

in the case of the BHP Billiton Plc DLC Dividend Share, BHP Billiton Limited or a wholly owned member of its group,

becomes the beneficial owner of the DLC Dividend Share.

7.5.7    Rights on return of assets on liquidation

Under the DLC structure, special provisions designed to ensure that, as far as practicable, the holders of ordinary shares in BHP Billiton Limited and holders of ordinary shares in BHP Billiton Plc are treated equitably having regard to the Equalisation Ratio, which would apply in the event of an insolvency of either or both companies.

On a return of assets on liquidation of BHP Billiton Limited, the assets of BHP Billiton Limited remaining available for distribution among shareholders after the payment of all prior ranking amounts owed to all creditors and holders of preference shares, and to all prior ranking statutory entitlements, are to be applied subject to the special provisions referred to above in paying to the holders of the BHP Billiton Limited Special Voting Share and the DLC Dividend Share of an amount of up to A$2.00 on each such share, on an equal priority with any amount paid to the holders of BHP Billiton Limited ordinary shares, and any surplus remaining is to be applied in making payments solely to the holders of BHP Billiton Limited ordinary shares in accordance with their entitlements.

On a return of assets on liquidation of BHP Billiton Plc, subject to the payment of all amounts payable under the special provisions referred to above, prior ranking amounts owed to the creditors of BHP Billiton Plc and to all prior ranking statutory entitlements, the assets of BHP Billiton Plc to be distributed on a winding-up are to be distributed to the holders of shares in the following order of priority:

To the holders of the cumulative preference shares, the repayment of a sum equal to the nominal capital paid up or credited as paid up on the cumulative preference shares held by them and any accrued Preferential Dividend, whether or not such dividend has been earned or declared, calculated up to the date of commencement of the winding-up.

To the holders of the BHP Billiton Plc ordinary shares and to the holders of the BHP Billiton Plc Special Voting Share and the DLC Dividend Share, the payment out of surplus, if any, remaining after the distribution above of an equal amount for each BHP Billiton Plc ordinary share, the BHP Billiton Plc Special Voting Share and the DLC Dividend Share subject to a maximum in the case of the BHP Billiton Plc Special Voting Share and the DLC Dividend Share of the nominal capital paid up on such shares.

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7.5.8    Redemption of preference shares

If BHP Billiton Limited at any time proposes to create and issue any preference shares, the terms of the preference shares may give either or both BHP Billiton Limited and the holder the right to redeem the preference shares.

The preference shares terms may also give the holder the right to convert the preference shares into ordinary shares.

Under the Constitution, the preference shares must give the holders:

the right (on redemption and on a winding-up) to payment in cash in priority to any other class of shares of (i) the amount paid or agreed to be considered as paid on each of the preference shares; and (ii) the amount, if any, equal to the aggregate of any dividends accrued but unpaid and of any arrears of dividends;

the right, in priority to any payment of dividend on any other class of shares, to the preferential dividend.

There is no equivalent provision in the Articles of Association of BHP Billiton Plc, although as noted above in section 7.5.2, BHP can issue preference shares that are subject to a right of redemption on terms the Board considers appropriate.

7.5.9    Capital calls

Subject to the terms on which any shares may have been issued, the Board may make calls on the shareholders in respect of all monies unpaid on their shares. BHP has a lien on every partly paid share for all amounts payable in respect of that share. Each shareholder is liable to pay the amount of each call in the manner, at the time and at the place specified by the Board (subject to receiving at least 14 days’ notice specifying the time and place for payment). A call is considered to have been made at the time when the resolution of the Board authorising the call was passed.

7.5.10    Borrowing powers

Subject to relevant law, the Directors may exercise all powers of BHP to borrow money, and to mortgage or charge its undertaking, property, assets (both present and future) and all uncalled capital or any part or parts thereof and to issue debentures and other securities, whether outright or as collateral security for any debt, liability or obligation of BHP or of any third party.

Rights attached to any class of shares issued by either BHP Billiton Limited or BHP Billiton Plc can only be varied (whether as a Joint Electorate Action or a Class Rights Action) where such variation is approved by:

the company that issued the relevant shares, as a special resolution; and

the holders of the issued shares of the affected class, either by a special resolution passed at a separate meeting of the holders of the issued shares of the class affected, or with the written consent of members with at least 75 per cent of the votes of that class.

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7.5.11    Conditions governing general meetings

The Board may, and must on requisition in accordance with applicable laws, call a general meeting of the shareholders at the time and place or places and in the manner determined by the Board. No shareholder may convene a general meeting of BHP except where entitled under law to do so. Any Director may convene a general meeting whenever the Director thinks fit. General meetings can also be cancelled, postponed or adjourned, where permitted by law or the Constitution or Articles of Association. Notice of a general meeting must be given to each shareholder entitled to vote at the meeting and such notice of meeting must be given in the form and manner in which the Board thinks fit. Five shareholders of the relevant company present in person or by proxy constitute a quorum for a meeting. A shareholder who is entitled to attend and cast a vote at a general meeting of BHP may appoint a person as a proxy to attend and vote for the shareholder in accordance with applicable law. All provisions relating to general meetings apply with any necessary modifications to any special meeting of any class of shareholders that may be held.

7.5.12    Limitations of rights to own securities

There are no limitations under the Constitution or the Articles of Association restricting the right to own BHP shares other than restrictions that reflect the takeovers codes under relevant Australian and English law. In addition, the Australian Foreign Acquisitions and Takeovers Act 1975 imposes a number of conditions that restrict foreign ownership of Australian-based companies.

For information on share control limits imposed by the Constitution and the Articles of Association, as well as relevant laws, refer to sections 7.11 and 7.3.2.

7.5.13    Documents on display

Documents filed by BHP Billiton Limited on the Australian Securities Exchange (ASX) are available at asx.com.au and documents filed on the London Stock Exchange (LSE) by BHP Billiton Plc are available at morningstar.co.uk/uk/NSM. Documents filed on the ASX, or on the LSE are not incorporated by reference into this Annual Report. The documents referred to in this Annual Report as being available on our website, bhp.com, are not incorporated by reference and do not form part of this Annual Report.

BHP Billiton Limited and BHP Billiton Plc both file Annual Reports and other reports and information with the US Securities and Exchange Commission (SEC). These filings are available on the SEC website at sec.gov. You may also read and copy any document that either BHP Billiton Limited or BHP Billiton Plc files at the SEC’s public reference room located at 100 F Street, NE, Washington, DC 20549. Please call the SEC at 1-800-SEC-0330 or access the SEC website at sec.gov for further information on the public reference room.

7.6    Share ownership

Share capital

The details of the share capital for both BHP Billiton Limited and BHP Billiton Plc are presented in note 14 ‘Share capital’ in section 5 and remain current as at 24 August 2018.

Major shareholders

The tables in section 3.3.18 and the information set out in section 4.18 present information pertaining to the shares in BHP Billiton Limited and BHP Billiton Plc held by Directors and members of the Key Management Personnel (KMP).

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Neither BHP Billiton Limited nor BHP Billiton Plc is directly or indirectly controlled by another corporation or by any government. Other than as described in section 7.3.2, no major shareholder possesses voting rights that differ from those attaching to all of BHP Billiton Limited and BHP Billiton Plc’s voting securities.

Substantial shareholders in BHP Billiton Limited

The following table shows holdings of five per cent or more of voting rights in BHP Billiton Limited’s shares as notified to BHP Billiton Limited under the Australian Corporations Act 2001, Section 671B as at 30 June 2018.⁽¹⁾

Title of class

Identity of person or group

Date of last notice

Percentage of total voting rights (2)

Date received

Date of change

Number owned

2018

2017

2016

Ordinary shares

BlackRock Group

19 December 2016

15 December 2016

160,784,672

5.00%

5.00%

<5.00%

⁽¹⁾  No changes in the holdings of five per cent or more of the voting rights in BHP Billiton Limited’s shares have been notified to BHP Billiton Limited between 1 July 2018 and 24 August 2018.

⁽²⁾  The percentages quoted are based on the total voting rights conferred by ordinary shares in BHP Billiton Limited as at 24 August 2018 of 3,211,691,105.

Substantial shareholders in BHP Billiton Plc

The following table shows holdings of three per cent or more of voting rights conferred by BHP Billiton Plc’s ordinary shares as notified to BHP Billiton Plc under the UK Disclosure and Transparency Rule 5 as at 30 June 2018. ⁽¹⁾

Title of class	Identity of person or group	Date of last notice						Percentage of total voting rights (2)
		Date received		Date of change		Number owned		2018		2017		2016
Ordinary shares	Aberdeen Asset Managers Limited		8 October 2015		7 October 2015		103,108,283		4.88%		4.88%		4.88%
Ordinary shares	BlackRock, Inc.		3 December 2009		1 December 2009		213,014,043		10.08%		10.08%		10.08%
Ordinary shares	Elliott Capital Advisors, L.P. (3)		3 February 2018		1 February 2018		115,183,724		5.45%		5.04%		–

⁽¹⁾  No changes in the holdings of three per cent or more of the voting rights in BHP Billiton Plc’s shares notified to BHP Billiton Plc between 1 July 2018 and 24 August 2018.

⁽²⁾  The percentages quoted are based on the total voting rights conferred by ordinary shares in BHP Billiton Plc as at 24 August 2018 of 2,112,071,796.

⁽³⁾  Holding is made up of 4.65 per cent ordinary shares and 0.80 per cent by financial instruments.

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Twenty largest shareholders as at 24 August 2018 (as named on the Register of Shareholders) ⁽¹⁾

BHP Billiton Limited		Number of fully paid shares		% of issued capital
1.	HSBC Custody Nominees (Australia) Limited		785,602,425		24.46
2.	J P Morgan Nominees Australia Limited		541,596,753		16.86
3.	Citicorp Nominees Pty Ltd		160,994,616		5.01
4.	Citicorp Nominees Pty Limited <Citibank NY ADR DEP A/C>		147,717,926		4.60
5.	National Nominees Limited		120,919,360		3.76
6.	BNP Paribas Nominees Pty Ltd <Agency Lending DRP A/C>		78,040,220		2.43
7.	Citicorp Nominees Pty Limited <Colonial First State INV A/C>		35,205,858		1.10
8.	BNP Paribas Noms Pty Ltd <DRP>		35,102,551		1.09
9.	HSBC Custody Nominees (Australia) Limited <NT-Comnwlth Super Corp A/C>		21,070,234		0.66
10.	Computershare Nominees Ci Ltd <ASX Shareplus Control A/C>		14,682,120		0.46
11.	Australian Foundation Investment Company Limited		13,990,941		0.44
12.	AMP Life Limited		10,425,018		0.32
13.	Argo Investments Limited		7,928,904		0.25
14.	HSBC Custody Nominees (Australia) Limited <Euroclear Bank SA NV A/C>		6,454,422		0.20
15.	HSBC Custody Nominees (Australia) Limited		5,872,938		0.18
16.	Navigator Australia Ltd <MLC Investment Sett A/C>		4,306,746		0.13
17.	Solium Nominees (Australia) Pty Ltd <VSA A/C>		4,198,613		0.13
18.	Milton Corporation Limited		4,007,921		0.12
19.	Netwealth Investments Limited <Wrap Services A/C>		3,978,295		0.12
20.	Ioof Investment Management Limited <IPS Super A/C>		3,442,918		0.11
			2,005,538,779		62.43

BHP Billiton Plc		Number of fully paid shares		% of issued capital
1.	PLC Nominees (Proprietary) Limited (2)		316,852,766		15.00
2.	State Street Nominees Limited <OM02>		165,720,882		7.85
3.	National City Nominees Limited		111,943,597		5.30
4.	The Bank of New York (Nominees) Limited		98,417, 980		4.66
5.	Chase Nominees Limited		65,915,276		3.12
6.	State Street Nominees Limited <OM04>		53,366,584		2.53
7.	Vidacos Nominees Limited <13559>		50,564,377		2.39
8.	Nortrust Nominees Limited		47,689,111		2.26
9.	Government Employees Pension Fund – PIC		38,967,150		1.84
10.	Hanover Nominees Limited <UBS03>		33,335,005		1.58
11.	Vidacos Nominees Limited <CLRLUX2>		31,999,848		1.52
12.	Chase Nominees Limited <VANLEND>		30,514,361		1.44
13.	Chase Nominees Limited <BBHLEND>		30,131,486		1.43
14.	State Street Nominees Limited <OD64>		30,103,353		1.43
15.	Euroclear Nominees Limited <EOC01>		27,103,495		1.28
16.	Lynchwood Nominees Limited <2006420>		25,634,631		1.21
17.	Nutraco Nominees Limited <781221>		25,200,000		1.19
18.	Industrial Development Corporation of South Africa		23,692,693		1.12
19.	HSBC Global Custody Nominee (UK) Limited <357206>		23,392,567		1.11
20.	Vidacos Nominees Limited <10245>		22,646,840		1.07
			1,253,192,002		59.33

⁽¹⁾  Many of the 20 largest shareholders shown for BHP Billiton Limited and BHP Billiton Plc hold shares as a nominee or custodian. In accordance with the reporting requirements, the tables reflect the legal ownership of shares and not the details of the underlying beneficial holders.

⁽²⁾  The largest holder on the South African register of BHP Billiton Plc is the Strate nominee in which the majority of shares in South Africa (including some of the shareholders included in this list) are held in dematerialised form.

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US share ownership as at 24 August 2018

	BHP Billiton Limited									BHP Billiton Plc
	Number of Shareholders		%		Number of shares			%		Number of Shareholders		%		Number of shares			%
Classification of holder
Registered holders of voting securities		1,639		0.30		4,066,238			0.13		75		0.47		98,766			0.01
ADR holders		1,628		0.30		147,717,926	(1)		4.60		206		1.28		111,943,596	(2)		5.30

⁽¹⁾  These shares translate to 73,858,963 ADRs.

⁽²⁾  These shares translate to 55,971,798 ADRs.

Geographical distribution of shareholders and shareholdings as at 24 August 2018

	BHP Billiton Limited								BHP Billiton Plc
	Number of Shareholders		%		Number of shares		%		Number of Shareholders		%		Number of shares		%
Registered address
Australia		519,546		96.56		3,150,597,284		98.1		1,511		9.40		2,105,308		0.10
New Zealand		10,157		1.89		25,676,865		0.80		29		0.18		46,688		0.01
United Kingdom		2,739		0.51		7,688,342		0.24		10,646		66.20		1,770,454,509		83.82
United States		1,639		0.30		4,066,238		0.13		75		0.47		98,766		0.01
South Africa		118		0.02		260,011		0.01		2,236		13.90		335,312,160		15.87
Other		3,878		0.72		23,402,365		0.72		1,584		9.85		4,054,365		0.19
Total		538,077		100.00		3,211,691,105		100.00		16,081		100.00		2,112,071,796		100.00

Distribution of shareholdings by size as at 24 August 2018

	BHP Billiton Limited								BHP Billiton Plc
	Number of Shareholders		%		Number of shares (1)		%		Number of Shareholders		%		Number of shares (1)		%
Size of holding
1 – 500 (2)		228,105		42.39		51,431,974		1.60		8,378		52.10		1,757,968		0.08
501 – 1,000		105,612		19.63		81,763,636		2.55		2,927		18.20		2,164,412		0.10
1,001 – 5,000		159,743		29.69		360,529,404		11.23		2,902		18.04		5,899,777		0.28
5,001 – 10,000		26,256		4.88		185,804,215		5.79		371		2.31		2,678,543		0.13
10,001 – 25,000		13,797		2.56		208,061,722		6.48		340		2.11		5,546,747		0.26
25,001 – 50,000		3,009		0.56		102,738,672		3.20		228		1.42		8,194,893		0.39
50,001 – 100,000		1,010		0.19		69,462,978		2.16		230		1.43		16,688,935		0.79
100,001 – 250,000		400		0.07		57,184,074		1.78		248		1.54		39,364,420		1.87
250,001 – 500,000		75		0.01		25,023,756		0.78		152		0.95		54,775,124		2.59
500,001 – 1,000,000		24		0.01		16,989,483		0.53		101		0.63		72,182,477		3.42
1,000,001 and over		46		0.01		2,052,701,191		63.90		204		1.27		1,902,818,500		90.09
Total		538,077		100.00		3,211,691,105		100.00		16,081		100.00		2,112,071,796		100.00

⁽¹⁾  One ordinary share entitles the holder to one vote.

⁽²⁾  The number of BHP Billiton Limited shareholders holding less than a marketable parcel (A$500) based on the market price of A$32.71 as at 24 August 2018 was 6,593.

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	BHP Billiton Limited								BHP Billiton Plc
	Number of Shareholders		%		Number of shares		%		Number of Shareholders		%		Number of shares		%
Classification of holder
Corporate		155,062		28.82		2,329,587,264		72.53		6,239		38.80		2,102,852,415		99.56
Private		383,015		71.18		882,103,841		27.47		9,842		61.20		9,219,381		0.44
Total		538,077		100.00		3,211,691,105		100.00		16,081		100.00		2,112,071,796		100.00

7.7    Dividends

Policy

The Group adopted a dividend policy in February 2016 that provides for a minimum 50 per cent payout of Underlying attributable profit at every reporting period. For information on Underlying attributable profit for FY2018, refer to section 1.11.1.

The Board will assess, at every reporting period, the ability to pay amounts additional to the minimum payment, in accordance with the Capital Allocation Framework, as described in section 1.4.3.

In FY2018, we determined our dividends and other distributions in US dollars as it is our main functional currency. BHP Billiton Limited paid its dividends in Australian dollars, UK pounds sterling, New Zealand dollars and US dollars. BHP Billiton Plc paid its dividends in UK pounds sterling (or US dollars, if elected) to shareholders registered on its principal register in the United Kingdom and in South African rand to shareholders registered on its branch register in South Africa.

Currency conversions were based on the foreign currency exchange rates on the record date, except for the conversion into South African rand, which takes place one week before the record date. Aligning the currency conversion date with the record date (for all currencies except the conversion into South African rand) enables a high level of certainty around the currency required to pay the dividend and helps to reduce the Group’s exposure to movements in exchange rates since the number of shares on which dividends are payable (and the elected currency) is final at close of business on the record date.

Aligning the final date to receive currency elections (currency election date) with the record date further simplifies the process.

Payments

BHP Billiton Limited shareholders may currently have their cash dividends paid directly into their bank account in Australian dollars, UK pounds sterling, New Zealand dollars or US dollars, provided they have submitted direct credit details and if required, a valid currency election nominating a financial institution to the BHP Share Registrar in Australia no later than close of business on the dividend record date. BHP Billiton Limited shareholders who do not provide their direct credit details will receive dividend payments by way of a cheque in Australian dollars.

BHP Billiton Plc shareholders on the UK register who wish to receive their dividends in US dollars must complete the appropriate election form and return it to the BHP Share Registrar in the United Kingdom no later than close of business on the dividend record date. BHP Billiton Plc shareholders may have their cash dividends paid directly into a bank or building society by completing a dividend mandate form, which is available from the BHP Share Registrar in the United Kingdom or South Africa.

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Dividend reinvestment plan

BHP offers a dividend reinvestment plan to registered shareholders, which provides the opportunity to use cash dividends to purchase BHP shares in the market.

7.8    Share price information

The following tables show the share prices for the period indicated for ordinary shares and ADSs for each of BHP Billiton Limited and BHP Billiton Plc. The share prices are the highest and lowest closing market quotations for ordinary shares reported on the Daily Official List of the ASX and LSE respectively, and the highest and lowest closing prices for ADSs quoted on the NYSE, adjusted to reflect stock dividends.

BHP Billiton Limited

		Ordinary shares				American Depositary Shares (1)
BHP Billiton Limited		High A$		Low A$		High US$		Low US$
FY2014			39.38		30.94		72.81		56.32
FY2015			39.68		26.90		73.50		40.71
FY2016			27.10		14.20		41.29		19.38
FY2017	First quarter		22.40		18.71		34.65		27.78
	Second quarter		26.50		22.27		39.57		33.88
	Third quarter		27.89		23.55		41.68		35.64
	Fourth quarter		25.73		24.07		38.39		33.67
FY2018	First quarter		27.73		23.23		44.54		36.18
	Second quarter		29.57		26.00		46.38		40.66
	Third quarter		31.90		28.21		50.69		43.49
	Fourth quarter		34.44		28.21		51.95		43.63
		Ordinary shares				American Depositary Shares (1)
BHP Billiton Limited		High A$		Low A$		High US$		Low US$
Month of January 2018			31.90		29.57		50.69		45.99
Month of February 2018			31.52		29.13		49.91		44.76
Month of March 2018			30.10		28.21		46.67		43.49
Month of April 2018			31.27		28.21		48.13		43.63
Month of May 2018			34.44		31.20		51.49		46.30
Month of June 2018			34.08		32.36		51.95		47.64
Month of July 2018			34.86		32.45		52.26		48.23
Month of August 2018			35.08		32.08		51.22		46.96

⁽¹⁾  Each ADS represents the right to receive two BHP Billiton Limited ordinary shares.

The total market capitalisation of BHP Billiton Limited at 24 August 2018 was A$105.1 billion (US$77.0 billion equivalent), which represented approximately 5.22 per cent of the total market capitalisation of the ASX All Ordinaries Index. The closing price for BHP Billiton Limited ordinary shares on the ASX on that date was A$32.17.

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BHP Billiton Plc

		Ordinary shares				American Depositary Shares (1)
BHP Billiton Plc		High UK pence		Low UK pence		High US$		Low US$
FY2014			1,995.00		1,666.50		66.73		62.35
FY2015			2,096.00		1,249.00		71.02		39.56
FY2016			1,272.50		580.90		39.87		17.07
FY2017	First quarter		1,168.00		921.10		30.38		24.18
	Second quarter		1,400.00		1,166.00		35.28		29.20
	Third quarter		1,480.50		1,197.00		37.20		30.63
	Fourth quarter		1,316.00		1,117.00		33.32		28.94
FY2018	First quarter		1,486.00		1,214.50		39.04		31.34
	Second quarter		1,522.50		1,328.50		40.53		35.70
	Third quarter		1,660.00		1,377.00		45.30		38.79
	Fourth quarter		1,779.20		1,373.80		47.86		38.80
		Ordinary shares				American Depositary Shares (1)
BHP Billiton Plc		High UK pence		Low UK pence		High US$		Low US$
Month of January 2018			1,660.00		1,522.50		45.28		40.30
Month of February 2018			1,598.00		1,475.00		45.30		40.51
Month of March 2018			1,468.00		1,377.00		41.13		38.79
Month of April 2018			1,558.00		1,373.80		43.00		38.80
Month of May 2018			1,779.20		1,518.80		47.24		41.64
Month of June 2018			1,779.00		1,602.80		47.86		42.70
Month of July 2018			1,754.60		1,609.20		46.26		42.61
Month of August 2018			1,724.60		1,610.60		44.98		41.27

⁽¹⁾  Each ADS represents the right to receive two BHP Billiton Plc ordinary shares.

The total market capitalisation of BHP Billiton Plc at 24 August 2018 was £35.09 billion (US$44.07 billion equivalent), which represented approximately 1.44 per cent of the total market capitalisation of the FTSE All-Share Index. The closing price for BHP Billiton Plc ordinary shares on the LSE on that date was £16.61.

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7.9    American Depositary Receipts fees and charges

We have American Depositary Receipts (ADR) programs for BHP Billiton Limited and BHP Billiton Plc.

Depositary fees

Citibank serves as the depositary bank for both of our ADR programs. ADR holders agree to the terms in the deposit agreement filed with the SEC for depositing ADSs or surrendering the ADSs for cancellation and for certain services as provided by Citibank. Holders are required to pay all fees for general depositary services provided by Citibank in each of our ADR programs, as set forth in the tables below.

Standard depositary fees:

Depositary service	Fee payable by the ADR holders
Issuance of ADSs upon deposit of shares	Up to US$5.00 per 100 ADSs (or fraction thereof) issued
Delivery of Deposited Securities against surrender of ADSs	Up to US$5.00 per 100 ADSs (or fraction thereof) surrendered
Distribution of Cash Distributions	No fee

Corporate actions depositary fees:

Depositary service	Fee payable by the ADR holders
Cash Distributions (i.e. sale of rights, other entitlements, return of capital)	Up to US$2.00 per 100 ADSs (or fraction thereof) held
Distribution of ADSs pursuant to exercise of rights to purchase additional ADSs. Excludes stock dividends and stock splits	Up to US$5.00 per 100 ADSs (or fraction thereof) held
Distribution of securities other than ADSs or rights to purchase additional ADSs (i.e. spin-off shares)	Up to US$5.00 per 100 ADSs (or fraction thereof) held
Distribution of ADSs pursuant to an ADR ratio change in which shares are not distributed	No fee

Fees payable by the Depositary to the Issuer

Citibank has provided BHP net reimbursement of US$1.5 million in FY2018 for ADR program-related expenses for both of BHP’s ADR programs (FY2017 US$1.4 million). ADR program-related expenses include legal and accounting fees, listing fees, expenses related to investor relations in the United States, fees payable to service providers for the distribution of material to ADR holders, expenses of Citibank as administrator of the ADS Direct Plan and expenses to remain in compliance with applicable laws.

Citibank has further agreed to waive other ADR program-related expenses for FY2018, amounting to less than US$0.03 million, which are associated with the administration of the ADR programs (FY2017 less than US$0.03 million).

Our ADR programs trade on the NYSE under the stock tickers BHP and BBL for the BHP Billiton Limited and BHP Billiton Plc programs, respectively. As of 24 August 2018, there were 73,858,963 ADRs on issue and outstanding in the BHP Billiton Limited ADR program and 55,971,798 ADRs on issue and outstanding in the BHP Billiton Plc ADR program. Both of the ADR programs have a 2:1 ordinary shares to ADR ratio.

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7.10    Taxation

The taxation discussion below describes the material Australian, UK and US federal income tax consequences to a US holder of owning BHP Billiton Limited ordinary shares or ADSs or BHP Billiton Plc ordinary shares or ADSs. The discussion below also outlines the potential South African tax issues for US holders of BHP Billiton Plc shares that are listed on the JSE.

The following discussion is not relevant to non-US holders of BHP Billiton Limited ordinary shares or ADSs or BHP Billiton Plc ordinary shares or ADSs. By its nature, the commentary below is of a general nature and we recommend that holders of ordinary shares or ADSs consult their own tax advisers regarding the Australian, UK, South African and US federal, state and local tax and other tax consequences of owning and disposing of ordinary shares and ADSs in their particular circumstances.

For purposes of this commentary, a US holder is a beneficial owner of ordinary shares or ADSs who is, for US federal income tax purposes:

• a citizen or resident alien of the US;

• a corporation (or other entity treated as a corporation for US federal income tax purposes) that is created or organised under the laws of the US or any political subdivision thereof;

• an estate, the income of which is subject to US federal income taxation regardless of its source; or

• a trust:

(a) if a court within the US is able to exercise primary supervision over its administration and one or more US persons have the authority to control all of its substantial decisions; or

(b) that has made a valid election to be treated as a US person for tax purposes.

This discussion of material tax consequences for US holders is based on the Australian, UK, US and South African laws currently in effect, the published practice of tax authorities in those jurisdictions and the double taxation treaties and conventions currently in existence. These laws are subject to change, possibly on a retroactive basis.

US holders in BHP Billiton Limited

(a) Australian taxation

Dividends

Dividends (including other distributions treated as dividends for Australian tax purposes) paid by BHP Billiton Limited to a US holder that is not an Australian resident for Australian tax purposes will generally not be subject to Australian withholding tax if they are fully franked (broadly, where a dividend is franked, tax paid by BHP Billiton Limited is imputed to the shareholders).

Dividends paid to such US holders, which are not fully franked, will generally be subject to Australian withholding tax not exceeding 15 per cent only to the extent (if any) that the dividend is neither:

• franked; nor

• declared by BHP Billiton Limited to be conduit foreign income. (Broadly, this means that the relevant part of the dividend is declared to have been paid out of foreign source amounts received by BHP Billiton Limited that are not subject to tax in Australia, such as dividends remitted to Australia by foreign subsidiaries).

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The Australian withholding tax outcome described above applies to US holders who are eligible for benefits under the Tax Convention between Australia and the US as to the Avoidance of Double Taxation (the Australian Tax Treaty). Otherwise, the rate of Australian withholding tax may be 30 per cent.

In contrast, dividends (including other distributions treated as dividends for Australian tax purposes) paid by BHP Billiton Limited to a US holder may instead be taxed by assessment in Australia if the US holder:

• is an Australian resident for Australian tax purposes (although the tax will generally not exceed 15 per cent where the US holder is eligible for benefits under the Australian Tax Treaty as a treaty resident of the US and any franking credits may be creditable against their Australian income tax liability); or

• carries on business in Australia through a permanent establishment as defined in the Australian Tax Treaty, or performs personal services from a fixed base in Australia, and the shareholding in respect of which the dividend is paid is effectively connected with that permanent establishment or fixed base, (however, in such a case any franking credits may be creditable against the Australian income tax liability).

The treatment of dividends outlined above may be modified where the shareholding in BHP Billiton Limited is held through a trust, limited partnership, limited liability company, pension fund, sovereign wealth fund or other investment vehicle. Affected US holders should seek their own advice in relation to such arrangements.

Sale of ordinary shares and ADSs

Gains made by US holders on the sale of ordinary shares or ADSs will generally not be taxed in Australia.

However, the precise Australian tax treatment of gains made by US holders on the sale of ordinary shares or ADSs generally depends on whether or not the gain is an Australian sourced gain of an income nature for Australian income tax purposes.

Where the gain is of an income nature, a US holder will generally only be liable to Australian income tax on an assessment basis (whether or not they are also an Australian resident for Australian tax purposes) if:

• they are not eligible for benefits under the Australian Tax Treaty and the gain is sourced in Australia for Australian tax purposes; or

• they are eligible for benefits under the Australian Tax Treaty but the gain constitutes any of the following (in which case the gain will be deemed to have an Australian source):

– business profits of an enterprise attributable to a permanent establishment situated in Australia through which the enterprise carries on business in Australia; or

– income or gains from the alienation of property that form part of the business property of a permanent establishment of an enterprise that the US holder has in Australia, or pertain to a fixed base available to the US holder in Australia for the purpose of performing independent personal services; or

– income derived from the disposition of shares in a company, the assets of which consist wholly or principally of real property (which includes rights to exploit or to explore for natural resources) situated in Australia, whether such assets are held directly or indirectly through one or more interposed entities.

Where the gain is not taxed as Australian sourced income, the US holder will generally only be liable to Australian capital gains tax on an assessment basis if they acquired (or are deemed to have acquired) their shares or ADSs after 19 September 1985 and one or more of the following applies:

• the US holder is an Australian resident for Australian tax purposes; or

• the ordinary shares or ADSs have been used by the US holder in carrying on a business through a permanent establishment in Australia; or

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• the ordinary shares or ADSs constitute an ‘indirect Australian real property interest’ for Australian CGT purposes – this will generally be the case if the US holder (either alone or together with associates) directly or indirectly owns or owned 10 per cent or more of the issued share capital of BHP Billiton Limited at the time of the disposal or throughout a 12-month period during the two years prior to the time of disposal and, at the time of the disposal, the sum of the market values of BHP Billiton Limited’s assets that are taxable Australian real property (held directly or through interposed entities) exceeds the sum of the market values of BHP Billiton Limited’s assets (held directly or through interposed entities) that are not taxable Australian real property at that time (which, for these purposes includes mining, quarrying or prospecting rights in respect of minerals, petroleum or quarry materials situated in Australia); or

• the US holder is an individual who is not eligible for benefits under the Australian Tax Treaty as a treaty resident of the US and elected on becoming a non-resident of Australia to continue to have the ordinary shares or ADSs subject to Australian capital gains tax.

In certain circumstances, if the ordinary shares or ADSs constitute an ‘indirect Australian real property interest’ for Australian CGT purposes, the purchaser may be required to withhold under the non-resident CGT withholding regime an amount equal to 12.5 per cent of the purchase price in situations including where the acquisition is undertaken by way of an off-market transfer. Affected US holders should seek their own advice in relation to how this withholding regime may apply to them.

The comments above on the sale of ordinary shares and ADSs do not apply:

• to temporary residents of Australia who should seek advice that is specific to their circumstances; or

• if the Investment Management Regime (IMR) applies to the US holder, which exempts from Australian income tax and capital gains tax gains made on disposals by certain categories of non-resident funds – called IMR entities – of (relevantly) portfolio interests in Australian public companies (subject to a number of conditions). The IMR exemptions broadly apply to widely held IMR entities in relation to their direct investments and indirect investments made through an independent Australian fund manager. The exemptions apply to gains made by IMR entities that are treated as companies for Australian tax purposes as well as gains made by non-resident investors in IMR entities that are treated as trusts and partnerships for Australian tax purposes.

Stamp duty, gift, estate and inheritance tax

Australia does not impose any stamp duty, gift, estate or inheritance taxes in relation to transfers or gifts of shares or ADSs or upon the death of a shareholder.

(b) US taxation

This section describes the material US federal income tax consequences to a US holder of owning ordinary shares or ADSs. It applies only to ordinary shares or ADSs that are held as capital assets for tax purposes. This section does not apply to a holder of ordinary shares or ADSs that is a member of a special class of holders subject to special rules, including a dealer in securities, a trader in securities that elects to use a mark-to-market method of accounting for its securities holdings, a tax-exempt organisation, a life insurance company, a person liable for alternative minimum tax, a person who actually or constructively owns 10 per cent or more of the combined voting power of the voting stock or of the total value of the stock of BHP Billiton Limited, a person that holds ordinary shares or ADSs as part of a straddle or a hedging or conversion transaction, a person that purchases or sells ordinary shares or ADSs as part of a wash sale for tax purposes, or a person whose functional currency is not the US dollar.

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If an entity or arrangement that is treated as a partnership for US federal income tax purposes holds the ordinary shares or ADSs, the US federal income tax treatment of a partner generally will depend on the status of the partner and the tax treatment of the partnership. A partner in a partnership holding the ordinary shares or ADSs should consult its tax adviser with regard to the US federal income tax treatment of an investment in the ordinary shares or ADSs.

This section is in part based on the representations of the Depositary and the assumption that each obligation in the deposit agreement and any related agreement will be performed in accordance with its terms.

In general, for US federal income tax purposes, a holder of ADSs will be treated as the owner of the ordinary shares represented by those ADSs. Exchanges of ordinary shares for ADSs, and ADSs for ordinary shares, generally will not be subject to US federal income tax.

Dividends

Under US federal income tax laws and subject to the Passive Foreign Investment Company (PFIC) rules discussed below, a US holder must include in its gross income the amount of any dividend paid by BHP Billiton Limited out of its current or accumulated earnings and profits (as determined for US federal income tax purposes) plus any Australian tax withheld from the dividend payment even though the holder does not receive it. The dividend is taxable to the holder when the holder, in the case of ordinary shares, or the Depositary, in the case of ADSs, actually or constructively receives the dividend.

Dividends paid to a non-corporate US holder on shares or ADSs will be taxable at the preferential rates applicable to long-term capital gains provided the US holder holds the shares or ADSs for more than 60 days during the 121-day period beginning 60 days before the ex-dividend date and does not enter into certain risk reduction transactions with respect to the shares or ADSs during the abovementioned holding period. However, a non-corporate US holder that elects to treat the dividend income as ‘investment income’ pursuant to Section 163(d)(4) of the US Internal Revenue Code will not be eligible for such preferential rates. In the case of a corporate US holder, dividends on shares and ADSs are taxed as ordinary income and will not be eligible for the dividends received deduction generally allowed to US corporations in respect of dividends received from other US corporations.

Distributions in excess of current and accumulated earnings and profits, as determined for US federal income tax purposes, will be treated as a non-taxable return of capital to the extent of the holder’s tax basis, determined in US dollars, in the ordinary shares or ADSs and thereafter as a capital gain.

The amount of any cash distribution paid in any foreign currency will be equal to the US dollar value of such currency, calculated by reference to the spot rate in effect on the date such distribution is received by the US holder or, in the case of ADSs, by the Depositary, regardless of whether and when the foreign currency is in fact converted into US dollars. If the foreign currency is converted into US dollars on the date received, the US holder generally should not recognise foreign currency gain or loss on such conversion. If the foreign currency is not converted into US dollars on the date received, the US holder will have a basis in the foreign currency equal to its US dollar value on the date received, and generally will recognise foreign currency gain or loss on a subsequent conversion or other disposal of such currency. Such foreign currency gain or loss generally will be treated as ordinary income or loss ineligible for the special tax rate applicable to qualified dividend income and generally will be income or loss from US sources for foreign tax credit limitation purposes.

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Subject to certain limitations, Australian tax withheld in accordance with the Australian Tax Treaty and paid over to Australia will be creditable against an individual’s US federal income tax liability. Special rules apply in determining the foreign tax credit limitation with respect to dividends that are taxed at the preferential rates applicable to long-term capital gains. To the extent a reduction or refund of the tax withheld is available to a US holder under Australian law or under the Australian Tax Treaty, the amount of tax withheld that could have been reduced or that is refundable will not be eligible for credit against the holder’s US federal income tax liability. A US holder that does not elect to claim a US foreign tax credit may instead claim a deduction for Australian income tax withheld, but only for a taxable year in which the US holder elects to do so with respect to all foreign income taxes paid or accrued in such taxable year.

Dividends will be income from sources outside the US, and generally will be ‘passive category’ income for the purpose of computing the foreign tax credit allowable to a US holder. In general, a taxpayer’s ability to use foreign tax credits may be limited and is dependent on the particular circumstances. US holders should consult their tax advisers with respect to these matters.

Sale of ordinary shares and ADSs

Subject to the PFIC rules discussed below, a US holder who sells or otherwise disposes of ordinary shares or ADSs will recognise a capital gain or loss for US federal income tax purposes equal to the difference between the US dollar value of the amount realised and the holder’s tax basis, determined in US dollars, in those ordinary shares or ADSs. The gain or loss will generally be income or loss from sources within the US for foreign tax credit limitation purposes. The capital gain of a non-corporate US holder is generally taxed at preferential rates where the holder has a holding period greater than 12 months in the shares or ADSs sold. There are limitations on the deductibility of capital losses.

The US dollar value of any foreign currency received upon a sale or other disposition of ordinary shares or ADSs will be calculated by reference to the spot rate in effect on the date of sale or other disposal (or, in the case of a cash basis or electing accrual basis taxpayer, on the settlement date). A US holder will have a tax basis in the foreign currency received equal to that US dollar amount, and generally will recognise foreign currency gain or loss on a subsequent conversion or other disposal of the foreign currency. This foreign currency gain or loss generally will be treated as US source ordinary income or loss for foreign tax credit limitation purposes.

Passive Foreign Investment Company rules

We do not believe that the BHP Billiton Limited ordinary shares or ADSs will be treated as stock of a PFIC for US federal income tax purposes, but this conclusion is a factual determination that is made annually at the end of the year and thus may be subject to change. If BHP Billiton Limited were treated as a PFIC, any gain realised on the sale or other disposition of ordinary shares or ADSs would in general not be treated as a capital gain. Instead, a US holder would be treated as if it had realised such gain and certain ‘excess distributions’ ratably over its holding period for the ordinary shares or ADSs and would be taxed at the highest tax rate in effect for each such year to which the gain was allocated, together with an interest charge in respect of the tax attributable to each such year. In addition, dividends received with respect to ordinary shares or ADSs would not be eligible for the special tax rates applicable to qualified dividend income if BHP Billiton Limited were a PFIC either in the taxable year of the distribution or the preceding taxable year, but instead would be taxable at rates applicable to ordinary income. Assuming the shares or ADSs are ‘marketable stock’, a US holder may mitigate the adverse tax consequences described above by electing to be taxed annually on a mark-to-market basis with respect to such shares or ADSs.

