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 2017.

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, low-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

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.

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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’, ‘we’, ‘us’, ‘our’ and ‘ourselves’ are used to refer to BHP Billiton Limited, BHP Billiton Plc and, except where the context otherwise requires, their respective subsidiaries. Cross references refer to sections of the Annual Report, unless stated otherwise.

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

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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	Performance summary	3
1.4	BHP – At a glance	4
1.5	Our strategy	13
1.6	Our performance	17
1.7	Samarco	26
1.8	Our operating environment	30
1.9	People	50
1.10	Sustainability	54
1.11	Our businesses	65
1.12	Summary of financial performance	88
1.13	Performance by commodity	115
1.14	Other information	135
2	Governance at BHP	137
2.1	Governance at BHP	137
2.2	Board of Directors and Executive Leadership Team	141
2.3	Shareholder engagement	148
2.4	Role and responsibilities of the Board	151
2.5	Board membership	154
2.6	Chairman	155
2.7	Renewal and re-election	155
2.8	Director skills, experience and attributes	156
2.9	Director induction, training and development	159
2.10	Independence	161
2.11	Board evaluation	163
2.12	Board meetings and attendance	165
2.13	Board committees	166
2.14	Risk management governance structure	187
2.15	Management	189
2.16	Business conduct	190
2.17	Market disclosure	191
2.18	Remuneration	191
2.19	Directors’ share ownership	191
2.20	Conformance with corporate governance standards	192
2.21	Additional UK disclosure	193
3	Remuneration Report	194
3.1	Annual statement by the Remuneration Committee Chairman	196
3.2	Remuneration policy report	200
3.3	Annual report on remuneration	213
4	Directors’ Report	240
4.1	Review of operations, principal activities and state of affairs	240
4.2	Share capital and buy-back programs	240
4.3	Results, financial instruments and going concern	242
4.4	Directors	242
4.5	Remuneration and share interests	243

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4.6	Secretaries	244
4.7	Indemnities and insurance	244
4.8	Employee policies	245
4.9	Corporate governance	245
4.10	Dividends	245
4.11	Auditors	246
4.12	Non-audit services	246
4.13	Political donations	246
4.14	Exploration, research and development	247
4.15	ASIC Instrument 2016/191	247
4.16	Proceedings on behalf of BHP Billiton Limited	247
4.17	Performance in relation to environmental regulation	247
4.18	Share capital, restrictions on transfer of shares and other additional information	247
5	Financial Statements	249
6	Additional information	250
6.1	Information on mining operations	250
6.2	Production	278
6.3	Reserves	283
6.4	Major projects	301
6.5	Legal proceedings	302
6.6	Glossary	308
7	Shareholder information	320
7.1	History and development	320
7.2	Markets	320
7.3	Organisational structure	320
7.4	Material contracts	323
7.5	Constitution	324
7.6	Share ownership	330
7.7	Dividends	334
7.8	Share price information	335
7.9	American Depositary Receipts fees and charges	336
7.10	Taxation	337
7.11	Government regulations	346
7.12	Ancillary information for our shareholders	350
8	Exhibits	355

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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 can be identified by the use of terminology such as ‘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 1.8.3 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.

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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	1.12
B	Capitalization and indebtedness	Not applicable
C	Reasons for the offer and use of proceeds	Not applicable
D	Risk factors	1.8.3
4.	Information on the Company
A	History and development of the company	1.4, 1.12, 1.13, 6.4, 6.5, 7.1 to 7.4 and 7.12
B	Business overview	1.4 to 1.5, 1.8, 1.11 to 1.13, 7.3, 7.4, 7.11
C	Organizational structure	7.3 and Note 28 to the Financial Statements
D	Property, plant and equipment	1.11.1 to 1.11.3, 1.13, 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	1.6, 1.8, 1.11 to 1.13, 7.11
B	Liquidity and capital resources	1.12.3, 5.1.4 and Notes 21 and 32 to the Financial Statements
C	Research and development, patents and licenses, etc.	1.5, 1.8.2, 1.11, 1.12, 4.14 and 6.3
D	Trend information	1.8.1, 1.11.1 to 1.11.3, 1.13
E	Off-balance sheet arrangements	1.14 and Notes 32 and 33 to the Financial Statements
F	Tabular disclosure of contractual obligations	1.14 and Notes 32 and 33 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	1.9, 1.9.4 and 1.9.5
E	Share ownership	2.19, 3.3.18, 3.3.19 and Note 23 to the Financial Statements
7.	Major Shareholders and Related Party Transactions
A	Major shareholders	7.6
B	Related party transactions	3.4 and Notes 22 and 31 to the Financial Statements
C	Interests of experts and counsel	Not applicable
8.	Financial Information
A	Consolidated statements and other financial information	1.7, 5.1, 5.6, 6.5, 7.7 and the pages beginning on F-1 in this Annual Report
B	Significant changes	Note 34 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
D	Selling shareholders	Not applicable

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Item Number	Description	Report section reference
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, 7.5, 7.11 and 7.12
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	7.5.14
I	Subsidiary information	Note 28 to the Financial Statements
11.	Quantitative and Qualitative Disclosures About Market Risk	1.8, Note 21 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 36 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	Exhibit 95.1
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 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 alternate 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.

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

Section 1 of this Annual Report 2017 constitutes our Strategic Report 2017. References to sections beyond section 1 are references to sections in this Annual Report 2017. 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 at the end of this Annual Report.

1.1    Chairman’s Review

Dear Shareholder,

It is an honour and a privilege to be able to write this letter as the new Chairman of BHP. At the outset, I want to acknowledge the contribution of my predecessor, Jac Nasser, who has led the Board for the past seven years. I thank Jac for his outstanding service to the Board and the Group during his tenure. While we will miss his strong leadership and wise counsel, he leaves a lasting legacy at BHP.

As incoming Chairman, I spent much of the past three months engaging with shareholders and other stakeholders around the world in order to better understand their perspectives. I plan to engage with investors on a regular basis.

Since I joined the Board in September last year, I have also taken the opportunity to visit many of our locations around the world to gain a better understanding of BHP from the front line. I have visited Western Australia Iron Ore in the Pilbara, coal operations in Queensland, the Jansen Potash Project in Canada, Onshore and Offshore petroleum operations in the United States and copper assets in Chile. This has been a rewarding experience and has reinforced to me the strength and potential of BHP to create long-term value for our shareholders.

BHP’s first-class assets generate significant amounts of cash in almost all phases of the commodity cycle, and the way we allocate that cash going forward is going to be an important determinant of how much shareholder value is created. The Board strongly supports the capital allocation framework that your CEO, Andrew Mackenzie, established at the beginning of 2016. It is however a framework, and since its inception, the Board and management team have been working together to strengthen its application. This work is ongoing.

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Your Board recognises the importance of cash returns to shareholders. The dividend policy provides for a minimum 50 per cent payout of Underlying attributable profit at every reporting period. For FY2017, the Board determined a final dividend of 43 US cents per share, which is covered by free cash flow generated in the current period. The final dividend comprises the minimum payout per share plus an additional amount of 10 US cents per share. Strict adherence to our capital allocation framework balances value creation through capital investment, cash returns to shareholders and balance sheet strength in a transparent and consistent manner.

The Board has continued to focus on responding to the tragedy at Samarco. A review of the non-operated minerals joint ventures was conducted in FY2017 and we have implemented a number of actions identified as part of that review. We have developed a global standard which defines the requirements for managing BHP’s interest in our non-operated minerals joint ventures. These minimum requirements include a framework for identification and management of risks to BHP from the non-operated joint ventures, which is consistent with the risk management framework for identifying and managing risks across BHP. More information can be found in section 1.7.

We take a structured and rigorous approach to Board succession planning, having regard to the skills, experience and attributes required to effectively govern and manage risk within BHP, so that we have the right balance on the Board and the Board continues to be fit-for-purpose.

During the year, John Schubert and Pat Davies retired from the Board. In addition, Malcolm Brinded and Grant King have decided that they will not stand for election at the 2017 Annual General Meetings. I thank all of these retiring directors for their service to BHP and wish them the very best.

In line with our planned approach to Board succession, Terry Bowen and John Mogford were appointed to the Board as Non-executive Directors with effect from 1 October 2017. Both have extensive executive experience which will enable them to make significant contributions to the BHP Board.

After several years of considered and deliberate effort, BHP is stronger, simpler and more productive. BHP has a world class management team, led by Andrew Mackenzie, and I look forward to supporting them in our pursuit of long-term value creation for all our shareholders.

Thank you for your continued support of BHP.

Ken MacKenzie

Chairman

1.2    Chief Executive Officer’s Report

Dear Shareholder,

To meet the challenges of today, we must think in decades and generations. BHP’s ability to plan, work and invest for the long term has always been our competitive advantage.

Over the past five years, we have laid the foundations to significantly improve returns and grow value. The benefits of this deliberate path are clear in our FY2017 results.

Safety is, and always will be, our highest priority. In the last 12 months, tragically, two of our colleagues died at work – one at our Escondida mine in Chile in October 2016 and one at the Goonyella Riverside mine in Australia in August 2017. I offer my sincere condolences to the families, friends and colleagues of the two team members who lost their lives.

The most important job our people have, myself included, is to make sure our team goes home safe at the end of each day. While our safety performance has improved in terms of total recordable injury frequency (down to 4.2 per million hours worked), we have renewed our efforts to help our people understand the risks and critical controls that must be in place to protect the health and safety of everyone who works with BHP.

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Our new five-year sustainability performance targets came into effect 1 July 2017. These targets are a public statement to our stakeholders about our commitment to sustainability and are consistent with our commitment to the Paris Agreement and the United Nations Sustainable Development Goals. They are also at the heart of how we work at BHP – we are determined to make a positive difference through our performance.

Our FY2017 financial and operational results were strong. All our operated assets were free cash flow positive and delivered a total free cash flow of US$12.6 billion. We used this cash to strengthen the balance sheet and return US$4.4 billion to you, our shareholders.

We have achieved a great deal over the past year, but we will not stand still. We are committed to maximising cash flow, maintaining capital discipline and improving value and returns.

We will deliver consistent and transparent application of our capital allocation framework, which includes cash returns to shareholders.

Our strong performance in FY2017 was achieved thanks to the hard work and passion of the people of BHP. It is a testament to what we can all achieve when we come together as a team of teams.

We know that the most diverse teams are those who perform the best – our data tells us this. That’s why we were proud to announce at last year’s Annual General Meetings our aspirational goal to achieve gender balance by FY2025. BHP has made great progress in 12 months, but we know we still have a long way to go.

The past financial year has taught us many things, but especially this – the world needs people who think boldly, think creatively and bring the best of themselves to what they do. It needs people who think big. For corporations like BHP, it is up to us to shape change for the better, through innovation, productivity and technology. It is our responsibility to have a voice and be transparent.

Thank you to our people, shareholders, suppliers, customers and host communities who work with us. Together, we work to improve the lives of millions of people across the world and drive global economic growth.

I also extend my thanks to outgoing Chairman Jac Nasser, who has been a source of strength and leadership for BHP, and to me personally, over the last decade. His remarkable legacy and contribution will be felt for years to come.

BHP is well-positioned for the future with our incoming Chairman, Ken MacKenzie. Together with the Board, I look forward to FY2018 and beyond as we grow shareholder value and increase returns.

Andrew Mackenzie

Chief Executive Officer

1.3    Performance summary

Not required for US reporting. Refer to sections section 1.12 and 1.13.

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1.4    BHP – At a glance

Key facts

BHP is a world-leading resources company. We extract and process minerals, oil and gas, with more than 60,000 employees and contractors, primarily in Australia and the Americas. Our products are sold worldwide, with sales and marketing led through Singapore and Houston, United States. Our global headquarters are in Melbourne, Australia.

We operate under a Dual Listed Company structure with two parent companies (BHP Billiton Limited and BHP Billiton Plc) operated as if we were a single economic entity, which we refer to as BHP. We are run by a unified Board and management.

4

What we do

5

Our purpose and strategy

Our corporate purpose is to create long-term shareholder value through the discovery, acquisition, development and marketing of natural resources. We do this through our strategy: to own and operate large, long-life, low-cost, expandable, upstream assets diversified by commodity, geography and market.

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1.4.1    Who we are

Our Operating Model

We have a simple and diverse portfolio of tier one assets around the world, with low-cost options for future growth and value creation. This allows us to apply our values and culture, emphasise safety and productivity, deploy technology and exert capital discipline to extract the most value and the highest returns from our assets.

Our Operating Model allows us to leverage our expertise across our business, with multifunctional teams that connect across the organisation to share best practice, make us safer and solve problems together.

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 safely 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 operation and operated by BHP. Our non-operated assets include interests that are owned as a joint venture but not operated by BHP.

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 practices, 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.

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Marketing and Supply: Our commercial businesses 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.

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. The Operations Management Committee (OMC) has responsibility for planning, directing and controlling the activities of BHP, including key Group strategic, investment and operational decisions, and recommendations to the Board.

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.

8

What we produce

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.

⁽¹⁾  For more information on the reconciliation of alternate performance measures to our statutory measures, including from Profit after taxation from Continuing and Discontinued operations to Underlying EBITDA (and Underlying EBITDA margin), refer to section 1.12.4. For more details on commodity performance, refer to section 1.13.

⁽²⁾  Percentage contribution to Group Underlying EBITDA, excluding Group and unallocated items.

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How we contributed in FY2017

Figures are rounded to the nearest decimal point. For more information refer to the Economic Contribution Report 2017.

⁽¹⁾  Calculated on an accrual basis.

⁽²⁾  Social investment target is 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 2017. Additional social investment of US$7.2 million (BHP Share) was made by our Equity Accounting Investments for a total social investment of US$80.1 million.

The resources we produce help build cities, produce energy and provide developing nations with the resources they need to grow.

We are proud of the value we generate and how this contributes to building trust with the communities in which we operate.

The economic contribution we make is important. We bring capital and high-paying jobs to the communities in which we work, both within our assets and throughout the supply chain. We also create value for our shareholders, lenders and investors. In FY2017, our total direct economic contribution was US$26.1 billion, including payments to suppliers, wages and employee benefits, dividends, taxes and royalties.

The taxes we pay enable governments to provide essential services to their citizens and invest in their communities for the future. We paid US$4.7 billion globally in taxes, royalties and other payments to governments in FY2017. Our statutory effective tax rate was 39.7 per cent and our global adjusted effective tax rate was 34 per cent. Including royalties, this increases to 44 per cent.

For more information, refer to section 1.12.4.

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1.4.2    Where we are

BHP locations (includes non-operated)

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⁽¹⁾  Non-operated joint venture.

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1.5    Our strategy

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

Our plan to grow value

Consistent with our strategy, we have a plan to create long-term shareholder value. This plan is focused on six key areas:

1. Cost efficiencies – focused on further gains

Since FY2012, we have reduced unit costs across BHP by more than 40 per cent. Our simple portfolio, standardised systems and greater connectivity across our assets and commodities, position us to further improve productivity.

2. Latent capacity – attractive returns, limited risk

We have further opportunities to optimise and debottleneck our existing mine, rig, port, rail and processing facilities. That means we can get more production, or replace production, from our existing infrastructure for lower cost. For example, we plan⁽¹⁾ to increase capacity at our Western Australia Iron Ore asset during FY2019 to a record 290 million tonnes per annum, by improving our rail signalling system and better utilising our equipment and infrastructure. This will help make full use of the port, rail network and mines we’ve already built.

3. Major projects – timed for value and 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 capacity 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 ktpa of payable copper in concentrate and 4 ktpa of payable molybdenum, with first production scheduled for the 2021 financial year. We are also continuing to investigate one of the best undeveloped potash resources in the world in Jansen in Canada. There are many ways we could realise the value of this project, but Board approval will be sought only if the project passes our strict investment hurdles and is in the best interests of our shareholders.

4. Exploration – positive results reduce risk for future wells

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. Exploration is the lowest cost way to add these resources to the portfolio, and investing now means we can take advantage of lower exploration costs. We recently had positive drilling results at Wildling in the US Gulf of Mexico following the discovery of oil in multiple horizons. Together with the successful bid for Trion and positive drilling results in the Caribbean, this provides us with additional confidence.

5. Technology – improves safety, lowers cost and unlocks resource

We will continue to develop and introduce new technology that increases efficiency, improves safety and unlocks resource. Our diverse portfolio enables us to adapt technology developed for one commodity to other areas of our business: for example, a tool that has been developed for assaying iron ore is now being trialled for use in our copper assets.

6. Onshore US – value and flexibility

Our regular portfolio review has concluded that the Onshore US assets are non-core and we are pursuing options to exit our quality acreage. This will take time, which we will use productively to maximise the value of our acreage through disciplined development, larger completions, acreage swaps, gas hedging and divestments.

⁽¹⁾  Assumes all internal and third party approvals received.

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1.5.1    Focus areas

Three critical focus areas underpin our strategy: safety, culture and productivity.

Safety

We achieve nothing if we do not do it safely.

We seek to prioritise the health and safety of our people, our host communities and the environment.

We know that we can never take the safety of our people for granted. We reassess our safety risks and controls regularly. If anything changes (for example, new technology is developed, new risks emerge or we gather new information), then we adapt our approach as needed to make sure our people are as safe as possible.

The performance of all of our people is measured by how safe our workplaces are. We have a goal of zero fatalities, and our total recordable injury frequency (TRIF) is a key performance indicator throughout BHP.

For more information on our approach to safety and our safety performance, see section 1.10.3 and our Sustainability Report 2017 at bhp.com.

Culture

We focus on our culture as it enables performance.

We believe it is important for every employee to understand how their work contributes to achieving our strategy, work in an environment where it’s ‘safe to speak up’ and be able to take up their full accountability. Our Employee Perception Survey (EPS) results serve to guide us on areas where we have performed well, and areas that require further attention.

In FY2017, our leaders put in place tailored plans to increase care and trusted relationships within our teams – attributes we have identified as critical in making the most of our Operating Model. These plans include local and BHP-wide priorities, including new leadership development programs focused on the identification and realisation of value and the management of risk. This work builds on years of investment in developing our leaders’ capabilities to engage and develop their teams and to lead change.

For more information on our culture and the actions we are taking to support it, see section 1.9.1.

Productivity

We have achieved significant productivity gains in recent years, helping us to produce our resources at significantly lower cost and achieve strong cash flows, even while commodity prices were low.

There is considerable value still to come from our assets and initiatives across BHP. The simplicity of our portfolio, the scale and quality of our ore bodies and oil and gas fields and our standardised systems and processes are all important attributes. When combined with a newly streamlined corporate structure, and centres of excellence in maintenance, projects and geoscience, we are well positioned to reduce costs and improve production even further.