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US holders in BHP Billiton Plc

(a) UK taxation

Dividends

Under UK law, no UK tax is required to be withheld at source from dividends paid on ordinary shares or ADSs.

Sale of ordinary shares and ADSs

US holders will not be liable for UK tax on capital gains realised on disposal of ordinary shares or ADSs unless:

• they are resident in the UK; or

• they carry on a trade, profession or vocation in the UK through a branch or agency for the year in which the disposal occurs and the shares or ADSs have been used, held or acquired for the purposes of such trade (or profession or vocation), branch or agency. In the case of a trade, the term ‘branch’ includes a permanent establishment.

An individual who ceases to be a resident in the UK for tax purposes while owning shares or ADSs and then disposes of those shares or ADSs while not a UK resident may become subject to UK tax on capital gains if he/she:

• had sole UK residence in the UK tax year preceding his/her departure from the UK;

• had sole UK residence at any time during at least four of the seven UK tax years preceding his/her year of departure from the UK; and

• subsequently becomes treated as having sole UK residence again before five complete UK tax years of non-UK residence have elapsed from the date he/she left the UK.

In this situation US holders will generally be entitled to claim US tax paid on such a disposition as a credit against any corresponding UK tax payable.

UK inheritance tax

Under the current UK–US Inheritance and Gift Tax Treaty, ordinary shares or ADSs held by a US holder who is domiciled for the purposes of the UK–US Inheritance and Gift Tax Treaty in the US, and is not for the purposes of the UK–US Inheritance and Gift Tax Treaty a national of the UK, will generally not be subject to UK inheritance tax on the individual’s death or on a chargeable gift of the ordinary shares or ADSs during the individual’s lifetime, provided that any applicable US federal gift or estate tax liability is paid, unless the ordinary shares or ADSs are part of the business property of a permanent establishment of the individual in the UK or, in the case of a shareholder who performs independent personal services, pertain to a fixed base situated in the UK. Where the ordinary shares or ADSs have been placed in trust by a settlor who, at the time of settlement, was a US resident shareholder, the ordinary shares or ADSs will generally not be subject to UK inheritance tax unless the settlor, at the time of settlement, was not domiciled in the US and was a UK national. In the exceptional case where the ordinary shares or ADSs are subject to both UK inheritance tax and US federal gift or estate tax, the UK–US Inheritance and Gift Tax Treaty generally provides for double taxation to be relieved by means of credit relief.

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UK stamp duty and stamp duty reserve tax

Under applicable legislation, UK stamp duty or stamp duty reserve tax (SDRT) is, subject to certain exemptions, payable on any issue or transfer of shares to the Depositary or their nominee where those shares are for inclusion in the ADR program at a rate of 1.5 per cent of their price (if issued), the amount of any consideration provided (if transferred on sale) or their value (if transferred for no consideration). However, from 1 October 2009, this 1.5 per cent charge has generally ceased to apply to issues of shares into European Union (EU) depositary receipt systems and into EU clearance systems. Further, the First-tier Tribunal has held that the 1.5 per cent SDRT charge on a transfer of shares to an issuer of ADRs (as an integral part of a fresh capital raising) was incompatible with EU law. Her Majesty’s Revenue and Customs has confirmed that it will no longer seek to impose the 1.5 per cent SDRT charge on the issue of shares (or, where it is integral to the raising of new capital, the transfer of shares) to a depositary receipt issuer or a clearance service, wherever located. The law in this area may still be susceptible to change. We recommend advice should be sought in relation to paying the 1.5 per cent SDRT or stamp duty charge in any circumstances.

No SDRT would be payable on the transfer of an ADS. No UK stamp duty should be payable on the transfer of an ADS provided that the instrument of transfer is executed and remains at all times outside the UK. Transfers of ordinary shares to persons other than the Depositary or their nominee will give rise to stamp duty or SDRT at the time of transfer. The relevant rate is currently 0.5 per cent of the amount payable for the shares. The purchaser normally pays the stamp duty or SDRT.

Special rules apply to transactions involving intermediates and stock lending.

(b) US taxation

This section describes the material US federal income tax consequences to a US holder of owning ordinary shares or ADSs. It applies only to ordinary shares or ADSs that are held as capital assets for tax purposes. This section does not apply to a holder of ordinary shares or ADSs that is a member of a special class of holders subject to special rules, including a dealer in securities, a trader in securities who elects to use a mark-to-market method of accounting for its securities holdings, a tax-exempt organisation, a life insurance company, a person liable for alternative minimum tax, a person who actually or constructively owns 10 per cent or more of the combined voting power of voting stock or of the total value of the stock of BHP Billiton Plc, a person that holds ordinary shares or ADSs as part of a straddle or a hedging or conversion transaction, a person that purchases or sells ordinary shares or ADSs as part of a wash sale for tax purposes, or a person whose functional currency is not the US dollar.

If an entity or arrangement that is treated as a partnership for US federal income tax purposes holds the ordinary shares or ADSs, the US federal income tax treatment of a partner generally will depend on the status of the partner and the tax treatment of the partnership. A partner in a partnership holding the ordinary shares or ADSs should consult its tax adviser with regard to the US federal income tax treatment of an investment in the ordinary shares or ADSs.

This section is in part based on the representations of the Depositary and the assumption that each obligation in the deposit agreement and any related agreement will be performed in accordance with its terms.

In general, for US federal income tax purposes, a holder of ADSs will be treated as the owner of the ordinary shares represented by those ADSs. Exchanges of ordinary shares for ADSs, and ADSs for ordinary shares, generally will not be subject to US federal income tax.

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Dividends

Under US federal income tax laws and subject to the PFIC rules discussed below, a US holder must include in its gross income the gross amount of any dividend paid by BHP Billiton Plc out of its current or accumulated earnings and profits (as determined for US federal income tax purposes). The dividend is taxable to the holder when the holder, in the case of ordinary shares, or the Depositary, in the case of ADSs, actually or constructively receives the dividend.

Dividends paid to a non-corporate US holder on shares or ADSs will be taxable at the preferential rates applicable to long-term capital gains provided that the US holder holds the shares or ADSs for more than 60 days during the 121-day period beginning 60 days before the ex-dividend date and does not enter into certain risk reduction transactions with respect to the shares or ADSs during the abovementioned holding period. However, a non-corporate US holder that elects to treat the dividend income as ‘investment income’ pursuant to Section 163(d)(4) of the US Internal Revenue Code will not be eligible for such preferential rates. In the case of a corporate US holder, dividends on shares and ADSs are taxed as ordinary income and will not be eligible for the dividends received deduction generally allowed to US corporations in respect of dividends received from other US corporations.

Distributions in excess of current and accumulated earnings and profits, as determined for US federal income tax purposes, will be treated as a non-taxable return of capital to the extent of the holder’s tax basis, determined in US dollars, in the ordinary shares or ADSs and thereafter as a capital gain.

The amount of any cash distribution paid in any foreign currency will be equal to the US dollar value of such currency, calculated by reference to the spot rate in effect on the date such distribution is received by the US holder or, in the case of ADSs, by the Depositary, regardless of whether and when the foreign currency is in fact converted into US dollars. If the foreign currency is converted into US dollars on the date received, the US holder generally should not recognise foreign currency gain or loss on such conversion. If the foreign currency is not converted into US dollars on the date received, the US holder will have a basis in the foreign currency equal to its US dollar value on the date received, and generally will recognise foreign currency gain or loss on a subsequent conversion or other disposal of such currency. Such foreign currency gain or loss generally will be treated as ordinary income or loss ineligible for the special tax rate applicable to qualified dividend income and generally will be income or loss from US sources for foreign tax credit limitation purposes.

Dividends will be income from sources outside the US, and generally will be ‘passive category’ income for the purpose of computing the foreign tax credit allowable to a US holder. In general, a taxpayer’s ability to use foreign tax credits may be limited and is dependent on the particular circumstances. US holders should consult their tax advisers with respect to these matters.

Sale of ordinary shares and ADSs

Subject to the PFIC rules discussed below, a US holder who sells or otherwise disposes of ordinary shares or ADSs will recognise a capital gain or loss for US federal income tax purposes equal to the difference between the US dollar value of the amount realised and the holder’s tax basis, determined in US dollars, in those ordinary shares or ADSs. The gain or loss will generally be income or loss from sources within the US for foreign tax credit limitation purposes. The capital gain of a non-corporate US holder is generally taxed at preferential rates where the holder has a holding period greater than 12 months in the shares or ADSs sold. There are limitations on the deductibility of capital losses.

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The US dollar value of any foreign currency received upon a sale or other disposition of ordinary shares or ADSs will be calculated by reference to the spot rate in effect on the date of sale or other disposal (or, in the case of a cash basis or electing accrual basis taxpayer, on the settlement date). A US holder will have a tax basis in the foreign currency received equal to that US dollar amount, and generally will recognise foreign currency gain or loss on a subsequent conversion or other disposal of the foreign currency. This foreign currency gain or loss generally will be treated as US source ordinary income or loss for foreign tax credit limitation purposes.

Passive Foreign Investment Company rules

We do not believe that the BHP Billiton Plc ordinary shares or ADSs will be treated as stock of a PFIC for US federal income tax purposes, but this conclusion is a factual determination that is made annually at the end of the year and thus may be subject to change. If BHP Billiton Plc were treated as a PFIC, any gain realised on the sale or other disposition of ordinary shares or ADSs would in general not be treated as a capital gain. Instead, a US holder would be treated as if it had realised such gain and certain ‘excess distributions’ ratably over its holding period for the ordinary shares or ADSs and would be taxed at the highest tax rate in effect for each such year to which the gain was allocated, together with an interest charge in respect of the tax attributable to each such year. In addition, dividends received with respect to ordinary shares or ADSs would not be eligible for the special tax rates applicable to qualified dividend income if BHP Billiton Plc were a PFIC either in the taxable year of the distribution or the preceding taxable year, but instead would be taxable at rates applicable to ordinary income. Assuming the shares or ADSs are ‘marketable stock’, a US holder may mitigate the adverse tax consequences described above by electing to be taxed annually on a mark-to-market basis with respect to such shares or ADSs.

(c) South African taxation

Dividends

During his Budget Speech presented on 22 February 2017, the Minister of Finance announced an increase in the withholding tax rate on dividends (South African Dividends Tax) from 15 per cent to 20 per cent. As a result, dividends paid or payable on or after 22 February 2017 in respect of shares in foreign companies that are listed on a South African exchange will attract South African Dividends Tax at the rate of 20 per cent, unless an exemption applies. In this regard, we note that where a foreign tax resident company, listed on the JSE declares a cash dividend to a non-South African tax resident, dividend withholding tax would not apply (refer section 64F(j) of the South African Income Tax Act).

Accordingly, it is unlikely that a US tax resident (or any other foreign tax resident) that is a holder of BHP Billiton Plc shares listed on the JSE would be subject to South African Dividends Tax on any cash dividends received or accrued in respect of their JSE listed BHP Billiton Plc shares. However, to qualify for the exemption, the US tax resident holder (or other foreign resident holder) must within the appropriate time period provide the prescribed declaration form confirming the application of the exemption to the regulated intermediary responsible for making payment of the dividend to that party (or any other appropriate party responsible for payment of the dividend).

If the US holder (or any other non-resident) is tax resident in South Africa they would be subject to dividends tax at a rate of 20%. Investors are cautioned to be certain of their tax residence to ensure correct tax treatment.

Although the beneficial owner of the dividend is liable for the South African Dividends Tax on a cash dividend, the South African Dividends Tax would be withheld from the gross amount of the dividend paid to the shareholder.

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No South African Dividends Tax is required to be withheld from cash dividends provided the dividends are paid to, inter alia, South African tax resident corporate shareholders (including South African companies, pension, provident, retirement annuity and benefit funds). However, these dividends will only be exempt from South African Dividends Tax if these types of shareholders provide the requisite exemption declarations and written undertakings to the regulated intermediaries (or the person who is obliged to withhold the dividends tax) making the cash dividend payments before they are paid.

South African tax resident shareholders who are natural persons (individuals) or trusts, other than closure rehabilitation trusts, do not qualify for an exemption from South African Dividends Tax.

Except for certain exclusions, generally speaking such dividends paid to South African tax resident natural persons or trusts are exempt from South African income tax and, as such, the South African Dividends Tax may be considered as a final and non-creditable levy.

Sale of ordinary shares and ADSs

A US holder who or which is tax resident in South Africa would be liable for either income tax on any profit on disposal of BHP Billiton Plc shares or ADSs, or capital gains tax on any gain on disposal of BHP Billiton Plc shares or ADSs, depending on whether the BHP Billiton Plc shares and ADSs are held on revenue or capital account.

Income tax is payable on any profit on disposal of BHP Billiton Plc shares or ADSs held by a US holder who or which is tax resident in the US, where the profit is of a revenue nature and sourced in South Africa, unless relief is afforded under the Double Tax Agreement concluded between South Africa and the US. In such a case, the profit would only be taxed in South Africa if it is attributable to a permanent establishment of that US holder in South Africa.

Where the BHP Billiton Plc shares or ADSs are not held on revenue account, US holders will not be liable for South African tax on capital gains realised on the disposal of BHP Billiton Plc shares or ADSs unless:

• such US holders are tax resident in South Africa;

• 80 per cent or more of the market value of the BHP Billiton Plc shares or ADSs is attributable (at the time of disposal of those BHP Billiton Plc shares or ADSs) directly or indirectly to immovable property situated in South Africa, held otherwise than as trading stock, and the US holder (alone or together with a connected person) in question directly or indirectly holds 20 per cent of such BHP Billiton Plc shares or ADSs; or

• the US holder’s BHP Billiton Plc shares or ADSs form part of the business property of a permanent establishment which an enterprise of the US holder has in South Africa.

For a US holder who will recognise a capital gain or loss for South African income tax purposes on a disposal of BHP Billiton Plc shares or ADSs, such gain or loss will be equal to the difference between the Rand value of the amount realised and the holder’s tax basis, determined in Rand, in those BHP Billiton Plc shares or ADSs. The holder’s tax basis will generally be equal to the cost that was incurred to acquire the BHP Billiton Plc shares or ADSs, if such shares or ADSs were acquired after 1 October 2001. South African capital gains tax is levied at an effective rate of 22.4 per cent for companies, up to 18 per cent for individuals (depending on the applicable tax bracket), and 36 per cent for trusts.

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Securities Transfer Tax

South African Securities Transfer Tax is levied at 0.25 per cent in respect of the transfer of shares in a foreign company that are listed on the JSE. Accordingly, a transfer of those BHP Billiton Plc shares listed on the JSE will be subject to this tax. The tax is levied on the amount of consideration at which the BHP Billiton Plc share is transferred or, where no amount/value is declared or if the amount so declared is less than the lowest price of the BHP Billiton Plc share, the closing price of the BHP Billiton Plc share. The tax is ultimately borne by the person to whom that BHP Billiton Plc share is transferred.

7.11    Government regulations

Our assets are subject to a broad range of laws and regulations imposed by governments and regulatory bodies. These regulations touch all aspects of our assets, including how we extract, process and explore for minerals, oil and natural gas and how we conduct our business, including regulations governing matters such as environmental protection, land rehabilitation, occupational health and safety, the rights and interests of Indigenous peoples, competition, foreign investment, export, marketing of minerals, oil and natural gas and taxes.

The ability to extract minerals, oil and natural gas is fundamental to BHP. In most jurisdictions, the rights to extract mineral or petroleum deposits are owned by the government. We obtain the right to access the land and extract the product by entering into licenses or leases with the government that owns the mineral, oil or natural gas deposit. The terms of the lease or licence, including the time period of the lease or licence, vary depending on the laws of the relevant government or terms negotiated with the relevant government. Generally, we own the product we extract and we are required to pay royalties or similar taxes to the government.

Related to our ability to extract is our ability to process the extracted minerals, oil or natural gas. Again, we rely on governments to grant the rights necessary to transport and treat the extracted material to prepare it for sale.

The rights to explore for minerals, oil and natural gas are granted to us by the government that owns the natural resources we wish to explore. Usually, the right to explore carries with it the obligation to spend a defined amount of money on the exploration, or to undertake particular exploration activities.

In certain jurisdictions where we have assets, such as Trinidad and Tobago, a production sharing contract (PSC) governs the relationship between the government and companies concerning how much of the oil and gas extracted from the country each will receive. In PSCs, the government awards rights for the execution of exploration, development and production activities to the company. The company bears the financial risk of the initiative and explores, develops and ultimately produces the field as required. When successful, the company is permitted to use the money from a certain set percentage of produced oil and gas to recover its capital and operational expenditures, known as ‘cost oil’. The remaining production is known as ‘profit oil’ and is split between the government and the company at a rate determined by the government and set out in the PSC.

Although onshore oil and gas rights in the United States can be owned by the government (state and federal), they are primarily owned by private property owners, which is the case for our onshore oil and gas rights. Oil and gas rights primarily take the form of a lease, but can also be owned outright in fee. If the rights are secured by lease, we are typically granted the right to access, explore, extract, produce and market the oil and gas for a specified period of time, which may be extended if we continue to produce oil or gas or operate on the leased land.

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Environmental protection, land rehabilitation and occupational health and safety are principally regulated by governments and to a lesser degree, if applicable, by leases. These obligations often require us to make substantial expenditures to minimise or remediate the environmental impact of our assets and to ensure the safety of our employees and contractors. Regulations setting emissions standards for fuels used to power vehicles and equipment at our assets and the modes of transport used in our supply chains can also have a substantial impact, both directly and indirectly, on the markets for these products, with flow-on impacts on our costs. For more information on these types of obligations, refer to section 1.9.

From time-to-time, certain trade sanctions are adopted by the United Nations (UN) Security Council and/or various governments, including in the United Kingdom, the United States, the European Union (EU) and Australia against certain countries, entities or individuals, that may restrict our ability to sell extracted minerals, oil or natural gas and/or our ability to purchase goods or services.

Disclosure of Iran-related activities pursuant to section 13(r) of the U.S. Securities Exchange Act of 1934

Section 219 of the Iran Threat Reduction and Syria Human Rights Act of 2012 added Section 13(r) to the U.S. Securities Exchange Act of 1934, as amended (the Exchange Act). Section 13(r) requires an issuer to disclose in its annual reports whether it or any of its affiliates knowingly engaged in certain activities, transactions or dealings relating to Iran. Disclosure is required even where the activities, transactions or dealings are conducted outside the United States by non-US persons in compliance with applicable law, and whether or not the activities are sanctionable under US law. Provided in this section is certain information concerning activities of certain affiliates of BHP that took place in FY2018. BHP believes that these activities are not sanctionable either as being outside the scope of US sanctions, or within the scope of a specific licence issued by the U.S. Department of the Treasury’s Office of Foreign Assets Control (OFAC). BHP is making this disclosure in the interests of transparency.

BHP Billiton Petroleum Great Britain Ltd (BHP GB), a wholly owned affiliate of BHP, holds a non-operating 16 per cent interest in the Bruce oil and gas field located offshore United Kingdom, together with co-venturers BP Exploration Operating Company Limited (BP) (operator and 37 per cent interest holder), Marubeni Oil & Gas (North Sea) Limited (3.75 per cent interest holder) and Total E&P UK Limited (43.25 per cent interest holder).

The Bruce platform provides transportation and processing services to the nearby Rhum gas field pursuant to a contract between the Bruce owners and Rhum owners (the Bruce-Rhum Agreement). According to BP, the Rhum field is operated by BP and owned under a 50:50 unincorporated joint arrangement between BP and Iranian Oil Company (U.K.) Limited (IOC). IOC is an indirect subsidiary of the National Iranian Oil Company (NIOC), which is a corporation owned by the Government of Iran. As a Bruce owner, BHP GB is party to the Bruce-Rhum Agreement with BP as the operator. The U.S. Department of the Treasury, Office of Foreign Assets Control (OFAC) issued licence No. IA-2013-302799-5 to BP and its affiliates for Rhum Field activities for the period to 30 September 2017 and thereafter authorised activities under OFAC licence No. IA-2013-302799-6, until the end of September 2018.

BHP ceased to rely on US persons for Bruce-Rhum Agreement related activities from 30 September 2017 and continues to monitor developments concerning the US Iranian sanctions program to maintain compliance with applicable sanctions laws and requirements.

For FY2018, BHP GB recognised a total US$9 million in cost recovery in accordance with the terms of the Bruce-Rhum Agreement, which has been booked as a reduction in operating expenses in the Bruce field.

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Uranium production in Australia

To mine, process, transport and sell uranium from within Australia, we are required to hold possession and export permissions, which are also subject to regulation by the Australian Government or bodies that report to the Australian Government.

To possess nuclear material, such as uranium, in Australia, a Permit to Possess Nuclear Materials (Possession Permit) must be held pursuant to the Australian Nuclear Non-Proliferation (Safeguards) Act 1987 (Non-Proliferation Act). A Possession Permit is issued by the Australian Safeguards and Non-Proliferation Office, an office established under the Non-Proliferation Act, which administers Australia’s domestic nuclear safeguards requirements and reports to the Australian Government.

To export uranium from Australia, a Permit to Export Natural Uranium (Export Permit) must be held pursuant to the Australian Customs (Prohibited Exports) Regulations 1958. The Export Permit is issued by the Minister with responsibility for Resources and Energy.

A special permit to transport nuclear material is required under the Non-Proliferation Act by a party that transports nuclear material from one specified location to another specified location. As we engage service providers to transport uranium, each of those service providers is required to hold a permit to transport nuclear material issued by the Australian Safeguards and Non-Proliferation Office.

Hydraulic fracturing

Our Onshore US assets involve hydraulic fracturing, which uses water, sand and a small amount of chemicals to fracture hydrocarbon-bearing subsurface rock formations to the allow flow of hydrocarbons into the wellbore. We depend on the use of hydraulic fracturing techniques in our Onshore US drilling and completion programs.

Several US federal agencies are reviewing or advancing regulatory proposals concerning hydraulic fracturing and related activities. On 13 December 2016, the US Environmental Protection Agency (EPA) issued its final report on the impacts of hydraulic fracturing activities on drinking water resources. The EPA concluded that hydraulic fracturing activities can impact drinking water resources under some circumstances, but noted it was not possible to fully assess the potential impacts on drinking water resources, including the frequency and severity of impacts.

On 16 July 2015, the EPA’s Office of Inspector General issued a report indicating that the EPA should review oversight of permit issuance for hydraulic fracturing using diesel fuels and that the agency should develop a plan for responding to the public’s concerns about chemicals used in hydraulic fracturing. In response to this report, the EPA has developed revised permitting guidance for hydraulic fracturing activities using diesel fuels. The EPA has also published a report analysing chemicals used in hydraulic fracturing fluids.

On 27 July 2018, BHP announced that we had entered into agreements for the sale of our entire interest in the Eagle Ford, Haynesville, Permian and Fayetteville Onshore US oil and gas assets. Both sales are subject to the satisfaction of customary regulatory approvals and conditions precedent. We expect completion of both transactions to occur by the end of October 2018.

Exchange controls and shareholding limits

BHP Billiton Plc

There are no laws or regulations currently in force in the United Kingdom that restrict the export or import of capital or the payment of dividends to non-resident holders of BHP Billiton Plc’s shares, although the Group does operate in some other jurisdictions where the payment of dividends could be affected by exchange control approvals.

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From time to time, certain sanctions are adopted by the UN Security Council and/or various governments, including in the United Kingdom, the United States, the EU and Australia against certain countries, entities or individuals that may restrict the export or import of capital or the remittance of dividends to certain non-resident holders of BHP Billiton Plc’s shares.

There are no restrictions under BHP Billiton Plc’s Articles of Association or (subject to the effect of any sanctions) under English law that limit the right of non-resident or foreign owners to hold or vote BHP Billiton Plc’s shares.

There are certain restrictions on shareholding levels under BHP Billiton Plc’s Articles of Association described under the heading ‘BHP Billiton Limited’ below.

BHP Billiton Limited

Under current Australian legislation, the payment of any dividends, interest or other payments by BHP Billiton Limited to non-resident holders of BHP Billiton Limited’s shares is not restricted by exchange controls or other limitations, except that, in certain circumstances, BHP Billiton Limited may be required to withhold Australian taxes.

From time-to-time, certain sanctions are adopted by the UN Security Council and/or various governments, including in the United Kingdom, the United States, the EU and Australia. Those sanctions prohibit or, in some cases, impose certain approval and reporting requirements on transactions involving sanctioned countries, entities and individuals and/or assets controlled or owned by them. Certain transfers into or out of Australia of amounts greater than A$10,000 in any currency may also be subject to reporting requirements.

The Australian Foreign Acquisitions and Takeovers Act 1975 (the FATA) restricts certain acquisitions of interests in shares in Australian companies, including BHP Billiton Limited. Generally, under the FATA, the prior approval of the Australian Treasurer must be obtained for proposals by a foreign person (either alone or together with its associates) to acquire 20 per cent or more of the voting power or issued shares in an Australian company. Any acquisition by a foreign government investor of the voting power or issued shares in an Australian company will require the prior approval of the Australian Treasurer to be obtained.

The FATA also empowers the Treasurer to make certain orders prohibiting acquisitions by foreign persons in Australian companies, including BHP Billiton Limited (and requiring divestiture if the acquisition has occurred) where the Treasurer considers the acquisition to be contrary to the national interest. Such orders may also be made in respect of acquisitions by foreign persons where two or more foreign persons (and their associates) in aggregate already control 40 per cent or more of the issued shares or voting power in an Australian company, including BHP Billiton Limited.

The restrictions in the FATA on share acquisitions in BHP Billiton Limited described above apply equally to share acquisitions in BHP Billiton Plc because BHP Billiton Limited and BHP Billiton Plc are dual listed entities.

There are certain other statutory restrictions and restrictions under BHP Billiton Limited’s Constitution and BHP Billiton Plc’s Articles of Association that apply generally to acquisitions of shares in BHP Billiton Limited and BHP Billiton Plc (i.e. the restrictions are not targeted at foreign persons only). These include restrictions on a person (and associates) breaching a voting power threshold of:

• above 20 per cent in relation to BHP Billiton Limited on a ‘stand-alone’ basis (i.e. calculated as if there were no Special Voting Share and only counting BHP Billiton Limited’s ordinary shares);

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• 30 per cent of BHP Billiton Plc. This is the threshold for a mandatory offer under Rule 9 of the UK takeover code and this threshold applies to all voting rights of BHP Billiton Plc (therefore including voting rights attached to the BHP Billiton Plc Special Voting Share);

• 30 per cent in relation to BHP Billiton Plc on a ‘stand-alone’ basis (i.e. calculated as if there were no Special Voting Share and only counting BHP Billiton Plc’s ordinary shares);

• above 20 per cent in relation to BHP Billiton Plc, calculated having regard to all the voting power on a joint electorate basis (i.e. calculated on the aggregate of BHP Billiton Limited’s and BHP Billiton Plc’s ordinary shares).

Under BHP Billiton Limited’s Constitution and BHP Billiton Plc’s Articles of Association, sanctions for breach of any of these thresholds, other than by means of certain ‘permitted acquisitions’, include withholding of dividends, voting restrictions and compulsory divestment of shares to the extent a shareholder and its associates exceed the relevant threshold.

Except for the restrictions under the FATA, there are no limitations, either under Australian law or under the Constitution of BHP Billiton Limited, on the right of non-residents to hold or vote BHP Billiton Limited ordinary shares.

7.12    Ancillary information for our shareholders

This Annual Report provides the detailed financial data and information on BHP’s performance required to comply with the reporting regimes in Australia, the United Kingdom and the United States.

Shareholders of BHP Billiton Limited and BHP Billiton Plc will receive a copy of the Annual Report if they have requested a copy. ADR holders may view all documents online at bhp.com or opt to receive a hard copy by accessing citibank.ar.wilink.com or calling Citibank Shareholder Services during normal business hours using the details listed on the inside back cover of this Annual Report.

Change of shareholder details and enquiries

Shareholders wishing to contact BHP on any matter relating to their shares or ADR holdings are invited to telephone the appropriate office of the BHP Share Registrar or Transfer Office listed on the inside back cover of this Annual Report.

Any change in shareholding details should be notified by the shareholder to the relevant Registrar in a timely manner.

Shareholders can also access their current shareholding details and change many of those details online at bhp.com. The website requires shareholders to quote their Shareholder Reference Number (SRN) or Holder Identification Number (HIN) in order to access this information.

Alternative access to the Annual Report

We offer an alternative for all shareholders who wish to be advised of the availability of the Annual Report through our website via an email notification. By providing an email address through our website, shareholders will be notified by email when the Annual Report has been released. Shareholders will also receive notification of other major BHP announcements by email. Shareholders requiring further information or wishing to make use of this service should visit our website, bhp.com.

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ADR holders wishing to receive a hard copy of the Annual Report 2018 can do so by accessing citibank.ar.wilink.com or calling Citibank Shareholder Services during normal business hours. ADR holders may also contact the adviser that administers their investments. Holders of BHP Billiton Plc shares dematerialised into Strate should liaise directly with their Central Securities Depository Participant (CSDP) or broker.

Key dates for shareholders

The following table sets out future dates in the next financial and calendar year of interest to our shareholders. If there are any changes to these dates, all relevant stock exchanges (see section 7.2) will be notified.

Date	Event
25 September 2018	Final dividend payment date
17 October 2018	BHP Billiton Plc Annual General Meeting in London Venue: The QEII Centre Broad Sanctuary Westminster London SW1P 3EE United Kingdom Time: 11.00 am (local time) Details of the business of the meeting are contained in the separate Notice of Meeting
8 November 2018	BHP Billiton Limited Annual General Meeting in Adelaide Venue: Adelaide Entertainment Centre Cnr Port Road and Adam Street Hindmarsh South Australia Australia Time: 10.00am (local time) Details of the business of the meeting are contained in the separate Notice of Meeting
19 February 2019	Interim results announced
8 March 2019	Interim dividend record date
26 March 2019	Interim dividend payment date

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Corporate Directory

BHP Registered Offices

BHP Billiton Limited

Australia

171 Collins Street

Melbourne VIC 3000

Telephone Australia 1300 55 47 57

Telephone International +61 3 9609 3333

Facsimile +61 3 9609 3015

BHP Billiton Plc

United Kingdom

Nova South, 160 Victoria Street

London SW1E 5LB

Telephone +44 20 7802 4000

Facsimile +44 20 7802 4111

Group Company Secretary

Margaret Taylor

BHP Corporate Centres

Chile

Cerro El Plomo 6000

Piso 18

Las Condes 7560623

Santiago

Telephone +56 2 2579 5000

Facsimile +56 2 2207 6517

United States

Our agent for service in the United States is Jennifer Lopez-Burkland at:

1500 Post Oak Boulevard, Suite 150

Houston, TX 77056-3020

Telephone +1 713 961 8500

Facsimile +1 713 961 8400

Marketing and Supply Office

Singapore

10 Marina Boulevard, #50-01

Marina Bay Financial Centre, Tower 2

Singapore 018983

Telephone +65 6421 6000

Facsimile +65 6421 7000

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Share Registrars and Transfer Offices

Australia

BHP Billiton Limited Registrar

Computershare Investor Services

Pty Limited

Yarra Falls, 452 Johnston Street

Abbotsford VIC 3067

Postal address – GPO Box 2975

Melbourne VIC 3001

Telephone 1300 656 780 (within Australia)

+61 3 9415 4020 (outside Australia)

Facsimile +61 3 9473 2460

Email enquiries: investorcentre.com/bhp

United Kingdom

BHP Billiton Plc Registrar

Computershare Investor Services PLC

The Pavilions, Bridgwater Road

Bristol BS13 8AE

Postal address (for general enquiries)

The Pavilions, Bridgwater Road

Bristol BS99 6ZZ

Telephone +44 344 472 7001

Facsimile +44 370 703 6101

Email enquiries: investorcentre.co.uk/contactus

South Africa

BHP Billiton Plc Branch Register and Transfer Secretary

Computershare Investor Services

(Pty) Limited

Rosebank Towers

15 Biermann Avenue

Rosebank

2196, South Africa

Postal address – PO Box 61051

Marshalltown 2107

Telephone +27 11 373 0033

Facsimile +27 11 688 5217

Email enquiries: web.queries@computershare.co.za

Holders of shares dematerialised

into Strate should contact their

CSDP or stockbroker.

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New Zealand

Computershare Investor Services Limited

Level 2/159 Hurstmere Road

Takapuna Auckland 0622

Postal address – Private Bag 92119

Auckland 1142

Telephone +64 9 488 8777

Facsimile +64 9 488 8787

United States

Computershare Trust Company, N.A.

250 Royall Street

Canton, MA 02021

Postal address – PO Box 43078

Providence, RI 02940-3078

Telephone +1 888 404 6340

(toll-free within US)

Facsimile +1 312 601 4331

ADR Depositary, Transfer Agent and Registrar

Citibank Shareholder Services

PO Box 43077

Providence, RI 02940-3077

Telephone +1 781 575 4555 (outside of US) +1 877 248 4237 (+1-877-CITIADR)

(toll-free within US)

Facsimile +1 201 324 3284

Email enquiries:

citibank@shareholders-online.com

Website: citi.com/dr

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8    Exhibits

Exhibits marked “*” have been filed as exhibits to this annual report on Form 20-F. Remaining exhibits have been incorporated by reference as indicated.

Exhibit 1    Constitution

1.1 Constitution of BHP Billiton Limited, incorporating the amendments approved by shareholders at the 2015 Annual General Meeting of BHP Billiton Limited on 19 November 2015 ⁽¹⁾

1.2 Memorandum and Articles of Association of BHP Billiton Plc, incorporating the amendments approved by shareholders at the 2015 Annual General Meeting of BHP Billiton Plc on 22 October 2015 ⁽¹⁾

Exhibit 4    Material Contracts

4.1 DLC Structure Sharing Agreement, dated 29 June 2001, between BHP Limited and Billiton Plc incorporating the amendments approved by shareholders at the 2015 Annual General Meeting of BHP Billiton Limited on 19 November 2015 and the Annual General Meeting of BHP Billiton Plc on 22 October 2015 ⁽¹⁾

4.2 SVC Special Voting Shares Deed, dated 29 June 2001, among BHP Limited, BHP SVC Pty Limited, Billiton Plc, Billiton SVC Limited and The Law Debenture Trust Corporation p.l.c. ^(2)(P)

4.3 SVC Special Voting Shares Amendment Deed, dated 13 August 2001, among BHP Limited, BHP SVC Pty Limited, Billiton Plc, Billiton SVC Limited and The Law Debenture Trust Corporation p.l.c. ^(2)(P)

4.4 Deed Poll Guarantee, dated 29 June 2001, of BHP Limited ^(2)(P)

4.5 Deed Poll Guarantee, dated 29 June 2001, of Billiton Plc ^(2)(P)

4.6 Form of Service Agreement for Specified Executive (referred to in this Annual Report as the Key Management Personnel) ⁽³⁾

4.7 BHP Billiton Ltd Group Incentive Scheme Rules 2004, dated August 2008 ⁽⁴⁾

4.8 BHP Billiton Ltd Long Term Incentive Plan Rules, dated November 2010 ^(2)(P)

4.9 BHP Billiton Plc Group Incentive Scheme Rules 2004, dated August 2008 ⁽⁴⁾

4.10 BHP Billiton Plc Long Term Incentive Plan Rules, dated November 2010 ^(2)(P)

4.11 Framework Agreement entered into on 2 March 2016 between Samarco Mineração S.A., Vale S.A. and BHP Billiton Brasil Ltda, the Federal Government of Brazil, the states of Espirito Santo and Minas Gerais and certain other public authorities in Brazil ⁽¹⁾

Exhibit 8    List of Subsidiaries

*8.1 List of subsidiaries of BHP Billiton Limited and BHP Billiton Plc

Exhibit 12    Certifications (section 302)

*12.1 Certification by Chief Executive Officer, Mr Andrew Mackenzie, dated 18  September 2018

*12.2 Certification by Chief Financial Officer, Mr Peter Beaven, dated 18  September 2018

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Exhibit 13    Certifications (section 906)

*13.1 Certification by Chief Executive Officer, Mr Andrew Mackenzie, dated 18  September 2018

*13.2 Certification by Chief Financial Officer, Mr Peter Beaven, dated 18  September 2018

Exhibit 15    Consent of Independent Registered Public Accounting Firm

*15.1 Consent of Independent Registered Public Accounting firms KPMG and KPMG Audit Plc for incorporation by reference of audit reports in registration statements on Form F-3 and Form S-8

Footnotes

(1) Previously filed as an exhibit to BHP’s annual report on Form 20-F for the year ended 30 June 2016 on 21 September 2016.

(2) Previously filed on paper form as an exhibit to BHP’s annual report on Form 20-F for the year ended 30 June 2001 on 19 November 2001.

(3) Previously filed as an exhibit to BHP’s annual report on Form 20-F for the year ended 30 June 2013 on 25 September 2013.

(4) Previously filed as an exhibit to BHP’s annual report on Form 20-F for the year ended 30 June 2008 on 15 September 2008.

(P) Previously filed on paper form.

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SIGNATURE

The registrants hereby certify that they meet all of the requirements for filing on Form 20-F and that they have duly caused and authorised the undersigned to sign this annual report on their behalf.

BHP Billiton Limited

BHP Billiton Plc

/s/ Peter Beaven

Peter Beaven

Chief Financial Officer

Date: 18 September 2018

Section 5 – Financial Statements

Financial Statements
5.1	Consolidated Financial Statements	F-2
	5.1.1 Consolidated Income Statement	F-2
	5.1.2 Consolidated Statement of Comprehensive Income	F-3
	5.1.3 Consolidated Balance Sheet	F-4
	5.1.4 Consolidated Cash Flow Statement	F-5
	5.1.5 Consolidated Statement of Changes in Equity	F-6
	5.1.6 Notes to the Financial Statements	F-11
5.2	Not required for US reporting	F-101
5.2A	Reports of Independent Registered Public Accounting Firms	F-101
5.3	Directors’ declaration	F-103
5.4	Statement of Directors’ responsibilities in respect of the Annual Report and the Financial Statements	F-104
5.5	Not required for US reporting	F-105
5.6	Included as Item 5.2A	F-105
5.7	Supplementary oil and gas information – unaudited	F-105
Notes to the Financial Statements		F-11
Performance		F-11
1	Segment reporting	F-11
2	Exceptional items	F-15
3	Significant events – Samarco dam failure	F-18
4	Expenses and other income	F-30
5	Income tax expense	F-31
6	Earnings per share	F-36
Working capital		F-37
7	Trade and other receivables	F-37
8	Trade and other payables	F-38
9	Inventories	F-38
Resource assets		F-39
10	Property, plant and equipment	F-39
11	Intangible assets	F-45
12	Deferred tax balances	F-46
13	Closure and rehabilitation provisions	F-49
Capital Structure		F-51
14	Share capital	F-51
15	Other equity	F-53
16	Dividends	F-55
17	Provisions for dividends and other liabilities	F-56
Financial Management		F-56
18	Net debt	F-56
19	Net finance costs	F-60
20	Financial risk management	F-60
Employee matters		F-72
21	Key management personnel	F-72
22	Employee share ownership plans	F-72
23	Employee benefits, restructuring and post-retirement employee benefits provisions	F-76
24	Pension and other post-retirement obligations	F-78
25	Employees	F-80

Group and related party information		F-80
26	Discontinued operations	F-80
27	Subsidiaries	F-84
28	Investments accounted for using the equity method	F-85
29	Interests in joint operations	F-89
30	Related party transactions	F-90
Unrecognised items and uncertain events		F-91
31	Commitments	F-91
32	Contingent liabilities	F-92
33	Subsequent events	F-93
Other items		F-93
34	Acquisitions and disposals of subsidiaries, operations, joint operations and equity accounted investments	F-93
35	Auditor’s remuneration	F-94
36	Not required for US reporting	F-95
37	Deed of Cross Guarantee	F-95
38	New and amended accounting standards and interpretations	F-97

About these Financial Statements

Reporting entity

In 2001, BHP Billiton Limited (previously known as BHP Limited), an Australian-listed company, and BHP Billiton Plc (previously known as Billiton Plc), a UK listed company, entered into a Dual Listed Company (DLC) merger. These entities and their subsidiaries operate together as a single for-profit economic entity (referred to as ‘BHP’ or ‘the Group’) with a common Board of Directors, unified management structure and joint objectives. In effect, the DLC structure provides the same voting rights and dividend entitlements from BHP Billiton Limited and BHP Billiton Plc irrespective of whether investors hold shares in BHP Billiton Limited or BHP Billiton Plc.