For more on productivity, see section 1.6.

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1.5.2    Managing performance and risk

Corporate planning

Our corporate planning process is designed to deliver long-term, sustainable shareholder value.

The Board sets the long-term strategy for BHP, considering all our opportunities for the creation of long-term shareholder value. The long-term strategy is developed by integrating portfolio, commodity and asset-level outlooks and is underpinned by our strategic objectives.

Our corporate planning process is an annual process that is fundamental to creating alignment across the organisation; it guides the development of plans, targets and budgets to help us decide where to deploy our capital and resources. The process starts with planning to maximise opportunities for the long-term creation of shareholder value by understanding our strategic options, then focuses on medium and short-term plans to deliver against these objectives.

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 against a constantly changing external environment, to capture and manage emerging risks and opportunities and cascade them through our planning processes. Long-term scenario planning is used to evaluate our portfolio of assets and to help us identify new opportunities and test the robustness of our strategy over a range of possible outcomes.

We also use signals tracking to monitor near-term trends and events that may give an early indication of threats and opportunities identified from evaluating the long-term scenarios. Signals also support actions to position BHP to mitigate or benefit from these threats and opportunities, while helping to inform major portfolio investment decisions.

Risk management

Identifying and managing risk and opportunity are central to achieving our corporate purpose of creating long-term shareholder value.

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

• Risk assessments – we regularly 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.

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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 1.8.3. For information on our risk management governance, refer to sections 2.13.1 and 2.14.

Capital management

Our Capital Allocation Framework aims to maximise the potential value of every dollar we earn for our shareholders.

We start by aiming to earn as much as we can through the safe and productive operation of our assets. We then put this capital to work to:

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

• keep our balance sheet strong, to give us stability and flexibility through good times and tough times;

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

We then look at what would be the most valuable 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;

• invest in growth, either through projects within our assets or through exploration or acquisitions, provided it will create more value than a share buy-back.

This disciplined and rigorous approach helps us to maximise the value of every dollar for our shareholders.

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1.6    Our performance

Key performance indicators

Our key performance indicators (KPIs) enable us to measure our sustainable development and financial performance.

These KPIs are used as direct and indirect measures in the short-term or long-term incentive remuneration arrangements for senior executives. Certain KPIs (Total recordable injury frequency, Greenhouse gas emissions, Underlying attributable profit, Underlying EBITDA and Total shareholder return) are used directly to calculate incentive outcomes (subject to certain adjustments as described in section 3) and the remainder (Community investment, Net operating cash flows and Long-term credit rating) are considered more broadly in determining final overall results.

Our Remuneration Report is contained in section 3 and provides information on our overall approach to executive remuneration, including remuneration policies and remuneration outcomes.

1.6.1    Non-financial KPIs

Sustainability KPIs

Total recordable injury frequency ⁽¹⁾

    Definition   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 between two sites for work, in a BHP vehicle. TRIF does not include events at non-operated assets.   Link to strategy   We are committed to ensuring the safety and health of our people and this is supported by Our Charter value of Sustainability.   FY2017 performance   Tragically one of our colleagues, Rudy Ortiz, died at Escondida in Chile in October 2016.   Our TRIF performance in FY2017 was 4.2 per million hours worked, a two per cent decrease on the previous financial year. This represents a decrease of nine per cent over five years.   For information on our approach to health and safety and our performance, refer to section 1.10.3.

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

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Greenhouse gas emissions ^{(1) (6)}

    Definition   Greenhouse gas (GHG) emissions are measured according to the World Resources Institute/World Business Council for Sustainable Development Greenhouse Gas Protocol. This data covers our operated assets (including, until 8 May 2015, assets that now form part of South32).   Link to strategy   The global challenge of climate change remains a priority for BHP and is core to our strategic decision-making. Our operational GHG emissions are monitored and our performance is tracked against our target.   FY2017 performance   In FY2012, we set ourselves the target of limiting our overall emissions in FY2017 to below our FY2006 baseline, while growing our business. With our FY2017 GHG emissions of 16.3 million tonnes of carbon dioxide equivalent (CO₂-e) being 21 per cent below the adjusted FY2006 baseline, we have successfully achieved our ambitious target. Projects at our Continuing operations tracked since FY2013 as part of our current GHG target achieved more than 975,000 tonnes CO₂-e of annualised abatement in FY2017.   For more information on our GHG emissions, refer to section 1.10.6.

⁽¹⁾  Measured according to the World Resources Institute/World Business Council for Sustainable Development Greenhouse Gas Protocol.

⁽²⁾  In order to compare the total GHG emissions in FY2015 to other financial years, GHG emissions (estimated) from South32 assets between the date of demerger and 30 June 2015 have been added to FY2015 GHG emissions as shown above.

⁽³⁾  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).

⁽⁴⁾  Scope 1 refers to direct GHG emissions from operated assets.

⁽⁵⁾  Our FY2006 baseline was adjusted as necessary for material acquisitions and divestments based on asset GHG emissions at the time of the applicable transaction.

⁽⁶⁾  Our GHG target for our operated assets is to keep our absolute FY2017 GHG emissions below our adjusted FY2006 baseline.

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Social investment ⁽¹⁾

    Definition   Our voluntary social investment is calculated as one per cent of the average of the previous three years’ pre-tax profit. For FY2017, as pre-tax profits for the period FY2014 to FY2016 were lower than in recent periods, social investment has also decreased. Expenditure includes BHP’s equity share for operated and non-operated joint ventures, and comprises cash, administrative costs and contributions to our BHP supported charities and the BHP Billiton Foundation.   Link to strategy   We believe in addition to operating a responsible and ethical company, we can make a broader contribution to the communities in which we operate and support Our Charter value of Sustainability.   FY2017 performance   Our voluntary social investment totalled US$80.1 million. This included US$75.1 million contributed to community development programs and associated administrative costs as well as a US$5 million contribution to the BHP Billiton Foundation.   For more information on our voluntary social investment, refer to section 1.10.4.

⁽¹⁾  Includes BHP’s equity share for both operated and non-operated joint ventures. Data prior to FY2016 includes payments made by operations demerged with South32.

Capital management KPIs

Total shareholder return (TSR)

    Definition   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).   Link to strategy   TSR measures BHP’s performance in terms of shareholder wealth generation, which aligns to our purpose as presented in Our Charter and enables the comparison of our performance with that of our peer companies.   FY2017 performance   TSR was 31.1 per cent during FY2017 as a result of increases in both the BHP share price and the dividends paid. From 1 July 2012 to 30 June 2017, BHP underperformed the sector peer group by 8.7 per cent and underperformed the Index TSR by 101 per cent.   For more information on our long-term incentive performance outcomes to June 2017, refer to section 3.3.3.

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Long-term credit rating

    Definition   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.   Link to strategy   The balance sheet is an enabler of strategy. An appropriately structured balance sheet enables BHP to act on value accretive opportunities at low points in the cycle and facilitate shareholder returns through the cycle. We aim to maintain a strong balance sheet consistent with seeking to achieve and maintain a solid ‘A’ credit rating.   FY2017 performance   Standard & Poor’s credit rating of BHP remained at the A level throughout FY2017. It affirmed this rating and changed its outlook on 20 January 2017 from negative to stable. Moody’s maintained its credit rating of BHP at A3 throughout FY2017 and improved its outlook from stable to positive on 3 May 2017.   For more information on our liquidity and capital resources, refer to section 1.12.3.

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1.6.2    Financial KPIs and performance overview

Financial KPls

Significantly higher prices have improved our margins, generated strong cash flow, reduced net debt and, in line with our financial performance, increased our dividends.

Profits and earnings

Attributable profit of US$5.9 billion includes an exceptional loss of US$842 million (after tax). This compares to an attributable loss of US$6.4 billion, including an exceptional loss of US$7.6 billion (after tax), in FY2016. The FY2017 exceptional loss related to the Samarco dam failure, Escondida industrial action and Chilean withholding tax paid at a concessional rate, partially offset by the reimbursement received on cancellation of the Caroona exploration licence. The FY2016 exceptional loss related to the impairment of our Onshore US assets, the Samarco dam failure and global taxation matters.

Our Underlying attributable profit was US$6.7 billion (FY2016: US$1.2 billion).

We reported Underlying EBITDA of US$20.3 billion, with higher prices, controllable cash cost improvements and other net movements (in total US$9.4 billion) more than offsetting the impacts of unfavourable exchange rate movements, inflation and one-off items (in total US$1.4 billion).

Cash flow and balance sheet

Our Net operating cash flow of US$16.8 billion reflects higher commodity prices and further cash cost efficiencies.

We continued to strengthen our balance sheet with a reduction in net debt of US$9.8 billion to finish the period at US$16.3 billion (FY2016: US$26.1 billion). This reduction reflects strong free cash flow generation during the period as well as non-cash adjustments of US$0.6 billion related to a fair value adjustment of US$1.2 billion from interest rate and foreign exchange rate movements, partially offset by the recognition of the Kelar finance lease of US$0.6 billion.

Our gearing ratio is 20.6 per cent (FY2016: 30.3 per cent).

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Reconciling our financial results to our key performance indicators

⁽¹⁾ Represents amounts attributable to non-controlling interests with respect of the Escondida industrial action (gross expense of US$(232) million; tax benefit of US$68 million; net expense of US$(164) million).

For more information on financial performance and alternate performance measures, refer to section 1.12.

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Capital management

We achieved strong capital management results in FY2017. We have focused on low-cost, high-return latent capacity projects, which has allowed us to reduce capital expenditure. We strengthened our balance sheet and our dividend policy enables the stability and flexibility to create value and reward shareholders in a more volatile environment.

Free cash flow

Net operating cash flow of US$16.8 billion and free cash flow⁽¹⁾ of US$12.6 billion in FY2017 were underpinned by higher commodity prices, strong operating performance and improved capital productivity. Our free cash flow position was our second highest on record and all operating assets were free cash flow positive.

We continued to strengthen our balance sheet through debt reduction (see cash flow and balance sheet commentary on the preceding pages).

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 33 US cents per share. Recognising the importance of cash returns to shareholders, the Board has determined to pay an additional amount of 10 US cents per share, taking the final dividend to 43 US cents per share which is covered by free cash flow generated in FY2017. In total, dividends of US$4.4 billion (83 US cents per share, an increase of 177 per cent from FY2016) have been determined for FY2017, including additional amounts of US$1.1 billion.

Capital and exploration expenditure reduced by 32 per cent to US$5.2 billion in FY2017, as we focused on capital efficient latent capacity projects and exercised flexibility in our Onshore US plans. Capital and exploration expenditure is expected to increase to US$6.9 billion in FY2018. The increase in expenditure compared to the prior year reflects continued investment in high-return latent capacity projects, increased Onshore US drilling activity and approval of Mad Dog Phase 2 and the Spence Growth Option.

⁽¹⁾  For more information on the reconciliation of alternate performance measures, refer to section 1.12.4.

Productivity and costs

Productivity gains (which represent changes in controllable cash costs, changes in volumes attributed to productivity and changes in capitalised exploration) of US$1.3 billion were achieved for the period, with total annualised productivity gains of more than US$12 billion accumulated over the last five years. Productivity gains were lower than expected, largely as a result of volumes at the lower end of expected ranges and increased exploration expenditure, including the successful bid for Trion in Mexico.

Improvements continue to be realised across the portfolio. We expect to deliver a further US$2.0 billion of productivity gains over the two years to the end of FY2019, with gains weighted to the second year.

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Group copper equivalent unit costs declined by four per cent compared to FY2016. Escondida and Western Australia Iron Ore (WAIO) unit cash costs decreased by 17 per cent to $0.93 per pound (excluding the impact of the industrial action) and three per cent to US$14.60 per tonne, respectively. Conventional petroleum and Queensland Coal unit costs increased by two per cent and eight per cent, respectively. Escondida unit costs were seven per cent lower than expected due to continued productivity improvements and favourable inventory movements. If costs related to the industrial action were included, Escondida unit costs would have been US$1.13 per pound (compared to US$1.12 per pound in FY2016). WAIO unit costs declined due to reductions in labour and contractor costs, and productivity improvements. Conventional petroleum unit costs were higher due to lower volumes as a result of planned maintenance at Atlantis and natural field decline. Queensland Coal unit costs were higher as sales volumes were impacted by Cyclone Debbie.

For more information, refer to section 1.12.2 and 1.6.3.

Case study: Driving value through excellence in maintenance

Achieving excellence in maintenance has the potential to drive real value for BHP. We have set ourselves the ambitious target of saving an aggregated US$1.2 billion in maintenance costs across BHP by the end of FY2022 and reducing down time by 20 per cent. We plan to do this by focusing on defect elimination, excellence in planning and scheduling, and safely embedding optimised maintenance strategies.

Across BHP’s operations, we use more than 3,000 machines, including 1,300 trucks, around 400 loaders, 450 dozers, 240 drills, 200 excavators, and more. We also rely on a variety of fixed plant equipment to process our commodities. All this equipment currently costs around US$3.5 billion annually to maintain.

BHP has created the Maintenance Centre of Excellence to partner with our operations with the goal of delivering safe, sustainable improvement in our equipment performance. The Centre aims to utilise BHP’s scale and draws on the deep expertise, data and systems we hold across our business to reduce cost, cut unplanned down time, improve production and ensure our equipment is safe and reliable for our people.

We have established regional planning hubs in Brisbane, Perth and Adelaide, co-located with supply chain and maintenance strategy teams, to enable work to be more accurately planned further in advance. The goal is to improve supply chain performance, making frontline maintenance teams more effective, which in turn leads to improved availability and reduced cost.

The Centre’s work to date has reduced master data errors, improved planning lead times and accuracy, and reduced life-of-asset costs. One example is the equipment strategy for our most important haul truck, the Caterpillar 793F, almost 300 of which are in use in BHP’s operations around the world. We brought together a team of experts from our Coal, Iron Ore, Copper, Technology and Supply teams to identify how to maximise the value of this truck based on the function it performs in our mining operations. By optimising the maintenance and supply chain strategies, and setting operating limits for how we use these trucks in the field, we have reduced costs by a projected 20 per cent across the remaining life of the fleet, and improved availability.

Another example is our Liebherr T282 haul trucks. By standardising pit stop servicing improvements, implementing preventative activities, such as targeted electrical component inspections for identified problem areas, and installing specific component updates and parts, we expect to reduce costs by a projected 18 per cent across the remaining life of the fleet. Similarly, for our fleet of D10 and D11 dozers, we expect to reduce costs by a projected 18 per cent across the remaining life of the fleet as a result of improvements to undercarriage, hydraulics and power train strategies.

Over the next three years and beyond, the Centre intends to work through BHP’s top 70 asset classes to accelerate the delivery of these productivity improvements. This significant program of work will focus on improving the end-to-end performance of these assets and the maintenance systems that support them to generate a step change in safety, equipment availability and cost performance.

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1.6.3     Commodity performance overview

Commodity prices

The following table shows the prices for our most significant commodities for the years ended 30 June 2017, 2016 and 2015. 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 1.13.

Year ended 30 June	2017 Closing		2016 Closing		2015 Closing		2017 Average		2016 Average		2015 Average		2017 vs 2016 Average
Natural gas Henry Hub (1) (US$/MMBtu)		3.0		2.9		2.8		3.0		2.2		3.3		33%
Natural gas Asian Spot LNG (2) (US$/MMBtu)		5.5		5.2		7.3		6.4		6.1		9.7		5%
Crude oil (Brent) (3) (US$/bbl)		47.4		48.4		61.1		49.6		43.2		73.9		15%
Ethane (4) (US$/bbl)		10.3		9.7		8.4		9.5		7.7		8.6		24%
Propane (5) (US$/bbl)		25.1		21.7		16.3		24.9		17.9		29.3		39%
Butane (6) (US$/bbl)		30.8		28.9		23.9		33.3		24.2		36.9		38%
Copper (LME cash) (US$/lb)		2.7		2.2		2.6		2.4		2.2		2.9		10%
Iron ore (7) (US$/dmt)		63.0		55.0		59.5		69.5		51.4		71.6		35%
Metallurgical coal (8) (US$/t)		148.5		91.5		88.0		190.4		81.6		102.9		133%
Energy coal (9) (US$/t)		82.5		56.5		61.7		80.5		53.4		64.4		51%
Nickel (LME cash) (US$/lb)		4.2		4.3		5.3		4.6		4.2		7.0		9%

⁽¹⁾  Platts Gas based on Henry Hub – typically applies to gas sales in the US gas market.

⁽²⁾  Platts Liquefied Natural Gas Delivery Ex-Ship (DES) Japan/Korea Marker – typically applies to Asian LNG spot sales.

⁽³⁾  Platts Dated Brent – a benchmark price assessment of the spot market value of physical cargoes of North Sea light sweet crude oil.

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

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

⁽⁶⁾  OPIS Mont Belvieu non-Tet Normal Butane – typically applies to butane sales in the US Gulf Coast market.

⁽⁷⁾  Platts 62 per cent Fe Cost and Freight (CFR) China – used for fines.

⁽⁸⁾  Platts Low-Vol hard coking coal Index FOB Australia – representative of high-quality hard coking coals.

⁽⁹⁾  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 FY2017 on our key financial measures is set out below.

	Impact on profit after taxation from Continuing and Discontinued operations  (US$M)		Impact on Underlying EBITDA (US$M)
US$1/bbl on oil price		48		73
US¢10/MMBtu on US gas price		17		28
US¢1/lb on copper price		18		26
US$1/t on iron ore price		142		202
US$1/t on metallurgical coal price		23		33
US$1/t on energy coal price		10		14
US¢1/lb on nickel price		1		1

1.7     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 mine tailings (water and mud-like mine waste) 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

Our commitment to do the right thing for the people and the environment is unwavering.

Our initial priority was to support Samarco in the humanitarian response and ensure the safety of people and the environment. We have now moved from that emergency phase to a more strategic, structured way of working, which is focused on engaging with the affected communities to provide the solutions they need. This work is being conducted through Fundação Renova.

Fundação Renova

Fundação Renova is implementing programs to restore the environment and rebuild the communities, as set out in the Framework Agreement with the relevant Brazilian authorities that was signed in March 2016 (see section 6.5 Legal proceedings for more information on the Framework Agreement). Fundação Renova is a not-for-profit, private foundation, named after the Portuguese word for ‘renew’. It was established by BHP Billiton Brasil, Vale and Samarco, in accordance with the Framework Agreement, and became operational on 2 August 2016.

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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 is governed by a Board of Governors, comprised of representatives nominated by BHP Billiton Brasil, Vale, Samarco and the Interfederative Committee. Its governance structure also comprises a Fiscal Council, Advisory Council, a Compliance Manager and an Ombudsman. The Advisory Council includes representation from impacted communities, and community development and education experts. The activities of Fundação Renova are overseen by an independent Interfederative Committee of 12 representatives from the Brazilian Government and environmental agencies, who monitor, guide and assess the progress of actions agreed in the Framework Agreement and are implemented by an Executive Board, comprised of members appointed by the Board of Governors. Fundação Renova’s staff of 400 people is supported by around 2,500 contractors and a small number of BHP employees seconded to the organisation who provide specialist environmental, social, legal, governance and communication advice. Fundação Renova’s budget for CY2017 was R$1.94 billion (approximately US$590 million).

To address 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, to be managed by the International Union for Conservation of Nature (IUCN), will provide expert advice to Fundação Renova. The panel is to be guided by the principles of independence, transparency, accountability and engagement, and its reports and recommendations will be publicly available. Chaired by Yolanda Kakabadse, currently President of WWF International, the panel intends to hold its first meeting prior to the end of CY2017.

Resettlement

Fundação Renova is relocating and rebuilding the communities of Bento Rodrigues, Paracatu and Gesteira, in consultation with the affected community members. The relocation process involves the identification and acquisition of land, design and planning for the urban development, including all services and reconstruction of 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.

Resettlement is progressing, with active participation of the communities. Residents collectively designed criteria for potential sites for the new communities and applied the criteria to agree a short list of options from a larger list of possible locations. They visited the different relocation options, viewed 3D videos and received booklets containing information such as soil quality, water, geology and vegetation. In addition, residents saw models of each site, to better assess different areas.

The communities identified their new locations through a voting process overseen by an independent audit company, and urban planning has commenced in consultation with the communities. However, issues with the sale of the land selected by Gesteira residents have delayed the process. Fundação Renova is now investigating alternatives for the residents’ consideration.

Remediation

Geochemical studies have concluded that the tailings material is non-toxic and does not pose human health concerns.

Fish surveys were conducted along stretches of the Rio Doce. The surveys identified the presence of fish in all areas studied, with experts concluding that it is likely that repopulation of Rio Doce fish stocks is being complemented by stocks in the river’s tributaries. However, precautionary fishing bans remain in place while definitive studies to assess any potential impacts on fish tissue metal levels or fish stocks are completed.

Areas to be rehabilitated have been temporarily revegetated with fast growing species to reduce potential for erosion while longer-term solutions are developed.

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Areas with the greatest potential to act as sources of sediment and contribute to turbidity were prioritised according to independent expert consultant reviews.

The majority of the emergency works for stabilisation of flood plains, tributaries and river banks in the priority areas are completed. Erosion stabilisation activities in non-priority areas will continue for the remainder of 2017.

Environmental compensation programs to rehabilitate 40,000 hectares of degraded land are in the design stage, with consultants engaged and consultation with regulatory and community stakeholders having commenced. Over 500 degraded natural springs have been revegetated as part of a Framework Agreement commitment to rehabilitate 5,000 springs over 10 years.

The program to build additional retention structures to contain tailings by December 2016 was completed successfully, controlling tailing releases during the wet season.

Compensation and financial assistance

Around 8,000 financial assistance cards have been distributed to people whose livelihoods were impacted by the dam failure, with the majority of those being for fishermen who are unable to fish following the dam failure.

The mediated compensation program is being rolled out throughout the impacted regions. It is intended to fairly compensate all individuals impacted by the dam failure. The program was designed based on inputs from public attorneys, local judges, technical entities and impacted families.

Around 400,000 people are expected to be entitled to compensation for interruption to water supplies along the Rio Doce. As at 22 July 2017, over 186,000 claims have been accepted for payment and 82,000 claims have been resolved. Over 14,000 families have registered for compensation for other damages, such as property loss or business impacts.

Lessons learned

Non-operated minerals joint ventures

Following a review of governance at our non-operated minerals joint ventures (NOJV), we have focused on the following actions.

Risk management and processes: we have developed a global standard which defines the requirements for managing BHP’s interest in our NOJVs. These minimum requirements include a framework for identification and management of risks to BHP from NOJVs, which is consistent with the risk management framework for identifying and managing risks across BHP. The global standard covers matters such as audits and input on succession planning for NOJV leadership positions. We are working closely with our NOJV partners with a view to establishing priority areas, communication strategies and workplans in line with this global standard.

Accountability and structure: the oversight of all our NOJVs has been centralised in our Minerals Americas asset group. We have created a NOJV leadership team and supporting team, who are a single point of accountability with responsibility for all NOJVs.

People: we have added to the capabilities of our teams to oversee the risks and opportunities at each NOJV. Further resources have been allocated to provide functional support, and for projects, governance and planning. This dedicated NOJV team of subject matter experts provides support to the NOJVs. These experts also contribute to discussions on governance improvement and value generation opportunities.

Our focus for FY2018 is on our governance processes for our NOJVs, including further development and implementation of specific standards for how BHP interacts with our NOJVs, based on best-practice governance benchmarking, and working with our NOJV partners to improve governance and assurance processes.

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Dams and tailings management

A risk review was conducted of all significant dams across our operated assets and the assets of our NOJVs in FY2016, which confirmed the dams to be stable.

Tailings dams require continuous monitoring and maintenance, so our focus has shifted to risk identification, governance and monitoring programs. We have identified opportunities for improvements to dam governance and risk management at our operated assets and at NOJVs. The following actions have been taken to address these issues:

• Dam safety reviews consistent with the Canadian Dam Association’s Dam Safety Guidelines are underway at all significant operated and non-operated sites, and are expected to be completed by December 2017. Those reviews include considering how climate change might impact the risk and design requirements for those dams, and will be repeated on a regular basis.

• A centralised function for dams and tailings governance and risk management has been created, to support our site management to apply appropriate dam risk management practices and build internal capability across the Group.

• We have investigated potential technological solutions for better dam management, in conjunction with leading technology providers. We have identified monitoring and early warning as having the greatest potential to enhance dam risk controls in the near term. We are also examining the feasibility of additional technologies to further enhance controls for dams.

BHP has used the lessons from the dam risk review to contribute to a broader tailings storage review by the International Council on Mining & Metals (ICMM). That review has resulted in the ICMM releasing a Tailings Position Statement, including a governance framework and benchmarks, which we intend to adopt.

Our focus for FY2018 will be on:

• the implementation of a stewardship program;

• progressing monitoring and early warning technologies and emergency response preparedness;

• further development of BHP’s dams and tailings controls and standards.

Legal proceedings

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 (approximately US$6.1 billion) public civil claim and the R$155 billion (approximately US$47 billion) Federal Public Prosecution Office claim relating to the dam failure.

The Preliminary Agreement also provides for the appointment of experts to advise the Federal Prosecutors on social and environmental remediation and the assessment and monitoring of the programs under the Framework Agreement. The expert advisors’ conclusions will be considered in the negotiation of a final settlement arrangement with the Federal Prosecutors.

Under the Preliminary Agreement, BHP Billiton Brasil, Vale and Samarco agreed to provide an interim security comprising R$1.3 billion (approximately US$395 million) in insurance bonds, R$100 million (approximately US$30 million) in liquid assets, a charge of R$800 million (approximately US$245 million) over Samarco’s assets and R$200 million (approximately US$60 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.

The Preliminary Agreement suspends a R$1.2 billion (approximately US$365 million) injunction order under the R$20 billion public civil claim and requests a suspension of that claim with a decision from the 12^th Court of Belo Horizonte pending. The Court also suspended the R$155 billion Federal Prosecution Office claim, including a R$7.7 billion (approximately US$2.3 billion) injunction request. The suspended legal proceedings and injunctions may be reinstated if a final settlement arrangement is not agreed by 30 October 2017.

For more information on legal proceedings relating to the Samarco dam failure, refer to section 6.5.

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.

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1.8    Our operating environment

1.8.1    Market factors and trends

We produce raw materials that are essential to modern life. Our success is tied to sustainable growth and development of both emerging and developed economies and, at the same time, is 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 will continue to drive 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 will 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 1.8.2). Exploration is inherently risky (see section 1.8.3) 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. After a period of weak prices, several of our commodities currently trade above long-term forecasts. In addition, there has been a marked rise in geopolitical uncertainty and protectionism, which has 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 FY2017 and protectionist policies that have the potential to curb international trade are becoming more common. Such policies are harmful for consumer purchasing power, and by extension, business confidence, investment and jobs.

Modest economic growth

Protectionism and political uncertainty lower the achievable ceiling for global economic growth while they remain in place. We expect world growth to remain in the 3–3.5 per cent range, on average, in coming years.

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Price volatility

Commodities markets will move back towards balance at various speeds, while prices are expected to remain volatile.

Petroleum market rebalances

Global demand for petroleum is expected to surpass global supply in the short term. Production outside the United States is likely to remain relatively flat and current excess inventories are likely to decline.

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 costs

The costs of producing some commodities are 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 costs rise, large producers are likely to benefit, as they can take advantage of scale and disciplined production practices.

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 high growth. Economic reforms appear to be maintaining their momentum, which will be critical to realising that potential.

Long term

Growth in population, wealth

Demand for commodities is expected to increase to meet the needs of the world’s growing population. Global energy needs are expected to increase by around 25 per cent in the next 20 years, with much of that demand coming from Asia, particularly China and India.

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 will continue to drive significant change. Environmental and risk concerns will drive increasing diversification of national energy sources.

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Technology

Technology can substantially alter the markets for and uses of our products. However, markets for essential products such as ours are typically slow to change. Our diversified portfolio provides some protection against disruption of demand caused by technological change.

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.

Key geographies

Our customers are geographically diverse. We have structured our business to flexibly 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, with 49 per cent of our revenues being derived from China. China is the largest manufacturing and exporting economy in the world and the second-largest importing economy, so its 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 FY2018, while remaining within the official GDP target range of between 6.5 and 7.0 per cent. We expect to see a cooling of growth rates in the housing and automobile markets, while infrastructure investment is expected to provide stability as overall growth slows.

China’s policymakers are likely to continue to seek a balance between the pursuit of reform and the maintenance of 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 will 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. As most of our transactions are denominated in US dollars, fluctuations in that currency can also influence our performance.

The medium-term outlook for the US economy is uncertain. Consumer confidence and spending are expected to remain strong, but a slowdown in the automotive and housing sectors may impact demand. Strong currency and higher interests rates may also reduce demand. Progress on growth enhancing infrastructure spending and tax reform has been slow and monetary conditions are expected to tighten further.

Protectionist policies would cut 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.

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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.

In the short to 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.

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 is solid, 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 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–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 FY2017 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 65 basis points to an average of 0.99 per cent in FY2017.

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1.8.2    Exploration

The world has abundant potential resources, but they are increasingly difficult to find and, for many resources, demand is increasing. For example, we estimate that demand for petroleum will increase by one per cent per year, while world production is expected to decline by three to four per cent per year by 2035.

A successful exploration program is the lowest cost way to add these resources to our portfolio. Innovation and discipline in exploration will be key to the discovery of new deposits. BHP has a proud history of successful exploration, since we first started mining silver, lead and zinc in Broken Hill over 130 years ago. We are building on that legacy; developing new technology and methods to identify and develop deposits. In this, we have the advantage of being the only global resource company that combines petroleum and minerals expertise. We are using that advantage to leverage science, technology and experience across our exploration program (see Leveraging our exploration expertise to create value on the next page).

Exploration strategy

Greenfield exploration is focused on copper and petroleum, and is the lowest cost way to build our portfolio of these assets. We are able to invest now, while others have cut back, which means we can take advantage of lower exploration costs. We are exploring for copper resources in Chile, Peru, Canada, South Australia and southwestern United States, and for petroleum liquids in the Gulf of Mexico, Trinidad and Tobago, and Western Australia. Like all investment decisions, these opportunities are carefully assessed and only pursued where they align with our strategy.

Exploration in FY2017

Petroleum

Our Petroleum exploration is informed by the results of an in-depth proprietary global endowment study. This study assesses the likelihood of significant hydrocarbon deposits and evaluates the viability of development and production of those deposits. Consistent with our strategy, we concentrate our efforts only in areas we feel have the potential to be high-quality assets: the Gulf of Mexico, the Caribbean and Western Australia.

In FY2017, we discovered gas at LeClerc in Trinidad and Tobago. Commercial evaluation of that discovery is well advanced: the region has large installed liquefied natural gas capacity and local petrochemical demand that is short of gas in the medium term.

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After finding oil at Shenzi North to the north of the operated Shenzi field in the US Gulf of Mexico in FY2016, we completed the nearby Caicos well in FY2017 and also discovered oil. The Caicos well reached a total depth of 9,198 metres and encountered oil in multiple horizons. Following these positive results, we accelerated our Wildling appraisal well and oil was discovered in multiple horizons in August 2017. Drilling of the Scimitar prospect, to the north of the Neptune field, is planned for FY2018.

Our exploration portfolio has been recently expanded with the acquisition of more leases in the Western Gulf of Mexico and the successful bid for the Trion discovered resource in Mexico’s deepwater. We have a partnership with Pemex to appraise and further explore opportunities over the licence area. The appraisal program is underway and drilling is planned for the beginning of FY2019. The appraisal program will allow us to further define the opportunity and assess commerciality.

For more details on Petroleum exploration, refer to section 1.13.1.

Copper

Our copper exploration is focused on the search for large, high-quality copper deposits in Chile, Peru, Ecuador, North America and Australia. We continue to review other jurisdictions and opportunities to partner with third parties to counter the increasing exploration maturity of our existing geographies.

In Chile, Peru and North America, activities focused on identifying and testing targets. In Australia, geophysical targets were identified and developed for testing. In Ecuador, five concessions were awarded to BHP via an auction process and we made applications for additional concessions. Establishment of an in-country presence in Ecuador has progressed, with a temporary office being rented and employment opportunities posted locally.

Sharing of exploration methodologies between the Petroleum and Copper teams has led to better targets for copper (see Leveraging our exploration expertise to create value below) and better research and development of new technology for Petroleum exploration.

Case study: Leveraging our exploration expertise to create value

Creating future value will require a very different approach to exploration. Identifying new deposits will be more difficult and expensive than in the past, but the rewards – if we get it right – will be correspondingly greater.

BHP is investing in geoscience excellence as a core skill and fundamental value driver for our business. Drawing on our petroleum liquids expertise, we have developed a systems approach to exploration that considers the whole earth system (tectonics, erosion, sedimentation, climate and more) in deep time, to determine where deposits are most likely to have formed. From this, we can determine which areas to target for further investigation and development.

This approach gives us more confidence in the potential of targeted areas, earlier, at lower cost. We have the potential to gain early mover advantage in undervalued regions, and better target our exploration and development spend to create value.

Driven by our Geoscience Centre of Excellence, the systems approach is already delivering results. We brought together an expert team of geoscientists from across our petroleum and copper assets, and reviewed our model for targeting copper exploration. From approximately 3,000 land-based sedimentary basins worldwide identified by our Petroleum business, we have selected around 200 with potential to contain copper deposits, and determined which to further investigate. As further data is collected, the certainty of finding a significant deposit improves.

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Exploration expenditure

Our brownfield minerals exploration expenditure increased by three per cent in FY2017 to US$120 million, while our greenfield expenditures decreased to US$43 million. Expenditure on brownfield and greenfield minerals exploration over the last three financial years is set out below.

Year ended 30 June	2017 US$M		2016 US$M		2015 US$M
Greenfield exploration		43		59		55
Brownfield exploration		120		116		194
Total minerals exploration		163		175		249

For more information on minerals exploration, refer to section 1.13.

Petroleum exploration

Petroleum exploration expenditure for FY2017 was US$805 million, of which US$473 million was expensed. Expenditure on Petroleum exploration over the last three financial years is set out below.

Year ended 30 June	2017 US$M		2016 US$M		2015 US$M
Petroleum exploration		805		590		567

Our Petroleum exploration program had positive results in FY2017. We are pursuing high-quality oil plays in our three priority basins and a US$715 million exploration program is planned for FY2018 as we progress testing of our future growth opportunities.

For more information on Petroleum exploration, refer to section 1.13.1.

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	2017 US$M		2016 US$M		2015 US$M
Exploration expense
Petroleum (1)		575		288		529
Copper		44		64		90
Iron Ore		70		74		38
Coal		9		18		20
Group and unallocated items (2)		16		1		21
Total Group		714		445		698

⁽¹⁾  Includes US$102 million (FY2016: US$15 million; FY2015: US$28 million) exploration expense previously capitalised, written off as impaired.

⁽²⁾  Group and unallocated items includes functions, other unallocated operations, including Potash, Nickel West and consolidation adjustments.

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1.8.3    Principal risks

Robust risk assessment and viability statement

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

The Directors have assessed the prospects of BHP over the next three years, taking 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 outlook and a 20-year strategic planning horizon. We have publicly stated our view that the outlook for the sector remains challenging and volatile in the short to medium term. This exchange rate and price volatility results in variability in plans and budgets. A three-year period strikes an appropriate balance between long 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 Board strategy discussions, which provide a strategic review of BHP’s markets and plans under divergent scenarios and consider available strategic options; the flexibility in BHP’s capital and exploration expenditure programs under the enhanced 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.

The Directors were also mindful of the scenario analysis incorporated in BHP’s corporate planning process. These scenarios help identify the key uncertainties facing the global economy and natural resources sector.

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 over the next three years.

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 oil, gas and minerals 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 FY2017 Profit after taxation from Continuing and Discontinued operations of US$142 million and US$48 million, respectively.

For more information in relation to commodity price impacts, refer to section 1.6.3. Volatility in global economic growth, particularly in developing economies, has the potential to adversely affect future demand and prices for commodities. 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 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- or long-term volatility in the prevailing prices of our products.

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Our financial results may be negatively affected by exchange rate fluctuations

The geographic diversity of the countries in which our assets are located means that 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.

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$18.9 billion (FY2016: US$13.2 billion) or 49.3 per cent (FY2016: 42.6 per cent) of our revenue in FY2017. FY2017 sales into China by commodity included 61 per cent Iron Ore, 22 per cent Copper, 16 per cent Coal and 1 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, regulation, political, community or social events, judicial or community activism or unrest in the countries where our assets are located could have a negative impact on our business

There are varying degrees of political, judicial and commercial stability and activism in the locations in which we have operated and non-operated assets 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 and non-operated assets could include terrorism, civil unrest, judicial activism, community challenge or opposition, regulatory investigation, 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 assets are affected by one or more of these risks, it could have a material adverse effect on our assets in those countries, as well as BHP’s overall operating results, financial condition and prospects.