Group and related party information is presented in note 30 ‘Related party transactions’ in section 5.1. This details the Group’s subsidiaries, associates, joint arrangements and the nature of transactions between these and other related parties. The nature of the operations and principal activities of the Group are described in the segment information (refer to note 1 ‘Segment reporting’ in section 5.1).

Presentation of the Consolidated Financial Statements

BHP Billiton Limited and BHP Billiton Plc Directors have included information in this report they deem to be material and relevant to the understanding of the Consolidated Financial Statements (the Financial Statements). Disclosure may be considered material and relevant if the dollar amount is significant due to its size or nature, or the information is important to understand the:

• Group’s current year results;

• impact of significant changes in the Group’s business; or

• aspects of the Group’s operations that are important to future performance.

These Financial Statements were approved by the Board of Directors on 6 September 2018. The Directors have the authority to amend the Financial Statements after issuance.

F-1

5.1    Consolidated Financial Statements

5.1.1    Consolidated Income Statement for the year ended 30 June 2018

	Notes		2018			2017			2016
			US$M			US$M Restated			US$M Restated
Continuing operations
Revenue		1		43,638			36,135			28,567
Other income		4		247			662			432
Expenses excluding net finance costs		4		(28,036	)		(24,515	)		(24,091	)
Profit/(loss) from equity accounted investments, related impairments and expenses		28		147			272			(2,104	)
Profit from operations				15,996			12,554			2,804
Financial expenses				(1,567	)		(1,560	)		(1,150	)
Financial income				322			143			137
Net finance costs		19		(1,245	)		(1,417	)		(1,013	)
Profit before taxation				14,751			11,137			1,791
Income tax expense				(6,879	)		(4,276	)		(1,858	)
Royalty-related taxation (net of income tax benefit)				(128	)		(167	)		(245	)
Total taxation expense		5		(7,007	)		(4,443	)		(2,103	)
Profit/(loss) after taxation from Continuing operations				7,744			6,694			(312	)
Discontinued operations
Loss after taxation from Discontinued operations		26		(2,921	)		(472	)		(5,895	)
Profit/(loss) after taxation from Continuing and Discontinued operations				4,823			6,222			(6,207	)
Attributable to non-controlling interests				1,118			332			178
Attributable to BHP shareholders				3,705			5,890			(6,385	)
Basic earnings/(loss) per ordinary share (cents)		6		69.6			110.7			(120.0	)
Diluted earnings/(loss) per ordinary share (cents)		6		69.4			110.4			(120.0	)
Basic earnings/(loss) from Continuing operations per ordinary share (cents)		6		125.0			119.8			(10.2	)
Diluted earnings/(loss) from Continuing operations per ordinary share (cents)		6		124.6			119.5			(10.2	)

The accompanying notes form part of these Financial Statements.

F-2

5.1.2    Consolidated Statement of Comprehensive Income for the year ended 30 June 2018

	Notes		2018			2017			2016
			US$M			US$M			US$M
Profit/(loss) after taxation from Continuing and Discontinued operations				4,823			6,222			(6,207	)
Other comprehensive income
Items that may be reclassified subsequently to the income statement:
Available for sale investments:
Net valuation gains/(losses) taken to equity				11			(1	)		2
Net valuation losses transferred to the income statement				–			–			1
Cash flow hedges:
Gains/(losses) taken to equity				82			351			(566	)
(Gains)/losses transferred to the income statement				(215	)		(432	)		664
Exchange fluctuations on translation of foreign operations taken to equity				2			(1	)		(1	)
Exchange fluctuations on translation of foreign operations transferred to income statement				–			–			(10	)
Tax recognised within other comprehensive income		5		36			24			(30	)
Total items that may be reclassified subsequently to the income statement				(84	)		(59	)		60
Items that will not be reclassified to the income statement:
Remeasurement gains/(losses) on pension and medical schemes				1			36			(20	)
Tax recognised within other comprehensive income		5		(14	)		(26	)		(17	)
Total items that will not be reclassified to the income statement				(13	)		10			(37	)
Total other comprehensive (loss)/income				(97	)		(49	)		23
Total comprehensive income/(loss)				4,726			6,173			(6,184	)
Attributable to non-controlling interests				1,118			332			176
Attributable to BHP shareholders				3,608			5,841			(6,360	)

The accompanying notes form part of these Financial Statements.

F-3

5.1.3    Consolidated Balance Sheet as at 30 June 2018

	Notes		2018			2017
			US$M			US$M
ASSETS
Current assets
Cash and cash equivalents		18		15,871			14,153
Trade and other receivables		7		3,096			2,836
Other financial assets		20		200			72
Inventories		9		3,764			3,673
Assets held for sale		26		11,939			–
Current tax assets				106			195
Other				154			127
Total current assets				35,130			21,056
Non-current assets
Trade and other receivables		7		180			803
Other financial assets		20		999			1,281
Inventories		9		1,141			1,095
Property, plant and equipment		10		67,182			80,497
Intangible assets		11		778			3,968
Investments accounted for using the equity method		28		2,473			2,448
Deferred tax assets		12		4,041			5,788
Other				69			70
Total non-current assets				76,863			95,950
Total assets				111,993			117,006
LIABILITIES
Current liabilities
Trade and other payables		8		5,977			5,551
Interest bearing liabilities		18		2,736			1,241
Liabilities held for sale		26		1,222			–
Other financial liabilities		20		138			394
Current tax payable				1,773			2,119
Provisions		3,13,17, 23		2,025			1,959
Deferred income				118			102
Total current liabilities				13,989			11,366
Non-current liabilities
Trade and other payables		8		3			5
Interest bearing liabilities		18		24,069			29,233
Other financial liabilities		20		1,093			1,106
Non-current tax payable				137			–
Deferred tax liabilities		12		3,472			3,765
Provisions		3,13,17, 23		8,223			8,445
Deferred income				337			360
Total non-current liabilities				37,334			42,914
Total liabilities				51,323			54,280
Net assets				60,670			62,726
EQUITY
Share capital – BHP Billiton Limited				1,186			1,186
Share capital – BHP Billiton Plc				1,057			1,057
Treasury shares				(5	)		(3	)
Reserves		15		2,290			2,400
Retained earnings				51,064			52,618
Total equity attributable to BHP shareholders				55,592			57,258
Non-controlling interests		15		5,078			5,468
Total equity				60,670			62,726

The accompanying notes form part of these Financial Statements.

The Financial Statements were approved by the Board of Directors on 6 September 2018 and signed on its behalf by:

Ken MacKenzie	Andrew Mackenzie
Chairman	Chief Executive Officer

F-4

5.1.4    Consolidated Cash Flow Statement for the year ended 30 June 2018

	Notes		2018			2017			2016
			US$M			US$M Restated			US$M Restated
Operating activities
Profit before taxation				14,751			11,137			1,791
Adjustments for:
Depreciation and amortisation expense				6,288			6,184			6,210
Impairments of property, plant and equipment, financial assets and intangibles				333			193			186
Net finance costs				1,245			1,417			1,013
Profit/(loss) from equity accounted investments, related impairments and expenses				(147	)		(272	)		2,104
Other				597			194			467
Changes in assets and liabilities:
Trade and other receivables				(662	)		267			1,387
Inventories				(182	)		(687	)		521
Trade and other payables				719			512			(1,272	)
Provisions and other assets and liabilities				7			(333	)		(316	)
Cash generated from operations				22,949			18,612			12,091
Dividends received				709			636			301
Interest received				290			164			128
Interest paid				(1,177	)		(1,148	)		(829	)
Settlement of cash management related instruments				(292	)		(140	)		–
Net income tax and royalty-related taxation refunded				17			337			435
Net income tax and royalty-related taxation paid				(4,935	)		(2,585	)		(2,286	)
Net operating cash flows from Continuing operations				17,561			15,876			9,840
Net operating cash flows from Discontinued operations				900			928			785
Net operating cash flows				18,461			16,804			10,625
Investing activities
Purchases of property, plant and equipment				(4,979	)		(3,697	)		(5,707	)
Exploration expenditure				(874	)		(966	)		(752	)
Exploration expenditure expensed and included in operating cash flows				641			610			419
Net investment and funding of equity accounted investments				204			(234	)		(217	)
Proceeds from sale of assets				89			529			93
Proceeds from divestment of subsidiaries, operations and joint operations, net of their cash		34		–			187			166
Other investing				(141	)		(153	)		(20	)
Net investing cash flows from Continuing operations				(5,060	)		(3,724	)		(6,018	)
Net investing cash flows from Discontinued operations				(861	)		(437	)		(1,227	)
Net investing cash flows				(5,921	)		(4,161	)		(7,245	)
Financing activities
Proceeds from interest bearing liabilities				528			1,577			7,239
(Settlements)/proceeds from debt related instruments				(218	)		36			156
Repayment of interest bearing liabilities				(4,188	)		(7,114	)		(2,781	)
Purchase of shares by Employee Share Ownership Plan (ESOP) Trusts				(171	)		(108	)		(106	)
Dividends paid				(5,220	)		(2,921	)		(4,130	)
Dividends paid to non-controlling interests				(1,582	)		(575	)		(62	)
Net financing cash flows from Continuing operations				(10,851	)		(9,105	)		316
Net financing cash flows from Discontinued operations				(40	)		(28	)		(32	)
Net financing cash flows				(10,891	)		(9,133	)		284
Net increase in cash and cash equivalents from Continuing operations				1,650			3,047			4,138
Net (decrease)/increase in cash and cash equivalents from Discontinued operations				(1	)		463			(474	)
Cash and cash equivalents, net of overdrafts, at the beginning of the financial year				14,108			10,276			6,613
Foreign currency exchange rate changes on cash and cash equivalents				56			322			(1	)
Cash and cash equivalents, net of overdrafts, at the end of the financial year		18		15,813			14,108			10,276

The accompanying notes form part of these Financial Statements.

F-5

5.1.5    Consolidated Statement of Changes in Equity for the year ended 30 June 2018

	Attributable to BHP shareholders
	Share capital				Treasury shares						Reserves			Retained earnings			Total equity attributable to BHP shareholders			Non- controlling interests			Total equity
US$M	BHP Billiton Limited		BHP Billiton Plc		BHP Billiton Limited			BHP Billiton Plc
Balance as at 1 July 2017		1,186		1,057		(2	)		(1	)		2,400			52,618			57,258			5,468			62,726
Total comprehensive income		–		–		–			–			(87	)		3,695			3,608			1,118			4,726
Transactions with owners:
Purchase of shares by ESOP Trusts		–		–		(159	)		(12	)		–			–			(171	)		–			(171	)
Employee share awards exercised net of employee contributions		–		–		156			13			(139	)		(30	)		–			–			–
Employee share awards forfeited		–		–		–			–			(2	)		2			–			–			–
Accrued employee entitlement for unexercised awards		–		–		–			–			123			–			123			–			123
Distribution to non-controlling interests		–		–		–			–			–			–			–			(14	)		(14	)
Dividends		–		–		–			–			–			(5,221	)		(5,221	)		(1,499	)		(6,720	)
Transfer to non-controlling interests		–		–		–			–			(5	)		–			(5	)		5			–
Balance as at 30 June 2018		1,186		1,057		(5	)		–			2,290			51,064			55,592			5,078			60,670
Balance as at 1 July 2016		1,186		1,057		(7	)		(26	)		2,538			49,542			54,290			5,781			60,071
Total comprehensive income		–		–		–			–			(59	)		5,900			5,841			332			6,173
Transactions with owners:
Purchase of shares by ESOP Trusts		–		–		(105	)		(3	)		–			–			(108	)		–			(108	)
Employee share awards exercised net of employee contributions		–		–		110			28			(167	)		29			–			–			–
Employee share awards forfeited		–		–		–			–			(18	)		18			–			–			–
Accrued employee entitlement for unexercised awards		–		–		–			–			106			–			106			–			106
Distribution to non-controlling interests		–		–		–			–			–			–			–			(16	)		(16	)
Dividends		–		–		–			–			–			(2,871	)		(2,871	)		(601	)		(3,472	)
Divestment of subsidiaries, operations and joint operations		–		–		–			–			–			–			–			(28	)		(28	)
Balance as at 30 June 2017		1,186		1,057		(2	)		(1	)		2,400			52,618			57,258			5,468			62,726
Balance as at 1 July 2015		1,186		1,057		(19	)		(57	)		2,557			60,044			64,768			5,777			70,545
Total comprehensive loss		–		–		–			–			60			(6,420	)		(6,360	)		176			(6,184	)
Transactions with owners:
Purchase of shares by ESOP Trusts		–		–		(106	)		–			–			–			(106	)		–			(106	)
Employee share awards exercised net of employee contributions		–		–		118			31			(193	)		46			2			–			2
Employee share awards forfeited		–		–		–			–			(26	)		26			–			–			–
Accrued employee entitlement for unexercised awards		–		–		–			–			140			–			140			–			140
Dividends		–		–		–			–			–			(4,154	)		(4,154	)		(172	)		(4,326	)
Balance as at 30 June 2016		1,186		1,057		(7	)		(26	)		2,538			49,542			54,290			5,781			60,071

The accompanying notes form part of these Financial Statements.

F-6

Basis of preparation

The Group’s Financial Statements as at and for the year ended 30 June 2018:

• is a consolidated general purpose financial report;

• has been prepared in accordance with the requirements of the:

^¡  Australian Corporations Act 2001;

^¡  UK Companies Act 2006;

• has been prepared in accordance with accounting standards and interpretations collectively referred to as ‘IFRS’ in this report, which encompass the:

^¡  International Financial Reporting Standards and interpretations as issued by the International Accounting Standards Board;

^¡  Australian Accounting Standards, being Australian equivalents to International Financial Reporting Standards and interpretations as issued by the Australian Accounting Standards Board (AASB);

^¡  International Financial Reporting Standards and interpretations adopted by the European Union (EU);

• is prepared on a going concern basis;

• measures items on the basis of historical cost principles, except for the following items:

^¡  derivative financial instruments and certain other financial assets, which are carried at fair value;

^¡  non-current assets or disposal groups that are classified as held-for-sale or held-for-distribution, which are measured at the lower of carrying amount and fair value less cost to dispose;

• includes significant accounting policies in the notes to the Financial Statements that summarise the recognition and measurement basis used and are relevant to an understanding of the Financial Statements;

• applies a presentation currency of US dollars, consistent with the predominant functional currency of the Group’s operations. Amounts are rounded to the nearest million dollars, unless otherwise stated, in accordance with ASIC (Rounding in Financial/Directors’ Reports) Instrument 2016/191;

• presents reclassified comparative information where required for consistency with the current year’s presentation;

• adopts all new and amended standards and interpretations under IFRS issued by the relevant bodies (listed above), that are mandatory for application beginning on or after 1 July 2017. None had a significant impact on the Financial Statements;

• has not early adopted any standards and interpretations that have been issued or amended but are not yet effective.

The accounting policies have been consistently applied by all entities included in the Financial Statements and are consistent with those applied in all prior years presented.

Principles of consolidation

In preparing the Financial Statements the effects of all intragroup balances and transactions have been eliminated.

A list of significant entities in the Group, including subsidiaries, joint arrangements and associates at year-end is contained in note 27 ‘Subsidiaries’, note 28 ‘Investments accounted for using the equity method’ and note 29 ‘Interests in joint operations’.

F-7

Subsidiaries: The Financial Statements of the Group include the consolidation of BHP Billiton Limited, BHP Billiton Plc and their respective subsidiaries being the entities controlled by the parent entities during the year. Control exists where the Group is:

• exposed to, or has rights to, variable returns from its involvement with the entity;

• has the ability to affect those returns through its power to direct the activities of the entity.

The ability to approve the operating and capital budget of a subsidiary and the ability to appoint key management personnel are decisions that demonstrate that the Group has the existing rights to direct the relevant activities of a subsidiary. Where the Group’s interest is less than 100 per cent, the interest attributable to outside shareholders is reflected in non-controlling interests. The financial statements of subsidiaries are prepared for the same reporting period as the Group, using consistent accounting policies. The acquisition method of accounting is used to account for the Group’s business combinations.

Joint arrangements: The Group undertakes a number of business activities through joint arrangements, which exist when two or more parties have joint control. Joint arrangements are classified as either joint operations or joint ventures, based on the contractual rights and obligations between the parties to the arrangement.

The Group has two types of joint arrangements:

• Joint operations: A joint operation is an arrangement in which the Group shares joint control, primarily via contractual arrangements with other parties. In a joint operation, the Group has rights to the assets and obligations for the liabilities relating to the arrangement. This includes situations where the parties benefit from the joint activity through a share of the output, rather than by receiving a share of the results of trading. In relation to the Group’s interest in a joint operation, the Group recognises: its share of assets and liabilities; revenue from the sale of its share of the output and its share of any revenue generated from the sale of the output by the joint operation; and its share of expenses. All such amounts are measured in accordance with the terms of the arrangement, which is usually in proportion to the Group’s interest in the joint operation.

• Joint ventures: A joint venture is a joint arrangement in which the parties that share joint control have rights to the net assets of the arrangement. A separate vehicle, not the parties, will have the rights to the assets and obligations to the liabilities relating to the arrangement. More than an insignificant share of output from a joint venture is sold to third parties, which indicates the joint venture is not dependent on the parties to the arrangement for funding, nor do the parties have an obligation for the liabilities of the arrangement. Joint ventures are accounted for using the equity accounting method.

Associates: The Group accounts for investments in associates using the equity accounting method. An entity is considered an associate where the Group is deemed to have significant influence but not control or joint control. Significant influence is presumed to exist where the Group:

• has over 20 per cent but less than 50 per cent of the voting rights of an entity, unless it can be clearly demonstrated that this is not the case; or

• holds less than 20 per cent of the voting rights of an entity; however, has the power to participate in the financial and operating policy decisions affecting the entity.

The Group uses the term ‘equity accounted investments’ to refer to joint ventures and associates collectively.

Foreign currencies

Transactions related to the Group’s worldwide operations are conducted in a number of foreign currencies. The majority of operations have assessed US dollars as the functional currency, however, some subsidiaries, joint arrangements and associates have functional currencies other than US dollars.

F-8

Monetary items denominated in foreign currencies are translated into US dollars as follows:

Foreign currency item	Applicable exchange rate
Transactions	Date of underlying transaction
Monetary assets and liabilities	Period-end rate

Foreign exchange gains and losses resulting from translation are recognised in the income statement, except for qualifying cash flow hedges (which are deferred to equity) and foreign exchange gains or losses on foreign currency provisions for site closure and rehabilitation costs (which are capitalised in property, plant and equipment for operating sites).

On consolidation, the assets, liabilities, income and expenses of non-US dollar denominated functional operations are translated into US dollars using the following applicable exchange rates:

Foreign currency amount	Applicable exchange rate
Income and expenses	Date of underlying transaction
Assets and liabilities	Period-end rate
Equity	Historical rate
Reserves	Historical and period-end rate

Foreign exchange differences resulting from translation are initially recognised in the foreign currency translation reserve and subsequently transferred to the income statement on disposal of a foreign operation.

Critical accounting policies, judgements and estimates

The Group has identified a number of critical accounting policies under which significant judgements, estimates and assumptions are made. Actual results may differ for these estimates under different assumptions and conditions. This may materially affect financial results and the carrying amount of assets and liabilities to be reported in the next and future periods.

Additional information relating to these critical accounting policies is embedded within the following notes:

Note
3	Significant events – Samarco dam failure
5	Taxation
9	Inventories
10 and 11	Exploration and evaluation
10	Development expenditure
10	Overburden removal costs
10	Depreciation of property, plant and equipment
10 and 11	Impairments of non-current assets – recoverable amount
13	Closure and rehabilitation provisions

F-9

Reserve estimates

Reserves are estimates of the amount of product that can be economically and legally extracted from the Group’s properties. In order to estimate reserves, estimates are required for a range of geological, technical and economic factors, including quantities, grades, production techniques, recovery rates, production costs, transport costs, commodity demand, commodity prices and exchange rates.

Estimating the quantity and/or grade of reserves requires the size, shape and depth of ore bodies or fields to be determined by analysing geological data such as drilling samples. This process may require complex and difficult geological judgements to interpret the data.

Additional information on the Group’s mineral and oil and gas reserves can be viewed within section 6.3. Section 6.3 is unaudited and does not form part of these Financial Statements.

Reserve impact on financial reporting

Estimates of reserves may change from period-to-period as the economic assumptions used to estimate reserves change and additional geological data is generated during the course of operations. Changes in reserves may affect the Group’s financial results and financial position in a number of ways, including:

• asset carrying values may be affected due to changes in estimated future production levels;

• depreciation, depletion and amortisation charged in the income statement may change where such charges are determined on the units of production basis, or where the useful economic lives of assets change;

• overburden removal costs recorded on the balance sheet or charged to the income statement may change due to changes in stripping ratios or the units of production basis of depreciation;

• decommissioning, site restoration and environmental provisions may change where changes in estimated reserves affect expectations about the timing or cost of these activities;

• the carrying amount of deferred tax assets may change due to changes in estimates of the likely recovery of the tax benefits.

F-10

5.1.6 Notes to the Financial Statements

Performance

1    Segment reporting

Reportable segments

The Group operated four reportable segments during FY2018, which are aligned with the commodities that are extracted and marketed and reflect the structure used by the Group’s management to assess the performance of the Group.

Reportable segment	Principal activities
Petroleum	Exploration, development and production of oil and gas
Copper	Mining of copper, silver, lead, zinc, molybdenum, uranium and gold
Iron Ore	Mining of iron ore
Coal	Mining of metallurgical coal and energy coal

Unless otherwise noted, the segment reporting information excludes Discontinued operations, being the Petroleum Onshore US operations comprising the Eagle Ford, Haynesville, Permian and Fayetteville oil and gas assets.

Group and unallocated items includes functions and other unallocated operations, including Potash, Nickel West and consolidation adjustments. Revenue not attributable to reportable segments comprises the sale of freight and fuel to third parties, as well as revenues from unallocated operations. Exploration and technology activities are recognised within relevant segments.

Year ended 30 June 2018 US$M	Petroleum			Copper			Iron Ore			Coal			Group and unallocated items/ eliminations (4)			Group total
Revenue		5,333			13,287			14,797			8,889			1,332			43,638
Inter-segment revenue		75			–			13			–			(88	)		–
Total revenue		5,408			13,287			14,810			8,889			1,244			43,638
Underlying EBITDA		3,341			6,522			8,930			4,397			(7	)		23,183
Depreciation and amortisation (1)		(1,719	)		(1,920	)		(1,721	)		(686	)		(242	)		(6,288	)
Impairment losses (2)		(76	)		(213	)		(14	)		(29	)		(1	)		(333	)
Underlying EBIT		1,546			4,389			7,195			3,682			(250	)		16,562
Exceptional items (3)		–			–			(539	)		–			(27	)		(566	)
Net finance costs																	(1,245	)
Profit before taxation																	14,751
Capital expenditure (cash basis)		656			2,428			1,074			409			412			4,979
Profit/(loss) from equity accounted investments, related impairments and expenses		(4	)		467			(509	)		192			1			147
Investments accounted for using the equity method		249			1,335			–			883			6			2,473
Total assets		12,938			26,824			22,208			12,257			37,766			111,993
Total liabilities		4,886			3,145			3,888			2,404			37,000			51,323

F-11

Year ended 30 June 2017 US$M	Petroleum			Copper			Iron Ore			Coal			Group and unallocated items/ eliminations (4)			Group total
Revenue		4,639			8,335			14,606			7,578			977			36,135
Inter-segment revenue		83			–			18			–			(101	)		–
Total revenue		4,722			8,335			14,624			7,578			876			36,135
Underlying EBITDA		3,117			3,545			9,077			3,784			(173	)		19,350
Depreciation and amortisation (1)		(1,648	)		(1,525	)		(1,828	)		(719	)		(252	)		(5,972	)
Impairment losses (2)		(102	)		(14	)		(52	)		(15	)		(5	)		(188	)
Underlying EBIT		1,367			2,006			7,197			3,050			(430	)		13,190
Exceptional items (3)		–			(546	)		(203	)		164			(51	)		(636	)
Net finance costs																	(1,417	)
Profit before taxation																	11,137
Capital expenditure (cash basis)		917			1,484			805			246			245			3,697
Profit/(loss) from equity accounted investments, related impairments and expenses		(3	)		295			(172	)		152			–			272
Investments accounted for using the equity method		264			1,306			–			873			5			2,448
Total assets		13,726			26,743			22,781			11,996			41,760			117,006
Total liabilities		4,715			2,643			3,606			1,860			41,456			54,280
Year ended 30 June 2016 US$M	Petroleum			Copper			Iron Ore			Coal			Group and unallocated items/ eliminations (4)			Group total
Revenue		4,431			8,249			10,516			4,518			853			28,567
Inter-segment revenue		118			–			22			–			(140	)
Total revenue		4,549			8,249			10,538			4,518			713			28,567
Underlying EBITDA		3,038			2,619			5,599			635			(171	)		11,720
Depreciation and amortisation (1)		(1,696	)		(1,560	)		(1,817	)		(890	)		(247	)		(6,210	)
Impairment losses (2)		(24	)		(17	)		(42	)		(94	)		(9	)		(186	)
Underlying EBIT		1,318			1,042			3,740			(349	)		(427	)		5,324
Exceptional items (3)		–			–			(2,388	)		–			(132	)		(2,520	)
Net finance costs																	(1,013	)
Loss before taxation																	1,791
Capital expenditure (cash basis)		1,278			2,786			1,061			298			284			5,707
Profit/(loss) from equity accounted investments, related impairments and expenses		(7	)		155			(2,244	)		(9	)		1			(2,104	)
Investments accounted for using the equity method		280			1,388			–			901			6			2,575
Total assets		14,120			26,143			24,330			12,754			41,606			118,953
Total liabilities		4,264			2,299			3,789			2,103			46,427			58,882

⁽¹⁾  Depreciation and amortisation excludes exceptional items of US$ nil (FY2017: US$212 million; FY2016: US$ nil).

⁽²⁾  Impairment losses excludes exceptional items of US$ nil (FY2017: US$5 million; FY2016: US$ nil).

⁽³⁾  Exceptional items reported in Group and unallocated include Samarco dam failure costs of US$(27) million (FY2017: US$(51) million; FY2016: US$(62) million). Refer to note 2 ‘Exceptional items’ for further information.

⁽⁴⁾  Total assets and total liabilities include balances for the years ended 30 June 2018, 2017 and 2016 relating to Onshore US assets.

F-12

Geographical information

	Revenue by location of customer
	2018		2017		2016
	US$M		US$M		US$M
Australia		2,304		2,037		1,846
Europe		1,886		1,641		1,141
China		22,935		18,875		13,177
Japan		4,709		3,086		2,941
India		2,484		1,938		1,478
South Korea		2,639		2,296		1,919
Rest of Asia		2,620		3,157		2,623
North America		2,715		2,233		2,355
South America		1,106		681		899
Rest of world		240		191		188
		43,638		36,135		28,567
	Non-current assets by location of assets
	2018		2017		2016
	US$M		US$M		US$M
Australia		45,157		46,949		49,465
North America (1)		8,246		22,860		23,943
South America (2)		18,267		18,899		18,614
Rest of world (2)		154		173		389
Unallocated assets (3)		5,039		7,069		8,828
		76,863		95,950		101,239

⁽¹⁾  Balances for the years ended 30 June 2017 and 2016 include non-current assets relating to Onshore US assets.

⁽²⁾  Prior periods have been restated to reflect the location of equity accounted investments operations rather than the location of the holding company.

⁽³⁾  Unallocated assets comprise deferred tax assets and other financial assets.

Underlying EBITDA

Underlying EBITDA is earnings before net finance costs, depreciation, amortisation and impairments, taxation expense, Discontinued operations and any exceptional items. Underlying EBITDA includes BHP’s share of profit/(loss) from investments accounted for using the equity method including net finance costs, depreciation, amortisation and impairments and taxation expense.

F-13

Underlying EBITDA is the key alternative performance measure that management uses internally to assess the performance of the Group’s segments and make decisions on the allocation of resources and, in the Group’s view, is more relevant to capital intensive industries with long-life assets.

We exclude exceptional items from Underlying EBITDA in order to enhance the comparability of such measures from period-to-period and provide our investors with further clarity in order to assess the underlying performance of our operations. Management monitors exceptional items separately. Refer to note 2 ‘Exceptional items’ for additional detail.

Segment assets and liabilities

Total segment assets and liabilities of reportable segments represents operating assets and operating liabilities, including the carrying amount of equity accounted investments and predominantly excludes cash balances, loans to associates, interest bearing liabilities and deferred tax balances. The carrying value of investments accounted for using the equity method represents the balance of the Group’s investment in equity accounted investments, with no adjustment for any cash balances, interest bearing liabilities or deferred tax balances of the equity accounted investment.

Recognition and measurement

Revenue

Revenue is measured at the fair value of the consideration received or receivable.

Sale of products

Revenue is recognised when the risk and rewards of ownership of the goods have passed to the buyer based on agreed delivery terms and it can be measured reliably. Depending on customer terms this can be based on issuance of a bill of lading or when delivery is completed as per the agreement with the customer.

Provisionally priced sales

Revenue on provisionally priced sales is initially recognised at the estimated fair value of consideration receivable with reference to the relevant forward and/or contractual price and the determined mineral or hydrocarbon specifications. Subsequently, provisionally priced sales are marked to market at each reporting period up until when final pricing and settlement is confirmed with the fair value adjustment recognised in revenue in the period identified. Refer to note 20 ‘Financial risk management’ for details of provisionally priced sales open at reporting period-end. The period between provisional pricing and final invoicing is typically between 60 and 120 days.

F-14

2    Exceptional items

Exceptional items are those gains or losses where their nature, including the expected frequency of the events giving rise to them, and amount is considered material to the Financial Statements. Such items included within the Group’s profit from Continuing operations for the year are detailed below. Exceptional items attributable to Discontinued operations are detailed in note 26 ‘Discontinued operations’.

Year ended 30 June 2018	Gross			Tax			Net
	US$M			US$M			US$M
Exceptional items by category
Samarco dam failure		(650	)		–			(650	)
US tax reform		–			(2,320	)		(2,320	)
Total		(650	)		(2,320	)		(2,970	)
Attributable to non-controlling interests		–			–			–
Attributable to BHP shareholders		(650	)		(2,320	)		(2,970	)

Samarco Mineração S.A. (Samarco) dam failure

The FY2018 exceptional loss of US$650 million related to the Samarco dam failure in November 2015 comprises the following:

Year ended 30 June 2018	US$M
Expenses excluding net finance costs:
Costs incurred directly by BHP Billiton Brasil Ltda and other BHP entities in relation to the Samarco dam failure		(57	)
Loss from equity accounted investments, related impairments and expenses:
Share of loss relating to the Samarco dam failure		(80	)
Samarco dam failure provision		(429	)
Net finance costs		(84	)
Total (1)		(650	)

⁽¹⁾  Refer to note 3 ‘Significant events – Samarco dam failure’ for further information.

US tax reform

On 22 December 2017, the US President signed the Tax Cuts and Jobs Act (the TCJA) into law. The TCJA (effective 1 January 2018) includes a broad range of tax reforms affecting the Group, including, but not limited to, a reduction in the US corporate tax rate from 35 per cent to 21 per cent and changes to international tax provisions.

F-15

Following enactment of the TCJA, the Group has recognised an exceptional income tax charge of US$2,320 million, primarily relating to the reduced US corporate income tax rate, which resulted in re-measurement of the Group’s deferred tax position and impairment of foreign tax credits due to reduced forecast utilisation, together with tax charges on the deemed repatriation of accumulated earnings of non-US subsidiaries.

Year ended 30 June 2018	US$M
Re-measurement of deferred taxes as a result of reduced US corporate income tax rate		(1,390	)
Impairment of foreign tax credits		(834	)
Net impact of tax charges on deemed repatriation of accumulated earnings of non-US subsidiaries (1)		(194	)
Recognition of Alternative Minimum Tax Credits		95
Other impacts		3
Total (2)		(2,320	)

⁽¹⁾  Includes US$(134) million to be settled over a period greater than 12 months and classified as a non-current tax payable on the face of the balance sheet.

⁽²⁾  Refer to note 5 ‘Income tax expense’ for further information.

Year ended 30 June 2017	Gross			Tax			Net
	US$M			US$M			US$M
Exceptional items by category
Samarco dam failure		(381	)		–		(381)
Escondida industrial action		(546	)		179		(367)
Cancellation of the Caroona exploration licence		164			(49	)	115
Withholding tax on Chilean dividends		–			(373	)	(373)
Total		(763	)		(243	)	(1,006)
Attributable to non-controlling interests – Escondida industrial action		(232	)		68		(164)
Attributable to BHP shareholders		(531	)		(311	)	(842)

Samarco Mineração S.A. (Samarco) dam failure

The FY2017 exceptional loss of US$381 million related to the Samarco dam failure in November 2015 comprises the following:

Year ended 30 June 2017	US$M
Expenses excluding net finance costs:
Costs incurred directly by BHP Billiton Brasil Ltda and other BHP entities in relation to the Samarco dam failure		(82	)
Loss from equity accounted investments, related impairments and expenses:
Share of loss relating to the Samarco dam failure		(134	)
Samarco dam failure provision		(38	)
Net finance costs		(127	)
Total (1)		(381	)

⁽¹⁾  Refer to note 3 ‘Significant events – Samarco dam failure’ for further information.

F-16

Escondida industrial action

Our Escondida asset in Chile began negotiations with Union N°1 on a new collective agreement in December 2016, as the existing agreement was expiring on 31 January 2017. Negotiations, including government-led mediation, failed and the union commenced strike action on 9 February 2017 resulting in a total shutdown of operations, including work on the expansion of key projects. On 24 March 2017, following a 44-day strike and a revised offer being presented to union members, Union N°1 exercised its rights under Article 369 of the Chilean Labour Code to extend the existing collective agreement for 18 months.

Industrial action through this period resulted in a reduction to FY2017 copper production of 214 kt and gave rise to idle capacity charges of US$546 million, including depreciation of US$212 million.

Cancellation of the Caroona exploration licence

Following the Group’s agreement with the New South Wales Government in August 2016 to cancel the exploration licence of the Caroona Coal project, a net gain of US$115 million (after tax expense) has been recognised.

Withholding tax on Chilean dividends

BHP Billiton Chile Inversiones Limitada paid a one-off US$2.3 billion dividend to its parent in April 2017 while a concessional tax rate was available, resulting in withholding tax of US$373 million.

Year ended 30 June 2016	Gross			Tax			Net
	US$M			US$M			US$M
Exceptional items by category
Samarco dam failure		(2,450	)		253			(2,197	)
Global taxation matters		(70	)		(500	)		(570	)
Total		(2,520	)		(247	)		(2,767	)
Attributable to non-controlling interests		–			–			–
Attributable to BHP shareholders		(2,520	)		(247	)		(2,767	)

F-17

Samarco Mineração S.A. (Samarco) dam failure

The FY2016 exceptional loss of US$2,450 million (before tax) related to the Samarco dam failure in November 2015 comprises the following:

Year ended 30 June 2016	US$M
Expenses excluding net finance costs:
Costs incurred directly by BHP Billiton Brasil Ltda and other BHP entities in relation to the Samarco dam failure		(70	)
Loss from equity accounted investments, related impairments and expenses:
Share of loss relating to the Samarco dam failure		(655	)
Impairment of the carrying value of the investment in Samarco		(525	)
Samarco dam failure provision		(1,200	)
Total (1)		(2,450	)

⁽¹⁾  BHP Billiton Brasil Ltda has adjusted its investment in Samarco to US$ nil (resulting from US$(655) million share of loss from Samarco and US$(525) million impairment), recognised a provision of US$(1,200) million for potential obligations under the Framework Agreement and together with other BHP entities incurred US$(70) million of direct costs in relation to the Samarco dam failure. US$(572) million of the US$(1,200) million provision represents an additional share of loss from Samarco with the remaining US$(628) million recognised as provision expense. Refer to note 3 ‘Significant events – Samarco dam failure’ for further information.

Global taxation matters

Global taxation matters include amounts provided for unresolved tax matters and other claims for which the timing of resolution and potential economic outflow are uncertain.

3    Significant events – Samarco dam failure

On 5 November 2015, the Samarco Mineração S.A. (Samarco) iron ore operation in Minas Gerais, Brazil, experienced a tailings dam failure that resulted in a release of mine tailings, flooding the communities of Bento Rodrigues, Gesteira and Paracatu and impacting other communities downstream (the Samarco dam failure). Refer to section 1.8 ‘Samarco’.

Samarco is jointly owned by BHP Billiton Brasil Ltda (BHP Billiton Brasil) and Vale S.A. (Vale). BHP Billiton Brasil’s 50 per cent interest is accounted for as an equity accounted joint venture investment. BHP Billiton Brasil does not separately recognise its share of the underlying assets and liabilities of Samarco, but instead records the investment as one line on the balance sheet. Each period, BHP Billiton Brasil recognises its 50 per cent share of Samarco’s profit or loss and adjusts the carrying value of the investment in Samarco accordingly. Such adjustment continues until the investment carrying value is reduced to US$ nil, with any additional share of Samarco losses only recognised to the extent that BHP Billiton Brasil has an obligation to fund the losses, or when future investment funding is provided. After applying equity accounting, any remaining carrying value of the investment is tested for impairment.

Any charges relating to the Samarco dam failure incurred directly by BHP Billiton Brasil or other BHP entities are recognised 100 per cent in the Group’s results.

F-18

The financial impacts of the Samarco dam failure on the Group’s income statement, balance sheet and cash flow statement for the year ended 30 June 2018 are shown in the table below and have been treated as an exceptional item. The table below does not include BHP Billiton Brasil’s share of the results of Samarco prior to the Samarco dam failure, which is disclosed in note 28 ‘Investments accounted for using the equity method’, along with the summary financial information related to Samarco as at 30 June 2018.