Our operated and non-operated assets 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.

Our business could be adversely affected by new or 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 conduct business 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 engagement or approvals can potentially result in significant delays or interruptions and may adversely affect the economics of new mining and oil and gas projects, the expansion of existing assets and operations and the performance of our assets. As regulatory standards and expectations are constantly developing, we may be exposed to increased regulatory review, compliance costs to meet new operating and reporting standards and unforeseen closure and site rehabilitation expenses.

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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 are complex, difficult to predict and outside our control. Potential compliance costs, litigation expenses, regulatory delays, rehabilitation expenses and operational impacts and costs arising from government action, regulatory change and evolving standards could materially and adversely affect BHP’s future results, prospects and our financial condition.

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 oil, gas and minerals 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 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 and 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. Reserve restatements could negatively affect our results and prospects.

Potential changes to our portfolio of assets through acquisitions and divestments 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:

• adverse market reaction to such changes or the timing or terms on which changes are made;

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• 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.

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 we transact with 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 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.

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Operational risks

Unexpected natural and operational catastrophes may adversely impact our assets

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 port and shipping incidents, underground mine and processing plant fire and explosion, 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 and cyber security attacks on BHP’s infrastructure. Our minerals and oil and gas assets may also be subject to unexpected natural catastrophes such as earthquakes, floods, hurricanes and tsunamis. Our 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. 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 to 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.

Breaches in, or failures of, our information technology may adversely impact our business activities

We maintain and increasingly rely on information technology (IT) systems, consisting of digital infrastructure, applications and networks to support our business activities. These systems may be subject to security breaches (e.g. cyber-crime or activists) or other incidents (e.g. from negligence) that can result in misappropriation of funds, increased health and safety risks to people, disruption to our assets, environmental damage, poor product quality, loss of intellectual property, disclosure of commercially or personally sensitive information, legal or regulatory breaches and liability, other costs and reputational damage.

Evolving convergence of IT and operational technology (OT) networks across industries, including ours, present additional cyber-related risk as traditionally IT networks have focused on availability of service to the enterprise.

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 environment of the Rio Doce basin. 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 1.7.

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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 2017, as described in 1.7 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 29 ‘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 is 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$6.1 billion) in aggregate for clean-up costs and damages and a R$155 billion (approximately US$47 billion) claim brought by the Federal Public Prosecution Service on 3 May 2016 for reparation, compensation and moral damages in relation to the Samarco dam failure. Given the status of these proceedings, 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. For further details on some of the legal proceedings relating to the Samarco dam failure, refer to section 6.5.

On 2 March 2016, BHP Billiton Brasil, together with Vale and Samarco, entered into a Framework Agreement (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. The Framework Agreement was ratified by the Conciliation Chamber of the Federal Court of Appeal in Brasilia on 5 May 2016, suspending the R$20 billion public civil claim. However, on 30 June 2016, the Superior Court of Justice issued a preliminary order (Interim Order) suspending the 5 May 2016 ratification of the Framework Agreement and reinstating the R$20 billion public civil claim. BHP Billiton Brasil, Vale and Samarco and the Federal Government have appealed the Interim Order before the Superior Court of Justice.

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 2017, BHP recognised a provision of US$1.1 billion, before tax and after discounting (30 June 2016, US$1.2 billion), in respect of BHP Billiton Brasil’s obligations under the Framework Agreement.

The measurement of the provision requires the use of 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 further technical analysis required under the Preliminary Agreement (referred to on the next page), the outcome of the ongoing negotiations with Federal Prosecutors, 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. 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.

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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 public civil claim. While a final decision by the Court on the issue of ratification of the Framework Agreement is pending, the Preliminary Agreement suspends a R$1.2 billion (approximately US$365 million) injunction order under the R$20 billion public civil claim. The Preliminary Agreement also requests suspension of the public civil claim, with a decision from the Court pending. The R$1.2 billion injunction order may be reinstated if a final settlement arrangement is not agreed by 30 October 2017. Given the status of these proceedings, 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.

With regard to the Preliminary Agreement, the 12th Federal Court of Belo Horizonte suspended the R$155 billion claim, including a R$7.7 billion (approximately US$2.3 billion) injunction request. However, proceedings may be resumed if a final settlement agreement is not agreed by 30 October 2017. Given the status of these proceedings, 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.

In addition, government inquiries and investigations relating to the Samarco dam failure have been commenced by numerous agencies of the Brazilian Government. Other lawsuits and investigations are at the early stages of proceedings, including a shareholder action in the United States against BHP and a Samarco bondholder action 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.

While additional retention structures have been completed, the potential remains for further release or downstream movement of tailings material, which may result in additional claims, fines and proceedings (or impact existing proceedings) and may also have additional consequences on the environment and the feasibility, timing and scope of any restart of Samarco operations.

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.

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.

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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 assets have their own management and operating standards, joint venture partners or other companies managing those non-operated assets 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 which 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 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 assets could lead to higher costs and reduced production, litigation and regulatory action, delays or interruptions and adversely impact our results, prospects and reputation.

Commercial counterparties, such as our suppliers, contractors and customers, may not comply with our HSEC standards or other standards we apply, causing adverse reputational, legal and financial 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, ground control failures, uncontrolled tailings containment breaches, well blowouts, explosions or gas leaks and accidents involving inadequate isolation, working from heights or lifting operations.

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 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.

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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.

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 new 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 is launching 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. In such a scenario, stranded reserve assets held on our balance sheet may need to be impaired or written off and our inability to make productive use of such assets may also negatively impact our financial condition and results.

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.

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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, 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 involve hydraulic fracturing, which includes using water, sand and a small amount of chemicals to fracture hydrocarbon-bearing subsurface rock formations, to allow 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 7.11.

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 and what such actions would require or prohibit. Additional legislation or regulation could subject our assets to delays and increased costs, or prohibit certain activities, which could adversely affect the financial performance of our Onshore US assets.

Governance and compliance

A failure of our governance or compliance processes may lead to regulatory penalties and loss of reputation. 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 and offers of anything of value to government officials and representatives of state-owned enterprises) may not operate to identify financial misstatements or prevent potential breaches of law, or of accounting or governance practice. Our BHP Code of Business 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.

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1.8.4    Management of principal risks

The scope of our assets and the number of industries in which we conduct our business and engage mean that a range of factors may impact our results. Material risks that could negatively affect our results and performance are described in this section. 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 (such as China or Europe) or changes in currency exchange rates, and actions by governments, including new regulations and standards, and political events that impact long-term fiscal stability	The diversification of our portfolio of commodities, geographies and currencies is a key strategy for reducing the effects of volatility. Section 1.8.1 describes external factors and trends affecting our results and note 21 ‘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.
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 governance 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 major capital projects and asset divestment and acquisitions. The Investment Committee oversees these as described in sections 2.14 and 2.15. Our Project Management 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 currency exchange rates are not generally hedged, and wherever possible, we take the prevailing market price. A hedging program for our shale gas assets is an exception and reflects the inherent differences in shale gas assets in our portfolio. A shale gas operation has a short-term investment cycle and a price responsive supply base, while hedging prices and input costs can be used to fix investment returns and manage volatilities. We use Cash Flow at Risk analysis to monitor volatilities and key financial ratios. Credit limits and review processes are required to be established for all customers and financial counterparties. The Financial Risk Management Committee oversees these, as described in sections 2.14 and 2.15. Note 21 ‘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. Breaches in IT security processes may adversely affect the conduct of our business activities. 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 assets 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 must be 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. IT security controls (to protect IT infrastructure, business applications and communication networks and respond to security incidents) are in place and subject to regular monitoring and assessment. To maintain adequate levels of protection, we also continue to monitor the development of threats in the external environment and assess potential responses to those threats. The Board has continued to focus its attention on responding to the tragedy at Samarco. As that response has now moved from the immediate, emergency stage to a more strategic, structured way of working, we have transitioned the work previously carried out by the Samarco Sub-committee of the Board to the Risk and Audit Committee, the Sustainability Committee, as appropriate, as well as the Board. For further information on BHP’s response to the Samarco dam failure, refer to section 1.7. BHP has identified a number of actions that we will take in the management of tailings dams and non-operated joint venture arrangements. For details of those actions, refer to section 1.7.
	We aim to maintain adequate operating margins through our strategy to own and operate large, long-life, low-cost, expandable, upstream assets.
	Our concentrated effort to reduce operating costs and drive productivity improvements has realised tangible results, with a reduction in controllable costs.
	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 organisation, providing a competitive advantage through defining work, organisation 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 assets.
	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.

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Principal risk area	Risk management approach
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 1.10. Our Requirements standards set out Group-wide HSEC-related performance requirements designed to support effective management control of these risks.
	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 work with a broad range 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 1.10.6.
	Our approach to engagement with community stakeholders is outlined in our minimum organisational requirements for Community. 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.
	Our Requirements for Risk Management standard provides the framework for risk management relating to climate change and material health, safety, environment and community risks. We conduct internal audits to test compliance with 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.
	Our Requirements standards and action plans are developed to address any gaps. Key findings are reported to senior management and reports are considered by relevant Board committees.
	Our Code of Business 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. 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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1.9    People

With a workforce of more than 60,000 employees and contractors working across 87 locations worldwide, BHP’s culture is shaped to support the creation of value from our portfolio.

Our culture is shaped through our policies and the programs we enact to build a positive work environment and engage our people. It is driven by our leaders and the behaviours they demonstrate. And it is supported by the dialogue we have with and between our people, every day.

1.9.1    Supporting our culture

We engaged with a selection of employees across all levels and geographies in FY2017 to gather their views on the strengths and challenges of our current culture. Despite the diversity of our business, we found a handful of enduring traits that span business lines, geographies and levels. These traits contain many strengths that have enabled the delivery of strong business performance over many years.

With input from our employees, a cohort of senior leaders (including the General Managers who lead the workforces at our assets) have identified the behaviours that we will focus on to leverage the strengths of those traits. Leaders around the globe have translated these priorities into plans to amplify care and trusted relationships within our teams. These plans comprise both local and BHP-wide priorities, including the further roll out of leadership development programs focused on the identification and realisation of value and the management of risk.

This work builds on years of investment in developing our leaders’ capabilities to engage and develop their teams and to lead change. The positive impact of the programs that have been run to date is reflected in improvements in our annual Employee Perception Survey results.

BHP’s culture of care

BHP values a culture that enables our people to do the right thing for each other, for our communities and for our shareholders; reducing risk and driving performance.

Our focus on inclusion and diversity enables us to challenge entrenched ideas and bring innovative perspectives to our work.

For more information on our culture, refer to section 1.5.1.

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1.9.2    Inclusion and diversity

At BHP, we believe all employees should have the opportunity to fulfil their potential and thrive in an inclusive and diverse workplace. We employ, develop and promote based on merit and we do not tolerate any form of unlawful discrimination, bullying or harassment. Our systems, processes and practices support fair treatment.

To better reflect the communities in which we work, we have set an ambitious, aspirational goal to achieve gender balance across BHP globally by FY2025. It’s an aspiration designed to harness the enormous potential that a more inclusive and diverse workplace will deliver at BHP. Progress on our goal of gender balance will be reported to the Board each year for review.

The commercial case for action on gender balance is compelling. For the past three years, BHP’s most inclusive and gender diverse operations have outperformed our average on a range of measures, including lower injury rates, adherence to work plans and meeting production targets.

Our CEO, Andrew Mackenzie, chairs the Global Inclusion and Diversity Council that has recommended four priorities: embedding flexible working; enabling our supply chain partners to support our commitment to inclusion and diversity; uncovering and taking steps to mitigate potential bias in our systems, behaviours, policies and processes; and ensuring our brand and industry are attractive to a diverse range of people.

The gender composition of BHP’s employees was 20.5 per cent women as at 30 June 2017; an increase of 2.9 per cent in one year⁽¹⁾. This was very close to the goal we set our Executive Leadership Team of reaching a three per cent year-on-year increase in representation of women among employees across the Group. This was achieved in part through an improved gender balance in external hiring and reduction of the turnover rate for women. Our work on culture has also supported us in becoming more inclusive and embedding flexibility in the way we work.

We’re also enabling our supply chain partners to support our commitment to inclusion and diversity, by working with our suppliers to identify opportunities for improvement, incorporating inclusion and diversity enablers into supplier procurement processes and working with suppliers to redesign equipment to allow for handling by all operators, regardless of gender.

⁽¹⁾  Based on a ‘point in time’ snapshot of employees as at 30 June 2017, as used in internal management reporting for the purposes of monitoring progress against our goals. This does not include contractors.

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Case study: Achieving gender balance in practice

BHP’s Mooka Ore Car Repair Shop (OCRS) is a high-tech, semi-automated production line, designed to safely conduct highly repetitive activities that are involved in maintenance of ore cars.

Mooka OCRS took on the challenge of achieving a more inclusive workplace. As part of our push for continuous improvement, we redesigned the OCRS to reduce risk from activities such as shunting and overhead crane use. This not only made the workplace safer, it also made it possible for a diverse pool of talent from the local community to participate in our workforce, without requiring specialist technical qualifications.

For example, the introduction of automated guided vehicles and a robotic gantry system means that dogging and rigging licences are no longer required, while the mechanisation of tasks that formerly required heavy lifting means people of different physiques can perform them safely. Tasks that require a trade-qualified operator are separated from tasks that do not, which has enabled the participation of people without trade qualifications or previous experience.

As a result, we were able to adapt our recruitment and assessment processes to reach a broader range of people from our local communities. We used information sessions and assessment centres to promote opportunities. Assessment focused on characteristics such as demonstrated behaviours and the ability to work in a team, rather than technical capabilities. Our workforce is now 30 per cent women (up from five per cent in FY2016) and 10 per cent Indigenous as at 30 June 2017.

We know that in addition to improving diversity, we must support inclusive workplaces. We focused on creating an inclusive culture through visible leadership, more face-to-face updates on performance and regular updates on any changes impacting the team. The strength of this approach is reflected in this year’s Mooka OCRS Employee Perception Survey results, which are higher than the BHP average and above external norms for high performing companies.

The success at Mooka OCRS means it can also act as a talent incubator for other BHP assets. We’re continuing to build on our achievements through active promotion of our apprenticeship program to a diverse range of participants, working with communities to develop a more structured work experience program for high school students, and developing a cultural plan to continue to drive an inclusive workforce.

1.9.3    Our people policies

We have a comprehensive set of frameworks that support our culture of safety and productivity.

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

Our Code of Business 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 internal dispute and grievance handling processes, as well as a business conduct advisory service, to address any potential breaches of the Code.

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, alternate arrangements are in place.

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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.

For more information on our people, including our focus on culture, inclusion and diversity, training and development, see our Sustainability Report 2017 at bhp.com.

1.9.4    Employee 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 FY2017.

The diagram below shows the average number of employees and contractors over the last three financial years.

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

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The table below shows the gender composition of our employees, senior leaders and the Board (Non-executive Directors) over the last three financial years.

	2017		2016		2015
Female employees (1)		4,868		4,708		5,183
Male employees (1)		21,278		22,119		24,487
Female senior leaders (2)(3)		65		65		62
Male senior leaders (2)(3)		211		251		293
Female Board members (2)		3		3		2
Male Board members (2)		7		7		10

⁽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 and in accordance with our reporting requirement under the UK Companies Act 2006. This does not reflect the number of employees as at the end of FY2017.

⁽²⁾  Based on actual numbers as at 30 June 2017, not rolling averages.

⁽³⁾  For UK law purposes, 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 FY2017, 276 senior leaders comprised the top people in the organisation. There were 12 Directors of subsidiary companies who are not senior leaders, comprising 10 men and two women. Therefore, for UK law purposes, the total number of senior managers was 221 men and 67 women (23 per cent women) in FY2017.

Changes in market conditions and our business transformation programs, focused on improving efficiencies and driving greater productivity, have resulted in a decrease in our workforce requirements.

1.9.5    Employee relations

Relationships with our employees are built on mutual respect. We strive to achieve outcomes that are mutually beneficial to our people and BHP.

We are committed to full compliance with legislative workplace requirements in the many jurisdictions in which we work, and we have both individual and collective employment contract arrangements in place. In FY2017, 55 per cent of our employees were covered by collective arrangements.

Where labour disputes arise, we aim to maintain the safety of employees while minimising the impact on our customers. A labour dispute arose at Escondida in Chile during negotiation of a new collective agreement (see section 1.11.2 for information on the dispute), which resulted in a 44-day strike by Union N°1 and the temporary suspension of operations. Following the resolution of Union N°1 to extend the existing collective agreement, the restart was conducted gradually to ensure the safety of our people and the mine has been fully operational since late April. BHP continues to engage proactively with our workforce at Escondida.

1.10    Sustainability

Sustainability is at the heart of everything we do. We put health and safety first, we are environmentally responsible, we respect human rights and we support our host communities.

As a partner in the communities in which we operate, we share stewardship of the environment, support local cultures and help drive economic development. Many of our assets last for decades, and the maintenance of a social licence to operate them is essential.

Full details of our sustainability framework, management, performance and targets and an introduction to our new sustainability targets and longer-term goals are available in our Sustainability Report 2017 at bhp.com.

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1.10.1    Our sustainability approach

Health, safety, environment and community (HSEC) considerations are integrated into our daily activities and decisions. Our approach to sustainability is defined by Our Charter and realised through Our Requirements standards. These clearly describe our mandatory minimum performance requirements and are the foundation for developing and implementing management systems at our assets.

We are committed to complying with the laws and regulations of the jurisdictions in which we operate and aim to exceed legal and regulatory requirements where those are less stringent than our own. Contractors working at our operated assets are required to comply with our HSEC standards and requirements. We also engage with and encourage our suppliers, agents and service providers to maintain business practices and workplace standards that are comparable to our own.

We believe high standards of governance are critical to deliver our strategy, create long-term value and maintain our social licence to operate. The Board oversees our sustainability approach. The Board’s Sustainability Committee assists with governance and monitoring. The Board’s Risk and Audit Committee assists with oversight of the Group’s systems of risk management.

For information on the Sustainability and Risk and Audit Committees, refer to section 2.13.

BHP has been setting global sustainability targets since 1997. A strong part of our history, these targets help us focus on our most material sustainability risks. FY2017 marked the end of our FY2013–FY2017 sustainability target period. Details of our performance against these targets are provided throughout this section of the Annual Report. Our new, five-year HSEC performance targets, which took effect from 1 July 2017, are framed around shared global challenges.

Engaging with our partners at non-operated joint ventures

Following a review of governance at our non-operated minerals joint ventures (NOJV), we created a NOJV leadership team and supporting team, and developed a global standard which defines the requirements for managing BHP’s interest in our NOJVs. For more information, refer to section 1.7.

1.10.2    Operating with ethics and integrity

Operating responsibly and ethically involves bringing Our Charter values to life. We cannot deliver value to our shareholders, employees or communities unless we demonstrate these values through our actions, processes, systems and interactions with all stakeholders.

Our BHP Code of Business Conduct (Code) demonstrates how to apply Our Charter by setting behavioural standards for everyone who works for, or on behalf of, BHP. Acting in accordance with our Code is a condition of employment, and all our people are required to undertake annual training on the Code.

Anti-corruption compliance

We are determined to play a significant role in the global fight against corruption to ensure communities benefit from the development of natural resources. Our commitment to anti-corruption compliance is reflected in our Code and the Our Requirements for Business Conduct standard.

Our Ethics and Compliance function is responsible for designing, monitoring and reporting on our anti-corruption compliance program. 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 to the Risk and Audit Committee.

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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 3,412 employees in FY2017, together with numerous employees of business partners and community partners.

More information on our anti-corruption compliance program (including risk assessments, training and communication) is available online at bhp.com/anticorruption.

Closure planning

We consider the entire life cycle of our operations, including closure, in our planning and decision-making.

Our operated assets are required to develop a closure plan, including a financial assessment, to minimise closure-related risks over the life of the asset. Our Internal Audit function tests the effectiveness of these plans, with findings reviewed and reported annually to Asset Presidents, and summary reports provided to the Risk and Audit Committee. Information about the financial provisions related to closure liabilities is available in note 14 ‘Closure and rehabilitation provisions’ in section 5.

Building trust through transparency

Our business model is based on trust. To earn this trust, we are dedicated to becoming a global leader in corporate transparency and public disclosure. Transparency is a priority for BHP because it allows our stakeholders to hold us accountable for our actions and minimises the risk that the significant taxes and royalties we pay around the world are diverted away from the citizens who should benefit from the wealth created by the resources we produce.

Our approach to transparency is guided by our Transparency Principles of responsibility, openness, fairness and accountability. Our annual Economic Contribution Report discloses our payments of taxes and royalties to all our host governments on a project-by-project basis, consistent with the European Union Transparency Directive.

Our approach to transparency and tax is detailed in our Economic Contribution Report 2017 available online at bhp.com.

1.10.3    Health and safety

Safety

The safety of our workforce and the communities in which we operate is an essential priority.

Our goal is zero fatalities and we are committed to achieving this through the effective management of safety risks.

We committed to a set of global safety priorities in FY2016 that continue to guide our decision-making and approach to safety. These four focus areas are:

• reinforce that safety comes before productivity;

• focus on in-field verification of material and fatal risks;

• enhance our internal investigation process and widely share and apply lessons;

• enable additional quality field time to engage our workforce.

This work is supported by our ongoing work on our culture of safety and productivity, in particular our focus on leadership. Recognising that visible leadership is a key driver of safety and productivity, our Field Leadership program is designed to drive a cultural change and help us achieve our goal of everyone going home safe. It involves leaders spending time in the field engaging with employees and contractors on how we can enhance our safety processes and observing at-risk activities. The program also focuses on improving in-field verification of material and fatal risks.

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Tragically, one of our colleagues, Rudy Ortiz, died in October 2016 during planned maintenance on the Laguna Seca Line 2 concentrator at Escondida in Chile. Following completion of the investigation, lessons were shared across BHP. At Escondida, a number of actions have been taken to improve our change management and in-field contractor management processes, as well as investigating the use of new technology to mitigate the inherent risks associated with this activity.

In August 2017, another colleague, a contractor from Independent Mining Services, died as a result of an incident at the Goonyella Riverside Mine in Queensland, after the period covered by this Report. An investigation is underway.

These fatalities are a tragic reminder that safety must come first in everything we do. We will continue to strive to make sure our people prioritise safety in their day-to-day activities.

We were encouraged that events with the potential to cause a fatality which had an associated injury reduced by 30 per cent at our operated assets compared with FY2016. This can be attributed to field leadership, in-field verification of critical controls and an increased focus on what we need to do to avoid single fatality risks.

Our total recordable injury frequency (TRIF) performance at our operated assets in FY2017 was 4.2 per million hours worked, a two per cent improvement on the previous financial year. This represents an improvement of nine per cent over five years.

Workplace fatalities ⁽¹⁾ (FY2008–FY2017)

⁽¹⁾  Includes data for all operated assets for the financial years being reported.

Health

Recognising 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 the minimum mandatory controls to identify and manage health risks for both employees and contractors.

In FY2012, we committed to reduce potential occupational exposure to carcinogens and airborne contaminants at our operated assets by 10 per cent by 30 June 2017. We have exceeded this target by reducing these occupational health exposures by 76 per cent.

A number of projects were rolled out in FY2017 to make sure we continue to reduce our people’s exposure to carcinogens and airborne contaminants.

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The majority of our reported occupational illnesses continue to be noise-induced hearing loss and musculoskeletal illness. We continue to implement solutions designed to minimise the risks through engineering and administrative controls.

The incidence of employee occupational illness at our operated assets in FY2017 was 4.92 per million hours worked, an increase of 18 per cent on FY2016. The incidence of contractor occupational illness was 1.43 per million hours worked, an increase of 23 per cent compared with FY2016.

The increase in musculoskeletal illness reporting has been driven by an improvement in reporting process and access to data in Minerals Americas. Historically, gradual onset musculoskeletal illnesses were not well recognised as being work-related under Chilean regulatory requirements.

We do not have full oversight 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.

In line with Our Charter and our culture of care, we also undertake activities to enhance the physical and mental wellbeing of our workforce. This includes the provision of preventative health measures and a Mental Health Framework focused on awareness, support and proactive management of mental wellbeing.

Coal workers’ pneumoconiosis

As at 30 June 2017, four current Queensland employees have been identified as having coal workers’ pneumoconiosis (CWP). We were deeply concerned to learn of these cases and have provided counselling, medical support and redeployment options to all four employees. In addition, as at 30 June 2017, two former Queensland workers and one former New South Wales worker have been diagnosed as having CWP.

Details of the steps BHP has taken in response to the re-identification of CWP in our industry are detailed in our Sustainability Report 2017.

1.10.4    Society

Strong and respectful engagement with host communities is vital to our business. Our minimum mandatory requirements guide our approach to these relationships and to engaging openly with communities to understand and respond to their concerns.

We play an important role in helping develop economies and improve standards of living. Our contribution includes employment opportunities, the purchase of local goods and services, the development of infrastructure and facilities and support of regional and national economies through the payment of taxes and royalties. Through these actions, we contribute to the achievement of the United Nations’ (UN) Sustainable Development Goals.

Engaging with host communities

By understanding the expectations, concerns and interests of the communities in which we work, we are better equipped to plan and implement commitments, as well as monitor and measure our performance. With community input, we undertake actions to understand the social and economic environment, recognise key stakeholders (including those who are vulnerable or disadvantaged) and identify the possible social impact of our operations. We also work closely with other industry partners to understand our collective impact and best approach to working together more effectively.

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Voluntary social investment

Aligned with the UN Sustainable Development Goals, our Social Investment Framework underpins our voluntary social investment approach and provides a consistent framework for local, regional, national and global investments. Using this Framework, we have voluntarily invested one per cent of our pre-tax profit¹ in community programs since 2001.

Our voluntary social investment in FY2017 (including BHP’s equity share for both operated assets and non-operated joint venture assets) totalled US$80.1 million. This included US$75.1 million contributed to community development programs and associated administrative costs, and a US$5 million contribution to the BHP Billiton Foundation.

Supporting local economic growth

Where our standards can be met, we choose to source products and services locally, benefiting local suppliers and local communities. In line with our expectations, all our operated assets had local procurement plans in effect during FY2017.These plans enabled us to direct 22 per cent of our external expenditure to local suppliers. An additional 68 per cent of our expenditure was within the regions in which we operate.

Our largest local expenditures were mostly made by our operated assets in the United States (86 per cent), Australia (12 per cent), Trinidad and Tobago (54 per cent) and Chile (16 per cent).

Building partnerships with Indigenous peoples

As the majority of our assets are located on or near traditional lands of Indigenous peoples, we have a responsibility to recognise and respect the status of Indigenous peoples as First Peoples and embrace the opportunity to establish long-lasting relationships, based on trust.

Our approach to engaging with Indigenous peoples is articulated in our Indigenous Peoples’ Position Statement, which we implement through our Indigenous Peoples Strategy. The Strategy focuses our engagement with Indigenous peoples on four priority areas: governance; economic empowerment; social and cultural support; and public engagement.

Examples of our achievements in each of the four priority areas of our Indigenous Peoples Strategy during FY2017 are available in our Sustainability Report 2017.

Respecting human rights

Respecting human rights wherever we operate is critical to the sustainability of our business and is consistent with our support for the UN Declaration on Human Rights, UN Guiding Principles on Business and Human Rights, the Voluntary Principles on Security and Human Rights and the 10 UN Global Compact principles.

We aim to identify and manage human rights-related risks in all our activities. Due diligence is performed to mitigate those risks, and we seek to remediate any adverse human rights impacts we have caused or to which we have contributed.

The most relevant human rights issues for our industry include occupational health and safety, labour conditions, activities of security forces, and respecting the rights of Indigenous peoples and communities near our operations.

⁽¹⁾  Calculated on the average of the previous three years’ pre-tax profit.

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Our Code of Business Conduct outlines the human rights commitments applicable to our people, as well as our contractors and suppliers (where under relevant contractual obligation). Mandatory minimum performance requirements are articulated in our relevant standards, including our security and emergency management and our risk management standard.

Information on BHP’s systems and processes for meeting the UN Guiding Principles on Business and Human Rights, our zero tolerance requirements in relation to human rights in the supply chain and BHP’s 2016 UK Modern Slavery Act Statement is available online at bhp.com/respectinghumanrights.

1.10.5    Environment

We recognise our responsibility to minimise our environmental impact and contribute to enduring benefits.

We have minimum mandatory requirements for environmental management, which are in addition to any local regulatory requirements. The standard requires us to take an integrated, risk-based approach to the management of impact on land, biodiversity, water and air.

Our operated assets are required to understand baseline conditions and prioritise actions to avoid, minimise and rehabilitate environmental impacts over the short and long term, in line with our mitigation hierarchy. We do this within our area of influence, taking account of direct, indirect and cumulative impacts. If there are impacts on important biodiversity and ecosystems (or they are reasonably foreseeable), we will implement compensatory actions such as biodiversity offsets.

Water

Water is a shared resource, with high economic, environmental and social value, and access to water is a basic human right. In recognition of this, all our operated assets are required to manage water at a catchment level and maintain quantitative water balance models that enable timely management responses to water-related risks, consistent with business requirements.

At the end of FY2017, in line with our target for water, all our operated assets that identified water-related material risks implemented at least one project to improve the management of associated water resources.

Where possible, we seek to use lower-quality or recycled water to minimise extraction requirements from higher quality water resources. Our total water input (water intended for use) at our operated assets in FY2017 was 283,900 megalitres, with 91 per cent defined as Type 2 (suitable for some purposes) or Type 3 (unsuitable for most purposes). This demonstrates our approach to utilising lower-quality water wherever feasible.

Land and biodiversity

In FY2017, in line with our target, all our operated assets maintained land and biodiversity management plans that include actions to avoid, minimise and rehabilitate environmental impacts, and to manage their biodiversity and ecosystems impacts.

In addition to the environmental management actions of our operated assets, in FY2013, we established a target to finance the conservation and ongoing management of areas of high biodiversity and ecosystem value that are of national or international conservation significance. We established an alliance with Conservation International to support the delivery of this target and improve our approach to biodiversity management more broadly.

Through our partnership with Conservation International, we committed more than US$50 million to conservation as at the end of FY2017, in addition to the environmental management activities undertaken at our operated assets.

Our case study on our partnership with Conservation International is available online at bhp.com/casestudies.

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Environmental events

Our operated assets are required to maintain emergency response plans to minimise the potential severity of, and respond effectively to, environmental events. We conduct thorough investigations when an actual or potential significant environmental event occurs, to understand the cause and identify any corrective actions to prevent similar events.

While no significant environmental events occurred at any BHP operated assets in FY2017, we are still working to address the significant environmental impacts of the tailings dam failure at our non-operated joint venture, Samarco, in November 2015.

1.10.6    Climate change

BHP’s strategy is tied to economic growth in both emerging and developed economies. As such, our sustained growth is not possible without an effective response to climate change.

Contributing to the global response

To support the development of that effective response, we seek to engage with governments, non-government organisations and other stakeholders to inform the development of an effective, long-term policy framework that delivers a measured transition to a lower emissions economy.

We are a signatory to the World Bank’s ‘Putting a Price on Carbon’ statement and a member of the World Bank’s Carbon Pricing Leadership Coalition. We are also a member of the Energy Transitions Commission, which aims to ‘identify pathways for change in our energy systems to ensure both better growth and a better climate’.

As part of this engagement, we regularly share lessons learned in order to help identify solutions that can drive emissions reductions at the lowest cost.

Our position on climate change

We accept the Intergovernmental Panel on Climate Change (IPCC) assessment of climate change science, which has found that warming of the climate is unequivocal, the human influence is clear and physical impacts are unavoidable.

We believe the world must pursue the twin objectives of limiting climate change to the lower end of the IPCC emission scenarios in line with current international agreements, while providing access to reliable and affordable energy to support economic development and improved living standards. We do not prioritise one of these objectives over the other – both are essential to sustainable development.

Under all current plausible scenarios, fossil fuels are expected to continue to be a significant part of the energy mix for decades. Therefore, an acceleration of effort to drive energy efficiency, develop and deploy low-emissions technology and adapt to the impacts of climate change is needed. We believe there should be a price on carbon, implemented in a way that addresses competitiveness concerns and achieves lowest cost emissions reductions.

More information is available in our Sustainability Report 2017 at bhp.com.

Transparent reporting

We recognise the importance of open engagement with our stakeholders, including investors, to ensure a good understanding of how climate-related risks and opportunities are identified, assessed and managed.

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We have a strong record of supporting and complying with robust reporting requirements on climate change issues. Our extensive engagement program with investors, government and the broader society includes our voluntary submission to CDP (formerly the Carbon Disclosure project; see cdp.net). This commitment has resulted in a significant improvement in our CDP scores since FY2013.

Our climate change disclosures are aligned with the newly issued recommendations of the Financial Stability Board’s Taskforce on Climate-related Financial Disclosures (TCFD). The TCFD has developed a voluntary framework for the reporting of climate-related financial risk disclosures for use by lenders, insurers, investors and other stakeholders. BHP has been a firm supporter of this work and our Vice President of Sustainability and Climate Change, Dr Fiona Wild, is a member of the TCFD. We believe the work of the TCFD builds a consistent framework for climate-related risk disclosure and see the recommendations as a strong endorsement of the work we have already undertaken.

Climate-related disclosures

Responding to climate change is an integral part of our strategy and operations. Therefore information relating to climate change is contained 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. Further information can also be found in BHP’s Sustainability Report 2017, Climate Change: Portfolio Analysis (2015) and Climate Change: Portfolio Analysis – Views after Paris (2016).

TCFD recommendation	Disclosure	Location
Governance – Disclose the organisation’s governance around climate-related risks and opportunities
a) Describe the Board’s oversight of climate-related risks and opportunities.	Board skills and experience – climate change Sustainability Committee – role and focus		2.8 2.13.4
b) Describe management’s role in assessing and managing climate-related risks and opportunities.	Our climate change strategy Sustainability Committee – role and focus FY2017 STI performance outcomes		1.10.6 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.	Sustainability risks Operational risks Climate change – overview		1.8.3 1.8.3 1.10.6
b) Describe the impact of climate-related risks and opportunities on the organisation’s businesses, strategy, and financial planning.	Sustainability risks Operational risks Portfolio evaluation		1.8.3 1.8.3 1.10.6
c) Describe the resilience of the organisation’s strategy, taking into consideration different climate-related scenarios, including a 2°C or lower scenario.	Portfolio evaluation		1.10.6
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		1.5.2
b) Describe the organisation’s processes for managing climate-related risks.	Managing performance and risk Sustainability risks		1.5.2 1.8.3
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 Sustainability risks Sustainability KPIs		1.5.2 1.8.3 1.6.1

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TCFD recommendation	Disclosure	Location
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.	Sustainability KPIs		1.6.1
b) Disclose Scope 1, Scope 2, and, if appropriate, Scope 3 greenhouse gas (GHG) emissions, and the related risks.	Sustainability KPIs (GHGs) Mitigation – GHGs Low emissions technology		1.6.1 1.10.6 1.10.6
c) Describe the targets used by the organisation to manage climate-related risks and opportunities and performance against targets.	Sustainability KPIs (GHGs) FY2017 STI performance outcomes		1.6.1 3.3.2

Our climate change strategy

Climate change is a priority governance and strategic issue for BHP. Our Board is actively engaged in the setting of strategy and governance of climate change issues, supported by the Sustainability Committee. Management has primary responsibility for the design and implementation of our response to climate change. GHG reduction is a key performance indicator for our business, and our performance against these targets is reflected in senior executive and leadership remuneration.

Our climate change strategy is informed and underpinned by active engagement with our stakeholders, including investors, policy makers, peer companies and non-government organisations. We regularly review our position on climate change in response to emerging scientific knowledge and changes in global regulation. We seek input and insight from external experts, such as the Forum on Corporate Responsibility. We also incorporate climate change considerations into our scenario planning to understand potential impacts on our portfolio.

Our response to climate change is focused on mitigation, adaptation, low-emissions technology and portfolio evaluation. These are outlined below. For more information, see our Sustainability Report 2017 at bhp.com.

Mitigation

As a major producer and consumer of energy, we prioritise reduction of GHG emissions and energy efficiency. Rather than use an intensity metric to define our Group GHG target, we have set ourselves a challenging goal to limit our overall emissions by keeping our absolute FY2017 GHG emissions at our operated assets below our FY2006 baseline (adjusted as necessary for material acquisitions and divestments). This encourages us to reduce GHG emissions, improve our energy efficiency and increase productivity.

With our FY2017 emissions total at 21 per cent below the adjusted FY2006 baseline, we have successfully achieved our ambitious target. Numerous individual improvement projects have contributed to this achievement, as well as improvements in productivity and technology and changes in production profile. Projects tracked since FY2013 as part of our current GHG target achieved more than 975,000 tonnes CO₂-e of annualised abatement in FY2017 at our Continuing operations.