Financial impacts of Samarco dam failure	2018			2017			2016
	US$M			US$M			US$M
Income statement
Expenses excluding net finance costs:
Costs incurred directly by BHP Billiton Brasil and other BHP entities in relation to the Samarco dam failure (1)(2)		(57	)		(82	)		(70	)
Loss from equity accounted investments, related impairments and expenses:
Share of loss relating to the Samarco dam failure (2)(3)		(80	)		(134	)		(655	)
Impairment of the carrying value of the investment in Samarco (3)		–			–			(525	)
Samarco dam failure provision (2)(3)		(429	)		(38	)		(1,200	)
Loss from operations		(566	)		(254	)		(2,450	)
Net finance costs		(84	)		(127	)		–
Loss before taxation		(650	)		(381	)		(2,450	)
Income tax benefit		–			–			253
Loss after taxation		(650	)		(381	)		(2,197	)
Balance sheet movement
Trade and other payables		4			(3	)		(11	)
Investments accounted for using the equity method		–			–			(1,180	)
Deferred tax assets		–			–			(158	)
Provisions		(228	)		143			(1,200	)
Deferred tax liabilities		–			–			411
Net (liabilities)/assets		(224	)		140			(2,138	)

F-19

			2018				2017				2016
			US$M				US$M				US$M
Cash flow statement
Loss before taxation				(650	)			(381	)			(2,450	)
Adjustments for:
Share of loss relating to the Samarco dam failure (2)(3)	80					134				655
Impairment of the carrying value of the investment in Samarco (3)	–					–				525
Samarco dam failure provision (2)(3)	429					38				1,200
Net finance costs (2)	84					127				–
Changes in assets and liabilities:
Trade and other payables	(4	)				3				11
Net operating cash flows				(61	)			(79	)			(59	)
Net investment and funding of equity accounted investments (4)				(365	)			(442	)			–
Net investing cash flows				(365	)			(442	)			–
Net decrease in cash and cash equivalents				(426	)			(521	)			(59	)

⁽¹⁾  Includes legal and advisor costs incurred.

⁽²⁾  Financial impacts of US$(650) million from the Samarco dam failure relates to US$(80) million share of loss from US$(80) million funding provided during the period, US$(57) million direct costs incurred by BHP Billiton Brasil Ltda and other BHP entities, US$(84) million amortisation of discounting impacting net finance costs, US$(560) million change in estimate and US$131 million exchange translation.

⁽³⁾  At 30 June 2016, BHP Billiton Brasil Ltda adjusted its investment in Samarco to US$ nil (resulting from US$(655) million share of loss from Samarco and US$(525) million impairment) and recognised a provision of US$(1,200) million for obligations under the Framework Agreement. US$(572) million of the US$(1,200) million provision represents an additional share of loss from Samarco with the remaining US$(628) million recognised as provision expense.

⁽⁴⁾  Includes US$(80) million funding provided during the period and US$(285) million utilisation of the Samarco dam failure provision, of which US$(281) million allowed for the continuation of reparatory and compensatory programs in relation to the Framework Agreement and a further US$(4) million for dam stabilisation and expert costs.

Equity accounted investment in Samarco

BHP Billiton Brasil’s investment in Samarco remains at US$ nil. BHP Billiton Brasil provided US$80 million funding under a working capital facility during the period and recognised additional share of losses of US$80 million. No dividends have been received by BHP Billiton Brasil from Samarco during the period. Samarco currently does not have profits available for distribution and is legally prevented from paying previously declared and unpaid dividends.

F-20

Provision for Samarco dam failure

			2018			2017
			US$M			US$M
At the beginning of the financial year				1,057			1,200
Movement in provision				228			(143	)
Comprising:
Utilised	(285	)			(308)
Adjustments charged to the income statement:
Change in estimate	560				60
Amortisation of discounting impacting net finance costs	84				127
Exchange translation	(131	)			(22)
At the end of the financial year				1,285			1,057
Comprising:
Current				313			310
Non-current				972			747
At the end of the financial year				1,285			1,057

Dam failure provisions and contingencies

As at 30 June 2018, BHP Billiton Brasil has identified provisions and contingent liabilities arising as a consequence of the Samarco dam failure as follows:

Environment and socio-economic remediation

Framework Agreement

On 2 March 2016, BHP Billiton Brasil, together with Samarco and Vale, entered into a Framework Agreement with the Federal Government of Brazil, the states of Espírito Santo and Minas Gerais and certain other public authorities to establish a foundation (Fundação Renova) that will develop and execute environmental and socio-economic programs (Programs) to remediate and provide compensation for damage caused by the Samarco dam failure. A committee (Interfederative Committee) comprising representatives from the Brazilian Federal and State Governments, local municipalities, environmental agencies, impacted communities and Public Defence Office oversees the activities of the Fundação Renova in order to monitor, guide and assess the progress of actions agreed in the Framework Agreement.

The term of the Framework Agreement is 15 years, renewable for periods of one year successively until all obligations under the Framework Agreement have been performed. Under the Framework Agreement, Samarco is responsible for funding Fundação Renova’s annual calendar year budget for the duration of the Framework Agreement. The funding amounts for each calendar year will be dependent on the remediation and compensation projects to be undertaken in a particular year. Annual contributions may be reviewed under the Framework Agreement. To the extent that Samarco does not meet its funding obligations under the Framework Agreement, each of Vale and BHP Billiton Brasil has funding obligations under the Framework Agreement in proportion to its 50 per cent shareholding in Samarco.

On 29 June 2018, BHP Billiton Brasil announced funding of US$158 million to support Fundação Renova for the six months to 31 December 2018, in the event Samarco does not meet its funding obligations under the Framework Agreement. Any support to Fundação Renova provided by BHP Billiton Brasil will be offset against the provision for the Samarco dam failure.

F-21

On 25 June 2018 a Governance Agreement (defined below) was entered into providing for the settlement of the R$20 billion (approximately US$5.2 billion) public civil claim, suspension of the R$155 billion (approximately US$40 billion) Federal Public Prosecution Office claim for 24 months, partial ratification of the Framework Agreement and a formal declaration that the Framework Agreement remains valid for the signing parties. On 8 August 2018 the 12th Federal Court of Minas Gerais ratified the Governance Agreement.

Mining and processing operations remain suspended following the dam failure. Samarco is currently progressing plans to resume operations, however significant uncertainties surrounding the nature and timing of ongoing future operations remain. In light of these uncertainties and based on currently available information, at 30 June 2018, BHP Billiton Brasil’s provision for its obligations under the Framework Agreement is US$1.3 billion before tax and after discounting (30 June 2017: US$1.1 billion).

Key judgements and estimates

The measurement of the provision requires the use of significant judgements, estimates and assumptions.

The provision reflects the estimated remaining costs to complete Programs under the Framework Agreement, of which 65 per cent are expected to be incurred by December 2020.

The provision may be affected by factors including, but not limited to:

• potential changes in scope of work and funding amounts required under the Framework Agreement including the impact of the decisions of the Interfederative Committee along with further technical analysis and community participation required under the Preliminary Agreement and Governance Agreement;

• the outcome of ongoing negotiations with State and Federal Prosecutors;

• actual costs incurred;

• resolution of uncertainty in respect of operational restart;

• updates to discount and foreign exchange rates;

• resolution of existing and potential legal claims;

• the status of the Framework Agreement and the renegotiation process established in the Governance Agreement.

Given these factors, future actual expenditures may differ from the amounts currently provided and changes to key assumptions and estimates could result in a material impact to the provision in future reporting periods.

Preliminary Agreement

On 18 January 2017, BHP Billiton Brasil, together with Samarco and Vale, entered into a Preliminary Agreement with the Federal Prosecutors’ Office in Brazil, which outlines the process and timeline for further negotiation towards a settlement regarding the R$20 billion (approximately US$5.2 billion) public civil claim and R$155 billion (approximately US$40 billion) Federal Public Prosecution Office claim relating to the dam failure.

The Preliminary Agreement provides for the appointment of experts to advise the Federal Prosecutors in relation to social and environmental remediation and the assessment and monitoring of programs under the Framework Agreement. The expert advisors’ conclusions are not binding on BHP Billiton Brasil, Samarco or Vale but will be considered in the negotiation of a final settlement arrangement with the Federal Prosecutors.

F-22

Under the Preliminary Agreement, BHP Billiton Brasil, Samarco and Vale agreed interim security (Interim Security) comprising R$1.3 billion (approximately US$335 million) in insurance bonds, R$100 million (approximately US$25 million) in liquid assets, a charge of R$800 million (approximately US$210 million) over Samarco’s assets, and R$200 million (approximately US$50 million) to be allocated within the next four years through existing Framework Agreement programs in the Municipalities of Barra Longa, Rio Doce, Santa Cruz do Escalvado and Ponte Nova.

On 24 January 2017, BHP Billiton Brasil, Samarco and Vale provided the Interim Security to the Court, which was to remain in place until the earlier of 30 June 2017 and the date that a final settlement arrangement was agreed between the Federal Prosecutors, and BHP Billiton Brasil, Vale and Samarco. Following a series of extensions, on 25 June 2018, the parties reached an agreement in the form of the Governance Agreement (summarised below).

Governance Agreement

On 25 June 2018, BHP Billiton Brasil, Samarco, Vale, the other parties to the Framework Agreement, the Public Prosecutors Office and the Public Defence Office agreed an arrangement which settles the R$20 billion (approximately US$5.2 billion) public civil claim, enhances community participation in decisions related to Programs under the Framework Agreement and establishes a process to renegotiate the Programs over two years to progress settlement of the R$155 billion (approximately US$40 billion) Federal Public Prosecution Office claim (Governance Agreement).

Renegotiation of the Programs will be based on certain agreed principles such as full reparation consistent with Brazilian law, the requirement for a technical basis for any proposed changes, consideration of findings from experts appointed by BHP Billiton Brasil, Samarco and Vale, consideration of findings from experts appointed by Prosecutors and consideration of feedback from impacted communities. During the renegotiation period and up until revisions to the Programs are agreed, the Fundação Renova will continue to implement the Programs in accordance with the terms of the Framework Agreement and the Governance Agreement.

The Governance Agreement was ratified by the 12th Federal Court of Minas Gerais on 8 August 2018 settling the R$20 billion (approximately US$5.2 billion) public civil claim and suspending the R$155 billion (approximately US$40 billion) Federal Public Prosecution Office claim for a period of two years from the date of ratification.

Interim Security provided under the Preliminary Agreement is maintained for a period of 30 months under the Governance Agreement, after which BHP Billiton Brasil, Vale and Samarco will be required to provide security of an amount equal to the Fundação Renova’s annual budget up to a limit of R$2.2 billion (approximately US$570 million).

Legal

The following matters are disclosed as contingent liabilities and given the status of proceedings it is not possible to provide a range of possible outcomes or a reliable estimate of potential future exposures for BHP, unless otherwise stated. Ultimately, all the legal matters disclosed as contingent liabilities could have a material adverse impact on BHP’s business, competitive position, cash flows, prospects, liquidity and shareholder returns.

Public civil claim

Among the claims brought against BHP Billiton Brasil was a public civil claim commenced by the Federal Government of Brazil, states of Espírito Santo, Minas Gerais and other public authorities on 30 November 2015, seeking the establishment of a fund of up to R$20 billion (approximately US$5.2 billion) in aggregate for clean-up costs and damages.

Ratification of the Governance Agreement on 8 August 2018 settled this public civil claim, including a R$1.2 billion (approximately US$310 million) injunction order.

F-23

Federal Public Prosecution Office claim

BHP Billiton Brasil is among the defendants named in a claim brought by the Federal Public Prosecution Office on 3 May 2016, seeking R$155 billion (approximately US$40 billion) for reparation, compensation and moral damages in relation to the Samarco dam failure.

The 12th Federal Court previously suspended the Federal Public Prosecution Office claim, including a R$7.7 billion (approximately US$2 billion) injunction request. Suspension of the claim continues for a period of two years from the date of ratification of the Governance Agreement on 8 August 2018.

United States class action complaint

In February 2016, a putative class action complaint (Complaint) was filed in the U.S. District Court for the Southern District of New York on behalf of purchasers of American Depositary Receipts (Plaintiffs) of BHP Billiton Limited and BHP Billiton Plc (Defendants) between 25 September 2014 and 30 November 2015 against BHP Billiton Limited and BHP Billiton Plc and certain of its current and former executive officers and directors.

Claims against current and former executive officers were subsequently dismissed. On 6 August 2018 the parties reached an in-principle settlement agreement of US$50 million to resolve all claims with no admission of liability by the Defendants. The agreement is subject to Court Approval. BHP expects to recover the majority of the settlement payment under its external insurance arrangements (refer BHP Insurance below).

United States class action complaint – Samarco bond holders

On 14 November 2016, a putative class action complaint (Complaint) was filed in the U.S. District Court for the Southern District of New York on behalf of all purchasers of Samarco’s ten-year bond notes (Plaintiff) due 2022-2024 between 31 October 2012 and 30 November 2015 against Samarco and the former chief executive officer of Samarco (Defendants).

The Complaint was subsequently amended to include BHP Billiton Limited, BHP Billiton Plc, BHP Billiton Brasil Ltda, Vale S.A. and officers of Samarco, including four of Vale S.A. and BHP Billiton Brasil Ltda’s nominees to the Samarco Board (Defendants). On 5 April 2017, the Plaintiff dismissed the claims against the individuals. The remaining corporate defendants filed a joint motion to dismiss the Plaintiff’s Complaint on 26 June 2017.

On 7 March 2018, the District Court granted the Defendants’ motion to dismiss the Complaint, however, the District Court granted the Plaintiff leave to file a second amended Complaint, which it did on 21 March 2018. On 21 May 2018, the Defendants moved to dismiss the Complaint. The Defendants’ motion is pending before the District Court. The amount of damages sought by the Plaintiff on behalf of the putative class is unspecified.

Australian class action complaint

On 31 May 2018, a shareholder class action was filed in the Federal Court of Australia against BHP Billiton Ltd on behalf of persons who, during the period from 21 October 2013 to 9 November 2015, acquired BHP Billiton Ltd shares on the Australian Securities Exchange or BHP Billiton Plc shares on the London Stock Exchange or Johannesburg Stock Exchange.

On 31 August 2018, an additional shareholder class action that makes similar allegations was filed in the Federal Court of Australia against BHP Billiton Ltd on behalf of persons who, during the period from 27 August 2014 to 9 November 2015, entered into a contract to acquire BHP Billiton Ltd shares on the Australian Securities Exchange or BHP Billiton Plc shares on the London Stock Exchange or Johannesburg Stock Exchange.

Orders have been made for the Court to consider how to manage the competing shareholder class actions on 29 October 2018.

F-24

The amount of damages sought in both class actions is unspecified.

Criminal charges

The Federal Prosecutors’ Office has filed criminal charges against BHP Billiton Brasil, Samarco and Vale and certain employees and former employees of BHP Billiton Brasil (Affected Individuals) in the Federal Court of Ponte Nova, Minas Gerais. On 3 March 2017, BHP Billiton Brasil filed its preliminary defences. BHP Billiton Brasil rejects outright the charges against the company and the Affected Individuals and will defend the charges and fully support each of the Affected Individuals in their defence of the charges.

Other claims

The civil public actions filed by State Prosecutors in Minas Gerais (claiming damages of approximately R$7.5 billion, US$2 billion), State Prosecutors in Espírito Santo (claiming damages of approximately R$2 billion, US$520 million), and public defenders in Minas Gerais (claiming damages of approximately R$10 billion, US$2.6 billion), have been consolidated before the 12th Federal Court and suspended. The Governance Agreement provides for a process to review whether these civil public claims should be terminated or suspended.

BHP Billiton Brasil is among the companies named as defendants in a number of legal proceedings initiated by individuals, non-governmental organisations (NGOs), corporations and governmental entities in Brazilian Federal and State courts following the Samarco dam failure. The other defendants include Vale, Samarco and Fundação Renova. The lawsuits include claims for compensation, environmental rehabilitation and violations of Brazilian environmental and other laws, among other matters. The lawsuits seek various remedies including rehabilitation costs, compensation to injured individuals and families of the deceased, recovery of personal and property losses, moral damages and injunctive relief. In addition, government inquiries and investigations relating to the Samarco dam failure have been commenced by numerous agencies of the Brazilian government and are ongoing.

Additional lawsuits and government investigations relating to the Samarco dam failure could be brought against BHP Billiton Brasil and possibly other BHP entities in Brazil or other jurisdictions.

BHP insurance

BHP has various third party liability insurances for claims related to the Samarco dam failure made directly against BHP Billiton Brasil or other BHP entities, their directors and officers, including class actions. External insurers have been advised of the Samarco dam failure, the third party claims and the class actions referred to above and formal claims have been prepared and submitted. As noted above, BHP expects to recover the majority of the settlement payment relating to the United States class action complaint under its external insurance arrangements.

At 30 June 2018, an insurance receivable has not been recognised for any potential recoveries in respect of ongoing matters.

Commitments

Under the terms of the Samarco joint venture agreement, BHP Billiton Brasil does not have an existing obligation to fund Samarco. For the year ended 30 June 2018, BHP Billiton Brasil has provided US$80 million funding to support Samarco’s operations and a further US$4 million for dam stabilisation and prosecutor experts costs, with undrawn amounts of US$16 million expiring as at 30 June 2018. On 29 June 2018, BHP Billiton Brasil made available a new short-term facility of up to US$53 million to carry out remediation and stabilisation work and support Samarco’s operations. Funds will be released to Samarco only as required and subject to the achievement of key milestones with amounts undrawn expiring at 31 December 2018.

Any additional requests for funding or future investment provided would be subject to a future decision, accounted for at that time.

F-25

The following section includes disclosure required by IFRS of Samarco Mineração S.A.’s provisions, contingencies and other matters arising from the dam failure.

Samarco

Dam failure related provisions and contingencies

As at 30 June 2018, Samarco has identified provisions and contingent liabilities arising as a consequence of the Samarco dam failure as follows:

Environment and socio-economic remediation

Framework Agreement

On 2 March 2016, Samarco, together with Vale and BHP Billiton Brasil, entered into a Framework Agreement with the Federal Government of Brazil, the states of Espírito Santo and Minas Gerais and certain other public authorities to establish a foundation (Fundação Renova) that will develop and execute environmental and socio-economic programs (Programs) to remediate and provide compensation for damage caused by the Samarco dam failure. A committee (Interfederative Committee) comprising representatives of the Brazilian Federal and State Governments, local municipalities, environmental agencies, impacted communities and Public Defence Office oversees the activities of the Fundação Renova in order to monitor, guide and assess the progress of actions agreed in the Framework Agreement.

The term of the Framework Agreement is 15 years, renewable for periods of one year successively until all obligations under the Framework Agreement have been performed. Under the Framework Agreement, Samarco is responsible for funding Fundação Renova’s annual calendar year budget for the duration of the Framework Agreement. The funding amounts for each calendar year will be dependent on the remediation and compensation projects to be undertaken in a particular year. Annual contributions may be reviewed under the Framework Agreement. It is expected that approximately 65 per cent of the remaining estimated total costs to complete Programs under the Framework Agreement will be incurred by December 2020.

On 25 June 2018 a Governance Agreement (defined below), was entered into providing for the settlement of the R$20 billion (approximately US$5.2 billion) public civil claim, suspension of the R$155 billion (approximately US$40 billion) Federal Public Prosecution Office claim for 24 months, partial ratification of the Framework Agreement and a formal declaration that the Framework Agreement remains valid for the signing parties. On 8 August 2018 the 12th Federal Court of Minas Gerais ratified the Governance Agreement.

As at 30 June 2018, Samarco has a provision of US$2.6 billion before tax and after discounting (30 June 2017: US$2.1 billion), in relation to its obligations under the Framework Agreement based on currently available information.

The measurement of the provision requires the use of significant judgements, estimates and assumptions which may be affected by factors including, but not limited to:

• potential changes in scope of work and funding amounts required under the Framework Agreement including the impact of the decisions of the Interfederative Committee along with further technical analysis and community participation required under the Preliminary Agreement and Governance Agreement;

• the outcome of ongoing negotiations with State and Federal Prosecutors;

• actual costs incurred;

• updates to discount and foreign exchange rates;

• resolution of existing and potential legal claims;

• the status of the Framework Agreement and the renegotiation process established in the Governance Agreement.

F-26

Given these factors, future actual expenditures may differ from the amounts currently provided and changes to key assumptions and estimates could result in a material impact to the provision in future reporting periods.

Preliminary Agreement

On 18 January 2017, Samarco, together with Vale and BHP Billiton Brasil, entered into a Preliminary Agreement with the Federal Prosecutors’ Office in Brazil, which outlines the process and timeline for further negotiation towards a settlement regarding the R$20 billion (approximately US$5.2 billion) public civil claim and R$155 billion (approximately US$40 billion) Federal Public Prosecution Office claim relating to the dam failure.

The Preliminary Agreement provides for the appointment of experts to advise the Federal Prosecutors in relation to social and environmental remediation and the assessment and monitoring of programs under the Framework Agreement. The expert advisors’ conclusions are not binding on Samarco, Vale or BHP Billiton Brasil but will be considered in the negotiation of a final settlement arrangement with the Federal Prosecutors.

Under the Preliminary Agreement, Samarco, Vale and BHP Billiton Brasil agreed interim security (Interim Security) comprising R$1.3 billion (approximately US$335 million) in insurance bonds, R$100 million (approximately US$25 million) in liquid assets, a charge of R$800 million (approximately US$210 million) over Samarco’s assets, and R$200 million (approximately US$50 million) to be allocated within the next four years through existing Framework Agreement programs in the Municipalities of Barra Longa, Rio Doce, Santa Cruz do Escalvado and Ponte Nova.

On 24 January 2017, Samarco, Vale and BHP Billiton Brasil provided the Interim Security to the Court which was to remain in place until the earlier of 30 June 2017 and the date that a final settlement arrangement was agreed between the Federal Prosecutors, and Samarco, Vale and BHP Billiton Brasil. Following a series of extensions, on 25 June 2018, the parties reached an agreement in the form of the Governance Agreement (summarised below).

Governance Agreement

On 25 June 2018 Samarco, Vale, BHP Billiton Brasil, the other parties to the Framework Agreement, the Public Prosecutors Office and the Public Defence Office agreed an arrangement which settles the R$20 billion (approximately US$5.2 billion) public civil claim, enhances community participation in decisions related to Programs under the Framework Agreement and establishes a process to renegotiate the Programs over two years to progress settlement of the R$155 billion (approximately US$40 billion) Federal Public Prosecution Office claim (Governance Agreement).

Renegotiation of the Programs will be based on certain agreed principles such as full reparation consistent with Brazilian law, the requirement for a technical basis for any proposed changes, consideration of findings from experts appointed by Samarco, Vale and BHP Billiton Brasil, consideration of findings from experts appointed by Prosecutors and consideration of feedback from impacted communities. During the renegotiation period and up until revisions to the Programs are agreed, the Fundação Renova will continue to implement the Programs in accordance with the terms of the Framework Agreement and the Governance Agreement.

The Governance Agreement was ratified by the 12th Federal Court of Minas Gerais on 8 August 2018 settling the R$20 billion (approximately US$5.2 billion) public civil claim and suspending the R$155 billion (approximately US$40 billion) Federal Public Prosecution Office claim for a period of two years from the date of ratification.

F-27

Interim Security provided under the Preliminary Agreement is maintained for a period of 30 months under the Governance Agreement, after which Samarco, Vale and BHP Billiton Brasil will be required to provide security of an amount equal to the Fundação Renova’s annual budget up to a limit of R$2.2 billion (approximately US$570 million).

Other

As at 30 June 2018, Samarco has recognised provisions of US$0.2 billion (30 June 2017: US$0.3 billion), in addition to its obligations under the Framework Agreement, based on currently available information. The magnitude, scope and timing of these additional costs are subject to a high degree of uncertainty and Samarco has indicated that it anticipates that it will incur future costs beyond those provided. These uncertainties are likely to continue for a significant period and changes to key assumptions could result in a material change to the amount of the provision in future reporting periods. Any such unrecognised obligations are therefore contingent liabilities and, at present, it is not practicable to estimate their magnitude or possible timing of payment. Accordingly, it is also not possible to provide a range of possible outcomes or a reliable estimate of total potential future exposures at this time.

Legal

The following matters are disclosed as contingent liabilities and given the status of proceedings it is not possible to provide a range of possible outcomes or a reliable estimate of potential future exposures for Samarco, unless otherwise stated. Ultimately, all the legal matters disclosed as contingent liabilities could have a material adverse impact on Samarco’s business, competitive position, cash flows, prospects, liquidity and shareholder returns.

Public civil claim

Among the claims brought against Samarco, was a public civil claim commenced by the Federal Government of Brazil, states of Espírito Santo, Minas Gerais and other public authorities on 30 November 2015, seeking the establishment of a fund of up to R$20 billion (approximately US$5.2 billion) in aggregate for clean-up costs and damages.

Ratification of the Governance Agreement on 8 August 2018 settled this public civil claim, including a R$1.2 billion (approximately US$310 million) injunction order.

Federal Public Prosecution Office claim

Samarco is among the defendants named in a claim brought by the Federal Public Prosecution Office on 3 May 2016, seeking R$155 billion (approximately US$40 billion) for reparation, compensation and moral damages in relation to the Samarco dam failure.

The 12th Federal Court previously suspended the Federal Public Prosecution Office claim, including a R$7.7 billion (approximately US$2 billion) injunction request. Suspension of the claim continues for a period of two years from the date of ratification of the Governance Agreement on 8 August 2018.

United Stated class action complaint – Samarco bond holders

On 14 November 2016, a putative class action complaint (Complaint) was filed in the U.S. District Court for the Southern District of New York on behalf of all purchasers of Samarco’s ten-year bond notes (Plaintiff) due 2022–2024 between 31 October 2012 and 30 November 2015 against Samarco and the former chief executive officer of Samarco (Defendants).

F-28

The Complaint was subsequently amended to include BHP Billiton Limited, BHP Billiton Plc, BHP Billiton Brasil Ltda and Vale S.A. and officers of Samarco, including four of Vale S.A. and BHP Billiton Brasil Ltda’s nominees to the Samarco Board (Defendants). On 5 April 2017, the Plaintiff dismissed the claims against the individuals. The remaining corporate defendants filed a joint motion to dismiss the Plaintiff’s Complaint on 26 June 2017.

On 7 March 2018, the District Court granted the Defendants’ motion to dismiss the Complaint, however, the District Court granted the Plaintiff leave to file a second amended Complaint, which it did on 21 March 2018. On 21 May 2018, the Defendants moved to dismiss the Complaint. The Defendants’ motion is pending before the District Court.

Criminal charges

The Federal Prosecutors’ Office has filed criminal charges against Samarco, Vale and BHP Billiton Brasil and certain employees and former employees of Samarco (Affected Individuals) in the Federal Court of Ponte Nova, Minas Gerais. On 2 March 2017, Samarco filed its preliminary defences. Samarco rejects outright the charges against the company and the Affected Individuals and will defend the charges.

Other claims

The civil public actions filed by State Prosecutors in Minas Gerais (claiming damages of approximately R$7.5 billion, US$2 billion), State Prosecutors in Espírito Santo (claiming damages of approximately R$2 billion, US$520 million), and public defenders in Minas Gerais (claiming damages of approximately R$10 billion, US$2.6 billion), have been consolidated before the 12th Federal Court and suspended. The Governance Agreement provides for a process to review whether these civil public claims should be terminated or suspended.

Samarco is among the companies named as defendants in a number of legal proceedings initiated by individuals, non-governmental organisations (NGOs), corporations and governmental entities in Brazilian Federal and State courts following the Samarco dam failure. The lawsuits include claims for compensation, environmental rehabilitation and violations of Brazilian environmental and other laws, among other matters. The lawsuits seek various remedies including rehabilitation costs, compensation to injured individuals and families of the deceased, recovery of personal and property losses, moral damages and injunctive relief. In addition, government inquiries and investigations relating to the Samarco dam failure have been commenced by numerous agencies of the Brazilian government and are ongoing.

Additional lawsuits and government investigations relating to the Samarco dam failure could be brought against Samarco.

Samarco insurance

Samarco has standalone insurance policies in place with Brazilian and global insurers. Samarco has notified insurers, including those covering Samarco’s property, project and liability risks. Insurers’ loss adjusters or claims representatives continue to investigate and assist with the claims process. An insurance receivable has not been recognised by Samarco for any recoveries under insurance arrangements at 30 June 2018.

Samarco commitments

At 30 June 2018, Samarco has commitments of US$1.1 billion (30 June 2017: US$1.5 billion). Following the dam failure Samarco invoked force majeure clauses in a number of long-term contracts with suppliers and service providers to suspend contractual obligations.

F-29

Samarco non-dam failure related contingent liabilities

The following non-dam failure related contingent liabilities pre-date and are unrelated to the Samarco dam failure. Samarco is currently contesting both of these matters in the Brazilian courts. Given the status of these tax matters, the timing of resolution and potential economic outflow for Samarco is uncertain.

Brazilian Social Contribution Levy

Samarco has received tax assessments for the alleged non-payment of Brazilian Social Contribution Levy for the calendar years 2007–2014 totalling approximately R$5.4 billion (approximately US$1.4 billion).

Brazilian corporate income tax rate

Samarco has received tax assessments for alleged incorrect calculation of Corporate Income Tax (IRPJ) in respect of the 2000–2003 and 2007–2014 income years totalling approximately R$4.2  billion (approximately US$1.1 billion).

4    Expenses and other income

	2018			2017			2016
	US$M			US$M			US$M
Employee benefits expense:
Wages, salaries and redundancies		3,653			3,392			3,324
Employee share awards		123			105			140
Social security costs		4			3			2
Pension and other post-retirement obligations		292			273			221
Less employee benefits expense classified as exploration and evaluation expenditure		(82	)		(79	)		(82	)
Changes in inventories of finished goods and work in progress		(142	)		(743	)		287
Raw materials and consumables used		4,389			3,830			3,985
Freight and transportation		2,294			1,786			1,648
External services		5,217			4,341			4,370
Third party commodity purchases		1,452			1,151			994
Net foreign exchange (gains)/losses		(93	)		103			(153	)
Government royalties paid and payable		2,168			1,986			1,349
Exploration and evaluation expenditure incurred and expensed in the current period		641			610			419
Depreciation and amortisation expense		6,288			6,184			6,210
Net impairments:
Property, plant and equipment		318			160			170
Goodwill and other intangible assets		14			33			16
Available for sale financial assets		1			–			–
Operating lease rentals		421			391			372
All other operating expenses		1,078			989			819
Total expenses		28,036			24,515			24,091
Losses/(Gains) on disposal of property, plant and equipment		10			(286	)		20
Other income		(257	)		(376	)		(452	)
Total other income		(247	)		(662	)		(432	)

F-30

Other income is generally income earned from transactions outside the course of the Group’s ordinary activities and may include certain management fees from non-controlling interests and joint venture arrangements, dividend income, royalties, commission income and gains or losses on divestment of subsidiaries or operations.

Recognition and measurement

Income is recognised when it is probable that the economic benefits associated with a transaction will flow to the Group and they can be reliably measured. Dividends are recognised upon declaration.

5    Income tax expense

	2018			2017			2016
	US$M			US$M			US$M
Total taxation expense comprises:
Current tax expense		5,052			4,412			2,621
Deferred tax expense/(benefit)		1,955			31			(518	)
		7,007			4,443			2,103
	2018			2017			2016
	US$M			US$M			US$M
Factors affecting income tax expense for the year
Income tax expense differs to the standard rate of corporation tax as follows:
Profit before taxation		14,751			11,137			1,791
Tax on profit at Australian prima facie tax rate of 30 per cent		4,425			3,341			537
Impact of US tax reform
Tax on remitted and unremitted foreign earnings (1)		194			–			–
Non-tax effected operating losses and capital gains		834			–			–
Tax rate changes		1,390			–			–
Recognition of previously unrecognised tax assets		(95	)		–			–
Other		(3	)		–			–
Subtotal		2,320			–			–
Other items not related to US tax reform
Tax on remitted and unremitted foreign earnings		401			478			(376	)
Non-tax effected operating losses and capital gains		721			242			457
Tax rate changes		(79	)		25			14
Amounts (over)/under provided in prior years		(51	)		175			(4	)
Foreign exchange adjustments		(152	)		88			125
Investment and development allowance		(180	)		(53	)		(36	)
Tax effect of profit/(loss) from equity accounted investments, related impairments and expenses (2)		(44	)		(82	)		631
Recognition of previously unrecognised tax assets		(170	)		(21	)		(36	)
Impact of tax rates applicable outside of Australia		(484	)		(136	)		5
Other		172			219			541
Income tax expense		6,879			4,276			1,858
Royalty-related taxation (net of income tax benefit)		128			167			245
Total taxation expense		7,007			4,443			2,103

F-31

⁽¹⁾ Comprising US$797 million repatriation tax and US$603 million of previously unrecognised tax credits.

⁽²⁾ The profit/(loss) from equity accounted investments, related impairments and expenses is net of income tax. This item removes the prima facie tax effect on such profits, related impairments and expenses.

Income tax recognised in other comprehensive income is as follows:

	2018			2017			2016
	US$M			US$M			US$M
Income tax effect of:
Items that may be reclassified subsequently to the income statement:
Available for sale investments:
Net valuation gains/(losses) taken to equity		(3	)		–			(1	)
Cash flow hedges:
Gains/(losses) taken to equity		(25	)		(105	)		170
(Gains)/losses transferred to the income statement		64			129			(199	)
Income tax credit/(charge) relating to items that may be reclassified subsequently to the income statement		36			24			(30	)
Items that will not be reclassified to the income statement:
Remeasurement gains/(losses) on pension and medical schemes		(22	)		(12	)		5
Employee share awards transferred to retained earnings on exercise		8			(14	)		(22	)
Income tax charge relating to items that will not be reclassified to the income statement		(14	)		(26	)		(17	)
Total income tax credit/(charge) relating to components of other comprehensive income (1)		22			(2	)		(47	)

⁽¹⁾  Included within total income tax relating to components of other comprehensive income is US$17 million relating to deferred taxes and US$5 million relating to current taxes (2017: US$12 million and US$(14) million; 2016: US$(25) million and US$(22) million).

F-32

Recognition and measurement

Taxation on the profit/(loss) for the year comprises current and deferred tax. Taxation is recognised in the income statement except to the extent that it relates to items recognised directly in equity, in which case the tax effect is also recognised in equity.

Current tax	Deferred tax	Royalty-related taxation
Current tax is the expected tax on the taxable income for the year, using tax rates and laws enacted or substantively enacted at the reporting date, and any adjustments to tax payable in respect of previous years.	Deferred tax is provided in full, on temporary differences arising between the tax bases of assets and liabilities and their carrying amounts in the Financial Statements. Deferred tax assets are recognised to the extent that it is probable that future taxable profits will be available against which the temporary differences can be utilised. Deferred tax is not recognised for temporary differences relating to: •   initial recognition of goodwill; •   initial recognition of assets or liabilities in a transaction that is not a business combination and that affects neither accounting nor taxable profit; •   investment in subsidiaries, associates and jointly controlled entities where the Group is able to control the timing of the reversal of the temporary difference and it is probable that they will not reverse in the foreseeable future. Deferred tax is measured at the tax rates that are expected to be applied when the asset is realised or the liability is settled, based on the laws that have been enacted or substantively enacted at the reporting date. Current and deferred tax assets and liabilities are offset when the Group has a legally enforceable right to offset and when the tax balances are related to taxes levied by the same tax authority and the Group intends to settle on a net basis, or realise the asset and settle the liability simultaneously.	Royalties and resource rent taxes are treated as taxation arrangements (impacting income tax expense/(benefit)) when they are imposed under government authority and the amount payable is calculated by reference to revenue derived (net of any allowable deductions) after adjustment for temporary differences. Obligations arising from royalty arrangements that do not satisfy these criteria are recognised as current provisions and included in expenses.

F-33

Uncertain tax and royalty matters

The Group operates across many tax jurisdictions. Application of tax law can be complex and requires judgement to assess risk and estimate outcomes, particularly in relation to the Group’s cross-border operations and transactions. The evaluation of tax risks considers both amended assessments received and potential sources of challenge from tax authorities. The status of proceedings for these matters will impact the ability to determine the potential exposure and in some cases, it may not be possible to determine a range of possible outcomes or a reliable estimate of the potential exposure.

The Group has unresolved tax and royalty matters for which the timing of resolution and potential economic outflow are uncertain. Tax and royalty matters with uncertain outcomes arise in the normal course of business and occur due to changes in tax law, changes in interpretation of tax law, periodic challenges and disagreements with tax authorities and legal proceedings.

Tax and royalty obligations assessed as having probable future economic outflows capable of reliable measurement are provided for at 30 June 2018. Matters with a possible economic outflow and/or presently incapable of being measured reliably are contingent liabilities and disclosed in note 32 ‘Contingent liabilities’. Irrespective of whether the potential economic outflow of the matter has been assessed as probable or possible, individually significant matters are included below, to the extent that disclosure does not prejudice the Group.

Transfer pricing – Sales of commodities to BHP Billiton Marketing AG in Singapore

The Group is currently in dispute with the Australian Taxation Office (ATO) regarding the price at which the Group’s Australian entities sell commodities to the Group’s principal marketing entity in Singapore, BHP Billiton Marketing AG. In April 2014, the Group received amended assessments for 2003–2008 totalling US$267 million (A$362 million) (inclusive of interest and penalties). In May 2016, the Group received further amended assessments totalling US$396 million (A$537 million) (inclusive of interest and penalties) for 2009–2013. The ATO is currently auditing the 2014–2016 income years. The Group has formally objected to the amended assessments. The ATO has yet to advise its decision on the objections to these amended assessments. The Group has made payments of approximately US$221 million (A$276 million) to the ATO in relation to the assessments under dispute pending resolution of the matter. As a consequence of the completion of the transfer pricing audit for 2009–2013, in June 2016, the Group also received an amended assessment in relation to its 2013 MRRT return totalling US$105 million (A$143 million) (inclusive of interest and penalties). The Group has formally objected to the amended assessment and has made a partial payment of US$39 million (A$52 million) in respect of the MRRT amended assessment.

Controlled Foreign Companies dispute

The Group is currently in dispute with the ATO regarding whether profits earned globally by the Group’s marketing organisation from the on-sale of commodities acquired from Australian subsidiaries of BHP Billiton Plc are subject to ‘top-up tax’ in Australia under the Controlled Foreign Companies rules. In June 2011 and December 2014, the Group received amended assessments relating to the 2006–2010 income years. The Group has objected to these amended assessments. On 30 June 2016, the Group received the ATO’s decision relating to the Group’s objection against these amended assessments. The objections were allowed in part by the ATO. The ATO also determined that the Group was not liable for any penalties. The dispute concerning the disallowed objections was heard before the full Federal Court in May 2018 and we are awaiting judgement. It is estimated the primary tax subject to dispute for the 2006–2010 income years will total US$32 million (A$43 million).

F-34

	Between May 2016 and May 2017, the Group received amended assessments for primary tax of US$29 million (A$39 million) relating to the 2012–2015 income years. The Group has formally objected to the amended assessments.
Samarco tax assessments	Details of uncertain tax and royalty matters relating to Samarco are disclosed in note 3 ‘Significant events – Samarco dam failure’.

Key judgements and estimates

Income tax classification

The Group’s accounting policy for taxation, including royalty-related taxation, requires management’s judgement as to the types of arrangements considered to be a tax on income in contrast to an operating cost.

Deferred tax

Judgement is required to determine the amount of deferred tax assets that are recognised based on the likely timing and the level of future taxable profits. The Group assesses the recoverability of recognised and unrecognised deferred taxes, including losses in Australia, the United States and Canada on a consistent basis, using assumptions and projected cash flows as applied in the Group impairment process for associated operations.

Deferred tax liabilities arising from temporary differences in investments, caused principally by retained earnings held in foreign tax jurisdictions, are recognised unless repatriation of retained earnings can be controlled and is not expected to occur in the foreseeable future.

Uncertain tax matters

Judgements are required about the application of income tax legislation and its interaction with income tax accounting principles. These judgements are subject to risk and uncertainty, hence there is a possibility that changes in circumstances will alter expectations, which may impact the amount of deferred tax assets and deferred tax liabilities recognised on the balance sheet and the amount of other tax losses and temporary differences not yet recognised.

Where the final tax outcomes are different from the amounts that were initially recorded, these differences impact the current and deferred tax provisions in the period in which the determination is made.

Measurement of uncertain tax and royalty matters considers a range of possible outcomes, including assessments received from tax authorities. Where management is of the view that potential liabilities have a low probability of crystallising, or it is not possible to quantify them reliably, they are disclosed as contingent liabilities (refer to note 32 ‘Contingent liabilities’).

US tax reform

As per note 2 ‘Exceptional items’, the impact of the TCJA has been included in the Financial Statements. The TCJA includes a number of complex provisions, the application of which are potentially subject to further implementation and regulatory guidance, and possible elections. Judgements are required about the application of the TCJA and its interaction with income tax accounting principles.

The Group has made preliminary determinations, based on currently available implementation guidance. However, judgements made are subject to risk and uncertainty, hence there is a possibility that changes in circumstances or future regulatory guidance may alter the judgements made, which may potentially impact the amount of deferred or current taxes recognised on the balance sheet and the amount of other tax balances not yet recognised.

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The significant judgements and estimates include:

• The TCJA requires mandatory deemed repatriation of post-1986 undistributed earnings and profits from specific non-US subsidiaries. In assessing the potential tax charge, the Group has made certain assumptions as to offsets available under the TCJA, including the use of available foreign tax credits to partially offset the deemed repatriation tax liability.

• The US will continue to tax foreign income from partnerships on a worldwide basis with the ability to offset US tax liabilities on foreign earnings with a credit for taxes paid in foreign jurisdictions. The reduction in the US corporate tax rate and the revised differential in tax rates with other jurisdictions impacts the forecasted utilisation of these foreign tax credits. The Group has made certain assumptions as to the utilisation of available foreign tax credits based on an assessment of probable future US income tax.

Where further clarifying regulatory guidance is issued, this may potentially impact the assumptions made and result in a different outcome.

6    Earnings per share

	2018		2017		2016
Earnings/(loss) attributable to BHP shareholders (US$M)
- Continuing operations		6,652		6,375		(539	)
- Total		3,705		5,890		(6,385	)
Weighted average number of shares (Million)
- Basic		5,323		5,323		5,322
- Diluted		5,337		5,336		5,322
Basic earnings/(loss) per ordinary share (US cents)
- Continuing operations		125.0		119.8		(10.2	)
- Total		69.6		110.7		(120.0	)
Diluted earnings/(loss) per ordinary share (US cents)
- Continuing operations		124.6		119.5		(10.2	)
- Total		69.4		110.4		(120.0	)

Refer to note 26 ‘Discontinued operations’ for basic earnings per share and diluted earnings per share for Discontinued operations.

Earnings on American Depositary Shares represent twice the earnings for BHP Billiton Limited or BHP Billiton Plc ordinary shares.

Recognition and measurement

Diluted earnings attributable to BHP shareholders are equal to the earnings attributable to BHP shareholders.

The calculation of the number of ordinary shares used in the computation of basic earnings per share is the aggregate of the weighted average number of ordinary shares of BHP Billiton Limited and BHP Billiton Plc outstanding during the period after deduction of the number of shares held by the Billiton Employee Share Ownership Plan Trust and the BHP Billiton Limited Employee Equity Trust.

For the purposes of calculating diluted earnings per share, the effect of 14 million dilutive shares has been taken into account for the year ended 30 June 2018 (2017: 13 million shares; 2016: nil). The Group’s only potential dilutive ordinary shares are share awards granted under the employee share ownership plans for which terms and conditions are described in note 22 ‘Employee share ownership plans’. Diluted earnings per share calculation excludes instruments which are considered antidilutive.

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The conversion of options and share rights would decrease the loss per share for the year ended 30 June 2016 and therefore its impact has been excluded from the diluted earnings per share calculation.

At 30 June 2018, there are no instruments which are considered antidilutive (2017: nil).

Working capital

7    Trade and other receivables

	2018		2017
	US$M		US$M
Trade receivables		1,857		1,855
Loans to equity accounted investments		13		644
Other receivables		1,406		1,140
Total		3,276		3,639
Comprising:
Current		3,096		2,836
Non-current		180		803

Recognition and measurement

Trade receivables are recognised initially at fair value and subsequently at amortised cost using the effective interest method, less an allowance for impairment.

The collectability of trade receivables is assessed continuously. At the reporting date, specific allowances are made for any doubtful receivables based on a review of all outstanding amounts at reporting period-end. Individual receivables are written off when management deems them unrecoverable. The net carrying amount of trade and other receivables approximates their fair values.

Credit risk

Trade receivables generally have terms of less than 30 days. The Group has no material concentration of credit risk with any single counterparty and is not dominantly exposed to any individual industry.

Credit risk can arise from the non-performance by counterparties of their contractual financial obligations towards the Group. To manage credit risk, the Group maintains Group-wide procedures covering the application for credit approvals, granting and renewal of counterparty limits, proactive monitoring of exposures against these limits and requirements triggering secured payment terms. As part of these processes, the credit exposures with all counterparties are regularly monitored and assessed on a timely basis. The credit quality of the Group’s customers is reviewed and the solvency of each debtor and their ability to pay on the receivable is considered in assessing receivables for impairment.

Receivables are deemed to be past due or impaired in accordance with the Group’s terms and conditions. These terms and conditions are determined on a case-by-case basis with reference to the customer’s credit quality, payment performance and prevailing market conditions. At 30 June 2018, trade receivables are stated net of provisions for doubtful debts of US$1 million (2017: US$ nil). As of 30 June 2018, trade receivables of US$32 million (2017: US$19 million) were past due but not impaired. The majority of these receivables were less than 30 days overdue. As at the reporting date, there are no indications that the debtors will not meet their payment obligations.

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8    Trade and other payables

	2018		2017
	US$M		US$M
Trade creditors		4,574		3,996
Other creditors		1,406		1,560
Total		5,980		5,556
Comprising:
Current		5,977		5,551
Non-current		3		5

9    Inventories

	2018		2017		Definitions
	US$M		US$M
Raw materials and consumables		1,266		1,241	Spares, consumables and other supplies yet to be utilised in the production process or in the rendering of services.
Work in progress		2,965		2,852	Commodities currently in the production process that require further processing by the Group to a saleable form.
Finished goods		674		675	Commodities held-for-sale and not requiring further processing by the Group.
Total (1)		4,905		4,768
Comprising:
Current		3,764		3,673
Non-current		1,141		1,095	Inventories classified as non-current are not expected to be utilised or sold within 12 months after the reporting date.

⁽¹⁾  Inventory write-downs of US$18 million were recognised during the year (2017: US$112 million; 2016: US$118 million). Inventory write-downs of US$2 million made in previous periods were reversed during the year (2017: US$19 million; 2016: US$118 million).

Recognition and measurement

Regardless of the type of inventory and its stage in the production process, inventories are valued at the lower of cost and net realisable value. Cost is determined primarily on the basis of average costs. For processed inventories, cost is derived on an absorption costing basis. Cost comprises costs of purchasing raw materials and costs of production, including attributable mining and manufacturing overheads taking into consideration normal operating capacity.

Minerals inventory quantities are assessed primarily through surveys and assays, while petroleum inventory quantities are derived through flow rate or tank volume measurement and the composition is derived via sample analysis.

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Key judgements and estimates

Accounting for inventory involves the use of judgements and estimates, particularly related to the measurement and valuation of inventory on hand within the production process. Certain estimates, including expected metal recoveries and work in progress volumes, are calculated by engineers using available industry, engineering and scientific data. Estimates used are periodically reassessed by the Group taking into account technical analysis and historical performance. Changes in estimates are adjusted for on a prospective basis.

Resource assets

10    Property, plant and equipment

	Land and buildings			Plant and equipment			Other mineral assets			Assets under construction			Exploration and evaluation			Total
	US$M			US$M			US$M			US$M			US$M			US$M
Net book value – 30 June 2018
At the beginning of the financial year		8,547			49,427			15,557			5,536			1,430			80,497
Additions (1)(2)		(20	)		110			873			5,423			258			6,644
Depreciation for the year		(548	)		(6,467	)		(730	)		–			–			(7,745	)
Impairments, net of reversals (3)		(9	)		(507	)		(260	)		–			(62	)		(838	)
Disposals		(7	)		(26	)		(36	)		(1	)		(9	)		(79	)
Transferred to assets held for sale		(21	)		(4,426	)		(5,563	)		(662	)		–			(10,672	)
Exchange variations taken to reserve		–			1			–			–			–			1
Transfers and other movements		210			2,773			(867	)		(2,742	)		–			(626	)
At the end of the financial year		8,152			40,885			8,974			7,554			1,617			67,182
– Cost		12,525			91,037			13,212			7,554			2,400			126,728
– Accumulated depreciation and impairments		(4,373	)		(50,152	)		(4,238	)		–			(783	)		(59,546	)
Net book value – 30 June 2017
At the beginning of the financial year		9,005			47,766			15,942			9,561			1,701			83,975
Additions (1)(2)		–			809			416			3,773			314			5,312
Depreciation for the year		(552	)		(6,419	)		(765	)		–			–			(7,736	)
Impairments, net of reversals		(8	)		(83	)		–			–			(69	)		(160	)
Disposals		(27	)		(56	)		(25	)		(1	)		(152	)		(261	)
Divestment and demerger of subsidiaries and operations		(47	)		(105	)		–			(42	)		–			(194	)
Exchange variations taken to reserve		–			–			(1	)		–			–			(1	)
Transfers and other movements		176			7,515			(10	)		(7,755	)		(364	)		(438	)
At the end of the financial year		8,547			49,427			15,557			5,536			1,430			80,497
– Cost		12,387			106,332			31,196			5,538			2,213			157,666
– Accumulated depreciation and impairments		(3,840	)		(56,905	)		(15,639	)		(2	)		(783	)		(77,169	)

⁽¹⁾  Includes net foreign exchange gains/(losses) related to the closure and rehabilitation provisions. Refer to note 13 ‘Closure and rehabilitation provisions’.

⁽²⁾ Property, plant and equipment of US$3 million (2017: US$593 million; 2016: US$ nil) was acquired under finance lease. This is a non-cash investing transaction that has been excluded from the Consolidated Cash Flow Statement.

⁽³⁾ Includes impairment charges related to Onshore US assets of US$520 million (2017: US$ nil). Refer to note 26 ‘Discontinued operations’.

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Recognition and measurement

Property, plant and equipment

Property, plant and equipment is recorded at cost less accumulated depreciation and impairment charges. Cost is the fair value of consideration given to acquire the asset at the time of its acquisition or construction and includes the direct costs of bringing the asset to the location and the condition necessary for operation and the estimated future costs of closure and rehabilitation of the facility.

Equipment leases

Assets held under lease, which result in the Group receiving substantially all of the risk and rewards of ownership are capitalised as property, plant and equipment at the lower of the fair value of the leased assets or the estimated present value of the minimum lease payments. Leased assets are depreciated on the same basis as owned assets or, where shorter, the lease term. The corresponding finance lease obligation is included within interest bearing liabilities. The interest component is charged to the income statement over the lease term to reflect a constant rate of interest over the remaining balance of the obligation.

Operating leases are not capitalised and rental payments are included in the income statement on a straight-line basis over the lease term. Ongoing contracted commitments under finance and operating leases are disclosed within note 31 ‘Commitments’.

Exploration and evaluation

Exploration costs are incurred to discover mineral and petroleum resources. Evaluation costs are incurred to assess the technical feasibility and commercial viability of resources found.

Exploration and evaluation expenditure is charged to the income statement as incurred, except in the following circumstances in which case the expenditure may be capitalised:

In respect of minerals activities:

• the exploration and evaluation activity is within an area of interest that was previously acquired as an asset acquisition or in a business combination and measured at fair value on acquisition; or

• the existence of a commercially viable mineral deposit has been established.

In respect of petroleum activities:

• the exploration and evaluation activity is within an area of interest for which it is expected that the expenditure will be recouped by future exploitation or sale; or

• exploration and evaluation activity has not reached a stage that permits a reasonable assessment of the existence of commercially recoverable reserves.

A regular review of each area of interest is undertaken to determine the appropriateness of continuing to carry forward costs in relation to that area. Capitalised costs are only carried forward to the extent that they are expected to be recovered through the successful exploitation of the area of interest or alternatively by its sale. To the extent that capitalised expenditure is no longer expected to be recovered, it is charged to the income statement.

F-40

Key judgements and estimates

Exploration and evaluation expenditure results in certain items of expenditure being capitalised for an area of interest where it is considered likely to be recoverable by future exploitation or sale, or where the activities have not reached a stage that permits a reasonable assessment of the existence of reserves. This policy requires management to make certain estimates and assumptions as to future events and circumstances, in particular whether an economically viable extraction operation can be established. These estimates and assumptions may change as new information becomes available. If, after having capitalised the expenditure under the policy, a judgement is made that recovery of the expenditure is unlikely, the relevant capitalised amount will be written off to the income statement.

Development expenditure

When proven mineral reserves are determined and development is sanctioned, capitalised exploration and evaluation expenditure is reclassified as assets under construction within property, plant and equipment. All subsequent development expenditure is capitalised and classified as assets under construction, provided commercial viability conditions continue to be satisfied.

The Group may use funds sourced from external parties to finance the acquisition and development of assets and operations. Finance costs are expensed as incurred, except where they relate to the financing of construction or development of qualifying assets. Borrowing costs directly attributable to acquiring or constructing a qualifying asset are capitalised during the development phase. Development expenditure is net of proceeds from the saleable material extracted during the development phase. On completion of development, all assets included in assets under construction are reclassified as either plant and equipment or other mineral assets and depreciation commences.

Key judgements and estimates

Development activities commence after project sanctioning by the appropriate level of management. Judgement is applied by management in determining when a project is economically viable. In exercising this judgement, management is required to make certain estimates and assumptions as to future events and circumstances, including reserve estimates, existence of an accessible market and forecast prices and cash flows. Estimates and assumptions may change as new information becomes available. If, after having commenced the development activity, a judgement is made that a development asset is impaired, the appropriate amount will be written off to the income statement.

Other mineral assets

Other mineral assets comprise:

• capitalised exploration, evaluation and development expenditure for assets in production;

• mineral rights and petroleum interests acquired;

• capitalised development and production stripping costs.

Overburden removal costs

The process of removing overburden and other waste materials to access mineral deposits is referred to as stripping. Stripping is necessary to obtain access to mineral deposits and occurs throughout the life of an open-pit mine. Development and production stripping costs are classified as other mineral assets in property, plant and equipment.

F-41

Stripping costs are accounted for separately for individual components of an ore body. The determination of components is dependent on the mine plan and other factors, including the size, shape and geotechnical aspects of an ore body. The Group accounts for stripping activities as follows:

Development stripping costs

These are initial overburden removal costs incurred to obtain access to mineral deposits that will be commercially produced. These costs are capitalised when it is probable that future economic benefits (access to mineral ores) will flow to the Group and costs can be measured reliably.

Once the production phase begins, capitalised development stripping costs are depreciated using the units of production method based on the proven and probable reserves of the relevant identified component of the ore body to which the initial stripping activity benefits.

Production stripping costs

These are post initial overburden removal costs incurred during the normal course of production activity, which commences after the first saleable minerals have been extracted from the component. Production stripping costs can give rise to two benefits, the accounting for which is outlined below:

	Production stripping activity
Benefits of stripping activity	Extraction of ore (inventory) in current period.	Improved access to future ore extraction.
Period benefited	Current period	Future period(s)
Recognition and measurement criteria	When the benefits of stripping activities are realised in the form of inventory produced; the associated costs are recorded in accordance with the Group’s inventory accounting policy.	When the benefits of stripping activities are improved access to future ore; production costs are capitalised when all the following criteria are met: •   the production stripping activity improves access to a specific component of the ore body and it is probable that economic benefits arising from the improved access to future ore production will be realised; •   the component of the ore body for which access has been improved can be identified; •   costs associated with that component can be measured reliably.
Allocation of costs	Production stripping costs are allocated between the inventory produced and the production stripping asset using a life-of-component waste-to-ore (or mineral contained) strip ratio. When the current strip ratio is greater than the estimated life-of-component ratio a portion of the stripping costs is capitalised to the production stripping asset.

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	Production stripping activity
Asset recognised from stripping activity	Inventory	Other mineral assets within property, plant and equipment.
Depreciation basis	Not applicable	On a component-by-component basis using the units of production method based on proven and probable reserves.

Key judgements and estimates

The identification of components of an ore body, as well as estimation of stripping ratios and mineral reserves by component require critical accounting judgements and estimates to be made by management. Changes to estimates related to life-of-component waste-to-ore (or mineral contained) strip ratios and the expected ore production from identified components are accounted for prospectively and may affect depreciation rates and asset carrying values.

Depreciation

Depreciation of assets, other than land, assets under construction and capitalised exploration and evaluation that are not depreciated, is calculated using either the straight-line (SL) method or units of production (UoP) method, net of residual values, over the estimated useful lives of specific assets. The depreciation method and rates applied to specific assets reflect the pattern in which the asset’s benefits are expected to be used by the Group. The Group’s reported reserves are used to determine UoP depreciation unless doing so results in depreciation charges that do not reflect the asset’s useful life. Where this occurs, alternative approaches to determining reserves are applied, such as using management’s expectations of future oil and gas prices rather than yearly average prices, to provide a phasing of periodic depreciation charges that better reflects the asset’s expected useful life.

Where assets are dedicated to a mine or petroleum lease, the below useful lives are subject to the lesser of the asset category’s useful life and the life of the mine or petroleum lease, unless those assets are readily transferable to another productive mine or lease.

Key judgements and estimates

The estimation of useful lives, residual values and depreciation methods requires significant management judgement and is reviewed annually. Any changes to useful lives may affect prospective depreciation rates and asset carrying values.

The table below summarises the principal depreciation methods and rates applied to major asset categories by the Group.

Category	Buildings	Plant and equipment	Mineral rights and petroleum interests	Capitalised exploration, evaluation and development expenditure
Typical depreciation methodology	SL	SL	UoP	UoP
Depreciation rate	25-50 years	3-30 years	Based on the rate of depletion of reserves	Based on the rate of depletion of reserves

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Impairment of non-current assets

Recognition and measurement

Impairment tests for all assets are performed when there is an indication of impairment, although goodwill is tested at least annually. If the carrying amount of the asset exceeds its recoverable amount, the asset is impaired and an impairment loss is charged to the income statement so as to reduce the carrying amount in the balance sheet to its recoverable amount.

Previously impaired assets (excluding goodwill) are reviewed for possible reversal of previous impairment at each reporting date. Impairment reversal cannot exceed the carrying amount that would have been determined (net of depreciation) had no impairment loss been recognised for the asset or cash generating units (CGUs). There were no reversals of impairment in the current or prior year.

How recoverable amount is calculated

The recoverable amount is the higher of an asset’s fair value less cost of disposal (FVLCD) and its value in use (VIU). For the purposes of assessing impairment, assets are grouped at the lowest levels for which there are separately identifiable cash flows.

Valuation methods

Fair value less cost of disposal

FVLCD is an estimate of the amount that a market participant would pay for an asset or CGU, less the cost of disposal. Fair value for mineral and petroleum assets is generally determined using independent market assumptions to calculate the present value of the estimated future post-tax cash flows expected to arise from the continued use of the asset, including the anticipated cash flow effects of any capital expenditure to enhance production or reduce cost, and its eventual disposal where a market participant may take a consistent view. Cash flows are discounted using an appropriate post-tax market discount rate to arrive at a net present value of the asset, which is compared against the asset’s carrying value.

Value in use

VIU is determined as the present value of the estimated future cash flows expected to arise from the continued use of the asset in its present form and its eventual disposal. VIU is determined by applying assumptions specific to the Group’s continued use and cannot take into account future development. These assumptions are different to those used in calculating FVLCD and consequently the VIU calculation is likely to give a different result (usually lower) to a FVLCD calculation.

Key judgements and estimates

In determining the recoverable amount of assets, in the absence of quoted market prices, estimates are made regarding the present value of future post-tax cash flows. These estimates require significant management judgement and are subject to risk and uncertainty that may be beyond the control of the Group; hence, there is a possibility that changes in circumstances will materially alter projections, which may impact the recoverable amount of assets at each reporting date. The estimates are made from the perspective of a market participant and include prices, future production volumes, operating costs, tax attributes and discount rates.

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11    Intangible assets

	2018									2017
	Goodwill			Other intangibles			Total			Goodwill			Other intangibles			Total
	US$M			US$M			US$M			US$M			US$M			US$M
Net book value
At the beginning of the financial year		3,269			699			3,968			3,273			846			4,119
Additions		–			50			50			–			81			81
Amortisation for the year		–			(197	)		(197	)		–			(195	)		(195	)
Impairments for the year (1)		(2,339	)		(14	)		(2,353	)		–			(33	)		(33	)
Disposals		(16	)		(7	)		(23	)		(4	)		–			(4	)
Transferred to assets held for sale		(667	)		–			(667	)		–			–			–
At the end of the financial year (2)		247			531			778			3,269			699			3,968
– Cost		247			1,665			1,912			3,269			1,722			4,991
– Accumulated amortisation and impairments		–			(1,134	)		(1,134	)		–			(1,023	)		(1,023	)

⁽¹⁾ Includes impairment charges related to Onshore US assets of US$2,339 million (2017: US$ nil). Refer to note 26 ‘Discontinued operations’.

⁽²⁾ The Group’s aggregate net carrying value of goodwill for Continuing operations is US$247 million (2017: US$247 million), representing less than one per cent of net equity at 30 June 2018 (2017: less than one per cent). The goodwill is allocated across a number of cash-generating units (CGUs).

Recognition and measurement

Goodwill

Where the fair value of the consideration paid for a business acquisition exceeds the fair value of the identifiable assets, liabilities and contingent liabilities acquired, the difference is treated as goodwill. Where consideration is less than the fair value of acquired net assets, the difference is recognised immediately in the income statement. Goodwill is not amortised and is measured at cost less any impairment losses.

Other intangibles

The Group capitalises amounts paid for the acquisition of identifiable intangible assets, such as software, licences and initial payments for the acquisition of mineral lease assets, where it is considered that they will contribute to future periods through revenue generation or reductions in cost. These assets, classified as finite life intangible assets, are carried in the balance sheet at the fair value of consideration paid less accumulated amortisation and impairment charges. Intangible assets with finite useful lives are amortised on a straight-line basis over their useful lives. The estimated useful lives are generally no greater than eight years.

Initial payments for the acquisition of intangible mineral lease assets are capitalised and amortised over the term of the permit. A regular review is undertaken of each area of interest to determine the appropriateness of continuing to carry forward costs in relation to that area. Capitalised costs are only carried forward to the extent that they are expected to be recovered through the successful exploitation of the area of interest or alternatively by its sale. To the extent that capitalised expenditure is no longer expected to be recovered, it is charged to the income statement.

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Key judgements and estimates

Determining the recoverable amount of intangible assets may require significant management judgement. If a judgement is made that recovery of previously capitalised intangible mineral lease assets is unlikely, the relevant amount will be written off to the income statement. This requires management to make certain estimates and assumptions as to future events and circumstances, in particular whether an economically viable extraction operation can be established.

Where indicators of impairment exist for intangible assets, in the absence of quoted market prices, estimates are made regarding the present value of future post-tax cash flows. These estimates require significant management judgement and are subject to risk and uncertainty that may be beyond the control of the Group; hence, there is a possibility that changes in circumstances will materially alter projections, which may impact the recoverable amount of assets at each reporting date. The estimates are made from the perspective of a market participant and include prices, future production volumes, operating costs, tax attributes and discount rates.

12    Deferred tax balances

The movement for the year in the Group’s net deferred tax position is as follows:

	2018			2017		2016
	US$M			US$M		US$M
Net deferred tax asset/(liability)
At the beginning of the financial year		2,023			1,823		(1,681	)
Income tax (charge)/credit recorded in the income statement (1)		(1,445	)		188		3,508
Income tax credit/(charge) recorded directly in equity		17			12		(25	)
Other movements		(26	)		–		21
At the end of the financial year		569			2,023		1,823

⁽¹⁾  Includes Discontinued operations income tax credit to the income statement of US$510 million (2017: US$219 million; 2016: US$2,990 million).

For recognition and measurement refer to note 5 ‘Income tax expense’.

F-46

The composition of the Group’s net deferred tax assets and liabilities recognised in the balance sheet and the deferred tax expense charged/(credited) to the income statement is as follows:

	Deferred tax assets						Deferred tax liabilities						Charged/(credited) to the income statement
	2018			2017			2018			2017			2018			2017			2016
	US$M			US$M			US$M			US$M			US$M			US$M			US$M
Type of temporary difference
Depreciation		(2,756	)		(3,454	)		1,356			1,411			(752	)		391			(2,282	)
Exploration expenditure		492			543			–			–			51			(22	)		(3	)
Employee benefits		321			379			(2	)		3			31			(37	)		56
Closure and rehabilitation		1,627			1,809			(194	)		(230	)		218			(151	)		36
Resource rent tax		468			559			1,328			1,614			(194	)		(189	)		(8	)
Other provisions		141			131			(2	)		(1	)		(11	)		14			8
Deferred income		21			(2	)		–			(10	)		(13	)		3			(49	)
Deferred charges		(374	)		(443	)		272			322			(119	)		(77	)		62
Investments, including foreign tax credits		546			1,145			691			648			615			(17	)		(284	)
Foreign exchange gains and losses		(120	)		(87	)		16			69			(20	)		(77	)		(310	)
Tax losses		3,758			5,352			–			–			1,595			(381	)		(809	)
Other		(83	)		(144	)		7			(61	)		44			355			75
Total		4,041			5,788			3,472			3,765			1,445			(188	)		(3,508	)

The Group recognises the benefit of tax losses amounting to US$3,758 million (2017: US$5,352 million) only to the extent of anticipated future taxable income or gains in relevant jurisdictions. The amounts recognised in the Financial Statements in respect of each matter are derived from the Group’s best judgements and estimates as described in note 5 ‘Income tax expense’.

The composition of the Group’s unrecognised deferred tax assets and liabilities is as follows:

	2018		2017
	US$M		US$M
Unrecognised deferred tax assets
Tax losses and tax credits (1)		3,028		2,687
Investments in subsidiaries (2)		1,659		856
Deductible temporary differences relating to PRRT (3)		2,282		2,293
Mineral rights (4)		2,263		2,293
Other deductible temporary differences (5)		437		478
Total unrecognised deferred tax assets		9,669		8,607
Unrecognised deferred tax liabilities
Investments in subsidiaries (2)		2,216		2,500
Taxable temporary differences relating to unrecognised deferred tax asset for PRRT (3)		685		694
Total unrecognised deferred tax liabilities		2,901		3,194

⁽¹⁾ At 30 June 2018, the Group had income and capital tax losses with a tax benefit of US$1,946 million (2017: US$1,844 million) and tax credits of US$1,082 million (2017: US$843 million), which are not recognised as deferred tax assets, because it is not probable that future taxable profits or capital gains will be available against which the Group can utilise the benefits.

F-47

The gross amount of tax losses carried forward that have not been recognised are as follows:

Year of expiry	Total
	US$M
Income tax losses
Not later than one year		363
Later than one year and not later than two years		402
Later than two years and not later than five years		897
Later than five years and not later than 10 years		398
Later than 10 years and not later than 20 years		2,446
Unlimited		1,734
		6,240
Capital tax losses
Not later than one year		–
Later than two years and not later than five years		144
Unlimited		3,471
Gross amount of tax losses not recognised		9,855
Tax effect of total losses not recognised		1,946

Of the US$1,082 million of tax credits, US$831 million expires not later than 10 years and US$251 million expires later than 10 years and not later than 20 years.

⁽²⁾ The Group had deferred tax assets of US$1,659 million at 30 June 2018 (2017: US$856 million) and deferred tax liabilities of US$2,216 million (2017: US$2,500 million) associated with undistributed earnings of subsidiaries that have not been recognised because the Group is able to control the timing of the reversal of the temporary differences and it is not probable that these differences will reverse in the foreseeable future.

⁽³⁾ The Group had US$2,282 million of unrecognised deferred tax assets relating to Australian Petroleum Resource Rent Tax (PRRT) at 30 June 2018 (2017: US$2,293 million relating to Australian PRRT), with a corresponding unrecognised deferred tax liability for income tax purposes of US$685 million (2017: US$694 million). Recognition of a deferred tax asset for PRRT depends on benefits expected to be obtained from the deduction against PRRT liabilities.

⁽⁴⁾ The Group had deductible temporary differences relating to mineral rights for which deferred tax assets of US$2,263 million at 30 June 2018 (2017: US$2,293 million) had not been recognised because it is not probable that future capital gains will be available, against which the Group can utilise the benefits. The deductible temporary differences do not expire under current tax legislation.

⁽⁵⁾ The Group had deductible temporary differences for which deferred tax assets of US$437 million at 30 June 2018 (2017: US$478 million) had not been recognised because it is not probable that future taxable profits will be available against which the Group can utilise the benefits. The deductible temporary differences do not expire under current tax legislation.

F-48

13    Closure and rehabilitation provisions

	2018			2017
	US$M			US$M
At the beginning of the financial year		6,738			6,502
Capitalised amounts for operating sites:
Change in estimate		35			71
Exchange translation		(122	)		99
Adjustments charged/(credited) to the income statement:
Increases to existing and new provisions		132			127
Exchange translation		(11	)		9
Released during the year		(165	)		(120	)
Other adjustments to the provision:
Amortisation of discounting impacting net finance costs		352			330
Expenditure on closure and rehabilitation activities		(178	)		(132	)
Exchange variations impacting foreign currency translation reserve		–			(1	)
Divestment and demerger of subsidiaries and operations		–			(146	)
Transferred to liabilities held for sale		(450	)		–
Other movements		(1	)		(1	)
At the end of the financial year		6,330			6,738
Comprising:
Current		274			255
Non-current		6,056			6,483
Operating sites		5,120			5,462
Closed sites		1,210			1,276

The Group is required to rehabilitate sites and associated facilities at the end of, or in some cases, during the course of production, to a condition acceptable to the relevant authorities, as specified in licence requirements and the Group’s environmental performance requirements as set out within Our Charter.

The key components of closure and rehabilitation activities are:

• the removal of all unwanted infrastructure associated with an operation;

• the return of disturbed areas to a safe, stable, productive and self-sustaining condition, consistent with the agreed end land use.

Recognition and measurement

Provisions for closure and rehabilitation are recognised by the Group when:

• it has a present legal or constructive obligation as a result of past events;

• it is more likely than not that an outflow of resources will be required to settle the obligation;

• the amount can be reliably estimated.

F-49

Initial recognition

Subsequent remeasurement

Closure and rehabilitation provisions are initially recognised when an environmental disturbance first occurs. The individual site provisions are an estimate of the expected value of future cash flows required to rehabilitate the relevant site using current restoration standards and techniques and taking into account risks and uncertainties. Individual site provisions are discounted to their present value using country specific discount rates aligned to the estimated timing of cash outflows. When provisions for closure and rehabilitation are initially recognised, the corresponding cost is capitalised as an asset, representing part of the cost of acquiring the future economic benefits of the operation.

The closure and rehabilitation asset, recognised within property, plant and equipment, is depreciated over the life of the operations. The value of the provision is progressively increased over time as the effect of discounting unwinds, resulting in an expense recognised in net finance costs. The closure and rehabilitation liability is reviewed at each reporting date to assess if the estimate continues to reflect the best estimate of the obligation. If necessary, the provision is remeasured to account for factors, including: •   revisions to estimated reserves, resources and lives of operations; •   developments in technology; •   regulatory requirements and environmental management strategies; •   changes in the estimated extent and costs of anticipated activities, including the effects of inflation and movements in foreign exchange rates; •   movements in interest rates affecting the discount rate applied. Changes to the closure and rehabilitation estimate are added to, or deducted from, the related asset and amortised on a prospective basis accordingly over the remaining life of the operation, generally applying the units of production method. Costs arising from unforeseen circumstances, such as the contamination caused by unplanned discharges, are recognised as an expense and liability when the event gives rise to an obligation that is probable and capable of reliable estimation.

Closed sites

Where future economic benefits are no longer expected to be derived through operation, changes to the associated closure and remediation costs are (credited)/charged to the income statement in the period identified. This amounted to a credit of US$(21) million in the year ended 30 June 2018 (2017: charge of US$33 million; 2016: charge of US$18 million).

F-50

Key judgements and estimates

The recognition and measurement of closure and rehabilitation provisions requires the use of significant judgements and estimates, including, but not limited to:

• the extent (due to legal or constructive obligations) of potential activities required for the removal of infrastructure and rehabilitation activities;

• costs associated with future rehabilitation activities;

• applicable real discount rates;

• the timing of cash flows and ultimate closure of operations.

Rehabilitation activities are generally undertaken at the end of the production life at the individual sites. Remaining production lives range from 2-127 years with an average for all sites, weighted by current closure provision, of approximately 29 years. A 0.5 per cent decrease in the real discount rates applied at 30 June 2018 would result in an increase to the closure and rehabilitation provision of US$604 million, an increase in property, plant and equipment of US$524 million in relation to operating sites and an income statement charge of US$80 million in respect of closed sites. In addition, the change would result in an increase of approximately US$46 million to depreciation expense and an immaterial reduction in net finance costs for the year ending 30 June 2019.

Estimates can also be impacted by the emergence of new restoration techniques and experience at other operations. These uncertainties may result in future actual expenditure differing from the amounts currently provided for in the balance sheet.

Capital structure

14    Share capital

	BHP Billiton Limited									BHP Billiton Plc
	2018 shares			2017 shares			2016 shares			2018 shares			2017 shares			2016 shares
Share capital issued
Opening number of shares		3,211,691,105			3,211,691,105			3,211,691,105			2,112,071,796			2,112,071,796			2,112,071,796
Purchase of shares by ESOP Trusts		(7,469,236	)		(6,481,292	)		(6,538,404	)		(679,223	)		(225,646	)		(17,000	)
Employee share awards exercised following vesting		7,339,522			6,945,570			6,846,091			711,705			940,070			966,473
Movement in treasury shares under Employee Share Plans		129,714			(464,278	)		(307,687	)		(32,482	)		(714,424	)		(949,473	)
Closing number of shares (1)		3,211,691,105			3,211,691,105			3,211,691,105			2,112,071,796			2,112,071,796			2,112,071,796
Comprising:
Shares held by the public		3,211,494,259			3,211,623,973			3,211,159,695			2,112,030,162			2,111,997,680			2,111,283,256
Treasury shares		196,846			67,132			531,410			41,634			74,116			788,540
Other share classes
Special Voting share of no par value		1			1			1			–			–			–
Special Voting share of US$0.50 par value		–			–			–			1			1			1
5.5% Preference shares of £1 each		–			–			–			50,000			50,000			50,000
DLC Dividend share		1			1			1			–			–			–

F-51

⁽¹⁾  No fully paid ordinary shares in BHP Billiton Limited or BHP Billiton Plc were issued on the exercise of Group Incentive Scheme awards during the period 1 July 2018 to 6 September 2018.

Recognition and measurement

Share capital of BHP Billiton Limited and BHP Billiton Plc is composed of the following classes of shares:

Ordinary shares fully paid	Special Voting shares	Preference shares
BHP Billiton Limited and BHP Billiton Plc ordinary shares fully paid of US$0.50 par value represent 99.99 per cent of the total number of shares. Any profit remaining after payment of preferred distributions is available for distribution to the holders of BHP Billiton Limited and BHP Billiton Plc ordinary shares in equal amounts per share.	Each of BHP Billiton Limited and BHP Billiton Plc issued one Special Voting share to facilitate joint voting by shareholders of BHP Billiton Limited and BHP Billiton Plc on Joint Electorate Actions. There has been no movement in these shares.	Preference shares have the right to repayment of the amount paid up on the nominal value and any unpaid dividends in priority to the holders of any other class of shares in BHP Billiton Plc on a return of capital or winding up. The holders of preference shares have limited voting rights if payment of the preference dividends are six months or more in arrears or a resolution is passed changing the rights of the preference shareholders. There has been no movement in these shares, all of which are held by JP Morgan Limited.

DLC Dividend share

Treasury shares

The DLC Dividend share supports the Dual Listed Company (DLC) equalisation principles in place since the merger in 2001, including the requirement that ordinary shareholders of BHP Billiton Plc and BHP Billiton Limited are paid equal cash dividends per share. This share enables efficient and flexible capital management across the DLC and was issued on 23 February 2016 at par value of US$10. On 20 September 2017 and on 21 March 2018, BHP Billiton Limited paid dividends of US$1,280 million and US$1,380 million, respectively to BHP Billiton (AUS) DDS Pty Ltd under the DLC dividend share arrangements. These dividends are eliminated on consolidation.

Treasury shares are shares of BHP Billiton Limited and BHP Billiton Plc and are held by the ESOP Trusts for the purpose of issuing shares to employees under the Group’s Employee Share Plans. Treasury shares are recognised at cost and deducted from equity, net of any income tax effects. When the treasury shares are subsequently sold or reissued, any consideration received, net of any directly attributable costs and income tax effects, is recognised as an increase in equity. Any difference between the carrying amount and the consideration, if reissued, is recognised in retained earnings.