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GHG Scope 1 and 2 (millions of tonnes CO₂-e)⁽¹⁾

Year ended 30 June (2)	2017		2016		2015
Scope 1 (3)		10.5		11.3		20.7
Scope 2 (4)		5.8		6.7		17.6
Total GHG millions of tonnes CO2-e		16.3		18.0		38.3

⁽¹⁾ Measured according to the World Resources Institute/World Business Council for Sustainable Development Greenhouse Gas Protocol.

⁽²⁾ Includes data for Continuing and Discontinued operations.

⁽³⁾ Scope 1 refers to direct GHG emissions from operated assets.

⁽⁴⁾  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).

In line with the requirements of the UK Companies Act 2006, our reported FY2017 GHG intensity was 2.4 tonnes of CO₂-e per tonne of copper equivalent production (FY2016: 2.8 tonnes of CO₂-e). Our reported FY2017 energy intensity was 20 petajoules per million tonnes of copper equivalent production. Copper equivalent production has been based on FY2013 average realised product prices.

Adaptation

Our assets are long-lived and therefore 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 change science to inform resilience planning at an asset level and improve our understanding of the climate vulnerabilities our operations and host communities may face.

All our operated assets 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 impacts of climate change.

Low-emissions technology

Rapid technology development is contributing to the task of global emissions reduction today, while further innovation has the potential to enable long-term climate goals to be met. We believe industry has a significant collaborative role to play with government, academia and the community to facilitate this necessary step change. BHP has an integrated strategy to invest across a range of new technologies that have the potential to reduce emissions in our operations and from the use of our products, which are significantly higher. In FY2017, our Scope 3 emissions were 585.1¹ million tonnes. This is why we are working in partnership across our supply chain to accelerate deployment of low emissions technology, improve energy efficiency and support effective, long-term policy responses.

When evaluating investment opportunities, we aim to look at factors including the potential to materially reduce emissions and the opportunity to use our expertise to accelerate the required change. Our investments also build capacity, capability and internal awareness within the business, and leverage BHP’s global Operating Model – replicability, scale and market power.

⁽¹⁾  Scope 3 refers to other indirect emissions, such as the extraction and production of purchased materials and fuels, transport-related activities in vehicles not owned or controlled by the reporting entity, electricity-related activities (e.g. transmission losses) not covered in Scope 2, outsourced activities, waste disposal, etc. 97 per cent of our Scope 3 emissions comes from the processing and use of sold products.

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We are focusing on carbon capture and storage (CCS), technologies to reduce fugitive emissions from coal and petroleum assets, renewable energy, battery storage and high-efficiency/low-emissions power generation and transportation. As well as reducing our own emissions, the result of this work will also be shared widely to assist others in the resource sector.

Portfolio evaluation

We recognise that even well-researched forecasts are subject to uncertainty in the face of rapid technology and policy change, and that the world could move in any number of different directions to address climate change. To understand the impact of this uncertainty on BHP’s portfolio, our corporate planning process uses scenario analysis to consider a wide spectrum of potential outcomes. Designed to interpret external factors, including technical, economic, political and governance trends facing the global resources industry, the scenarios offer a means to explore potential portfolio discontinuities and opportunities, as well as to test the robustness of decisions. We also test the portfolio against shock events: unlikely and extreme events, which are typically short term, but may have associated longer-term impacts.

Our Portfolio Analysis (first published in FY2015) shows our uniquely diversified portfolio of high-quality, low-cost assets is robust under both an orderly and a more rapid transition to a two degree Celsius world. We also have a strong project pipeline with many capital-efficient growth options that continue to generate shareholder value in a two degree Celsius world.

In September 2016, we released Climate Change: Portfolio Analysis – Views after Paris, which included analysis of emerging climate policy (e.g. 21st Conference of the Parties (COP21)) and low-emissions technology developments. As an outcome of COP21 in Paris, the Paris Agreement was significant for establishing a common ambition to reduce emissions, but the Nationally Determined Contributions, which described each nation’s plans to achieve this targets, were still relatively modest. It is important that Parties to the Paris Agreement provide regular progress assessments and increase ambition over time.

We expect non-hydro renewables, principally wind and solar, will gain market share in the power sector, mainly at the expense of energy coal. This uptake is expected to triple the combined share of wind and solar in the power mix in the next 25 years. We expect demand growth for oil to decrease due to the rise in electric vehicles and an increase in fuel efficiency of internal combustion engines vehicles.

Nevertheless, despite rapid growth in renewables and electric vehicles, the world will still require roughly four-fifths of its growing total energy needs to come from non-renewable sources in 2040. As such, it is important to look at other options to reduce emissions from the production and use of fossil fuels, such as CCS and improved power generation efficiency.

We are committed to keeping our stakeholders informed of the impact of climate change to BHP.

1.11    Our businesses

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

1.11.1    Minerals Australia

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

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Copper asset

Olympic Dam

Overview

Olympic Dam is one of the world’s largest ore bodies. Located 560 kilometres north of Adelaide, it is one of the world’s largest deposits of copper, gold and uranium, and it also has a significant deposit of silver. Olympic Dam operates a fully integrated processing facility from ore to metal.

Olympic Dam’s underground mine is made up of more than 450 kilometres of underground roads and tunnels. The asset extracts copper uranium ore, with the ore hauled by automated train to feed underground crushing, storage and ore hoisting facilities.

Olympic Dam’s processing plant consists of two grinding circuits in which high-quality copper concentrate is extracted from sulphide ore through a flotation extraction process. The asset includes 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 FY2017

Olympic Dam’s copper production decreased following the state-wide power outage during September and October 2016 and unplanned maintenance that took place at the refinery during December 2016 and January 2017.

Looking ahead

Development in the Southern Mining Area is progressing well and is expected to support a gradual increase in copper production to 230 kilotonnes (kt) in FY2021.

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Through the first half of FY2018, BHP’s Olympic Dam smelter operations will be enhanced through a total A$350 million investment.

The smelter upgrade involves combined investment in the following three areas to ensure the ongoing integrity of critical infrastructure and to continue to deliver safe and reliable performance:

• rebuilding key elements of the smelter flash furnace;

• demolishing and building a new electric slag furnace;

• removing and replacing the five-storey high electro static precipitator.

Olympic Dam is also using the planned down time to undertake further refinery asset maintenance.

We are investigating further options for expanding production at Olympic Dam. The brownfield expansion project could see production grow to approximately 280 kilotonnes per annum (ktpa), with a potential upside of 330 ktpa. We are also seeing encouraging results in our heap leach trials which, if proven, would enable potential growth to 450–500 ktpa of copper.

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.

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WAIO’s Pilbara reserve base is relatively concentrated, allowing development to be planned around integrated mining hubs joined 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 mining hub – Newman, Yandi, Mining Area C and Jimblebar – ore from mines 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 entered into separate joint venture agreements with some customers that involve the sublease of parts of WAIO’s existing mineral leases: JW4, Wheelarra and Posmac. The JW4 sublease arrangement expired on 1 April 2017 and, as such, control of the sublease area was handed back to the Yandi JV.

The ore is sold to the main joint ventures. BHP is entitled to 85 per cent of production from these subleases.

All ore is transported by rail on the Mt Newman JV and Mt Goldsworthy JV rail lines to our 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 FY2017

WAIO has achieved record production as a result of continued focus on productivity improvements, the rail renewal program and the ramp-up of additional capacity at Jimblebar, where a new primary crusher and additional conveying capacity was successfully commissioned.

Productivity improvements included a reduction of locomotive service times by 50 per cent and the introduction of an improved drilling fleet configuration, which has lowered fuel usage and engine load factor. Automation was introduced for blast hole drilling across all WAIO mine sites. With some mine blasts requiring more than 6,000 drill holes, automation reduces people exposure to hazardous environments, is a key enabler for diversity, saves time and allows for greater accuracy.

The rail renewal and maintenance program progressed ahead of schedule and is now complete. In the short term, the program has resulted in higher unit costs for FY2017. However, this cost is offset by the benefits of creating a more integrated and ‘just in time’ supply chain; the re-railing has unlocked further capacity and enabled us to better mitigate the impacts of unplanned events, such as bad weather.

Looking ahead

We will continue to focus on productivity improvements through standardised work processes, simplification and further cost reduction. BHP will continue to work with the regulatory authorities in relation to the necessary licence amendment to increase BHP’s current authorised export capacity to 290 million tonnes (Mt).

Pre-commitment funding of US$184 million has been approved for the development of the South Flank deposit adjacent to the existing Mining Area C operations. The South Flank project, which will leverage and expand the existing Mining Area C hub, is BHP’s preferred option to replace production from the 80 million tonnes per annum (Mtpa) Yandi mine (100 per cent basis) when it reaches the end of its economic life in the early-to-mid 2020s. The project is expected to be submitted for Board approval in the middle of CY2018, with first ore targeted in CY2021 and ramp-up timed to coincide with the ramp-down of Yandi.

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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.

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 then 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 the port via trains or trucks. 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, including 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. BMA is owned 50:50 by BHP and Mitsubishi Development.

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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.

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 FY2017

Tropical Cyclone Debbie hit the Queensland coast in March 2017, and the extreme rainfall that followed impacted access, power, logistics and services in the Bowen Basin. Dewatering infrastructure installed after the 2011 floods is working as designed and all sites have been fully operational since early April 2017.

BMA has announced an intention to invest US$204 million (100 per cent basis) in the Caval Ridge Southern Circuit (CRSC) capital growth 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 will create up to 400 new construction jobs and 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.

The Integrated Remote Operations Center (IROC) in Brisbane, which supports our people working in coal surface mines and port operations in Queensland and New South Wales, was completed in February 2017. IROC provided remote monitoring of the status of our sites during Tropical Cyclone Debbie and the immediate recovery phase, updating our business in a timely and consistent manner.

Looking ahead

Construction of the CRSC capital growth project commenced in April 2017 and will take approximately 18 months to complete. The first coal on conveyor is expected in August 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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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 FY2017

Following our 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 in the FY2017 financial results.

IndoMet Coal (Indonesia)

The sale of our 75 per cent interest in Indomet Coal to equity partner PT Alam Tri Abadi (Adaro) was completed in October 2016.

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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 production sold as 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 more than 650 ktpa of concentrate to produce nickel matte. Nickel West Kwinana then refines granulated nickel matte from the Kalgoorlie smelter into nickel powder and premium-grade nickel metal briquettes containing over 99 per cent nickel. Nickel matte and metal are exported to overseas markets via the Port of Fremantle.

Key developments during FY2017

The installation of a third grinding mill and other low-cost upgrades have lifted the production capacity at the Kwinana Refinery. This resulted in record production being achieved in FY2017, exceeding the previous record by eight per cent.

Within the Leinster underground mines, the development of the access drives to the Venus ore body has progressed, while mining of the Leinster 1A ore body continued to provide high-grade ore to the concentrator.

An environmental referral for a satellite pit at Mt Keith was lodged with the Western Australian Environmental Protection Authority in May 2017. The satellite pit will continue to supply ore to the Mt Keith concentrator upon completion of mining within the current pit.

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Looking ahead

Debottlenecking projects at Kwinana will continue and a range of projects are underway to extract further value from the refinery.

Exploration access to the Venus nickel deposit is scheduled to be completed in FY2018 and the drilling program to define the ore body will commence thereafter. The Venus deposit has the potential to support the extension of the expected life of Nickel West to FY2032.

1.11.2    Minerals Americas

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

Copper assets

Our copper assets in the Americas (Chile and Peru) consist of 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 where it is exported to our customers around the world.

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 expected 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 pits will feed three concentrator plants (which use grinding and flotation technologies to produce copper concentrate), as well as two leaching operations (oxide and sulphide).

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Key developments during FY2017

Tragically, one of our colleagues, Rudy Ortiz, died in October 2016 during planned maintenance on the Laguna Seca Line 2 concentrator. Following completion of the investigation into the fatality, lessons have been shared across BHP. At Escondida, a number of actions have been taken to improve our change management and in-field contractor management processes, as well as investigating the use of new technology to mitigate the inherent risks associated with this activity.

Negotiations with Union N°1 began in December 2016 on a new collective agreement, as the existing agreement was set to expire on 31 January 2017. Negotiations, including government-led mediation, were unsuccessful and the union commenced strike action on 9 February 2017. 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. Operations returned to full capacity in April 2017.

BHP is investing in long-term sustainable water and power solutions in Chile. The Escondida Water Supply project, approved in July 2013, consists of a new 2,500 litres per second sea water desalination facility at a cost of US$3.4 billion (US$2.0 billion BHP share). First water was delivered in the March 2017 quarter, on schedule and budget and the project was officially handed over to operations on 1 July 2017. This project is an important step towards our progressive substitution of water from ground to sea sources.

We have also awarded a long-term energy agreement for the development, operation and maintenance of Kelar, a 517 megawatt combined-cycle gas-fired power plant in the town of Mejillones, Chile. The plant, which is connected to the Northern Interconnected System, commenced generation in the December 2016 quarter and will supply the increasing demand for electricity at Escondida and Pampa Norte.

Looking ahead

In June 2016, the Escondida Los Colorados Extension project was approved at a cost of US$180 million (US$103 million BHP share). First production is expected in the September 2017 quarter, adding incremental milling capacity of around 100 kilotonnes per day (ktpd).

The commissioning of the Escondida Water Supply project in June 2017 and the planned ramp-up of the Los Colorados Extension project in the September 2017 quarter are expected to allow full utilisation of three concentrators during FY2018.

Negotiations with Escondida Union N°2, comprising around 700 specialist and supervisor level staff, will occur during FY2018 as the current agreement expires on 31 December 2017.

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 FY2017

Spence processed a record 20 Mt of ore and had record production in FY2017, following the completion of the Recovery Optimisation (SRO) project.

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The SRO project was commissioned in September 2016 and has improved the production run rate from around 180 ktpa to 200 ktpa, as at December 2016. The SRO project was a low-cost, capital-efficient investment that accelerated leaching rates and increased metal recoveries from existing heap leach processes.

Looking ahead

The Spence Growth Option project was approved in August 2017 with expected capital expenditure of US$2.46 billion, and will extend Spence mining operations by more than 50 years. The project will access primary ore beneath the current mine footprint through the continued development of the existing pit. It will involve the design, engineering and construction of a 95 ktpd concentrator and the outsourcing of a 1,000 litre per second desalination plant, creating up to 5,000 jobs during the construction phase. The project will increase copper production capacity by around 200 ktpa and is expected to deliver first production in FY2021. The current copper cathode stream will continue until FY2025.

Antamina (Peru)

Overview

We own 33.75 per cent of Antamina, a large, low-cost copper and zinc mine in north central Peru. Antamina by-products include molybdenum, lead/bismuth concentrate and silver.

Key developments during FY2017

Antamina continued to study options to debottleneck the operation and increase throughput. In this regard, Antamina achieved record material mined of 245 Mt in FY2017.

Looking ahead

Antamina remains focused on improving productivity and reducing unit cash costs. Copper production is expected to decrease to 125 kt in FY2018, as mining continues to progress through a zinc-rich ore zone consistent with the mine plan. Zinc production is expected to increase from 88 kt to approximately 100 kt in FY2018.

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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.

Key developments during FY2017

Studies to identify the best development pathway for the project progressed in FY2017. The multi-year National Environmental Policy Act permitting process continued according to plan. Community engagement activities with Native Americans, environmental advocates and local communities also progressed. Our share of project expenditure for FY2017 was US$49 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. The next key milestone for the project is in December 2018 when a draft version of the Environmental Impact Study is expected to be made public.

Coal assets

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.

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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.

Key developments during FY2017

The drought conditions that impacted Cerrejón in FY2016 have abated, allowing for resequencing of the mine plan. Production in the second half of FY2017 was affected by wet weather.

Concerns have been expressed by resettled communities near Cerrejón, including impacts associated with sustainable livelihoods and access to water. We support Cerrejón to continue to work towards outcomes that reflect strong community engagement processes and meet international best practice for resettlements.

Through a roundtable process, resettled communities and Cerrejón have collectively discussed and addressed common issues and concerns to work towards a mutually agreed solution.

Looking ahead

Cerrejón is focused on safely improving throughput by increasing asset utilisation and securing the necessary permits to access new ore reserves.

New Mexico Coal (United States)

Following the sale of the Navajo mine, we continued to manage and operate the mine until the Mine Management Agreement with Navajo Transitional Energy Company (NTEC) ended on 31 December 2016. This transaction completes the divestment of the New Mexico coal assets.

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Iron ore asset

Samarco (Brazil)

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

Overview

As a result of the tragic dam failure at Samarco in November 2015, operations at Samarco remain suspended. For further information on the Samarco dam failure, refer to section 1.7. 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 FY2017

For information on the progress made on remediation, resettlement and compensation in response to the Fundão dam failure, refer to section 1.7.

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.

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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 comprised of 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.

However, in the near term, overcapacity is likely to get worse. In the 10 years to 2016, the industry added nearly 27 Mt of annual ‘nameplate’ capacity. Further greenfield supply will come on stream over the next five years. As a result, potash prices are currently at their lowest levels in a decade and are likely to get worse before they get better.

Although the near-term outlook may be sombre, we expect the peak of oversupply to occur within the next few years. Positive underlying demand fundamentals, assisted by affordable pricing, should see consumption catch up to capacity in the 2020s. Our projections are that demand for potash will continue to grow at a rate of about two to three per cent per year (compound annual growth rate) and that, even taking into account new projects and latent capacity in the industry, demand will outstrip supply within the next decade.

Potash has the potential to create significant value and provide BHP with an opportunity to capture long-term growth and diversification benefits.

Our investment in the Jansen Potash Project presents an opportunity to develop a multi-decade, multi-mine business; a potential fifth major commodity offering for BHP. It is consistent with our strategy to own and operate large, expandable assets that deliver value. However, the Project will be presented to the Board for approval only if it passes our strict Capital Allocation Framework tests.

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Jansen Potash Project

BHP holds exploration permits and mining leases covering approximately 9,600 square kilometres in the province of Saskatchewan, Canada. The Jansen Potash Project is located about 140 kilometres east of Saskatoon. We 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 FY2017

Over the year, our focus was on the safe excavation and lining of two 7.3 metre diameter shafts. Both shafts were safely excavated through the Blairmore formation (which lies about 450 metres below the surface), with steel tubbing in place to prevent water inflow and provide structural support. By the end of FY2017, the production shaft had reached a depth of approximately 730 metres of the design depth of 975 metres and the service shaft had been excavated to approximately 710 metres of its eventual one-kilometre depth. Capital expenditure in the Jansen Potash Project in FY2017 was US$162 million.