F-52

15    Other equity

	2018		2017		2016		Recognition and measurement
	US$M		US$M		US$M
Share premium account		518		518		518	The share premium account represents the premium paid on the issue of BHP Billiton Plc shares recognised in accordance with the UK Companies Act 2006.
Foreign currency translation reserve		42		40		41	The foreign currency translation reserve represents exchange differences arising from the translation of non-US dollar functional currency operations within the Group into US dollars.
Employee share awards reserve		196		214		293	The employee share awards reserve represents the accrued employee entitlements to share awards that have been charged to the income statement and have not yet been exercised. Once exercised, the difference between the accumulated fair value of the awards and their historical on-market purchase price is recognised in retained earnings.
Hedging reserve		58		153		210	The hedging reserve represents hedging gains and losses recognised on the effective portion of cash flow hedges. The cumulative deferred gain or loss on the hedge is recognised in the income statement when the hedged transaction impacts the income statement, or is recognised as an adjustment to the cost of non-financial hedged items. The hedging reserve records the portion of the gain or loss on a hedging instrument in a cash flow hedge that is determined to be an effective hedge relationship.
Financial assets reserve		16		10		11	The financial assets reserve represents the revaluation of available for sale financial assets. Where a revalued financial asset is sold or impaired, the relevant portion of the reserve is transferred to the income statement.
Share buy-back reserve		177		177		177	The share buy-back reserve represents the par value of BHP Billiton Plc shares that were purchased and subsequently cancelled. The cancellation of the shares creates a non-distributable capital redemption reserve.
Non-controlling interest contribution reserve		1,283		1,288		1,288	The non-controlling interest contribution reserve represents the excess of consideration received over the book value of net assets attributable to equity instruments when acquired by non-controlling interests.
Total reserves		2,290		2,400		2,538

F-53

Summarised financial information relating to each of the Group’s subsidiaries with non-controlling interests (NCI) that are material to the Group before any intra-group eliminations is shown below:

	2018							2017
US$M	Minera Escondida Limitada			Other individually immaterial subsidiaries (incl. intra- group eliminations)		Total		Minera Escondida Limitada			Other individually immaterial subsidiaries (incl. intra- group eliminations)		Total
Group share (per cent)		57.5							57.5
Current assets		2,751							2,107
Non-current assets		13,389							14,528
Current liabilities		(1,781	)						(1,339	)
Non-current liabilities		(4,352	)						(4,300	)
Net assets		10,007							10,996
Net assets attributable to NCI		4,253			825		5,078		4,673			795		5,468
Revenue		8,775							4,576
Profit after taxation		2,221							516
Other comprehensive income		(2	)						–
Total comprehensive income		2,219							516
Profit after taxation attributable to NCI		944			174		1,118		219			113		332
Other comprehensive income attributable to NCI		(1	)		1		–		–			–		–
Net operating cash flow		5,041							1,964
Net investing cash flow		(997	)						(999	)
Net financing cash flow		(3,392	)						(968	)
Dividends paid to NCI (1)		1,469			135		1,604		507			74		581

⁽¹⁾  Includes dividends paid to non-controlling interests related to Onshore US of US$22 million (2017: US$6 million). Refer to note 26 ‘Discontinued operations’.

While the Group controls Minera Escondida Limitada, the non-controlling interests hold certain protective rights that restrict the Group’s ability to sell assets held by Minera Escondida Limitada, or use the assets in other subsidiaries and operations owned by the Group. Minera Escondida Limitada is also restricted from paying dividends without the approval of the non-controlling interests.

F-54

16    Dividends

	Year ended 30 June 2018				Year ended 30 June 2017				Year ended 30 June 2016
	Per share		Total		Per share		Total		Per share		Total
	US cents		US$M		US cents		US$M		US cents		US$M
Dividends paid during the period (1)
Prior year final dividend		43		2,291		14		746		62		3,299
Interim dividend		55		2,930		40		2,125		16		855
		98		5,221		54		2,871		78		4,154

⁽¹⁾  5.5 per cent dividend on 50,000 preference shares of £1 each determined and paid annually (2017: 5.5 per cent; 2016: 5.5 per cent).

Dividends paid during the period differs from the amount of dividends paid in the Cash Flow Statement as a result of foreign exchange gains and losses relating to the timing of equity distributions between the record date and the payment date.

The Dual Listed Company merger terms require that ordinary shareholders of BHP Billiton Limited and BHP Billiton Plc are paid equal cash dividends on a per share basis. Each American Depositary Share (ADS) represents two ordinary shares of BHP Billiton Limited or BHP Billiton Plc. Dividends determined on each ADS represent twice the dividend determined on BHP Billiton Limited or BHP Billiton Plc ordinary shares.

Dividends are determined after period-end and announced with the results for the period. Interim dividends are determined in February and paid in March. Final dividends are determined in August and paid in September. Dividends determined are not recorded as a liability at the end of the period to which they relate. Subsequent to year-end, on 21 August 2018, BHP Billiton Limited and BHP Billiton Plc determined a final dividend of 63 US cents per share (US$3,354 million), which will be paid on 25 September 2018 (30 June 2017: final dividend of 43 US cents per share – US$2,289 million; 30 June 2016: final dividend of 14 US cents per share – US$746 million).

BHP Billiton Limited dividends for all periods presented are, or will be, fully franked based on a tax rate of 30 per cent.

	2018		2017		2016
	US$M		US$M		US$M
Franking credits as at 30 June		10,400		10,155		9,640
Franking credits arising from the payment of current tax		1,330		1,239		81
Total franking credits available (1)		11,730		11,394		9,721

⁽¹⁾  The payment of the final 2018 dividend determined after 30 June 2018 will reduce the franking account balance by US$867 million.

F-55

17    Provisions for dividends and other liabilities

The disclosure below excludes closure and rehabilitation provisions (refer to note 13 ‘Closure and rehabilitation provisions’), employee benefits, restructuring and post-retirement employee benefits provisions (refer to note 23 ‘Employee benefits, restructuring and post-retirement employee benefits provisions’) and the Samarco dam failure provision (refer to note 3 ‘Significant events – Samarco dam failure’).

	2018			2017
	US$M			US$M
Movement in provision for dividends and other liabilities
At the beginning of the financial year		984			930
Dividends determined		5,221			2,871
Charge/(credit) for the year:
Underlying		337			316
Discounting		4			5
Exchange variations		3			53
Released during the year		(78	)		(122	)
Utilisation		(150	)		(223	)
Dividends paid		(5,325	)		(2,921	)
Transferred to liabilities held for sale		(39	)		–
Transfers and other movements		(13	)		75
At the end of the financial year (1)		944			984
Comprising:
Current		290			332
Non-current		654			652

⁽¹⁾  Includes unpaid dividend determined to non-controlling interest of US$ nil (2017: US$105 million).

F-56

Financial management

18    Net debt

The Group’s corporate purpose is to create long-term shareholder value through the discovery, acquisition, development and marketing of natural resources. The Group will invest capital in assets where they fit its strategy.

The Group monitors capital using the net debt balance and the gearing ratio, being the ratio of net debt to net debt plus net assets.

	2018					2017
US$M	Current		Non-current			Current		Non-current
Interest bearing liabilities
Bank loans		308		2,247			192		2,089
Notes and debentures		2,228		21,070			771		26,270
Finance leases		77		725			82		815
Bank overdraft and short-term borrowings		58		–			45		–
Other		65		27			151		59
Total interest bearing liabilities		2,736		24,069			1,241		29,233
Less cash and cash equivalents
Cash		1,065		–			882		–
Short-term deposits		14,806		–			13,271		–
Total cash and cash equivalents		15,871		–			14,153		–
Net debt				10,934					16,321
Net assets				60,670					62,726
Gearing				15.3	%				20.6	%

Cash and short-term deposits are disclosed in the cash flow statement net of bank overdrafts and interest bearing liabilities at call.

	2018			2017			2016
	US$M			US$M			US$M
Total cash and cash equivalents		15,871			14,153			10,319
Bank overdrafts and short-term borrowing		(58	)		(45	)		(43	)
Total cash and cash equivalents, net of overdrafts		15,813			14,108			10,276

Recognition and measurement

Cash and short-term deposits in the balance sheet comprise cash at bank and on hand and highly liquid cash deposits with short-term maturities and are readily convertible to known amounts of cash with insignificant risk of change in value. The Group considers that the carrying value of cash and cash equivalents approximate fair value due to their short term to maturity.

Cash and cash equivalents includes US$98 million (2017: US$180 million) restricted by legal or contractual arrangements.

F-57

Interest bearing liabilities and cash and cash equivalents include balances denominated in the following currencies:

	Interest bearing liabilities				Cash and cash equivalents
	2018		2017		2018		2017
	US$M		US$M		US$M		US$M
USD		12,981		14,035		7,024		7,980
EUR		9,070		10,324		5,845		4,663
GBP		3,104		3,520		1,560		1,318
AUD		1,077		1,987		9		9
CAD		573		608		1,301		77
Other		–		–		132		106
Total		26,805		30,474		15,871		14,153

Liquidity risk

The Group’s liquidity risk arises from the possibility that it may not be able to settle or meet its obligations as they fall due and is managed as part of the portfolio risk management strategy. Operational, capital and regulatory requirements are considered in the management of liquidity risk, in conjunction with short-term and long-term forecast information.

Recognising the cyclical volatility of operating cash flows, the Group has defined minimum target cash and liquidity buffers to be maintained to mitigate liquidity risk and support operations through the cycle.

The Group’s strong credit profile, diversified funding sources, its minimum cash buffer and its committed credit facilities ensure that sufficient liquid funds are maintained to meet its daily cash requirements. The Group’s policy on counterparty credit exposure ensures that only counterparties of an investment grade standing are used for the investment of any excess cash.

Standard & Poor’s credit rating of the Group remained at the A level with stable outlook throughout FY2018. Moody’s maintained their credit rating for the Group of A3 with positive outlook throughout FY2018.

There were no defaults on loans payable during the period.

Counterparty risk

The Group is exposed to credit risk from its financing activities, including short-term cash deposits with banks and derivative contracts. This risk is managed by Group Treasury in line with the counterparty risk framework, which aims to minimise the exposure to a counterparty and mitigate the risk of financial loss through counterparty failure.

Exposure to counterparties is monitored at a Group level across all products and includes exposure with derivatives and short-term cash deposits.

Short-term cash deposits and derivatives are transacted with approved counterparties who have been assigned specific limits based on a quantitative credit risk model. The policy is reviewed annually and limits are updated at least bi-annually. Derivatives must be transacted with approved counterparties and are subject to tenor limits.

F-58

Standby arrangements and unused credit facilities

The Group’s committed revolving credit facility operates as a back-stop to the Group’s uncommitted commercial paper program. The combined amount drawn under the facility or as commercial paper will not exceed US$6.0 billion. As at 30 June 2018, US$ nil commercial paper was drawn (2017: US$ nil). The revolving credit facility has a five-year maturity ending 7 May 2021. A commitment fee is payable on the undrawn balance and an interest rate comprising an interbank rate plus a margin applies to any drawn balance. The agreed margins are typical for a credit facility extended to a company with the Group’s credit rating.

Maturity profile of financial liabilities

The maturity profile of the Group’s financial liabilities based on the contractual amounts, taking into account the derivatives related to debt, is as follows:

2018 US$M	Bank loans, debentures and other loans		Expected future interest payments		Derivatives related to net debt		Other derivatives		Obligations under finance leases		Trade and other payables		Total
Due for payment:
In one year or less or on demand		2,647		682		302		17		127		5,788		9,563
In more than one year but not more than two years		1,545		957		188		1		113		3		2,807
In more than two years but not more than five years		8,019		2,203		823		–		335		–		11,380
In more than five years		13,287		5,519		1,191		–		590		–		20,587
Total		25,498		9,361		2,504		18		1,165		5,791		44,337
Carrying amount		26,003		–		1,213		18		802		5,791		33,827
2017 US$M	Bank loans, debentures and other loans		Expected future interest payments		Derivatives related to net debt		Other derivatives		Obligations under finance leases		Trade and other payables		Total
Due for payment:
In one year or less or on demand		1,157		686		267		144		135		5,417		7,806
In more than one year but not more than two years		2,471		1,022		245		4		132		5		3,879
In more than two years but not more than five years		8,279		2,611		503		7		343		–		11,743
In more than five years		16,706		6,248		1,975		–		705		–		25,634
Total		28,613		10,567		2,990		155		1,315		5,422		49,062
Carrying amount		29,577		–		1,345		155		897		5,422		37,396

F-59

19    Net finance costs

	2018			2017			2016
	US$M			US$M			US$M
Financial expenses
Interest on bank loans, overdrafts and all other borrowings		1,168			1,130			969
Interest capitalised at 4.24% (2017: 3.25%; 2016: 2.61%) (1)		(139	)		(113	)		(123	)
Discounting on provisions and other liabilities		414			450			304
Fair value change on hedged loans		(265	)		(1,185	)		1,444
Fair value change on hedging derivatives		329			1,244			(1,448	)
Exchange variations on net debt		(19	)		(23	)		(24	)
Other financial expenses		79			57			28
		1,567			1,560			1,150
Financial income
Interest income		(322	)		(143	)		(137	)
Net finance costs		1,245			1,417			1,013

⁽¹⁾  Interest has been capitalised at the rate of interest applicable to the specific borrowings financing the assets under construction or, where financed through general borrowings, at a capitalisation rate representing the average interest rate on such borrowings. Tax relief for capitalised interest is approximately US$42 million (2017: US$34 million; 2016: US$37 million).

Recognition and measurement

Interest income is accrued using the effective interest rate method. Finance costs are expensed as incurred, except where they relate to the financing of construction or development of qualifying assets.

20    Financial risk management

Financial and capital risk management strategy

The financial risks arising from the Group’s operations comprise market, liquidity and credit risk. These risks arise in the normal course of business and the Group manages its exposure to them in accordance with the Group’s portfolio risk management strategy. The objective of the strategy is to support the delivery of the Group’s financial targets, while protecting its future financial security and flexibility by taking advantage of the natural diversification provided by the scale, diversity and flexibility of the Group’s operations and activities.

A Cash Flow at Risk (CFaR) framework is used to measure the aggregate and diversified impact of financial risks upon the Group’s financial targets. The principal measurement of risk is CFaR measured on a portfolio basis, which is defined as the worst expected loss relative to projected business plan cash flows over a one-year horizon under normal market conditions at a confidence level of 90 per cent.

Market risk

The Group’s activities expose it to market risks associated with movements in interest rates, foreign currencies and commodity prices. Under the strategy outlined above, the Group seeks to achieve financing costs, currency impacts, input costs and commodity prices on a floating or index basis. This strategy gives rise to a risk of variability in earnings, which is measured under the CFaR framework.

F-60

In executing the strategy, financial instruments are potentially employed in three distinct but related activities. The following table summarises these activities and the key risk management processes:

Activity	Key risk management processes
1   Risk mitigation
On an exception basis, hedging for the purposes of mitigating risk related to specific and significant expenditure on investments or capital projects will be executed if necessary to support the Group’s strategic objectives.	Execution of transactions within approved mandates.
2   Economic hedging of commodity sales, operating costs, short-term cash deposits and debt instruments
Where Group commodity production is sold to customers on pricing terms that deviate from the relevant index target and where a relevant derivatives market exists, financial instruments may be executed as an economic hedge to align the revenue price exposure with the index target.	•   Measuring and reporting the exposure in customer commodity contracts and issued debt instruments. •   Executing hedging derivatives to align the total group exposure to the index target. •   Execution of transactions within approved mandates.
Where debt is issued in a currency other than the US dollar and/or at a fixed interest rate, fair value and cash flow hedges may be executed to align the debt exposure with the Group’s functional currency of US dollars and/or to swap to a floating interest rate.
Where short-term cash deposits are held in a currency other than US dollars, derivative financial instruments may be executed to align the foreign exchange exposure to the Group’s functional currency of US dollars.
3   Strategic financial transactions
Opportunistic transactions may be executed with financial instruments to capture value from perceived market over/under valuations.	Execution of transactions within approved mandates.

Primary responsibility for the identification and control of financial risks, including authorising and monitoring the use of financial instruments for the above activities and stipulating policy thereon, rests with the Financial Risk Management Committee under authority delegated by the Chief Executive Officer.

Interest rate risk

The Group is exposed to interest rate risk on its outstanding borrowings and short-term cash deposits from the possibility that changes in interest rates will affect future cash flows or the fair value of fixed interest rate financial instruments. Interest rate risk is managed as part of the portfolio risk management strategy.

The majority of the Group’s debt is issued at fixed interest rates. The Group has entered into interest rate swaps and cross currency interest rate swaps to convert most of its fixed interest rate exposure to floating US dollar interest rate exposure. As at 30 June 2018, 89 per cent of the Group’s borrowings were exposed to floating interest rates inclusive of the effect of swaps (2017: 90 per cent).

F-61

The fair value of interest rate swaps and cross currency interest rate swaps in hedge relationships used to hedge both interest rate and foreign currency risks are shown in the valuation hierarchy section of this note.

Based on the net debt position as at 30 June 2018, taking into account interest rate swaps and cross currency interest rate swaps, it is estimated that a one percentage point increase in the US LIBOR interest rate will decrease the Group’s equity and profit after taxation by US$54 million (2017: decrease of US$92 million). This assumes the change in interest rates is effective from the beginning of the financial year and the fixed/floating mix and balances are constant over the year. However, interest rates and the net debt profile of the Group may not remain constant over the coming financial year and therefore such sensitivity analysis should be used with care.

Currency risk

The US dollar is the predominant functional currency within the Group and as a result, currency exposures arise from transactions and balances in currencies other than the US dollar. The Group’s potential currency exposures comprise:

• translational exposure in respect of non-functional currency monetary items;

• transactional exposure in respect of non-functional currency expenditure and revenues.

The Group’s foreign currency risk is managed as part of the portfolio risk management strategy.

Translational exposure in respect of non-functional currency monetary items

Monetary items, including financial assets and liabilities, denominated in currencies other than the functional currency of an operation are periodically restated to US dollar equivalents and the associated gain or loss is taken to the income statement. The exception is foreign exchange gains or losses on foreign currency denominated provisions for closure and rehabilitation at operating sites, which are capitalised in property, plant and equipment.

The principal non-functional currencies to which the Group is exposed are the Australian dollar, the Euro, the Pound sterling and the Chilean peso; however, 88 per cent (2017: 86 per cent) of the Group’s net financial liabilities are denominated in US dollars. Based on the Group’s net financial assets and liabilities as at 30 June 2018, a weakening of the US dollar against these currencies (one cent strengthening in Australian dollar, one cent strengthening in Euro, one penny strengthening in Pound sterling and 10 pesos strengthening in Chilean peso), with all other variables held constant, would decrease the Group’s equity and profit after taxation by US$10 million (2017: decrease of US$16 million).

Transactional exposure in respect of non-functional currency expenditure and revenues

Certain operating and capital expenditure is incurred in currencies other than their functional currency. To a lesser extent, certain sales revenue is earned in currencies other than the functional currency of operations and certain exchange control restrictions may require that funds be maintained in currencies other than the functional currency of the operation. These currency risks are managed as part of the portfolio risk management strategy. The Group enters into forward exchange contracts when required under this strategy.

F-62

Commodity price risk

Contracts for the sale and physical delivery of commodities are executed whenever possible on a pricing basis intended to achieve a relevant index target. While the Group has succeeded in transitioning substantially all of the Group commodity production sales to market-based index pricing terms, derivative commodity contracts may from time to time be used to align realised prices with the relevant index. Contracts for the physical delivery of commodities are not typically financial instruments and are carried in the balance sheet at cost (typically at US$ nil); they are therefore excluded from the fair value and sensitivity analysis. Accordingly, the financial instrument exposures set out below do not represent all of the commodity price risks managed according to the Group’s objectives. Movements in the fair value of contracts included are offset by movements in the fair value of the physical contracts; however, only the former movement is recognised in the Group’s income statement prior to settlement. The risk associated with commodity prices is managed as part of the portfolio risk management strategy.

Financial instruments with commodity price risk comprise forward commodity and other derivative contracts with a net assets fair value of US$210 million (2017: US$358 million). Significant commodity price risk instruments within other derivative balances include derivatives embedded in physical commodity purchase and sales contracts of gas in Trinidad and Tobago with a net assets fair value of US$216 million (2017: US$370 million).

The potential effect of using reasonably possible alternative assumptions in these models, based on a change in the most significant input, such as commodity prices, by an increase/(decrease) of 10 per cent while holding all other variables constant will increase/(decrease) profit after taxation by US$9 million (2017: US$62 million).

Provisionally priced commodity sales and purchases contracts

Provisionally priced sales or purchases volumes are those for which price finalisation, referenced to the relevant index, is outstanding at the reporting date. Provisional pricing mechanisms embedded within these sales and purchases arrangements have the character of a commodity derivative and are carried at fair value through profit and loss as part of trade receivables or trade payables. The Group’s exposure at 30 June 2018 to the impact of movements in commodity prices upon provisionally invoiced sales and purchases volumes was predominately around copper.

The Group had 356 thousand tonnes of copper exposure at 30 June 2018 (2017: 213 thousand tonnes) that was provisionally priced. The final price of these sales or purchases will be determined during the first half of FY2019. A 10 per cent change in the price of copper realised on the provisionally priced sales, with all other factors held constant, would increase or decrease profit after taxation by US$178 million (2017: US$90 million). The relationship between commodity prices and foreign currencies is complex and movements in foreign exchange rates can impact commodity prices. The sensitivities should therefore be used with care.

Liquidity risk

Refer to note 18 ‘Net debt’ for details on the Group liquidity risk.

Credit risk

Refer to note 7 ‘Trade and other receivables’ and note 18 ‘Net debt’ for details on the Group credit risk.

Financial assets and liabilities

The financial assets and liabilities are presented by class in the tables on page F-68 at their carrying amounts, which generally approximate to fair value.

F-63

Recognition and measurement

All financial assets and liabilities, other than derivatives, are initially recognised at the fair value of consideration paid or received, net of transaction costs as appropriate, and subsequently carried at fair value or amortised cost. Derivatives are initially recognised at fair value on the date the contract is entered into and are subsequently remeasured at their fair value.

The Group classifies its financial assets and liabilities into:

• loans and receivables;

• available for sale securities;

• held at fair value through profit or loss;

• cash flow hedges;

• financial assets and liabilities at amortised cost.

The classification depends on the purpose for which the financial assets and liabilities are held. Management determines the classification of its financial assets at initial recognition.

Loans and receivables

Available for sale shares and other investments

Loans and receivables are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market and include cash and cash equivalents and trade receivables. They are included in current assets, except for those with maturities greater than 12 months after the reporting date, which are classified as non-current assets. Loans and receivables are initially measured at fair value of consideration paid and subsequently carried at either fair value or amortised cost less impairment. At the end of each reporting period, loans and receivables are assessed for objective evidence that they are impaired. The amount of loss is measured as the difference between its carrying amount and the present value of its estimated future cash flows. The loss is recognised in the income statement.

Available for sale shares and other investments are measured at fair value. Gains and losses on the remeasurement of other investments are recognised directly in the income statement. Gains and losses on the remeasurement of available for sale shares are recognised directly in equity and subsequently recognised in the income statement when realised by sale or redemption, or when a reduction in fair value is judged to represent an impairment.

Other financial liabilities at amortised cost

Trade and other payables represents amounts that are non-interest bearing. The carrying value approximates their fair value, which represents liabilities for goods and services provided to the Group prior to the end of the reporting period that are unpaid.

Interest bearing liabilities are initially recognised at fair value of the consideration received, net of transaction costs. Interest bearing liabilities are subsequently measured at amortised cost using the effective interest method. Interest bearing liabilities are removed from the balance sheet when the obligation specified in the contract is discharged, cancelled or expired. The difference between the carrying amount of an interest bearing liability that has been extinguished or transferred to another party and the consideration paid, including any non-cash assets transferred or liabilities assumed, is recognised in the income statement as other income or finance costs.

F-64

The Group has finance lease liabilities in relation to certain items of property, plant and equipment. Finance lease liabilities are initially recognised at the fair value of the underlying assets or, if lower, the estimated present value of the minimum lease payments. Each lease payment is allocated between the liability and finance cost, and the finance cost is charged to the income statement over the lease period to reflect a constant periodic rate of interest on the remaining balance of the liability for each period.

Derivatives and hedging

Derivatives, including embedded derivatives separated from the host contracts, are included within financial assets or liabilities at fair value through profit or loss unless they are designated as effective hedging instruments. Financial instruments in this category are classified as current if they are expected to be settled within 12 months; otherwise they are classified as non-current.

The Group uses financial instruments to hedge its exposure to certain market risks arising from operational, financing and investing activities. At the start of the transaction, the Group documents:

• the type of hedge;

• the relationship between the hedging instrument and hedged items;

• its risk management objective and strategy for undertaking various hedge transactions.

The documentation also demonstrates, both at hedge inception and on an ongoing basis, that the hedge is expected to continue to be highly effective.

The Group has two types of hedges:

	Fair value hedges	Cash flow hedges
Exposure	As the majority of the Group’s debt is issued at fixed interest rates, the Group has entered into interest rate swaps and cross currency interest rate swaps to mitigate its exposure to changes in the fair value of borrowings.	As a portion of the Group’s debt is denominated in currencies other than US dollars, the Group has entered into cross currency interest rate swaps to mitigate currency exposures.
Recognition date	At the date the instrument is entered into.
Measurement	Measured at fair value.
Fair value approach	Based on internal valuations using standard valuation techniques with current market inputs, including interest rates and forward commodity prices; and exchange rates. Quoted market prices or dealer quotes for similar instruments are used for long-term debt instruments held.

F-65

	Fair value hedges	Cash flow hedges
How are changes in fair value accounted for?	The following changes in the fair value are recognised immediately in the income statement: •   the gain or loss relating to the effective portion of interest rate swaps, hedging fixed rate borrowings, together with the gain or loss in the fair value of the hedged fixed rate borrowings attributable to interest rate risk; •   the gain or loss relating to the ineffective portion of the hedge. If the hedge no longer meets the criteria for hedge accounting, the adjustment to the carrying amount of a hedged item for which the effective interest method is used is amortised to the income statement over the period to maturity using a recalculated effective interest rate.	•   Changes in the fair value of derivatives designated as cash flow hedges are recognised directly in other comprehensive income and accumulated in equity in the hedging reserve to the extent that the hedge is highly effective. •   To the extent that the hedge is ineffective, changes in fair value are recognised immediately in the income statement. •   Amounts accumulated in equity are transferred to the income statement or the balance sheet for a non-financial asset at the same time as the hedged item is recognised. •   When a hedging instrument expires or is sold, terminated or exercised, or when a hedge no longer meets the criteria for hedge accounting, any cumulative gain or loss existing in equity at that time remains in equity and is recognised when the underlying forecast transaction occurs. •   When a forecast transaction is no longer expected to occur, the cumulative gain or loss that was reported in equity is immediately transferred to the income statement.

Certain derivative instruments do not qualify for hedge accounting. Changes in the fair value of any derivative instrument that does not qualify for hedge accounting are recognised immediately in the income statement.

F-66

Valuation hierarchy

The carrying amount of financial assets and liabilities measured at fair value is principally calculated based on inputs other than quoted prices that are observable for these financial assets or liabilities, either directly (i.e. as unquoted prices) or indirectly (i.e. derived from prices). Where no price information is available from a quoted market source, alternative market mechanisms or recent comparable transactions, fair value is estimated based on the Group’s views on relevant future prices, net of valuation allowances to accommodate liquidity, modelling and other risks implicit in such estimates.

The inputs used in fair value calculations are determined by the relevant segment or function. The functions support the assets and operate under a defined set of accountabilities authorised by the Executive Leadership Team. Movements in the fair value of financial assets and liabilities may be recognised through the income statement or in other comprehensive income.

For financial assets and liabilities carried at fair value, the Group uses the following to categorise the method used:

Fair value hierarchy	Level 1	Level 2	Level 3
Valuation method	Based on quoted prices (unadjusted) in active markets for identical financial assets and liabilities.	Based on inputs other than quoted prices included within Level 1 that are observable for the financial asset or liability, either directly (i.e. as unquoted prices) or indirectly (i.e. derived from prices).	Based on inputs not observable in the market using appropriate valuation models, including discounted cash flow modelling.

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The financial assets and liabilities are presented by class in the tables below at their carrying amounts, which generally approximate to fair value. In the case of US$3,019 million (2017: US$3,019 million) of fixed rate debt not swapped to floating rate, the fair value at 30 June 2018 was US$3,434 million (2017: US$3,523 million).

2018 US$M

Loans and receivables

Available for sale securities

Held at fair value through profit or loss

Cash flow hedges

Other financial assets and liabilities at amortised cost

Total

Fair value hierarchy (1)

Level 3

Levels 1,2 & 3

Level 2

Current cross currency and interest rate swaps

–

–

12

–

–

12

Current other derivative contracts (2)

–

–

170

–

–

170

Current available for sale shares and other investments (3)(4)

–

–

18

–

–

18

Non-current cross currency and interest rate swaps

–

–

423

(27

)

–

396

Non-current other derivative contracts (2)

–

–

195

–

–

195

Non-current available for sale shares and other investments (3)(4)(5)

–

80

328

–

–

408

Total other financial assets

–

80

1,146

(27

)

–

1,199

Cash and cash equivalents

15,871

–

–

–

–

15,871

Trade and other receivables (6)

1,799

–

1,126

–

–

2,925

Loans to equity accounted investments

13

–

–

–

–

13

Total financial assets

17,683

80

2,272

(27

)

–

20,008

Non-financial assets

91,985

Total assets

111,993

Current cross currency and interest rate swaps

–

–

171

(50

)

–

121

Current other derivative contracts (2)(7)

–

–

17

–

–

17

Non-current cross currency and interest rate swaps

–

–

298

794

–

1,092

Non-current other derivative contracts (2)(7)

–

–

1

–

–

1

Total other financial liabilities

–

–

487

744

–

1,231

Trade and other payables (8)

–

–

377

–

5,414

5,791

Bank overdrafts and short-term borrowings (9)

–

–

–

–

58

58

Bank loans (9)

–

–

–

–

2,555

2,555

Notes and debentures (9)

–

–

–

–

23,298

23,298

Finance leases

–

–

–

–

802

802

Other (9)

–

–

–

–

92

92

Total financial liabilities

–

–

864

744

32,219

33,827

Non-financial liabilities

17,496

Total liabilities

51,323

F-68

2017 US$M

Loans and receivables

Available for sale securities

Held at fair value through profit or loss

Cash flow hedges

Other financial assets and liabilities at amortised cost

Total

Fair value hierarchy (1)

Level 3

Levels 1,2 & 3

Level 2

Current other derivative contracts (2)

–

–

41

–

–

41

Current available for sale shares and other investments (3) (4)

–

–

31

–

–

31

Non-current cross currency and interest rate swaps

–

–

578

27

–

605

Non-current other derivative contracts (2)

–

–

332

–

–

332

Non-current available for sale shares and other investments (3) (4) (5)

–

70

274

–

–

344

Total other financial assets

–

70

1,256

27

–

1,353

Cash and cash equivalents

14,153

–

–

–

–

14,153

Trade and other receivables (6)

1,813

–

920

–

–

2,733

Loans to equity accounted investments

644

–

–

–

–

644

Total financial assets

16,610

70

2,176

27

–

18,883

Non-financial assets

98,123

Total assets

117,006

Current cross currency and interest rate swaps

–

–

(4

)

254

–

250

Current other derivative contracts (2) (7)

–

–

144

–

–

144

Non-current cross currency and interest rate swaps

–

–

42

1,053

–

1,095

Non-current other derivative contracts (2) (7)

–

–

4

7

–

11

Total other financial liabilities

–

–

186

1,314

–

1,500

Trade and other payables (8)

–

–

502

–

4,920

5,422

Bank overdrafts and short-term borrowings (9)

–

–

–

–

45

45

Bank loans (9)

–

–

–

–

2,281

2,281

Notes and debentures (9)

–

–

–

–

27,041

27,041

Finance leases

–

–

–

–

897

897

Other (9)

–

–

–

–

210

210

Total financial liabilities

–

–

688

1,314

35,394

37,396

Non-financial liabilities

16,884

Total liabilities

54,280

⁽¹⁾ All of the Group’s financial assets and financial liabilities recognised at fair value were valued using market observable inputs categorised as Level 2 with the exception of the specified items in the following footnotes.

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⁽²⁾ Includes other derivative contracts of US$213 million (2017: US$365 million) categorised as Level 3.

⁽³⁾  Includes investments held by BHP Billiton Foundation which are restricted and not available for general use by the Group of US$343 million (2017: US$304 million).

⁽⁴⁾  Includes other investments held at fair value through profit or loss (US Treasury Notes) of US$108 million categorised as Level 1 (2017: US$97 million).

⁽⁵⁾  Includes shares and other investments available for sale of US$80 million (2017: US$70 million) categorised as Level 3.

⁽⁶⁾  Excludes input taxes of US$338 million (2017: US$262 million) included in other receivables. Refer to note 7 ‘Trade and other receivables’.

⁽⁷⁾  Includes US$nil (2017: US$7 million) natural gas futures contracts used by the Group to mitigate price risk designated as cash flow hedges.

⁽⁸⁾  Excludes input taxes of US$189 million (2017: US$134 million) included in other payables. Refer to note 8 ‘Trade and other payables’.

⁽⁹⁾  All interest bearing liabilities, excluding finance leases, are unsecured.

For financial instruments that are carried at fair value on a recurring basis, the Group determines whether transfers have occurred between levels in the hierarchy by reassessing categorisation (based on the lowest level input that is significant to the fair value measurement as a whole) at the end of each reporting period. There were no transfers between categories during the period.

For financial instruments not valued at fair value on a recurring basis, the Group uses a method that can be categorised as Level 2.

Offsetting financial assets and liabilities

The Group enters into derivative transactions under International Swaps and Derivatives Association Master Agreements that do not meet the criteria for offsetting, but allow for the related amounts to be set-off in certain circumstances. The amounts set out as cross currency and interest rate swaps in the table above represent the derivative financial assets and liabilities of the Group that may be subject to the above arrangements and are presented on a gross basis.

F-70

Interest bearing liabilities and related derivatives

The movement in the year in the Group’s interest bearing liabilities and related derivatives is as follows:

2018 US$M	Interest bearing liabilities														Derivatives (assets)/ liabilities
	Bank loans			Notes and debentures			Finance leases			Bank overdraft and short- term borrowings		Other			Cross currency and interest rate swaps			Total
At the beginning of the financial year		2,281			27,041			897			45		210			740
Proceeds from interest bearing liabilities		500			–			–			–		28			–			528
Settlements of debt related instruments		–			–			–			–		–			(218	)		(218	)
Repayment of interest bearing liabilities		(221	)		(3,736	)		(81	)		–		(150	)		–			(4,188	)
Change from Net financing cash flows		279			(3,736	)		(81	)		–		(122	)		(218	)		(3,878	)
Other movements:
Interest rate impacts		–			(353	)		–			–		–			329
Foreign exchange impacts		–			245			(9	)		–		–			(254	)
Other interest bearing liabilities/derivative related changes		(5	)		101			–			13		4			208
Liabilities transferred to held for sale		–			–			(5	)		–		–			–
At the end of the financial year		2,555			23,298			802			58		92			805

Recognition and measurement

Financial assets and liabilities are offset and the net amount reported in the balance sheet where the Group currently has a legally enforceable right to offset the recognised amounts and there is an intention to settle on a net basis or realise the asset and settle the liability simultaneously.

F-71

Employee matters

21    Key management personnel

Key management personnel compensation comprises:

	2018		2017		2016
	US$		US$		US$
Short-term employee benefits		13,190,838		16,439,948		14,979,983
Post-employment benefits		1,506,108		1,895,828		2,356,594
Share-based payments		13,356,657		13,747,355		16,837,179
Total		28,053,603		32,083,131		34,173,756

Following the dissolution of the Operations Management Committee (OMC) in FY2018, the Remuneration Committee re-examined the classification of Key Management Personnel (KMP) for FY2018 and determined that the roles which have the authority and responsibility for planning, directing and controlling the activities of BHP are Non-executive Directors, the CEO, the Chief Financial Officer, the President Operations, Minerals Australia, the President Operations, Minerals Americas, and the President Operations, Petroleum. The Remuneration Committee also determined that, effective 1 July 2017 the Chief External Affairs Officer and Chief People Officer roles are no longer considered KMP.

Transactions and outstanding loans/amounts with key management personnel

There were no purchases by key management personnel from the Group during the financial year (2017: US$ nil; 2016: US$ nil).

There were no amounts payable by key management personnel at 30 June 2018 (2017: US$ nil; 2016: US$ nil).

There were no loans receivable from or payable to key management personnel at 30 June 2018 (2017: US$ nil; 2016: US$ nil).

Transactions with personally related entities

A number of Directors of the Group hold or have held positions in other companies (personally related entities) where it is considered they control or significantly influence the financial or operating policies of those entities. There were no transactions with those entities and no amounts were owed by the Group to personally related entities at 30 June 2018 (2017: US$ nil; 2016: US$ nil).

For more information on remuneration and transactions with key management personnel, refer to section 3.

22    Employee share ownership plans

Awards, in the form of the right to receive ordinary shares in either BHP Billiton Limited or BHP Billiton Plc, have been granted under the following employee share ownership plans: Long-Term Incentive Plan (LTIP), Short-Term Incentive Plan (STIP), Management Award Plan (MAP), Group Short-Term Incentive Plan (GSTIP), Transitional Executive KMP awards and the all-employee share plan, Shareplus.

Some awards are eligible to receive a cash payment, or the equivalent value in shares, equal to the dividend amount that would have been earned on the underlying shares awarded to those participants (the Dividend Equivalent Payment, or DEP). The DEP is provided to the participants once the underlying shares are allocated or transferred to them. Awards under the plans do not confer any rights to participate in a share issue; however, there is discretion under each of the plans to adjust the awards in response to a variation in the share capital of BHP Billiton Limited or BHP Billiton Plc.

F-72

The table below provides a description of each of the plans.

Plan	STIP and GSTIP	LTIP and MAP	Transitional Executive KMP awards	Shareplus
Type	Short-term incentive	Long-term incentive	Long-term incentive	All-employee share purchase plan
Overview	The STIP is a plan for the Executive KMP and the GSTIP is a plan for BHP senior management who are not KMP. Under both plans, half of the value of a participant’s short-term incentive amount is awarded as rights to receive BHP Billiton Limited or BHP Billiton Plc shares at the end of the vesting period.	The LTIP is a plan for Executive KMP and awards are granted annually. The MAP is a plan for BHP senior management who are not KMP. The number of share rights awarded is determined by a participant’s role and grade.	Awards may be granted to new Executive KMP recruited from within the Group to bridge the gap created by the different timeframes of the vesting of MAP awards, granted in their non-KMP role, and LTIP awards, granted to Executive KMP. No Transitional awards were granted to Executive KMP in FY2018.	Employees may contribute up to US$5,000 to acquire shares in any plan year. On the third anniversary of the start of a plan year, the Group will match the number of acquired shares.
Vesting conditions	Service condition only.	LTIP: Service and performance conditions. For awards granted from December 2013 onwards, BHP’s Total Shareholder Return (TSR)(1) performance relative to the Peer Group TSR over a five-year performance period determines the vesting of 67 per cent of the awards, while performance relative to the Index TSR (being the index value where the comparator group is a market index) determines the vesting of 33 per cent of the awards. For the awards to vest in full, BHP’s TSR(1) must exceed the Peer Group TSR and Index TSR (if applicable) by a specified percentage per year, determined for each grant by the Remuneration Committee. Since the establishment of the LTIP in 2004, this percentage has been set at 5.5 per cent per year. MAP: Service conditions only.	Service conditions and performance conditions. The Remuneration Committee has absolute discretion to determine if the performance condition has been met and whether any, all or part of the award will vest (or otherwise lapse), having regard to (but not limited to) the BHP’s TSR(1) over the three- or four-year performance period (respectively), the participant’s contribution to Group outcomes and the participant’s personal performance (with guidance on this assessment from the CEO).	Service conditions only.

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Plan	STIP and GSTIP	LTIP and MAP	Transitional Executive KMP awards	Shareplus
Vesting period	2 years	LTIP – 5 years MAP – 1 to 5 years	3 years or 4 years	3 years
Dividend Equivalent Payment	Yes, except GSTIP awards granted after 1 July 2011	Yes, except MAP granted after 1 July 2011	No	No
Exercise period	None	LTIP – None MAP – None	None	None

⁽¹⁾ BHP’s TSR is the weighted average of the TSRs of BHP Billiton Limited and BHP Billiton Plc.

Employee share awards

2018	Number of awards at the beginning of the financial year		Number of awards issued during the year		Number of awards vested and exercised		Number of awards lapsed		Number of awards at the end of the financial year		Number of awards vested and exercisable at the end of the financial year		Weighted average remaining contractual life (years)
BHP Billiton Limited
STIP awards		497,634		274,743		464,349		–		308,028		–		1.0
GSTIP awards		2,001,583		1,422,338		1,383,656		31,810		2,008,455		28,981		0.8
LTIP awards		4,679,513		1,523,309		65,247		156,600		5,980,975		–		2.5
Transitional OMC awards		137,194		–		61,485		28,869		46,840		–		0.7
MAP awards		7,348,428		5,731,891		2,185,614		515,442		10,379,263		60,134		1.5
Shareplus		5,998,517		2,483,091		3,184,545		521,984		4,775,079		–		1.2
Employee Share Plan shares (legacy plan)		338,883		–		338,883		–		–		–		n/a
BHP Billiton Plc
GSTIP awards		84,250		40,957		59,577		1,762		63,868		–		0.8
LTIP awards		386,912		–		74,988		311,924		–		–		n/a
MAP awards		596,443		133,926		406,783		8,135		315,451		–		1.3
Shareplus		336,108		137,832		165,450		26,331		282,159		–		1.2

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Fair value and assumptions in the calculation of fair value for awards issued

2018	Weighted average fair value of awards granted during the year US$		Risk-free interest rate			Estimated life of awards		Share price at grant date		Estimated volatility of share price			Dividend yield
BHP Billiton Limited
STIP awards		20.65		n/a			3 years		A$27.97		n/a			n/a
GSTIP awards		18.83		n/a			3 years		A$25.98		n/a			4.30	%
LTIP awards		13.11		2.08	%		5 years		A$27.97		33.0	%		n/a
MAP awards		18.37		n/a			1-2-3 years		A$25.98		n/a			4.30	%
Shareplus		18.12		1.85	%		3 years		A$24.00		n/a			4.33	%
BHP Billiton Plc
GSTIP awards		16.48		n/a			3 years		£13.29		n/a			5.10	%
MAP awards		15.62		n/a			1-2-3 years		£13.29		n/a			5.10	%
Shareplus		13.48		0.17	%		3 years		£12.34		n/a			5.10	%

Employee share awards expense is US$123.313 million (2017: US$106.214 million; 2016: US$140.445 million). ⁽¹⁾

⁽¹⁾  Total employee share awards expense includes Onshore US. Refer to note 4 ‘Expenses and other income’ employee share awards for continuing operations.

Recognition and measurement

The fair value at grant date of equity-settled share awards is charged to the income statement over the period for which the benefits of employee services are expected to be derived. The fair values of awards granted were estimated using a Monte Carlo simulation methodology and Black-Scholes option pricing technique and consider the following factors:

• exercise price;

• expected life of the award;

• current market price of the underlying shares;

• expected volatility using an analysis of historic volatility over different rolling periods. For the LTIP, it is calculated for all sector comparators and the published MSCI World index;

• expected dividends;

• risk-free interest rate, which is an applicable government bond rate;

• market-based performance hurdles;

• non-vesting conditions.

Where awards are forfeited because non-market-based vesting conditions are not satisfied, the expense previously recognised is proportionately reversed.

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The tax effect of awards granted is recognised in income tax expense, except to the extent that the total tax deductions are expected to exceed the cumulative remuneration expense. In this situation, the excess of the associated current or deferred tax is recognised in other comprehensive income and forms part of the employee share awards reserve. The fair value of awards as presented in the tables above represents the fair value at grant date.

In respect of employee share awards, the Group utilises the Billiton Employee Share Ownership Trust and the BHP Billiton Limited Employee Equity Trust. The trustees of these trusts are independent companies, resident in Jersey. The trusts use funds provided by the Group to acquire ordinary shares to enable awards to be made or satisfied. The ordinary shares may be acquired by purchase in the market or by subscription at not less than nominal value. The BHP Billiton Limited Employee Equity Trust has waived its rights to current and future dividends on shares held to meet future awards under the plans.

23    Employee benefits, restructuring and post-retirement employee benefits provisions

	2018		2017
	US$M		US$M
Employee benefits (1)		1,232		1,177
Restructuring (2)		8		10
Post-retirement employee benefits		449		438
Total provisions		1,689		1,625
Comprising:
Current		1,148		1,062
Non-current		541		563

2018	Employee benefits			Restructuring			Post- retirement employee benefits (3)			Total
	US$M			US$M			US$M			US$M
At the beginning of the financial year		1,177			10			438			1,625
Charge/(credit) for the year:
Underlying		1,073			6			22			1,101
Discounting		–			–			34			34
Net interest expense		–			–			(15	)		(15	)
Exchange variations		(29	)		–			5			(24	)
Released during the year		(31	)		(1	)		–			(32	)
Remeasurement gains taken to retained earnings		–			–			(1	)		(1	)
Utilisation		(958	)		(7	)		(34	)		(999	)
At the end of the financial year		1,232			8			449			1,689

⁽¹⁾  The expenditure associated with total employee benefits will occur in a pattern consistent with when employees choose to exercise their entitlement to benefits.

⁽²⁾  Total restructuring provisions include provisions for terminations and office closures.

⁽³⁾  Refer to note 24 ‘Pension and other post-retirement obligations’.

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Recognition and measurement

Provisions are recognised by the Group when:

• there is a present legal or constructive obligation as a result of past events;

• it is more likely than not that a permanent outflow of resources will be required to settle the obligation;

• the amount can be reliably estimated and measured at the present value of management’s best estimate of the cash outflow required to settle the obligation at reporting date.

Provision	Description
Employee benefits	Liabilities for annual leave and any accumulating sick leave accrued up until the reporting date that are expected to be settled within 12 months are measured at the amounts expected to be paid when the liabilities are settled. Liabilities for long service leave are measured as the present value of estimated future payments for the services provided by employees up to the reporting date and disclosed within employee benefits. Liabilities that are not expected to be settled within 12 months are discounted at the reporting date using market yields of high-quality corporate bonds or government bonds for countries where there is no deep market for corporate bonds. The rates used reflect the terms to maturity and currency that match, as closely as possible, the estimated future cash outflows. In relation to industry-based long service leave funds, the Group’s liability, including obligations for funding shortfalls, is determined after deducting the fair value of dedicated assets of such funds. Liabilities for unpaid wages and salaries are recognised in other creditors.
Restructuring	Restructuring provisions are recognised when: •   the Group has a detailed formal plan identifying the business or part of the business concerned, the location and approximate number of employees affected, a detailed estimate of the associated costs, and an appropriate timeline; •   the restructuring has either commenced or been publicly announced and can no longer be withdrawn. Payments falling due greater than 12 months after the reporting date are discounted to present value.

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24    Pension and other post-retirement obligations

The Group operates or participates in a number of pension (including superannuation) schemes throughout the world. The funding of the schemes complies with local regulations. The assets of the schemes are generally held separately from those of the Group and are administered by trustees or management boards.

Schemes/Obligations	Description
Defined contribution pension schemes and multi-employer pension schemes	For defined contribution schemes or schemes operated on an industry-wide basis where it is not possible to identify assets attributable to the participation by the Group’s employees, the pension charge is calculated on the basis of contributions payable. The Group contributed US$277 million during the financial year (2017: US$247 million; 2016: US$232 million) to defined contribution plans and multi-employer defined contribution plans. These contributions are expensed as incurred.
Defined benefit pension schemes	For defined benefit pension schemes, the cost of providing pensions is charged to the income statement so as to recognise current and past service costs, net interest cost on the net defined benefit obligations/plan assets and the effect of any curtailments or settlements. Remeasurement gains and losses are recognised directly in equity. An asset or liability is consequently recognised in the balance sheet based on the present value of defined benefit obligations less the fair value of plan assets, except that any such asset cannot exceed the present value of expected refunds from and reductions in future contributions to the plan. Defined benefit obligations are estimated by discounting expected future payments using market yields at the reporting date on high-quality corporate bonds in countries that have developed corporate bond markets. However, where developed corporate bond markets do not exist, the discount rates are selected by reference to national government bonds. In both instances, the bonds are selected with terms to maturity and currency that match, as closely as possible, the estimated future cash flows. The Group has closed all defined benefit pension schemes to new entrants. Defined benefit pension schemes remain operating in Australia, the United States, Canada and Europe for existing members. Full actuarial valuations are prepared and updated annually to 30 June by local actuaries for all schemes. The Group operates final salary schemes (that provide final salary benefits only), non-salary related schemes (that provide flat dollar benefits) and mixed benefit schemes (that consist of a final salary defined benefit portion and a defined contribution portion).
Defined benefit post-retirement medical schemes	The Group operates a number of post-retirement medical schemes in the United States, Canada and Europe and certain Group companies provide post-retirement medical benefits to qualifying retirees. In some cases, the benefits are provided through medical care schemes to which the Group, the employees, the retirees and covered family members contribute. Full actuarial valuations are prepared by local actuaries for all schemes. These schemes are recognised on the same basis as described for defined benefit pension schemes. All of the post-retirement medical schemes in the Group are unfunded.
Defined benefit post-employment obligations	The Group has a legal obligation to provide post-employment benefits to employees in Chile. The benefit is a function of an employee’s final salary and years of service. These obligations are recognised on the same basis as described for defined benefit pension schemes. Full actuarial valuations are prepared by local actuaries. These post-employment obligations are unfunded.

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Risk

The Group’s defined benefit schemes/obligations expose the Group to a number of risks, including asset value volatility, interest rate variations, inflation, longevity and medical expense inflation risk.

Recognising this, the Group has adopted an approach of moving away from providing defined benefit pensions. The majority of Group-sponsored defined benefit pension schemes have been closed to new entrants for many years. Existing benefit schemes and the terms of employee participation in these schemes are reviewed on a regular basis.

Fund assets

The Group follows a coordinated strategy for the funding and investment of its defined benefit pension schemes (subject to meeting all local requirements). The Group’s aim is for the value of defined benefit pension scheme assets to be maintained at close to the value of the corresponding benefit obligations, allowing for some short-term volatility.

Scheme assets are invested in a diversified range of asset classes, predominantly comprising bonds and equities.

The Group’s aim is to progressively shift defined benefit pension scheme assets towards investments that match the anticipated profile of the benefit obligations, as funding levels improve and benefit obligations mature. Over time, this is expected to result in a further reduction in the total exposure of pension scheme assets to equity markets. For pension schemes that pay lifetime benefits, the Group may consider and support the purchase of annuities to back these benefit obligations if it is commercially sensible to do so.

Net liability recognised in the Consolidated Balance Sheet

The net liability recognised in the Consolidated Balance Sheet is as follows:

	Defined benefit pension schemes/post- employment obligations						Post-retirement medical schemes
	2018			2017			2018		2017
	US$M			US$M			US$M		US$M
Present value of funded defined benefit obligation		616			665			–		–
Present value of unfunded defined benefit obligation		274			256			192		204
Fair value of defined benefit scheme assets		(633	)		(687	)		–		–
Scheme deficit		257			234			192		204
Unrecognised surplus		–			–			–		–
Unrecognised past service credits		–			–			–		–
Adjustment for employer contributions tax		–			–			–		–
Net liability recognised in the Consolidated Balance Sheet		257			234			192		204

The Group has no legal obligation to settle these liabilities with any immediate contributions or additional one-off contributions. The Group intends to continue to contribute to each defined benefit pension and post-retirement medical scheme in accordance with the latest recommendations of each scheme actuary.

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25    Employees

	2018		2017		2016
	Number		Number		Number
Average number of employees (1)
Australia		16,504		15,906		15,834
South America		6,729		6,361		6,509
North America		1,839		2,072		2,748
Asia		1,368		1,019		822
Europe		70		74		61
Total average number of employees from Continuing operations		26,510		25,432		25,974
Total average number of employees from Discontinued operations		651		714		853
Total average number of employees		27,161		26,146		26,827

⁽¹⁾  Average employee numbers include the Executive Director, 100 per cent of employees of subsidiary companies and our share of employees of joint operations. Employees of equity accounted investments are not included. Part-time employees are included on a full-time equivalent basis. Employees of businesses disposed of during the year are included for the period of ownership. Contractors are not included.

Group and related party information

26    Discontinued operations

On 27 July 2018 BHP announced that it had entered into agreements for the sale of its entire interests in its Eagle Ford, Haynesville, Permian and Fayetteville Onshore US oil and gas assets for a combined base consideration of US$10.8 billion, payable in cash.

BP American Production Company, a wholly owned subsidiary of BP Plc, has agreed to acquire 100 per cent of the issued share capital of Petrohawk Energy Corporation, the BHP subsidiary which holds the Eagle Ford (being Black Hawk and Hawkville), Haynesville and Permian assets, for a consideration of US$10.5 billion (less customary completion adjustments), comprising 50 per cent paid in cash at completion and 50 per cent in deferred consideration, payable in cash over a six month period.

MMGJ Hugoton III, LLC, a company owned by Merit Energy Company, has agreed to acquire 100 per cent of the issued share capital of BHP Billiton Petroleum (Arkansas) Inc. and 100 per cent of the membership interests in BHP Billiton Petroleum (Fayetteville) LLC, which hold the Fayetteville assets, for a total consideration of US$0.3 billion (less customary completion adjustments), paid in cash at completion.

Both sales are subject to the satisfaction of customary regulatory approvals and conditions precedent and are expected to complete by the end of October 2018.

Significant joint operations that have been classified as assets and liabilities held for sale are listed below:

Significant joint operations	Country of operation		Group interest (1)
		Principal activity	2018 %		2017 %
Eagle Ford	US	Hydrocarbons exploration and production		<1-100		<1-100
Fayetteville	US	Hydrocarbons exploration and production		<1-100		<1-100
Haynesville	US	Hydrocarbons exploration and production		<1-100		<1-100
Permian	US	Hydrocarbons exploration and production		<1-100		<1-100

⁽¹⁾ Ranges reflect the Group’s interest in multiple joint arrangements within the joint operation.

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The contribution of Discontinued operations included within the Group’s profit and cash flows are detailed below:

Income statement – Discontinued operations

	2018			2017			2016
	US$M			US$M			US$M
Revenue		2,171			2,150			2,345
Other income		34			74			12
Expenses excluding net finance costs		(5,790	)		(3,025	)		(11,396	)
Loss from operations		(3,585	)		(801	)		(9,039	)
Financial expenses		(22	)		(14	)		(11	)
Net finance costs		(22	)		(14	)		(11	)
Loss before taxation		(3,607	)		(815	)		(9,050	)
Income tax benefit		686			343			3,155
Loss after taxation		(2,921	)		(472	)		(5,895	)
Attributable to non-controlling interests		26			13			(49	)
Attributable to BHP shareholders		(2,947	)		(485	)		(5,846	)
Basic loss per ordinary share (cents)		(55.4	)		(9.1	)		(109.8	)
Diluted loss per ordinary share (cents)		(55.4	)		(9.1	)		(109.8	)

The total comprehensive income attributable to BHP shareholders from Discontinued operations was a loss of US$2,943 million (2017: loss of US$489 million; 2016: loss of US$5,846 million).

The conversion of options and share rights would decrease the loss per share for the years ended 30 June 2018, 2017 and 2016 and therefore its impact has been excluded from the diluted earnings per share calculation.

Cash flows from Discontinued operations

	2018			2017			2016
	US$M			US$M			US$M
Net operating cash flows		900			928			785
Net investing cash flows (1)		(861	)		(437	)		(1,227	)
Net financing cash flows (2)		(40	)		(28	)		(32	)
Net (decrease)/increase in cash and cash equivalents from Discontinued operations		(1	)		463			(474	)

⁽¹⁾  Includes purchases of property, plant and equipment of US$900 million (2017: US$555 million; 2016: US$1,239 million), capitalised exploration of US$ nil (2017: US$ nil; 2016: US$2 million) less proceeds from sale of assets of US$39 million (2017: US$118 million; 2016: US$14 million).

⁽²⁾  Includes net repayment of interest bearing liabilities of US$4 million (2017: US$6 million; 2016: US$7 million), distribution/(contribution) to non-controlling interests of US$14 million (2017: US$16 million; 2016: US$(1) million) and dividends paid to non-controlling interests of US$22 million (2017: US$6 million; 2016: US$26 million).

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Assets and liabilities held for sale

The assets and liabilities classified as current assets and liabilities held for sale are presented in the table below:

	2018
	US$M
Assets
Trade and other receivables		529
Other financial assets		2
Inventories		36
Property, plant and equipment		10,672
Intangible assets		667
Other		33
Total assets		11,939
Liabilities
Trade and other payables		725
Interest bearing liabilities		5
Other financial liabilities		3
Provisions		489
Total liabilities		1,222
Net assets		10,717

Exceptional items – Discontinued operations

Exceptional items are those gains or losses where their nature, including the expected frequency of the events giving rise to them, and amount is considered material to the Financial Statements. Such items related to Discontinued operations included within the Group’s profit for the year are detailed below:

Year ended 30 June 2018	Gross			Tax		Net
	US$M			US$M		US$M
Exceptional items by category
US tax reform		–			492		492
Impairment of Onshore US assets		(2,859	)		109		(2,750	)
Total		(2,859	)		601		(2,258	)
Attributable to non-controlling interests		–			–		–
Attributable to BHP shareholders		(2,859	)		601		(2,258	)

US tax reform

On 22 December 2017, the US President signed the Tax Cuts and Jobs Act (TCJA) into law. The TCJA (effective 1 January 2018) includes a broad range of tax reforms affecting the Group, including, but not limited to, a reduction in the US corporate tax rate from 35 per cent to 21 per cent and changes to international tax provisions. As a result of the TCJA, the Group has recognised an exceptional income tax benefit of US$492 million relating to the re-measurement of the Onshore US deferred tax positions arising from temporary differences.

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Impairment of Onshore US assets

For the purposes of assessing impairment, assets are grouped at the lowest levels for which there are separately identifiable cash flows. At 30 June 2018, the Onshore US assets, including goodwill, have been allocated to two CGUs reflecting the separately identifiable cash flows expected from the divestment of the assets.

The Group recognised impairment charges as follows:

Cash generating unit	Property, plant and equipment			Goodwill			Total
	US$M			US$M			US$M
Petrohawk		–			(2,253	)		(2,253	)
Fayetteville		(520	)		(86	)		(606	)
Total impairment of non-current assets		(520	)		(2,339	)		(2,859	)

The charges reflect a robust and competitive exit process with fair value based on the agreed sales consideration (Level 2 of the fair value hierarchy) less expected costs of disposal.

In previous reporting periods the Group performed impairment testing of the five individual Onshore US assets as each asset had separately identifiable cash flows. In addition, the goodwill attributable to the Onshore US group of CGUs (2017: US$3,022 million) was tested for impairment after the assessment of the individual CGUs. The recoverable amount determinations for the Onshore US CGUs were based on FVLCD using discounted cash flow techniques. The FVLCD calculations were based primarily on Level 3 inputs and significant assumptions included management’s assessment of a market participant’s perspective of crude oil and natural gas prices, production volumes and discount rates.

Year ended 30 June 2017

There were no exceptional items related to Discontinued operations for the year ended 30 June 2017.

Year ended 30 June 2016	Gross			Tax		Net
	US$M			US$M		US$M
Exceptional items by category
Impairment of Onshore US assets		(7,184	)		2,300		(4,884	)
Total		(7,184	)		2,300		(4,884	)
Attributable to non-controlling interests		(80	)		29		(51	)
Attributable to BHP shareholders		(7,104	)		2,271		(4,833	)

Impairment of Onshore US assets

The Group recognised an impairment charge of US$4,884 million (after tax benefit) against the carrying value of its Onshore US assets in the year ended 30 June 2016. The impairment reflects changes to price assumptions, discount rates and development plans. This follows significant volatility and much weaker prices experienced in the oil and gas industry, which have more than offset the Group’s substantial productivity improvements.

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27    Subsidiaries

Significant subsidiaries of the Group are those with the most significant contribution to the Group’s net profit or net assets. The Group’s interest in the subsidiaries results are listed in the table below. For a complete list of the Group’s subsidiaries, refer to Exhibit 8.1 – List of Subsidiaries.

Significant subsidiaries	Country of incorporation		Group interest
		Principal activity	2018 %		2017 %
Coal
BHP Billiton Mitsui Coal Pty Ltd	Australia	Coal mining		80		80
Hunter Valley Energy Coal Pty Ltd	Australia	Coal mining		100		100
Copper
BHP Billiton Olympic Dam Corporation Pty Ltd	Australia	Copper and uranium mining		100		100
Compañía Minera Cerro Colorado Limitada	Chile	Copper mining		100		100
Minera Escondida Limitada (1)	Chile	Copper mining		57.5		57.5
Minera Spence S.A.	Chile	Copper mining		100		100
Iron Ore
BHP Billiton Iron Ore Pty Ltd	Australia	Service company		100		100
BHP Billiton Minerals Pty Ltd	Australia	Iron ore and coal mining		100		100
BHP Iron Ore (Jimblebar) Pty Ltd (2)	Australia	Iron ore mining		85		85
BHP Billiton (Towage Service) Pty Ltd	Australia	Freight services		100		100
Marketing
BHP Billiton Freight Singapore Pte Limited	Singapore	Freight services		100		100
BHP Billiton Marketing AG	Switzerland	Marketing and trading		100		100
BHP Billiton Marketing Asia Pte Ltd	Singapore	Marketing support and other services		100		100
Group and Unallocated
BHP Billiton Canada Inc.	Canada	Potash development		100		100
BHP Billiton Finance BV	The Netherlands	Finance		100		100
BHP Billiton Finance Limited	Australia	Finance		100		100
BHP Billiton Finance (USA) Ltd	Australia	Finance		100		100
BHP Billiton Group Operations Pty Ltd	Australia	Administrative services		100		100
BHP Billiton International Services Ltd	UK	Service company		100		100
BHP Billiton Nickel West Pty Ltd	Australia	Nickel mining, smelting, refining and administrative services		100		100
WMC Finance (USA) Limited	Australia	Finance		100		100

⁽¹⁾ As the Group has the ability to direct the relevant activities at Minera Escondida Limitada, it has control over the entity. The assessment of the most relevant activity in this contractual arrangement is subject to judgement. The Group establishes the mine plan and the operating budget and has the ability to appoint the key management personnel, demonstrating that the Group has the existing rights to direct the relevant activities of Minera Escondida Limitada.

⁽²⁾ The Group has an effective interest of 92.5 per cent in BHP Iron Ore (Jimblebar) Pty Ltd; however, by virtue of the shareholder agreement with ITOCHU Minerals & Energy of Australia Pty Ltd and Mitsui & Co. Iron Ore Exploration & Mining Pty Ltd, the Group’s interest in the Jimblebar mining operation is 85 per cent, which is consistent with the other respective contractual arrangements at Western Australia Iron Ore.

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28    Investments accounted for using the equity method

Significant interests in equity accounted investments of the Group are those with the most significant contribution to the Group’s net profit or net assets. The Group’s ownership interest in equity accounted investments results are listed in the table below. For a complete list of the Group’s associates and joint ventures, refer to Exhibit 8.1 – List of Subsidiaries.

Significant associates and joint ventures	Country of incorporation/ principal place of business	Associate or joint venture	Principal activity	Reporting date	Ownership interest
					2018 %		2017 %
Cerrejón	Anguilla/ Colombia/Ireland	Associate	Coal mining in Colombia	31 December		33.33		33.33
Compañía Minera Antamina S.A. (Antamina)	Peru	Associate	Copper and zinc mining	31 December		33.75		33.75
Samarco Mineração S.A. (Samarco)	Brazil	Joint venture	Iron ore mining	31 December		50.00		50.00

Voting in relation to relevant activities in Antamina and Cerrejón, determined to be the approval of the operating and capital budgets, does not require unanimous consent of all participants to the arrangement, therefore joint control does not exist. Instead, because the Group has the power to participate in the financial and operating policies of the investee, these investments are accounted for as associates.

Samarco is jointly owned by BHP Billiton Brasil and Vale. As the Samarco entity has the rights to the assets and obligations to the liabilities relating to the joint arrangement and not its owners, this investment is accounted for as a joint venture.

The Group is restricted in its ability to make dividend payments from its investments in associates and joint ventures as any such payments require the approval of all investors in the associates and joint ventures. The ownership interest at the Group’s and the associates’ or joint ventures’ reporting dates are the same. When the annual financial reporting date is different to the Group’s, financial information is obtained as at 30 June in order to report on an annual basis consistent with the Group’s reporting date.

The movement for the year in the Group’s investments accounted for using the equity method is as follows:

Year ended 30 June 2018 US$M	Investment in associates			Investment in joint ventures			Total equity accounted investments
At the beginning of the financial year		2,448			–			2,448
Profit/(loss) from equity accounted investments, related impairments and expenses (1)		656			(509	)		147
Investment in equity accounted investments		62			80			142
Dividends received from equity accounted investments		(693	)		–			(693	)
Other		–			429			429
At the end of the financial year		2,473			–			2,473

⁽¹⁾ US$(509) million represents US$(80) million share of loss from US$(80) million funding provided during the period and US$(429) million movement in the Samarco dam failure provision including US$(560) million change in estimate and US$131 million exchange translation. Refer to note 3 ‘Significant events – Samarco dam failure’ for further information.

F-85

The following table summarises the financial information relating to each of the Group’s significant equity accounted investments. BHP Billiton Brasil’s 50 per cent portion of Samarco’s commitments, for which BHP Billiton Brasil has no funding obligation, is US$550 million (2017: US$750 million).

	Associates									Joint ventures
2018 US$M	Antamina			Cerrejón			Individually immaterial (1)			Samarco (2)			Individually immaterial		Total
Current assets		1,099			1,187						79	(3)
Non-current assets		4,385			2,485						6,023
Current liabilities		(532	)		(585	)					(5,811	) (4)
Non-current liabilities		(1,064	)		(663	)					(4,265	) (5)
Net assets/(liabilities) – 100%		3,888			2,424						(3,974	)
Net assets/(liabilities) – Group share		1,312			808						(1,987	)
Adjustments to net assets related to accounting policy adjustments		1			75						357	(6)
Impairment of the carrying value of the investment in Samarco		–			–						(525	) (7)
Additional share of Samarco losses		–			–						2,092	(8)
Unrecognised losses		–			–						63	(9)
Carrying amount of investments accounted for using the equity method		1,313			883			277			–			–		2,473
Revenue – 100%		4,262			2,453						30
Profit/(loss) from Continuing operations – 100%		1,613			576						(1,558	) (10)
Share of operating profit/(loss) of equity accounted investments		544			192						(823	)
Additional share of Samarco losses		–			–						251
Unrecognised losses		–			–						63	(9)
Profit/(loss) from equity accounted investments, related impairments and expenses		544			192			(80	)		(509	)		–		147
Comprehensive income – 100%		1,613			576						(1,558	)
Share of comprehensive income/(loss) – Group share in equity accounted investments		544			192			(80	)		(509	)		–		147
Dividends received from equity accounted investments		496			181			16			–			–		693

F-86

	Associates									Joint ventures
2017 US$M	Antamina			Cerrejón			Individually immaterial (1)			Samarco (2)			Individually immaterial		Total
Current assets		995			782						174	(3)
Non-current assets		4,273			2,540						6,128
Current liabilities		(530	)		(364	)					(5,236	) (4)
Non-current liabilities		(993	)		(621	)					(3,482	) (5)
Net assets/(liabilities) – 100%		3,745			2,337						(2,416	)
Net assets/(liabilities) – Group share		1,264			779						(1,208	)
Adjustments to net assets related to accounting policy adjustments		1			80						401	(6)
Impairment of the carrying value of the investment in Samarco		–			–						(525	) (7)
Additional share of Samarco losses		–			–						1,332
Carrying amount of investments accounted for using the equity method		1,265			859			324			–			–		2,448
Revenue – 100%		3,317			2,247						28
Profit/(loss) from Continuing operations – 100%		1,010			388						(1,520	) (10)
Share of operating profit/(loss) of equity accounted investments		341			129						(760	)
Additional share of Samarco losses		–			–						588
Profit/(loss) from equity accounted investments, related impairments and expenses		341			129			(26	)		(172	)		–		272
Comprehensive income – 100%		1,010			388						(1,520	)
Share of comprehensive income/(loss) – Group share in equity accounted investments		341			129			(26	)		(172	)		–		272
Dividends received from equity accounted investments		425			163			32			–			–		620

F-87

	Associates								Joint ventures
2016 US$M	Antamina		Cerrejón			Individually immaterial			Samarco (2)			Individually immaterial		Total
Revenue – 100%		2,639		1,575						937
Profit/(loss) from Continuing operations – 100%		606		(73	)					(2,182	)
Share of operating profit/(loss) of equity accounted investments		203		(24	)		(39	)		(1,091	) (11)		–		(951	)
Samarco dam failure provision expense		–		–			–			(628	) (7)		–		(628	)
Impairment of the carrying value of the investment in Samarco		–		–			–			(525	) (7)		–		(525	)
Profit/(loss) from equity accounted investments, related impairments and expenses		203		(24	)		(39	)		(2,244	)		–		(2,104	)
Comprehensive income – 100%		606		(73	)					(2,182	)
Share of comprehensive income/(loss) – Group share in equity accounted investments		203		(24	)		(39	)		(2,244	)		–		(2,104	)
Dividends received from equity accounted investments		233		29			31			–			–		293

⁽¹⁾ The unrecognised share of losses for the period was US$56 million (2017: unrecognised share of profits for the period was US$21 million), which increased the cumulative losses to US$196 million (2017: decrease to US$140 million).

⁽²⁾ Refer to note 3 ‘Significant events – Samarco dam failure’ for further information regarding the financial impact of the Samarco dam failure in November 2015 on BHP Billiton Brasil’s share of Samarco’s losses.

⁽³⁾ Includes cash and cash equivalents of US$23 million (2017: US$29 million).

⁽⁴⁾ Includes current financial liabilities (excluding trade and other payables and provisions) of US$5,066 million (2017: US$4,581 million).

⁽⁵⁾ Includes non-current financial liabilities (excluding trade and other payables and provisions) of US$nil (2017: US$1 million).

⁽⁶⁾ Relates mainly to dividends declared by Samarco that remain unpaid at balance date and which, in accordance with the Group’s accounting policy, are recognised when received not receivable.

⁽⁷⁾ BHP Billiton Brasil has adjusted its investment in Samarco to US$ nil (resulting from US$(655) million share of loss from Samarco and US$(525) million impairment) and recognised a provision of US$(1,200) million for obligations under the Framework Agreement. US$(572) million of the US$(1,200) million provision represents an additional share of loss from Samarco with the remaining US$(628) million recognised as provision expense.

⁽⁸⁾ BHP Billiton Brasil has recognised accumulated additional share of Samarco losses of US($2,092) million resulting from US$(214) million share of loss from funding provided to Samarco and US$(1,878) million relating to obligations under the Framework Agreement, including US$(211) million recognised as net finance costs.

⁽⁹⁾ Share of Samarco’s losses for which BHP Billiton Brasil does not have an obligation to fund.

F-88

⁽¹⁰⁾ Includes depreciation and amortisation of US$73 million (2017: US$88 million; 2016: US$148 million), interest income of US$31 million (2017: US$57 million; 2016: US$43 million), interest expense of US$385 million (2017: US$473 million; 2016: US$209 million) and income tax (expense)/benefit of US$(154) million (2017: US$(851) million; 2016: US$564 million).

⁽¹¹⁾ US$(1,091) million represents US$(1,227) million share of loss relating to the Samarco dam failure (exceptional item) and US$136 million share of operating profit prior to the dam failure.

29    Interests in joint operations

Significant joint operations of the Group are those with the most significant contributions to the Group’s net profit or net assets. The Group’s interest in the joint operations results are listed in the table below. For a list of significant joint operations of the Group classified as ‘held for sale’ refer to note 26 ‘Discontinued operations’. For a complete list of the Group’s investments in joint operations, refer to Exhibit 8.1 – List of Subsidiaries.

			Group interest
Significant joint operations	Country of operation	Principal activity	2018 %		2017 %
Bass Strait	Australia	Hydrocarbons production		50		50
Greater Angostura	Trinidad and Tobago	Hydrocarbons production		45		45
Gulf of Mexico	US	Hydrocarbons exploration and production		23.9–44		23.9–44
Macedon (1)	Australia	Hydrocarbons exploration and production		71.43		71.43
North West Shelf	Australia	Hydrocarbons production		12.5–16.67		12.5–16.67
Pyrenees (1)	Australia	Hydrocarbons exploration and production		40–71.43		40–71.43
ROD Integrated Development (2)	Algeria	Hydrocarbons exploration and production		29.50		29.50
Mt Goldsworthy (3)	Australia	Iron ore mining		85		85
Mt Newman (3)	Australia	Iron ore mining		85		85
Yandi (3)	Australia	Iron ore mining		85		85
Central Queensland Coal Associates	Australia	Coal mining		50		50

⁽¹⁾ While the Group holds a greater than 50 per cent interest in these joint operations, all the participants in these joint operations approve the operating and capital budgets and therefore the Group has joint control over the relevant activities of these arrangements.

⁽²⁾ Group interest reflects the working interest and may vary year-on-year based on the Group’s effective interest in producing wells.

⁽³⁾ These contractual arrangements are controlled by the Group and do not meet the definition of joint operations. However, as they are formed by contractual arrangement and are not entities, the Group recognises its share of assets, liabilities, revenue and expenses arising from these arrangements.

F-89

Assets held in joint operations subject to significant restrictions are as follows:

	Group share
	2018		2017
	US$M		US$M (2)
Current assets		2,445		2,755
Non-current assets		36,144		51,446
Total assets (1)		38,589		54,201

⁽¹⁾  While the Group is unrestricted in its ability to sell a share of its interest in these joint operations, it does not have the right to sell individual assets that are used in these joint operations without the unanimous consent of the other participants. The assets in these joint operations are also restricted to the extent that they are only available to be used by the joint operation itself and not by other operations of the Group.

⁽²⁾  Includes US$14,408 million related to Onshore US assets.

30    Related party transactions

The Group’s related parties are predominantly subsidiaries, joint operations, joint ventures and associates and key management personnel of the Group. Disclosures relating to key management personnel are set out in note 21 ‘Key management personnel’. Transactions between each parent company and its subsidiaries are eliminated on consolidation and are not disclosed in this note.

• All transactions to/from related parties are made at arm’s length, i.e. at normal market prices and rates and on normal commercial terms.

• Outstanding balances at year-end are unsecured and settlement occurs in cash. Loan amounts owing from related parties represent secured loans made to joint operations, associates and joint ventures under co-funding arrangements. Such loans are made on an arm’s length basis with interest charged at market rates and are due to be repaid by 16 August 2022.

• No guarantees are provided or received for any related party receivables or payables.

• No provision for doubtful debts has been recognised in relation to any outstanding balances and no expense has been recognised in respect of bad or doubtful debts due from related parties.

• There were no other related party transactions in the year ended 30 June 2018 (2017: US$ nil), other than those with post-employment benefit plans for the benefit of Group employees. These are shown in note 24 ‘Pension and other post-retirement obligations’.

Transactions with related parties

Further disclosures related to other related party transactions are as follows:

Joint operations

Joint ventures

Associates

2018

2017

2018

2017

2018

2017

US$M

US$M

US$M

US$M

US$M

US$M

Sales of goods/services

–

–

–

–

–

–

Purchases of goods/services

–

–

–

–

1,358.016

1,052.885

Interest income

1.764

1.850

–

–

19.337

34.911

Interest expense

–

0.010

–

–

–

0.006

Dividends received

–

–

–

–

693.105

619.894

Net loans made to/(repayments from) related parties

60.566

(82.701

)

–

–

(599.979

)

(272.276

)

F-90

Outstanding balances with related parties

Disclosures in respect of amounts owing to/from joint operations represent the amount that does not eliminate on consolidation.

	Joint operations				Joint ventures				Associates
	2018		2017		2018		2017		2018		2017
	US$M		US$M		US$M		US$M		US$M		US$M
Trade amounts owing to related parties		–		–		–		–		210.716		217.803
Loan amounts owing to related parties		55.667		118.288		–		–		4.097		39.097
Trade amounts owing from related parties		–		–		–		–		3.932		3.083
Loan amounts owing from related parties		18.089		20.144		–		–		12.939		647.918

Unrecognised items and uncertain events

31    Commitments

The Group’s commitments for capital expenditure were US$2,110 million as at 30 June 2018 (2017: US$2,084 million). The Group’s other commitments are as follows:

	Commitments under finance leases						Commitments under operating leases
	2018			2017			2018		2017
	US$M			US$M			US$M		US$M
Due not later than one year		127			135			388		420
Due later than one year and not later than five years		448			475			785		672
Due later than five years		590			705			839		660
Total		1,165			1,315			2,012		1,752
Future financing liability		(363	)		(418	)
Right to reimbursement from joint operations partner		–			–
Finance lease liability		802			897

Finance leases include leases of power generation and transmission assets. Certain lease payments may be subject to inflation escalation clauses on which contingent rentals are determined. The leases contain extension and renewal options.

Operating leases include leases of property, plant and equipment. Rental payments are generally fixed, but with inflation escalation clauses on which contingent rentals are determined. Certain leases contain extension and renewal options.

F-91

32    Contingent liabilities

	2018		2017
	US$M		US$M
Associates and joint ventures (1)		1,588		1,784
Subsidiaries and joint operations (1)		1,915		1,825
Total		3,503		3,609

⁽¹⁾ There are a number of matters, for which it is not possible at this time to provide a range of possible outcomes or a reliable estimate of potential future exposures, and for which no amounts have been included in the table above.

A contingent liability is a possible obligation arising from past events and whose existence will be confirmed only by occurrence or non-occurrence of one or more uncertain future events not wholly within the control of the Group. A contingent liability may also be a present obligation arising from past events but is not recognised on the basis that an outflow of economic resources to settle the obligation is not viewed as probable, or the amount of the obligation cannot be reliably measured.

When the Group has a present obligation, an outflow of economic resources is assessed as probable and the Group can reliably measure the obligation, a provision is recognised.

The Group has entered into various counter-indemnities of bank and performance guarantees related to its own future performance, which are in the normal course of business. The likelihood of these guarantees being called upon is considered remote.

The Group presently has tax matters, litigation and other claims, for which the timing of resolution and potential economic outflow are uncertain. Obligations assessed as having probable future economic outflows capable of reliable measurement are provided at reporting date and matters assessed as having possible future economic outflows capable of reliable measurement are included in the total amount of contingent liabilities above. Individually significant matters, including narrative on potential future exposures incapable of reliable measurement, are disclosed below, to the extent that disclosure does not prejudice the Group.

Uncertain tax and royalty matters The Group is subject to a range of taxes and royalties across many jurisdictions, the application of which is uncertain in some regards. Changes in tax law, changes in interpretation of tax law, periodic challenges and disagreements with tax authorities, and legal proceedings result in uncertainty of the outcome of the application of taxes and royalties to our business. Areas of uncertainty at reporting date include the application of taxes and royalties (including transfer pricing) to the Group’s cross-border operations and transactions.   Details of uncertain tax and royalty matters have been disclosed in note 5 ‘Income tax expense’. To the extent uncertain tax and royalty matters give rise to a contingent liability, an estimate of the potential liability is included within the table above, where it is capable of reliable measurement.

Samarco contingent liabilities The table above includes contingent liabilities related to the Group’s equity accounting investment in Samarco to the extent they are capable of reliable measurement. Details of contingent liabilities related to Samarco are disclosed in note 3 ‘Significant events – Samarco dam failure’.