During the year, we awarded the detailed engineering design contract studying the feasibility of Jansen Stage 1 to Hatch Bantrel, which formed a joint venture partnership to complete this work.

Looking ahead

Jansen is in the feasibility study phase and we continue to assess how we can reduce risk and unlock value. The current scope of work was 70 per cent complete at the end of FY2017. Work on the shafts will continue in FY2018. Once shaft excavation is complete, the shafts will be connected underground and shaft infrastructure will be installed. This falls within the current approved scope of work.

Construction beyond the current scope of work will require Board approval. With a later market window now anticipated, the Jansen Potash Project will not be brought to the Board in CY2018. In the meantime, we are considering multiple options to maximise the value of Jansen, including further improvements to capital efficiency, further optimisation of design and diluting our interest by bringing in a partner. Board approval will be sought for the project only if it passes our strict Capital Allocation Framework tests.

1.11.3    Petroleum

BHP has been in oil and gas since the 1960s. Petroleum is a high-margin business and we have globally competitive operating capability that can support long-term value creation.

Our Petroleum unit comprises conventional and unconventional oil and gas assets, and includes exploration, development and production activities. We have a high-quality resource base concentrated in the United States and Australia. We have conventional assets located in the US Gulf of Mexico, Australia and Trinidad and Tobago, and unconventional Onshore US assets. 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 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 Gulf of Mexico fields are located, to connecting pipelines that transport product onshore.

Key developments during FY2017

Mad Dog Phase 2, located in the Green Canyon area in the Deepwater Gulf of Mexico, is a southern and southwestern 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 the Mad Dog 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). BP (the operator) sanctioned the Mad Dog Phase 2 project in December 2016 and the revised project 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. Our share of the development costs is approximately US$2.2 billion.

For more information, refer to section 1.13.1.

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Onshore US 

Overview

We hold more than 794,000 net acres in four prolific US shale areas – Eagle Ford, Permian, Haynesville and Fayetteville – where we produce oil, condensate, gas and NGLs. The Black Hawk field of Eagle Ford and the Permian area are two of our largest liquids-focused field developments.

Eagle Ford

We are one of the largest producers in the liquids-focused Eagle Ford shale. Our Eagle Ford area (approximately 246,000 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 63 per cent. We acted as joint venture operator for approximately 37 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 1,650 kilometres of pipelines that deliver volumes to five central delivery points, from which volumes are processed 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 91 per cent. We acted as joint venture operator for around 91 per cent of our gross wells. Permian has 113 kilometres of water pipelines and a gathering system that consists of 183 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 197,000 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 is approximately 36 per cent. We acted as joint venture operator for around 35 per cent of our gross wells.

Fayetteville

The Fayetteville production operation is located in north central Arkansas and consists of approximately 268,000 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 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.

Key developments during FY2017

The development phase of an onshore shale operation requires an extensive drilling and completion program, associated gas compression and treatment facilities, and connecting pipelines. Shale development has a repetitive, manufacturing-like nature that provides opportunities for increased efficiency. Our development of the shale reservoirs utilises horizontal drilling, with average lateral lengths between 1,500–3,000 metres. We enter into service contracts with third parties to provide drilling and completion services at our operated sites. Five drilling rigs were in operation at the end of FY2017.

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In the Eagle Ford, tests continue on the potential for staggered wells to increase recovery, larger fracturing jobs to improve productivity and the potential of the Upper Eagle Ford horizon.

The optimisation of Permian acreage has progressed through trades and swaps in the Delaware Basin, so that we can drill longer lateral wells to improve well economics. Activity is expected to increase as we complete the trials we need to inform the future development plan.

In Haynesville, development activity is increasing with the approval of two additional rigs. We expect rates of return on portions of our FY2018 production will be strengthened by gas hedging and supply contracts secured under favourable terms.

We are working with joint venture partners in the Fayetteville to assess the potential of the Moorefield horizon.

Strategic developments

As part of our ongoing review of our portfolio, the Board and management determined in August 2017 that our Onshore US assets are non-core and options to exit these assets are being actively pursued. We will be flexible with our plans and commercial in our approach. We are examining multiple alternatives but will only divest for value. Execution of these options may take time, which we will use to continue to complete our well trials and acreage swaps, and to investigate mid-stream solutions to increase the value, profitability and marketability of our Onshore US acreage.

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Australia

Overview

Bass Strait

We have produced oil and gas from Bass Strait (50 per cent interest) for over 40 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.

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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 around 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.

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 2017 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 Minerva (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. Minerva end-of-field life is expected in FY2018, after which operations will be discontinued and wells will be plugged and abandoned.

Key developments during FY2017

Bass Strait Longford Gas Conditioning

The Longford Gas Conditioning Plant (LGCP) Project was approved by the Board in December 2012 to allow the production of Turrum reserves and the production of Kipper and other undeveloped high carbon dioxide content hydrocarbons. The facility is designed to process around 400 million cubic feet per day (MMcf/d) of high carbon dioxide gas. The project was completed and first gas production occurred in FY2017, with maximum rates achieved in March 2017. Our share of development costs is approximately US$520 million, of which US$505 million was incurred as of 30 June 2017.

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Bass Strait Kipper gas field development

The Kipper gas field began production in FY2017 following the completion of the Longford Gas Conditioning Plant. Funding for the installation of mercury treatment facilities was approved in March 2014, with completion in FY2017. The project included two new subsea wells, three new pipelines and platform modifications to supply 3,000 barrels per day (Mbbl/d) of condensate and 80 MMcf/d of gas.

Bass Strait Turrum field development

The Turrum field development is located 42 kilometres offshore in about 60 metres of water and operates under the Gippsland Basin Joint Venture. The Turrum field has a capacity of 10 Mbbl/d of oil and 200 MMcf/d of gas. Initial production of low carbon dioxide gas through the Turrum facilities occurred in June 2013. High carbon dioxide gas production from the Turrum reservoir has come online with completion of the Longford Gas Conditioning Plant in FY2017.

North West Shelf Other – Persephone

Persephone is a two well subsea project located northeast of the existing North Rankin complex. Execution activities are in progress, with first production expected in CY2017. Our share of development costs is around US$190 million.

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$314 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 transaction to divest 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 future final investment decision is made for the development of the Scarborough gas field.

WA-1-R and WA-62-R together contain the Scarborough gas field. WA-61-R and WA-63-R contain the Jupiter and Thebe gas fields. Woodside will operate WA-61-R, WA-62-R and WA-63-R and we now hold a 50 per cent working interest. Esso is the operator of the WA-1-R lease and we now hold a 25 per cent working interest.

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Other production operations

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 29.5 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 1.13.1.

1.11.4    Marketing and Supply

Marketing and Supply is an interdependent core business of BHP. It is the link between BHP’s global operations, our customers and our local and global suppliers. It is aligned to our asset groups – Minerals Australia, Minerals Americas and Petroleum.

It’s how we take our iron ore mined in Australia and sell it to customers in China to make steel. It’s how we source our trucks from Illinois, our rail track from Japan, our contractors from Adelaide, our rolling stock from China and our drilling rigs from Texas. It’s how we connect a fabricator in Japan with copper cathode from our Chilean operations and how we pump oil in the Gulf of Mexico to fuel US transport.

Marketing focuses on optimising realised prices and sales outcomes, allowing the assets to focus on safety, volume and cost, and presenting one face to markets and customers across multiple assets. Marketing secures sales of BHP products and manages associated risks, gets our resources to market, 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 is our global procurement division, which purchases the goods and services that are used by our assets, working 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.

A simple, centralised organisation co-located with key markets

Our Marketing and Supply businesses are strategically located in close proximity to our customers and suppliers. Singapore is our primary Marketing and Supply business, reflecting the fact that about 77 per cent of our sales and suppliers are in Asia. Another major Marketing and Supply business is located in Houston, United States. More than half of our oil and gas sales are to customers in North America. In addition, we have regional marketers located close to our customers in eight other cities across the world and global Supply teams supporting our assets in Australia, Chile and the United States.

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Marketing and Supply – strategically located close to our key markets

Safer, more sustainable and efficient freight

BHP is one of the largest global shippers of bulk commodities. We use our scale and deep understanding of our markets to procure safe, low-cost freight. Our objective is to create a competitive advantage through using the highest quality freight service providers and ship owners. We drive improvement in industry safety standards and emissions reduction; for example, through our support for the Rightship ship vetting services and the use of data analytics to measure our counterparties’ safety performance. We also look for ways to improve efficiency, such as by coordinating our inbound and outbound ocean freight requirements.

Sustainable supply

We set global standards for critical supply controls. Our focus is on the sustainability of our supply chain, and we develop sustainable partnerships with local businesses in our communities as well as global suppliers, taking into account human rights and environmental risks.

Developing market insight to inform strategic decision-making

Through our centralised network, Marketing and Supply analyses the fundamentals of demand and incorporates views on supply to inform our long-run outlook of commodity markets and key cost drivers for our procurement. We consider various global scenarios in our modelling and regularly monitor evolving trends in the market.

Our commodity views support asset and portfolio investment decisions, strategic planning, valuations and capital management. Marketing and Supply’s outlook on the global economy, the resource industry and each of the commodities in our portfolio also serves to inform broader organisational priorities, such as our position on climate change.

1.12    Summary of financial performance

1.12.1    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.

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Unless otherwise noted, comparative financial information for FY2014 and FY2013 has been restated to reflect 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 assets that were demerged with South32, unless otherwise noted. Details of the contribution of the South32 assets to the Group’s results are disclosed in note 27 ‘Discontinued operations’ in section 5.

Year ended 30 June US$M	2017		2016			2015			2014		2013
Consolidated Income Statement (section 5.1.1)
Revenue		38,285		30,912			44,636			56,762		53,860
Profit/(loss) from operations		11,753		(6,235	)		8,670			22,649		21,977
Profit/(loss) after taxation from Continuing operations		6,222		(6,207	)		4,390			14,955		14,132
(Loss)/profit after taxation from Discontinued operations		–		–			(1,512	)		269		(1,312	)
Profit/(loss) after taxation from Continuing and Discontinued operations attributable to BHP shareholders (Attributable profit/(loss)) (1)		5,890		(6,385	)		1,910			13,832		11,223
Dividends per ordinary share – paid during the period (US cents)		54.0		78.0			124.0			118.0		114.0
Dividends per ordinary share – determined in respect of the period (US cents)		83.0		30.0			124.0			121.0		116.0
Basic earnings/(loss) per ordinary share (US cents) (1)(2)		110.7		(120.0	)		35.9			260.0		210.9
Diluted earnings/(loss) per ordinary share (US cents) (1)(2)		110.4		(120.0	)		35.8			259.1		210.2
Basic earnings/(loss) from Continuing operations per ordinary share (US cents) (2)		110.7		(120.0	)		65.5			256.5		238.6
Diluted earnings/(loss) from Continuing operations per ordinary share (US cents) (2)		110.4		(120.0	)		65.3			255.7		237.8
Number of ordinary shares (million)
– At period end		5,324		5,324			5,324			5,348		5,348
– Weighted average		5,323		5,322			5,318			5,321		5,322
– Diluted		5,336		5,322			5,333			5,338		5,340
Consolidated Balance Sheet (section 5.1.3) (3)
Total assets		117,006		118,953			124,580			151,413		139,178
Net assets		62,726		60,071			70,545			85,382		75,291
Share capital (including share premium)		2,761		2,761			2,761			2,773		2,773
Total equity attributable to BHP shareholders		57,258		54,290			64,768			79,143		70,667
Consolidated Cash Flow Statement (section 5.1.4)
Net operating cash flows (4)		16,804		10,625			19,296			25,364		20,154
Capital and exploration expenditure (5)		5,220		7,711			12,763			16,210		22,425

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Year ended 30 June US$M	2017		2016		2015		2014		2013
Other financial information
Net debt (6)		16,321		26,102		24,417		25,786		27,510
Underlying attributable profit (6)		6,732		1,215		6,417		13,263		12,017
Underlying EBITDA (6)		20,296		12,340		21,852		30,292		28,109
Underlying EBIT (6)		12,389		3,469		11,866		22,098		21,680
Underlying basic earnings per share (US cents) (6)		126.5		22.8		120.7		249.3		225.8

⁽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 FY2015 does not include the assets and liabilities demerged to South32. The Consolidated Balance Sheet of FY2014 and FY2013 does include the asset 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. Purchase of property, plant and equipment includes capitalised deferred stripping of US$416 million for FY2017 (FY2016: US$750 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 alternate performance measures to reflect the underlying performance of the Group. Refer to section 1.12.4 for a reconciliation of alternate performance measures to their respective IFRS measure. Refer to section 1.12.5 for the definition and method of calculation of alternate performance measures. Refer to note 19 ‘Net debt’ in section 5 for the composition of Net debt.

1.12.2    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 FY2017.

Year ended 30 June	2017 US$M			2016 US$M			2015 US$M
Revenue (1)		38,285			30,912			44,636
Other income		736			444			496
Employee benefits expense		(3,787	)		(3,702	)		(4,971	)
Changes in inventories of finished goods and work in progress		745			(294	)		(139	)
Raw materials and consumables used		(3,908	)		(4,063	)		(4,667	)
Freight and transportation		(2,284	)		(2,226	)		(2,644	)
External services		(4,765	)		(4,984	)		(6,284	)
Third party commodity purchases		(1,157	)		(1,013	)		(1,165	)
Net foreign exchange (losses)/gains		(103	)		153			469
Government royalties paid and payable		(1,986	)		(1,349	)		(1,708	)
Exploration and evaluation expenditure incurred and expensed in the current period		(612	)		(430	)		(670	)

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Year ended 30 June	2017 US$M			2016 US$M			2015 US$M
Depreciation and amortisation expense		(7,931	)		(8,661	)		(9,158	)
Impairment of assets		(193	)		(7,394	)		(4,024	)
Operating lease rentals		(469	)		(528	)		(636	)
All other operating expenses		(1,090	)		(996	)		(1,413	)
Expenses excluding net finance costs		(27,540	)		(35,487	)		(37,010	)
Profit/(loss) from equity accounted investments, related impairments and expenses		272			(2,104	)		548
Profit/(loss) from operations		11,753			(6,235	)		8,670
Net finance costs		(1,431	)		(1,024	)		(614	)
Total taxation (expense)/benefit		(4,100	)		1,052			(3,666	)
Profit/(loss) after taxation from Continuing operations		6,222			(6,207	)		4,390
Loss after taxation from Discontinued operations		–			–			(1,512	)
Profit/(loss) after taxation from Continuing and Discontinued operations		6,222			(6,207	)		2,878
Attributable to non-controlling interests		332			178			968
Attributable to BHP shareholders		5,890			(6,385	)		1,910

⁽¹⁾  Includes the sale of third party products.

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$38.3 billion increased by US$7.4 billion, or 24 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, at Queensland Coal due to the impact of Cyclone Debbie and at Onshore US due to deferral of activity for value and natural field decline. For information on our average realised prices and production of our commodities, refer to section 1.13.

Total expenses of US$27.5 billion decreased by US$7.9 billion, or 22 per cent, from FY2016. This primarily reflects impairments to our Onshore US assets recorded in FY2016, with FY2017 impairment expenses declining by US$7.2 billion. Lower depreciation and amortisation expense of US$730 million reflected lower production at our coal, copper and petroleum operations and a reduction in the depreciable asset base resulting from previously recorded impairment charges in Onshore US. Changes in finished goods and work in progress inventories of US$745 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.

Net finance costs of US$1.4 billion increased by US$407 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 1.12.3 and note 19 ‘Net debt’ in section 5.

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Total taxation expense, including royalty-related taxation and exchange rate movements, was US$4.1 billion representing a statutory effective tax rate of 39.7 per cent. The FY2017 taxation expense reflects higher profits as explained earlier in this section. The FY2016 taxation benefit reflects operating losses resulting from the recognition of impairments as explained earlier in this section.

Financial results for the year ended 30 June 2016 compared with year ended 30 June 2015

Loss after taxation from Continuing and Discontinued operations attributable to the BHP shareholders was US$6.4 billion in FY2016 compared with a profit of US$1.9 billion in FY2015.

Revenue of US$30.9 billion reduced by US$13.7 billion, or 31 per cent, from US$44.6 billion in FY2015. This decrease was primarily attributable to weaker average realised prices across all major commodities. For a discussion of the average realised prices of our commodities, refer to section 1.6.3 ‘Commodity performance overview’. Lower volumes during the year, particularly for copper at Escondida (due to anticipated grade decline) and Onshore US (deferral of development activity for value), also contributed to the decline in revenue. For production results from our operations during the periods, refer to section 6.2.

Total expenses of US$35.5 billion reduced by US$1.5 billion, or four per cent, from US$37.0 billion in FY2015. This was due to a US$1.3 billion reduction in Employee benefits expense related to lower headcount, a US$1.3 billion reduction in External services related to lower contractor expenditure and a US$604 million reduction in Raw materials and consumables used due to lower fuel and energy costs.

Depreciation and amortisation expense declined by US$497 million due to a reduction in the depreciable asset base at Onshore US due to impairments previously recorded. Impairment of assets of US$7.4 billion in FY2016 primarily relates to Onshore US assets.

(Loss)/profit from operations of US$(6.2) billion reduced by US$14.9 billion from FY2015 primarily as a result of a significant decline in commodity prices, the impairment of the Onshore US assets and the financial impacts of the Samarco dam failure, partially offset by the cost reductions described above.

Net finance costs of US$1.0 billion increased by US$410 million, or 67 per cent, from US$614 million in FY2015 due to the issue of multi-currency hybrid notes during FY2016 (refer to section 1.12.3), higher benchmark interest rates and a gain on the early redemption of the Petrohawk Energy Corporation Senior Notes in FY2015.

The Group’s statutory effective tax rate for FY2016 presents as nil (FY2015: 45.5 per cent) because we recognised a total taxation benefit of US$1.1 billion (including government imposed royalty-related taxation calculated by reference to profits), and a loss before taxation for the period of US$7.3 billion. The Group’s adjusted effective tax rate was 35.8 per cent (FY2015: 31.8 per cent). The increase in the Group’s adjusted effective tax rate in FY2016 reflects the relative higher proportion of profit from Australian petroleum assets (which are subject to a higher rate of tax due to the Petroleum Resource Rent Tax) in the Group’s overall profit compared to FY2015.

Government royalties paid and payable which are not profit based are recognised as operating costs within (Loss)/profit before taxation. These amounted to US$1.3 billion during the period (FY2015: US$1.7 billion).