F-92

Demerger of South32 As part of the demerger of South32 Limited (South32) in May 2015, certain indemnities were agreed under the Separation Deed. Subject to certain exceptions, BHP Billiton Limited indemnifies South32 against claims and liabilities relating to the Group Businesses and former Group Businesses prior to the demerger and South32 indemnifies the Group against all claims and liabilities relating to the South32 Businesses and former South32 Businesses. No material claims have been made pursuant to the Separation Deed as at 30 June 2018.

33    Subsequent events

Other than the matters outlined in the Financial Statements, no matters or circumstances have arisen since the end of the financial year that have significantly affected, or may significantly affect, the operations, results of operations or state of affairs of the Group in subsequent accounting periods.

Other items

34    Acquisitions and disposals of subsidiaries, operations, joint operations and equity accounted investments

Acquisitions

There were no material acquisitions made during the years ended 30 June 2018, 2017 and 2016.

Divestments

The Group disposed of the following subsidiaries, operations, joint operations and equity accounted investments during the year ended:

30 June 2018

There were no divestments completed during the year ended 30 June 2018.

30 June 2017

• BHP Navajo Coal Company

• IndoMet Coal

30 June 2016

• Pakistan gas business

• San Juan Mine

	2018		2017			2016
	US$M		US$M			US$M
Net assets disposed		–		189			153
Gross cash consideration		–		187			168
Less cash and cash equivalents disposed		–		–			(2	)
Total consideration		–		187			166
Other effects (1)		–		–			1
Net (loss)/gain on disposal recognised in other income		–		(2	)		14

⁽¹⁾ Other effects include deferred consideration of US$ nil for 30 June 2018 (2017: US$ nil; 2016: US$1 million).

F-93

35    Auditor’s remuneration

	2018		2017		2016
	US$M		US$M		US$M
Fees payable to the Group’s auditors for assurance services
Audit of the Group’s Annual Report		3.909		3.381		3.126
Audit of subsidiaries, joint ventures and associates		13.902		7.040		7.715
Audit-related assurance services		4.039		3.597		3.493
Other assurance services		1.343		1.849		1.508
Total assurance services		23.193		15.867		15.842
Fees payable to the Group’s auditors for other services
Other services relating to corporate finance		0.104		0.042		0.276
All other services		0.553		0.589		0.815
Total other services		0.657		0.631		1.091
Total fees		23.850		16.498		16.933

All amounts were paid to KPMG or KPMG affiliated firms. Fees are determined in local currencies and are predominantly billed in US dollars based on the exchange rate at the beginning of the relevant financial year.

Fees payable to the Group’s auditors for assurance services

For all periods disclosed, no fees are payable in respect of the audit of pension funds.

Audit of subsidiaries, joint ventures and associates comprise audits of the Group’s subsidiaries, joint ventures and associates including additional non-recurring audits fees in FY2018 in connection with the sale of the Onshore US oil and gas assets.

Audit-related assurance services comprise review of half-year reports and audit work in relation to compliance with section 404 of the US Sarbanes-Oxley Act.

Other assurance services comprise assurance in respect of the Group’s sustainability reporting.

Fees payable to the Group’s auditors for other services

Other services relating to corporate finance comprise services in connection with debt raising transactions.

All other services comprise non-statutory assurance based procedures, advice on accounting matters, as well as tax compliance services of US$ nil (2017: US$0.027 million; 2016: US$0.089 million).

F-94

36    Not required for US reporting

37    Deed of Cross Guarantee

BHP Billiton Limited together with wholly owned subsidiaries identified in Exhibit 8.1 – List of Subsidiaries entered into a Deed of Cross Guarantee (Deed) on 6 June 2016. The effect of the Deed is that BHP Billiton Limited has guaranteed to pay any outstanding liabilities upon the winding up of any wholly owned subsidiary that is party to the Deed. Wholly owned subsidiaries that are party to the Deed have also given a similar guarantee in the event that BHP Billiton Limited or another party to the Deed is wound up.

The wholly owned Australian subsidiaries identified in Exhibit 8.1 – List of Subsidiaries are relieved from the requirements to prepare and lodge audited financial reports.

A Consolidated Statement of Comprehensive Income and Retained Earnings and Consolidated Balance Sheet, comprising BHP Billiton Limited and the wholly owned subsidiaries that are party to the Deed for the year ended 30 June 2018 and 30 June 2017 are as follows:

Consolidated Statement of Comprehensive Income and Retained Earnings	2018			2017
	US$M			US$M
Revenue		20,434			19,394
Other income		3,188			4,988
Expenses excluding net finance costs		(12,693	)		(12,085	)
Net finance costs		(470	)		(591	)
Income tax expense		(2,218	)		(2,351	)
Profit after taxation		8,241			9,355
Total other comprehensive income		12			18
Total comprehensive income		8,253			9,373
Retained earnings at the beginning of the financial year		45,979			40,462
Net effect on retained earnings of entities added to/removed from the Deed		48			(1,699	)
Profit after taxation for the year		8,241			9,355
Transfers to and from reserves		(15	)		33
Dividends		(5,811	)		(2,172	)
Retained earnings at the end of the financial year		48,442			45,979

F-95

Consolidated Balance Sheet	2018			2017
	US$M			US$M
ASSETS
Current assets
Cash and cash equivalents		2			1
Trade and other receivables		3,977			3,541
Loans to related parties		16,730			14,081
Inventories		1,649			1,536
Other		90			72
Total current assets		22,448			19,231
Non-current assets
Trade and other receivables		73			76
Loans to related parties		151			335
Inventories		323			278
Property, plant and equipment		31,009			30,579
Intangible assets		444			550
Investments in Group companies		27,354			27,816
Deferred tax assets		329			402
Other		68			59
Total non-current assets		59,751			60,095
Total assets		82,199			79,326
LIABILITIES
Current liabilities
Trade and other payables		3,425			2,762
Loans from related parties		15,719			15,978
Interest bearing liabilities		115			202
Current tax payable		1,053			1,318
Provisions		952			683
Deferred income		6			8
Total current liabilities		21,270			20,951
Non-current liabilities
Trade and other payables		3			3
Loans from related parties		7,870			7,660
Interest bearing liabilities		191			251
Deferred tax liabilities		573			613
Provisions		2,475			2,479
Deferred income		18			21
Total non-current liabilities		11,130			11,027
Total liabilities		32,400			31,978
Net assets		49,799			47,348
EQUITY
Share capital – BHP Billiton Limited		1,186			1,186
Treasury shares		(5	)		(1	)
Reserves		176			184
Retained earnings		48,442			45,979
Total equity		49,799			47,348

F-96

38    New and amended accounting standards and interpretations

The Group adopted the amendment to IAS 7 ‘Statement of Cash Flows: Disclosure Initiative’ in the current year. This amendment requires disclosure about changes in liabilities arising from financing activities, including changes arising from financing cash flows and non-cash changes (such as foreign exchange gains or losses). While having no impact on the primary financial statements, an additional reconciliation has been provided in note 20 ‘Financial risk management’ to comply with this amendment. This amendment has been endorsed by the EU.

There are no other new or amended accounting standards or interpretations adopted for the first time during the year that have a significant impact on these Financial Statements.

Issued but not yet effective

The following new accounting standards and interpretations will become effective for future reporting periods and may have a significant impact on the income statement or net assets of the Group.

Applicable from 1 July 2018

The following accounting standards and interpretations are applicable to the Group from 1 July 2018. The impacts of these are currently expected to be immaterial, although industry application of these standards continues to develop.

Title of standard / interpretation

Summary of impact on the Financial Statements

IFRS 15/AASB 15 ‘Revenue from Contracts with Customers’

This standard modifies the determination of when to recognise revenue and how much revenue to recognise. Revenue is recognised when control of the promised goods or services pass to the customer. The amount of revenue recognised should reflect the consideration to which the entity expects to be entitled in exchange for those goods or services. The Group has undertaken a process of understanding the standard contractual arrangements across its principal revenue streams, particularly key terms and conditions which may impact revenue recognition. In addition, detailed reviews of a representative sample of individual contracts across all the Group’s revenue streams have been completed. While no significant changes in accounting arising from the implementation of the new standard have been identified, the following points are noted. •   Certain of the Group’s sales are provisionally priced, where the final price depends on future index prices. Any adjustments between the provisional and final price are accounted for under IFRS 9/AASB 9 ‘Financial Instruments’ and will be recognised as other revenue. Where applicable, system and process changes have been implemented to appropriately measure and capture this data for disclosure. •   A significant proportion of the Group’s products are sold on Cost, Insurance and Freight (CIF) or Cost and Freight (CFR) Incoterms, where the Group is required to provide freight and shipping services after the date at which the goods have transferred to the customer. Revenue from freight and shipping services, currently recognised when the product is loaded onto the ship, should be treated as a separate performance obligation under the new standard and recognised over time. The impact of this is immaterial at 30 June 2018.

F-97

Title of standard / interpretation	Summary of impact on the Financial Statements
	•   Certain sales contracts require the Group to physically deliver unrefined concentrate. Revenue is currently recognised at the gross value of the final refined metal content delivered with contractually agreed treatment costs and refining charges recorded as an expense. While having no net income statement impact, under the new standard the treatment costs and refining charges must be recognised as a reduction to revenue. The impact of applying this change during the year ended 30 June 2018 would have been to reduce revenue and expenses, respectively by US$509 million with no impact on profit. •   The Group participates in certain arrangements which entitle it to a proportion of the physical output of an operation. Currently, the Group recognises revenue to the extent of its entitlement. Under the new standard, all product sold by the Group to third parties in a period will be recognised as revenue from contracts with customers. Any difference to the Group’s entitlement represents a form of revenue or is closely connected to revenue transactions and will therefore be recognised as other revenue. •   Revenues from the sale of significant by-products are within the scope of the new standard and will continue to be included in revenue. The Group expects to apply the full retrospective transition approach, resulting in the restatement of comparative information where applicable.
IFRS 9/AASB 9 ‘Financial Instruments’	This standard revises the classification and measurement of financial assets and financial liabilities, introduces a forward looking ‘expected credit loss’ impairment model and modifies the approach to hedge accounting. The Group has undertaken a comprehensive analysis of the impact of the new standard based on the financial instruments it holds and the way in which they are used with no material impact on the face of balance sheet or in the income statement expected. However, there will be presentational changes in some of our note disclosures, as well as additional disclosures around classification and measurement of financial instruments. Adoption impacts include: •   The new standard requires classification and measurement of financial assets based on the business model in which they are managed and their cash flow characteristics. Under the new standard, the Group’s financial assets will be classified as measured at amortised cost, fair value through profit or loss, or fair value through equity. No significant measurement impacts have been identified as a result of reclassifying financial assets into the categories required by the new standard. Equity investments currently classified as available for sale are expected to be carried at fair value with revaluation gains and losses recognised directly in equity with future recycling through the income statement no longer permitted. Gains and losses on this category of financial asset currently recognised in equity are immaterial. Classification of future equity investments will be considered on an instrument by instrument basis. For financial liabilities, the current classification and measurement requirements are largely retained.

F-98

Title of standard / interpretation	Summary of impact on the Financial Statements
	•   Financial assets carried at amortised cost must be tested for impairment based on expected losses, as opposed to the current policy of recognising impairments only when there is objective evidence that a credit loss is present. This is not expected to have a significant impact given the Group’s counterparty risk framework. •   The new standard amends the rules on hedge accounting to enable closer alignment between the Group’s risk management strategy and the accounting outcomes. The standard broadens the scope of arrangements that may qualify for hedge accounting and allows for simplification of hedge designations. Certain of the Group’s derivatives will be designated into simplified hedging relationships from 1 July 2018, with no material impact to net assets expected. Other changes under the standard mean that hedge effectiveness is only considered on a prospective basis with no set quantitative thresholds, certain costs of hedging, previously taken to the income statement, will be recognised directly in equity and voluntary de-designation of hedges is prohibited. The Group will monitor increased opportunities to apply hedge accounting in the future. The Group will adjust the opening balance sheet as of 1 July 2018, with no restatement of comparatives required.
IFRIC 22 ‘Foreign Currency Transactions and Advance Consideration’	This interpretation clarifies the exchange rate to use on initial recognition of the related asset, expense or income when an entity receives or pays advance consideration in a foreign currency. The Group has made some minor changes to processes to comply with this interpretation.

Applicable from 1 July 2019 and beyond

The following accounting standards and interpretations are applicable to the Group from 1 July 2019 and beyond.

Title of standard / interpretation

Summary of impact on the Financial Statements

IFRS 16/AASB 16 ‘Leases’

This standard provides a new model for lessee accounting under which all leases with the exception of short-term (under 12 months) and low value leases, will be accounted for by the recognition on the balance sheet of a right of use asset and a corresponding lease liability. Lease costs will be recognised in the income statement over the lease term in the form of depreciation on the right of use asset and finance charges representing the unwind of the discount on the lease liability.

F-99

Title of standard / interpretation	Summary of impact on the Financial Statements
	The Group has progressed its implementation project, focusing on a review of contracts, aggregation of data to support the evaluation of the accounting impacts of applying the new standard and assessment of the need for changes to systems and processes. While the Group’s evaluation of the effect of adopting the standard is ongoing, it is expected that it will have a material effect on the Group’s Financial Statements, significantly increasing the Group’s recognised assets and liabilities. Further, compared with the existing accounting for operating leases, the classification and timing of expenses will be impacted and consequently the classification between cash flow from operating activities and cash flow from financing activities. Many commonly used financial ratios and performance metrics, using existing definitions, will also be impacted including net debt, gearing, EBITDA, unit costs and operating cash flows. The Group is considering available options for transition, which include either retrospective with restatement of comparatives or the modified approach with the cumulative impact of application recognised as at 1 July 2019. The Group’s existing operating leases will be the main source of leases under the new standard. The impact of the standard continues to be assessed as it will be impacted by the transition approach selected by the Group and the lease population at the point of transition. Information on the undiscounted amount of the Group’s operating lease commitments under IAS 17/AASB 117 ‘Leases’, the current leasing standard, is disclosed in note 31 ‘Commitments’.
IFRIC 23 ‘Uncertainty over Income Tax Treatments’ (1)	This interpretation clarifies the application of the recognition and measurement requirements in IAS 12/AASB 112 ‘Income Taxes’ for calculating provisions for uncertain tax positions. The Group is currently assessing the impact of the interpretation on its Financial Statements.
Conceptual Framework for Financial Reporting (1)	The revised framework may affect the application of IFRS in situations where no standard applies to a specific transaction or event. The Group is currently assessing the impact of the revised framework on its Financial Statements.

⁽¹⁾  IFRIC 23 and the Conceptual Framework for Financial Reporting have not been endorsed by the EU and hence are not available for early adoption in the EU.

F-100

5.2    Not required for US reporting

5.2A    Reports of Independent Registered Public Accounting Firms

Report of Independent Registered Public Accounting Firms

To the members of BHP Billiton Plc and BHP Billiton Limited:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of the BHP Group (comprising BHP Billiton Plc, BHP Billiton Limited and their respective subsidiaries) as of 30 June 2018 and 2017, the related consolidated income statements, consolidated statements of comprehensive income, consolidated statements of changes in equity and consolidated cash flow statements for each of the years in the three-year period ended 30 June 2018, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the BHP Group as of 30 June 2018 and 2017, and the results of its operations and its cash flows for each of the years in the three-year period ended 30 June 2018, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the BHP Group’s internal control over financial reporting as of 30 June 2018, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated 18 September 2018 expressed an unqualified opinion on the effectiveness of the BHP Group’s internal control over financial reporting.

Basis for Opinion

These consolidated financial statements are the responsibility of the BHP Group’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the BHP Group in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ KPMG KPMG LLP	/s/ KPMG KPMG
We have served as the BHP Group’s auditor since 3 May 2002.	We have served as the BHP Group’s auditor since 3 May 2002.
London, United Kingdom 18 September 2018	Melbourne, Australia 18 September 2018

F-101

Report of Independent Registered Public Accounting Firms

To the members of BHP Billiton Plc and BHP Billiton Limited:

Opinion on Internal Control Over Financial Reporting

We have audited the BHP Group’s (comprising BHP Billiton Plc, BHP Billiton Limited and their respective subsidiaries) internal control over financial reporting as of 30 June 2018, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the BHP Group maintained, in all material respects, effective internal control over financial reporting as of 30 June 2018, based on criteria established in Internal Control – Integrated Framework (2013) issued by the COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the BHP Group as of 30 June 2018 and 30 June 2017, the related consolidated income statements, consolidated statements of comprehensive income, consolidated statements of changes in equity and consolidated cash flow statements for each of the years in the three-year period ended 30 June 2018, and the related notes (collectively, the consolidated financial statements), and our report dated 18 September 2018 expressed an unqualified opinion on those consolidated financial statements.

Basis for Opinion

The BHP Group’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying section 2.13.1 Risk and Audit Committee Report. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the BHP Group in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorisations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorised acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

F-102

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ KPMG KPMG LLP	/s/ KPMG KPMG
London, United Kingdom 18 September 2018	Melbourne, Australia 18 September 2018

5.3    Directors’ declaration

In accordance with a resolution of the Directors of BHP Billiton Limited and BHP Billiton Plc, the Directors declare that:

(a) in the Directors’ opinion and to the best of their knowledge the Financial Statements and notes, set out in sections 5.1 and 5.2, are in accordance with the UK Companies Act 2006 and the Australian Corporations Act 2001, including:

(i) complying with the applicable Accounting Standards;

(ii) giving a true and fair view of the assets, liabilities, financial position and profit or loss of each of BHP Billiton Limited, BHP Billiton Plc, the Group and the undertakings included in the consolidation taken as a whole as at 30 June 2018 and of their performance for the year ended 30 June 2018;

(b) the Financial Statements also comply with International Financial Reporting Standards, as disclosed in section 5.1;

(c) to the best of the Directors’ knowledge, the management report (comprising the Strategic Report and Directors’ Report) includes a fair review of the development and performance of the business and the financial position of the Group and the undertakings included in the consolidation taken as a whole, together with a description of the principal risks and uncertainties that the Group faces;

(d) in the Directors’ opinion there are reasonable grounds to believe that each of BHP Billiton Limited, BHP Billiton Plc and the Group will be able to pay its debts as and when they become due and payable;

(e) in the Directors’ opinion, as at the date of this declaration, there are reasonable grounds to believe that BHP Billiton Limited and each of the Closed Group entities identified in Exhibit 8.1 – List of Subsidiaries will be able to meet any liabilities to which they are or may become subject to, because of the Deed of Cross Guarantee between BHP Billiton Limited and those group entities pursuant to ASIC Corporations (Wholly-owned Companies) Instrument 2016/785;

(f) the Directors have been given the declarations required by Section 295A of the Australian Corporations Act 2001 from the Chief Executive Officer and Chief Financial Officer for the financial year ended 30 June 2018.

Signed in accordance with a resolution of the Board of Directors.

Ken MacKenzie

Chairman

Andrew Mackenzie

Chief Executive Officer

Dated this 6th day of September 2018

F-103

5.4    Statement of Directors’ responsibilities in respect of the Annual Report and the Financial Statements

The Directors are responsible for preparing the Annual Report and the Group and Parent company Financial Statements in accordance with applicable law and regulations. References to the ‘Group and Parent company Financial Statements’ are made in relation to the Group and individual Parent company Financial Statements of BHP Billiton Plc.

UK company law requires the Directors to prepare Group and Parent company Financial Statements for each financial year. The Directors are required to prepare the Group Financial Statements in accordance with IFRS as adopted by the EU and applicable law and have elected to prepare the Parent company Financial Statements in accordance with UK Accounting Standards and applicable law (UK Generally Accepted Accounting Practice).

The Group Financial Statements must, in accordance with IFRS as adopted by the EU and applicable law, present fairly the financial position and performance of the Group; references in the UK Companies Act 2006 to such Financial Statements giving a true and fair view are references to their achieving a fair presentation.

The Parent company Financial Statements must, in accordance with UK Generally Accepted Accounting Practice, give a true and fair view of the state of affairs of the parent company at the end of the financial year and of the profit or loss of the parent company for the financial year.

In preparing each of the Group and Parent company Financial Statements, the Directors are required to:

• select suitable accounting policies and then apply them consistently;

• make judgements and estimates that are reasonable and prudent;

• for the Group Financial Statements, state whether they have been prepared in accordance with IFRS as adopted by the EU;

• for the Parent company Financial Statements, state whether applicable UK Accounting Standards have been followed, subject to any material departures disclosed and explained in the Parent company Financial Statements;

• assess the Group and parent company’s ability to continue as a going concern, disclosing, as applicable, related matters;

• use the going concern basis of accounting unless they either intend to liquidate the Group or the parent company or to cease operations, or have no realistic alternative but to do so.

The Directors are responsible for keeping proper accounting records that disclose with reasonable accuracy at any time the financial position of the parent company and enable them to ensure that its Financial Statements comply with the UK Companies Act 2006. They are responsible for such internal control as they determine is necessary to enable the preparation of Financial Statements that are free from material misstatement, whether due to fraud or error, and have general responsibility for taking such steps as are reasonably open to them to safeguard the assets of the Group and to prevent and detect fraud and other irregularities.

Under applicable law and regulations, the Directors are also responsible for preparing a Strategic Report, Directors’ Report, Directors’ Remuneration Report and Corporate Governance Statement that complies with that law and those regulations.

The Directors are responsible for the maintenance and integrity of the corporate and financial information included on the Group’s website. Legislation in the United Kingdom governing the preparation and dissemination of Financial Statements may differ from legislation in other jurisdictions.

F-104

5.5    Not required for US reporting

5.6    Included as Item 5.2A

5.7    Supplementary oil and gas information – unaudited

In accordance with the requirements of the Financial Accounting Standards Board (FASB) Accounting Standard Codification ‘Extractive Activities-Oil and Gas’ (Topic 932) and SEC requirements set out in Subpart 1200 of Regulation S-K, the Group is presenting certain disclosures about its oil and gas activities. These disclosures are presented below as supplementary oil and gas information, in addition to information disclosed in section 1.12.1 ‘Petroleum’ and section 6.3.1 ‘Petroleum reserves’.

The information set out in this section is referred to as unaudited as it is not included in the scope of the audit opinion of the independent auditor on the Consolidated Financial Statements, refer to section 5.6 ‘Independent Auditors’ reports’.

On 27 July 2018, BHP announced that it had entered into agreements for the sale of its entire interests in its Eagle Ford, Haynesville, Permian and Fayetteville Onshore US oil and gas assets. The financial and non-financial impact of the Onshore US assets is included in the supplementary oil and gas information presented below. The financial and non-financial impact of these assets has been footnoted beneath each applicable table.

Reserves and production

Proved oil and gas reserves and net crude oil and condensate, natural gas, LNG and NGL production information is included in section 6.2.2 ‘Production – Petroleum’ and section 6.3.1 ‘Petroleum reserves’.

F-105

Capitalised costs relating to oil and gas production activities

The following table shows the aggregate capitalised costs relating to oil and gas exploration and production activities and related accumulated depreciation, depletion, amortisation and valuation provisions.

	Australia			United States (1)			Other (2)			Total
	US$M			US$M			US$M			US$M
Capitalised cost
2018
Unproved properties		10			4,528			202			4,740
Proved properties		16,258			43,885			2,424			62,567
Total costs		16,268			48,413			2,626			67,307
Less: Accumulated depreciation, depletion, amortisation and valuation provisions		(9,984	)		(33,437	)		(2,065	)		(45,486	)
Net capitalised costs		6,284			14,976			561			21,821
2017
Unproved properties		94			5,284			165			5,543
Proved properties		16,190			41,837			2,404			60,431
Total costs		16,284			47,121			2,569			65,974
Less: Accumulated depreciation, depletion, amortisation and valuation provisions		(9,085	)		(30,969	)		(1,984	)		(42,038	)
Net capitalised costs		7,199			16,152			585			23,936
2016
Unproved properties		338			5,074			119			5,531
Proved properties		15,523			40,929			2,372			58,824
Total costs		15,861			46,003			2,491			64,355
Less: Accumulated depreciation, depletion, amortisation and valuation provisions		(8,364	)		(28,664	)		(1,938	)		(38,966	)
Net capitalised costs		7,497			17,339			553			25,389

⁽¹⁾  Net capitalised costs includes Onshore US assets of US$10,672 million (2017: US$11,803 million; 2016: US$12,844 million).

⁽²⁾  Other is primarily comprised of Algeria, Pakistan (divested 31 December 2015), Trinidad and Tobago and the United Kingdom.

F-106

Costs incurred relating to oil and gas property acquisition, exploration and development activities

The following table shows costs incurred relating to oil and gas property acquisition, exploration and development activities (whether charged to expense or capitalised). Amounts shown include interest capitalised.

	Australia		United States (3)		Other (4)		Total
	US$M		US$M		US$M		US$M
2018
Acquisitions of proved property		–		–		–		–
Acquisitions of unproved property		–		9		–		9
Exploration (1)		25		418		291		734
Development		195		1,548		34		1,777
Total costs (2)		220		1,975		325		2,520
2017
Acquisitions of proved property		–		–		–		–
Acquisitions of unproved property		–		12		62		74
Exploration (1)		32		471		235		738
Development		360		1,034		18		1,412
Total costs (2)		392		1,517		315		2,224
2016
Acquisitions of proved property		–		–		–		–
Acquisitions of unproved property		22		42		–		64
Exploration (1)		42		385		194		621
Development		412		1,254		200		1,866
Total costs (2)		476		1,681		394		2,551

⁽¹⁾ Represents gross exploration expenditure, including capitalised exploration expenditure, geological and geophysical expenditure and development evaluation costs charged to income as incurred.

⁽²⁾  Total costs include US$1,970 million (2017: US$1,744 million; 2016: US$2,256 million) capitalised during the year.

⁽³⁾  Total costs includes Onshore US assets of US$1,081 million (2017: US$608 million; 2016: US$862 million).

⁽⁴⁾  Other is primarily comprised of Algeria and Trinidad and Tobago.

F-107

Results of operations from oil and gas producing activities

The following information is similar to the disclosures in note 1 ‘Segment reporting’ in section 5.1, but differs in several respects as to the level of detail and geographic information. Amounts shown in the following table exclude financial income, financial expenses, and general corporate overheads.

Income taxes were determined by applying the applicable statutory rates to pre-tax income with adjustments for permanent differences and tax credits.

	Australia			United States (7)			Other (8)			Total
	US$M			US$M			US$M			US$M
2018
Oil and gas revenue (1)		3,229			3,747			421			7,397
Production costs		(701	)		(1,312	)		(121	)		(2,134	)
Exploration expenses		(25	)		(270	)		(254	)		(549	)
Depreciation, depletion, amortisation and valuation provision (2)		(1,045	)		(2,842	)		(81	)		(3,968	)
Production taxes (3)		(171	)		–			(1	)		(172	)
		1,287			(677	)		(36	)		574
Accretion expense (4)		(81	)		(46	)		(14	)		(141	)
Income taxes		(418	)		(723	)		(124	)		(1,265	)
Royalty-related taxes (5)		(103	)		–			–			(103	)
Results of oil and gas producing activities (6)		685			(1,446	)		(174	)		(935	)
2017
Oil and gas revenue (1)		2,876			3,479			356			6,711
Production costs		(533	)		(1,515	)		(200	)		(2,248	)
Exploration expenses		(32	)		(242	)		(206	)		(480	)
Depreciation, depletion, amortisation and valuation provision (2)		(814	)		(2,592	)		(91	)		(3,497	)
Production taxes (3)		(158	)		(4	)		–			(162	)
		1,339			(874	)		(141	)		324
Accretion expense (4)		(56	)		(32	)		(14	)		(102	)
Income taxes		(361	)		386			(142	)		(117	)
Royalty-related taxes (5)		(104	)		–			–			(104	)
Results of oil and gas producing activities (6)		818			(520	)		(297	)		1
2016
Oil and gas revenue (1)		2,777			3,487			321			6,585
Production costs		(605	)		(1,705	)		(162	)		(2,472	)
Exploration expenses		(44	)		(128	)		(124	)		(296	)
Depreciation, depletion, amortisation and valuation provision (2)		(720	)		(10,569	)		(90	)		(11,379	)
Production taxes (3)		(132	)		(13	)		(2	)		(147	)
		1,276			(8,928	)		(57	)		(7,709	)
Accretion expense (4)		(54	)		(23	)		(7	)		(84	)
Income taxes		(465	)		3,047			(143	)		2,439
Royalty-related taxes (5)		(206	)		–			(4	)		(210	)
Results of oil and gas producing activities (6)		551			(5,904	)		(211	)		(5,564	)

F-108

⁽¹⁾  Includes sales to affiliated companies of US$75 million (2017: US$83 million; 2016: US$118 million).

⁽²⁾  Includes valuation provision of US$596 million (2017: US$102 million; 2016: US$7,232 million).

⁽³⁾  Includes royalties and excise duty.

⁽⁴⁾  Represents the unwinding of the discount on the closure and rehabilitation provision.

⁽⁵⁾  Includes petroleum resource rent tax and petroleum revenue tax where applicable.

⁽⁶⁾  Amounts shown exclude financial income, financial expenses and general corporate overheads and, accordingly, do not represent all of the operations attributable to the Petroleum segment presented in note 1 ‘Segment reporting’ in section 5.1.

⁽⁷⁾  Results of oil and gas producing activities includes Onshore US assets of US$(465) million (2017: US$(564) million; 2016: US$(5,855) million).

⁽⁸⁾  Other is primarily comprised of Algeria, Pakistan (divested 31 December 2015), Trinidad and Tobago and the United Kingdom.

Standardised measure of discounted future net cash flows relating to proved oil and gas reserves (Standardised measure)

The following tables set out the standardised measure of discounted future net cash flows, and changes therein, related to the Group’s estimated proved reserves as presented in section 6.3.1 ‘Petroleum reserves’, and should be read in conjunction with that disclosure.

The analysis is prepared in compliance with FASB Oil and Gas Disclosure requirements, applying certain prescribed assumptions under Topic 932 including the use of, unweighted average first-day-of-the-month market prices for the previous 12-months, year-end cost factors, currently enacted tax rates and an annual discount factor of 10 per cent to year end quantities of net proved reserves.

Certain key assumptions prescribed under Topic 932 are arbitrary in nature and may not prove to be accurate. The reserve estimates on which the Standard measure is based are subject to revision as further technical information becomes available or economic conditions change.

F-109

Discounted future cash flows like those shown below are not intended to represent estimates of fair value. An estimate of fair value would also take into account, among other things, the expected recovery of reserves in excess of proved reserves, anticipated future changes in commodity prices, exchange rates, development and production costs as well as alternative discount factors representing the time value of money and adjustments for risk inherent in producing oil and gas.

	Australia			United States (1)			Other (2)			Total
	US$M			US$M			US$M			US$M
Standardised measure
2018
Future cash inflows		17,398			28,012			2,124			47,534
Future production costs		(5,345	)		(11,182	)		(501	)		(17,028	)
Future development costs		(3,842	)		(6,554	)		(189	)		(10,585	)
Future income taxes		(1,919	)		(1,236	)		(901	)		(4,056	)
Future net cash flows		6,292			9,040			533			15,865
Discount at 10 per cent per annum		(1,713	)		(3,783	)		(129	)		(5,625	)
Standardised measure		4,579			5,257			404			10,240
2017
Future cash inflows		18,407			23,537			1,954			43,898
Future production costs		(6,663	)		(11,176	)		(534	)		(18,373	)
Future development costs		(3,714	)		(6,451	)		(208	)		(10,373	)
Future income taxes		(1,508	)		(18	)		(746	)		(2,272	)
Future net cash flows		6,522			5,892			466			12,880
Discount at 10 per cent per annum		(2,104	)		(2,426	)		(108	)		(4,638	)
Standardised measure		4,418			3,466			358			8,242
2016
Future cash inflows		21,902			13,088			2,026			37,016
Future production costs		(7,306	)		(6,514	)		(567	)		(14,387	)
Future development costs		(3,431	)		(3,063	)		(282	)		(6,776	)
Future income taxes		(3,082	)		800			(668	)		(2,950	)
Future net cash flows		8,083			4,311			509			12,903
Discount at 10 per cent per annum		(2,961	)		(834	)		(121	)		(3,916	)
Standardised measure		5,122			3,477			388			8,987

⁽¹⁾  Standardised measure includes Onshore US assets of US$1,932 million (2017: US$1,962 million; 2016: US$1,889 million).

⁽²⁾  Other is primarily comprised of Algeria, Pakistan (divested 31 December 2015), Trinidad and Tobago and the United Kingdom.

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Changes in the Standardised measure are presented in the following table.

	2018			2017			2016
	US$M			US$M			US$M
Changes in the Standardised measure
Standardised measure at the beginning of the year		8,242			8,987			17,244
Revisions:
Prices, net of production costs		5,540			(96	)		(14,146	)
Changes in future development costs		(358	)		275			1,342
Revisions of quantity estimates (1)		(166	)		2,961			(2,870	)
Accretion of discount		1,016			1,147			2,547
Changes in production timing and other		946			(1,611	)		1,280
		15,220			11,663			5,397
Sales of oil and gas, net of production costs		(5,091	)		(4,301	)		(3,936	)
Acquisitions of reserves-in-place		–			–			–
Sales of reserves-in-place		(26	)		(15	)		(114	)
Previously estimated development costs incurred		1,068			718			1,823
Extensions, discoveries, and improved recoveries, net of future costs		502			(401	)		84
Changes in future income taxes		(1,433	)		578			5,733
Standardised measure at the end of the year (2)		10,240			8,242			8,987

⁽¹⁾  Changes in reserves quantities are shown in the Petroleum reserves tables in section 6.3.1.

⁽²⁾  Standardised measure at the end of the year includes Onshore US assets of US$1,932 million (2017: US$1,962 million; 2016: US$1,889 million).

Accounting for suspended exploratory well costs

Refer to note 10 ‘Property, plant and equipment’ in section 5.1 for a discussion of the accounting policy applied to the cost of exploratory wells. Suspended wells are also reviewed in this context.

The following table provides the changes to capitalised exploratory well costs that were pending the determination of proved reserves for the three years ended 30 June 2018, 30 June 2017 and 30 June 2016.

	2018			2017			2016
	US$M			US$M			US$M
Movement in capitalised exploratory well costs
At the beginning of the year		668			770			484
Additions to capitalised exploratory well costs pending the determination of proved reserves		186			258			304
Capitalised exploratory well costs charged to expense		(62	)		(69	)		(18	)
Capitalised exploratory well costs reclassified to wells, equipment, and facilities based on the determination of proved reserves		2			(155	)		–
Other		–			(136	)		–
At the end of the year		794			668			770

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The following table provides an ageing of capitalised exploratory well costs, based on the date the drilling was completed, and the number of projects for which exploratory well costs has been capitalised for a period greater than one year since the completion of drilling.

	2018		2017		2016
	US$M		US$M		US$M
Ageing of capitalised exploratory well costs
Exploratory well costs capitalised for a period of one year or less		124		120		262
Exploratory well costs capitalised for a period greater than one year		670		548		508
At the end of the year		794		668		770
	2018		2017		2016
Number of projects that have been capitalised for a period greater than one year		17		14		23

Drilling and other exploratory and development activities

The number of crude oil and natural gas wells drilled and completed for each of the last three years was as follows:

	Net exploratory wells						Net development wells
	Productive		Dry		Total		Productive		Dry		Total		Total
Year ended 30 June 2018
Australia		–		–		–		1		–		1		1
United States (1)		1		1		2		84		1		85		87
Other (2)		–		–		–		–		–		–		–
Total		1		1		2		85		1		86		88
Year ended 30 June 2017
Australia		–		–		–		–		–		–		–
United States (1)		–		–		–		80		–		80		80
Other (2)		3		2		5		1		–		1		6
Total		3		2		5		81		–		81		86
Year ended 30 June 2016
Australia		–		–		–		2		–		2		2
United States (1)		1		–		1		137		2		139		140
Other (2)		–		–		–		1		–		1		1
Total		1		–		1		140		2		142		143

⁽¹⁾  Includes Onshore US assets net productive development wells of 84 (2017: 79; 2016: 135) and net dry development wells of 1 (2017: nil; 2016: 2). Onshore US assets had nil net exploratory wells in 2018, 2017 and 2016.

⁽²⁾  Other is primarily comprised of Algeria, Trinidad and Tobago and the United Kingdom.

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The number of wells drilled refers to the number of wells completed at any time during the respective year, regardless of when drilling was initiated. Completion refers to the installation of permanent equipment for production of oil or gas, or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned.

An exploratory well is a well drilled to find oil or gas in a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. A development well is a well drilled within the limits of a known oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

A productive well is an exploratory, development or extension well that is not a dry well. Productive wells include wells in which hydrocarbons were encountered and the drilling or completion of which, in the case of exploratory wells, has been suspended pending further drilling or evaluation. A dry well (hole) is an exploratory, development, or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

Oil and gas properties, wells, operations, and acreage

The following tables show the number of gross and net productive crude oil and natural gas wells and total gross and net developed and undeveloped oil and natural gas acreage as at 30 June 2018. A gross well or acre is one in which a working interest is owned, while a net well or acre exists when the sum of fractional working interests owned in gross wells or acres equals one. Productive wells are producing wells and wells mechanically capable of production. Developed acreage is comprised of leased acres that are within an area by or assignable to a productive well. Undeveloped acreage is comprised of leased acres on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil and gas, regardless of whether such acres contain proved reserves.

The number of productive crude oil and natural gas wells in which we held an interest at 30 June 2018 was as follows:

	Crude oil wells				Natural gas wells				Total
	Gross		Net		Gross		Net		Gross		Net
Australia		354		178		135		48		489		226
United States (1)		998		547		6,660		2,012		7,658		2,559
Other (2)		59		22		36		8		95		30
Total		1,411		747		6,831		2,068		8,242		2,815

⁽¹⁾  Crude oil wells includes Onshore US assets of 971 Gross and 536 Net. Natural gas wells includes Onshore US assets of 6,660 Gross and 2,012 Net.

⁽²⁾  Other is primarily comprised of Algeria, Trinidad and Tobago and the United Kingdom.

Of the productive crude oil and natural gas wells, 20 (net: 9) operated wells had multiple completions.

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Developed and undeveloped acreage (including both leases and concessions) held at 30 June 2018 was as follows:

	Developed acreage				Undeveloped acreage
Thousands of acres	Gross		Net		Gross		Net
Australia		2,152		823		4,326		2,605
United States (1)		1,137		669		1,313		1,085
Other (2)(3)		175		64		3,029		2,337
Total		3,464		1,556		8,668		6,027

⁽¹⁾  Developed acreage includes Onshore US assets of 1,039 thousand gross acres (633 thousand net acres). Undeveloped acreage includes Onshore US assets of 210 thousand gross acres (162 thousand net acres).

⁽²⁾  Developed acreage in Other primarily consists of Algeria and the United Kingdom.

⁽³⁾  Undeveloped acreage in Other primarily consists of acreage in Brazil and Trinidad and Tobago. It also includes the addition of Trion.

Approximately 4,245 thousand gross acres (2,850 thousand net acres), 526 thousand gross acres (278 thousand net acres) and 1,490 thousand gross acres (1,078 thousand net acres) of undeveloped acreage will expire in the years ending 30 June 2019, 2020 and 2021 respectively, if the Group does not establish production or take any other action to extend the terms of the licenses and concessions.

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