Discontinued operations

South32’s contribution to BHP Billiton’s FY2015 results comprised a US$1.5 billion Loss after taxation. Details of the contribution of the South32 assets to the Group’s results are disclosed in note 27 ‘Discontinued operations’ in section 5.

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Principal factors that affect Revenue, Profit/(loss) from operations and Underlying EBITDA

The following table describes the impact of the principal factors that affected Revenue, Profit/(loss) from operations and Underlying EBITDA for FY2017 and relates them back to our Consolidated Income Statement. For information on the method of calculation of the principal factors that affect Revenue, Profit/(loss) from operations and Underlying EBITDA, refer to section 1.12.6.

	Revenue US$M			Total expenses, Other income and Profit/(loss) from equity accounted investments US$M			Profit/(loss) from operations US$M			Depreciation, amortisation and impairments and Exceptional Items US$M			Underlying EBITDA US$M
For the year ended 30 June 2016
Revenue		30,912
Other income					444
Expenses excluding net finance costs					(35,487	)
Loss from equity accounted investments, related impairments and expenses					(2,104	)
Total other income, expenses excluding net finance costs and Loss from equity accounted investments, related impairments and expenses					(37,147	)
Loss from operations								(6,235	)
Depreciation, amortisation and impairments (1)											8,871
Exceptional items (1) (refer to note 2 ‘Exceptional items’ in section 5)											9,704
Underlying EBITDA														12,340
Change in sales prices		9,261			(274	)		8,987			–			8,987
Price-linked costs		–			(779	)		(779	)		–			(779	)
Net price impact		9,261			(1,053	)		8,208			–			8,208
Productivity volumes		422			(82	)		340			–			340
Growth volumes		(668	)		401			(267	)		–			(267	)
Changes in volumes		(246	)		319			73			–			73
Operating cash costs		–			1,131			1,131			–			1,131
Exploration and business development		–			(170	)		(170	)		–			(170	)
Change in controllable cash costs (2)		–			961			961			–			961
Exchange rates		38			(554	)		(516	)		–			(516	)
Inflation on costs		–			(308	)		(308	)		–			(308	)
Fuel and energy		–			(7	)		(7	)		–			(7	)
Non-cash		–			(357	)		(357	)		–			(357	)
One-off items		–			(602	)		(602	)		–			(602	)
Change in other costs		38			(1,828	)		(1,790	)		–			(1,790	)
Asset sales		–			176			176			–			176
Ceased and sold operations		(478	)		417			(61	)		–			(61	)
Share of operating profit from equity accounted investments		–			172			172			–			172
Other		(1,202	)		1,419			217			–			217
Depreciation, amortisation and impairments (1)		–			964			964			(964	)		–
Exceptional items (1)		–			9,068			9,068			(9,068	)		–

93

	Revenue US$M		Total expenses, Other income and Profit/(loss) from equity accounted investments US$M			Profit/(loss) 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		38,285
Other income				736
Expenses excluding net finance costs				(27,540	)
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				(26,532	)
Profit/(loss) from operations							11,753
Depreciation, amortisation and impairments (1)									7,907
Exceptional items (1) (refer to note 2 ‘Exceptional items’ in section 5)									636
Underlying EBITDA											20,296

⁽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$188 million (FY2016: US$210 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.

Higher average realised prices across our key commodities increased Underlying EBITDA by US$9.0 billion in FY2017. This was partially offset by an increase to price-linked costs of US$779 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. This was partially offset by US$267 million lower growth volumes reflecting deferral of development activity for value at Onshore US and expected natural field decline.

Our focus on best-in-class performance underpinned a US$961 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.

94

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.

Principal factors affecting Underlying EBITDA for the year ended 30 June 2016 compared with year ended 30 June 2015

Lower average realised prices across our major commodities reduced Underlying EBITDA by US$11.3 billion in FY2016, partially offset by a reduction in price-linked costs by US$592 million reflecting lower royalty charges at Western Australia Iron Ore as a result of lower average realised prices.

Anticipated grade decline of 28 per cent at Escondida was the major contributor to lower productivity-led volumes of US$782 million in Underlying EBITDA. Deferral of development activity for value at Onshore US reduced gas volumes supporting a further volume-related decrease in Underlying EBITDA of US$383 million.

Our focus on best-in-class performance underpinned a US$1.0 billion reduction in operating cash costs during FY2016. Lower operating cash costs across the Group more than offset the impact of the drawdown of lower-grade inventory and grade decline at Escondida.

A stronger US dollar against the Australian dollar and Chilean peso increased Underlying EBITDA by US$1.1 billion during the period.

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	2017 US$M			2016 US$M			2015 US$M
Cash generated from operations		19,377			12,671			21,620
Dividends received		636			301			740
Net interest paid		(985	)		(702	)		(541	)
Settlement of cash management related instruments		(140	)		–			–
Net taxation paid		(2,084	)		(1,645	)		(4,025	)
Net operating cash flows from Continuing operations		16,804			10,625			17,794
Net operating cash flows from Discontinued operations		–			–			1,502
Net operating cash flows		16,804			10,625			19,296
Purchases of property, plant and equipment		(4,252	)		(6,946	)		(11,947	)
Exploration expenditure		(968	)		(765	)		(816	)
Subtotal: Capital and exploration expenditure		(5,220	)		(7,711	)		(12,763	)
Exploration expenditure expensed and included in operating cash flows		612			430			670
Net investment and funding of equity accounted investments		(234	)		40			117
Other investing activities		681			(4	)		474
Net investing cash flows from Continuing operations		(4,161	)		(7,245	)		(11,502	)
Net investing cash flows from Discontinued operations		–			–			(1,066	)
Cash disposed on demerger of South32		–			–			(586	)

95

Year ended 30 June	2017 US$M			2016 US$M			2015 US$M
Net investing cash flows		(4,161	)		(7,245	)		(13,154	)
Net (repayment of)/proceeds from interest bearing liabilities		(5,507	)		4,607			(728	)
(Distributions)/contributions to/from non-controlling interests		(16	)		–			53
Dividends paid		(2,921	)		(4,130	)		(6,498	)
Dividends paid to non-controlling interests		(581	)		(87	)		(554	)
Other financing activities		(108	)		(106	)		(346	)
Net financing cash flows from Continuing operations		(9,133	)		284			(8,073	)
Net financing cash flows from Discontinued operations		–			–			(203	)
Net financing cash flows		(9,133	)		284			(8,276	)
Net increase/(decrease) in cash and cash equivalents from Continuing operations		3,510			3,664			(1,781	)
Net increase in cash and cash equivalents from Discontinued operations		–			–			233
Cash disposed on demerger of South32		–			–			(586	)

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.

For additional information and a breakdown of capital and exploration expenditure on a commodity basis, refer to section 1.13.

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 1.12.3 and note 19 ‘Net debt’ in section 5.

Financial results for the year ended 30 June 2016 compared with year ended 30 June 2015

Net operating cash inflows after interest and tax of US$10.6 billion reduced by US$8.7 billion from FY2015. The major contributor was a US$8.9 billion decrease in cash generated from operations (after changes in working capital balances), which was partially offset by a decrease of US$2.4 billion in net taxes paid. Despite the significant decline in commodity prices, we generated US$3.4 billion of free cash flow during FY2016 due to a reduction in operating costs and a targeted reduction of working capital.

Net investing cash outflows of US$7.2 billion reduced by US$5.9 billion from FY2015 due to a US$5.1 billion reduction in capital and exploration expenditure. Exploration expenditure was US$765 million, including US$430 million classified within Net operating cash flows.

Net financing cash inflows of US$284 million increased by US$8.6 billion from outflows of US$8.3 billion in FY2015, due to the issue of multi-currency hybrid notes during FY2016 (refer to section 1.12.3) and lower dividends paid in line with the revised dividend policy.

96

1.12.3    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.

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⁽¹⁾ (FY2016: US$10.3 billion). This resulted in net debt⁽²⁾ 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.

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. In addition to the Group’s uncommitted debt issuance programs, we hold the following committed standby facilities.

⁽¹⁾  Included within Cash and cash equivalents were short-term deposits of US$13.3 billion (FY2016: US$9.8 billion).

⁽²⁾  We use alternate performance measures to reflect the underlying performance of BHP. Refer to section 1.12.5 for the definition and method of calculation of alternate performance measures. Refer to note 19 ‘Net debt’ in section 5 for the composition of net debt.

97

	Facility available 2017 US$M		Drawn 2017 US$M		Undrawn 2017 US$M		Facility available 2016 US$M		Drawn 2016 US$M		Undrawn 2016 US$M
Revolving credit facility (3)		6,000		–		6,000		6,000		–		6,000
Total financing facilities		6,000		–		6,000		6,000		–		6,000

⁽³⁾  The Company’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$6.0 billion. As at 30 June 2017, US$ nil commercial paper was drawn (FY2016: US$ nil), therefore US$6.0 billion of committed facility was available to use (FY2016: 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 the Company’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 21 ‘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, and any rating should be evaluated independently of any other information.

Year ended 30 June 2016 compared with year ended 30 June 2015

Interest bearing liabilities, net debt and gearing

At the end of FY2016, Interest bearing liabilities were US$36.4 billion (2015: US$31.2 billion) and Cash and cash equivalents less overdrafts were US$10.3 billion (2015: US$6.8 billion). Included within Cash and cash equivalents were short-term deposits of US$9.8 billion compared with US$5.8 billion at 30 June 2015. This resulted in net debt of US$26.1 billion, which represented an increase of US$1.7 billion compared with the net debt position at 30 June 2015. Gearing, which is the ratio of net debt to net debt plus net assets, was 30.3 per cent at 30 June 2016, compared with 25.7 per cent at 30 June 2015.

Funding sources

In October 2015, BHP issued the following hybrid notes:

• US$3.25 billion of subordinated fixed rate reset notes across two tranches, comprising US$1,000 million in a 60NC5 maturity bearing an initial coupon of 6.250 per cent and US$2,250 million in a 60NC10 maturity bearing an initial coupon of 6.750 per cent.

98

• €2.0 billion of subordinated fixed rate reset notes across two tranches comprising €1,250 million in a 60.5NC5.5 maturity bearing an initial coupon of 4.750 per cent and €750 million in a 64NC9 maturity bearing an initial coupon of 5.625 per cent.

• £600 million of subordinated fixed rate reset notes in a 62NC7 maturity bearing an initial coupon of 6.500 per cent.

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.

For more information regarding the maturity profile of our debt obligations and details of our standby and support agreements, refer to note 21 ‘Financial risk management’ in section 5.

99

1.12.4    Alternate performance measures

We use various alternate performance measures to reflect our underlying performance. Our two primary measures of performance are Underlying attributable profit and Underlying EBITDA. These measures, and other alternate performance measures, are reconciled below and defined in section 1.12.5.

We believe these alternate 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 to distribute 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 alternate 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.

Prior to FY2016, we reported Underlying EBIT as a key alternate performance measure of operating results. Management believes focusing on Underlying EBITDA more closely reflects the operating cash generative capacity and hence the underlying performance of the Group’s business. Management also uses this measure because financing structures and tax regimes differ across the Group’s assets and substantial components of the Group’s tax and interest charges are levied at a Group level rather than an operational level.

Underlying EBITDA and Underlying EBIT are included in the FY2017 Consolidated Financial Statements, as required by IFRS 8 ‘Operating Segments’.

Reconciling alternate performance measures

The following tables provide reconciliations between the alternate performance measure and the respective IFRS measure. Section 1.12.5 outlines the definition and calculation methodology of our alternate performance measures.

Year ended 30 June 2017 US$M	Petroleum			Copper			Iron Ore			Coal			Group and unallocated items/ eliminations (3)			BHP Group
Revenue		6,872			8,335			14,624			7,578			876					38,285
Revenue – Group production (1)		6,856			7,232			14,543			7,578			869			37,078
Revenue – Third party products (1)		16			1,103			81			–			7			1,207
Other income		265			62			172			192			45					736
Non-exceptional items		265			62			172			23			45			567
Exceptional items attributable to BHP shareholders		–			–			–			169			–			169
Depreciation and amortisation expense		(3,395	)		(1,737	)		(1,828	)		(719	)		(252	)				(7,931	)
Non-exceptional items		(3,395	)		(1,525	)		(1,828	)		(719	)		(252	)		(7,719	)
Exceptional items attributable to non-controlling interests		–			(90	)		–			–			–			(90	)

100

Year ended 30 June 2017 US$M	Petroleum			Copper			Iron Ore			Coal			Group and unallocated items/ eliminations (3)			BHP Group
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		(12	)		(1,080	)		(58	)		–			(7	)				(1,157	)
All other operating expenses		(3,059	)		(4,401	)		(5,692	)		(3,969	)		(1,138	)				(18,259	)
Non-exceptional items		(3,059	)		(4,067	)		(5,661	)		(3,969	)		(1,087	)		(17,843	)
Exceptional items attributable to non-controlling interests		–			(142	)		–			–			–			(142	)
Exceptional items attributable to BHP shareholders		–			(192	)		(31	)		–			(51	)		(274	)
Expenses excluding net finance costs		(6,568	)		(7,232	)		(7,630	)		(4,708	)		(1,402	)				(27,540	)
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		566			1,460			6,994			3,214			(481	)				11,753
Net finance costs																			(1,431	)
Non-exceptional items																	(1,304	)
Exceptional items attributable to BHP shareholders																	(127	)
Profit/(loss) before taxation																			10,322
Total taxation (expense)/benefit																			(4,100	)
Non-exceptional items																	(3,857	)
Exceptional items attributable to non-controlling interests																	68
Exceptional items attributable to BHP shareholders																	(311	)
Profit/(loss) 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		–			546			203			(164	)		51			127		763
Tax effect of exceptional items																			243
Exceptional items attributable to non-controlling interests (2)																			(232	)
Tax effect of exceptional items attributable to non-controlling interests (2)																			68

101

Year ended 30 June 2017 US$M	Petroleum			Copper			Iron Ore			Coal			Group and unallocated items/ eliminations (3)			BHP Group
Subtotal: Exceptional items attributable to BHP shareholders																		842
Profit/(loss) after taxation from Continuing and Discontinued operations attributable to non-controlling interests																		(332	)
Underlying attributable profit																		6,732
Profit/(loss) after taxation from Continuing operations attributable to non-controlling interests																		332
Exceptional items attributable to non-controlling interests (2)																		232
Tax effect of exceptional items attributable to non-controlling interests (2)																		(68	)
Taxation expense from non-exceptional items																		3,857
Net finance costs excluding exceptional items																		1,304
Underlying EBIT																		12,389
Depreciation, amortisation and impairments excluding exceptional items		3,497			1,539			1,880			734			257				7,907
Underlying EBITDA		4,063			3,545			9,077			3,784			(173	)			20,296
Underlying EBITDA – Group production (1)		4,059			3,522			9,054			3,784			(173	)		20,246
Underlying EBITDA – Third party products (1)		4			23			23			–			–			50
Basic and Underlying basic earnings per share
Underlying attributable profit (US$M)																		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/(loss) per ordinary share (US cents)																		110.7
Segment contribution to Underlying EBITDA
Segment contribution to the Group’s Underlying EBITDA (4)		20	%		17	%		44	%		19	%						100	%
Margin calculation
Underlying EBITDA margin		59	%		49	%		62	%		50	%						55	%
Margin on third party products		25	%		2	%		28	%		–							4	%

102

Year ended 30 June 2017	Profit/(loss) before taxation US$M		Income tax (expense)/ benefit US$M			%
Adjusted effective tax rate reconciliation
Statutory effective tax rate		10,322		(4,100	)		39.7
Adjusted for:
Exchange rate movements		–		88
Exceptional items		763		243
Adjusted effective tax rate		11,085		(3,769	)		34.0

Year ended 30 June 2016 US$M	Petroleum			Copper			Iron Ore			Coal			Group and unallocated items/ elimination (3)			BHP Group
Revenue		6,894			8,249			10,538			4,518			713					30,912
Revenue – Group production (1)		6,766			7,411			10,454			4,512			701			29,844
Revenue – Third party products (1)		128			838			84			6			12			1,068
Other income		447			87			256			48			(394	)				444
Depreciation and amortisation expense		(4,147	)		(1,560	)		(1,817	)		(890	)		(247	)				(8,661	)
Net impairments		(7,232	)		(17	)		(42	)		(94	)		(9	)				(7,394	)
Non-exceptional items		(48	)		(17	)		(42	)		(94	)		(9	)		(210	)
Exceptional items attributable to non-controlling interest		(80	)		–			–			–			–			(80	)
Exceptional items attributable to BHP shareholders		(7,104	)		–			–			–			–			(7,104	)
Third party commodity purchases		(111	)		(792	)		(92	)		(6	)		(12	)				(1,013	)
All other operating expenses		(3,565	)		(5,080	)		(5,247	)		(3,916	)		(611	)				(18,419	)
Non-exceptional items		(3,565	)		(5,080	)		(5,239	)		(3,916	)		(479	)		(18,279	)
Exceptional items attributable to BHP shareholders		–			–			(8	)		–			(132	)		(140	)
Expenses excluding net finance costs		(15,055	)		(7,449	)		(7,198	)		(4,906	)		(879	)				(35,487	)
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		(7,721	)		1,042			1,352			(349	)		(559	)				(6,235	)
Net finance costs																			(1,024	)
Profit/(loss) before taxation																			(7,259	)
Total taxation (expense)/benefit																			1,052
Non-exceptional items																	(1,001	)
Exceptional items attributable to non-controlling interest																	29

103

Year ended 30 June 2016 US$M	Petroleum		Copper		Iron Ore			Coal		Group and unallocated items/ elimination (3)			BHP Group
Exceptional items attributable to BHP shareholders														2,024
Profit/(loss) after taxation from Continuing and Discontinued operations																(6,207	)
Attributable to non-controlling interests														178
Attributable to BHP shareholders														(6,385	)
Reconciliation to Underlying attributable profit, Underlying EBITDA and Underlying EBIT
Exceptional items		7,184		–		2,388			–		132					9,704
Tax effect of exceptional items																(2,053	)
Exceptional items attributable to non-controlling interests (2)																(80	)
Tax effect of exceptional items attributable to non-controlling interests (2)																29
Subtotal: Exceptional items attributable to BHP shareholders																7,600
Profit/(loss) after taxation from Continuing and Discontinued operations attributable to non-controlling interests																(178	)
Underlying attributable profit																1,215
Profit/(loss) after taxation from Continuing operations attributable to non-controlling interests																178
Exceptional items attributable to non-controlling interests (2)																80
Tax effect of exceptional items attributable to non-controlling interests (2)																(29	)
Taxation expense from non-exceptional items																1,001
Net finance costs																1,024
Underlying EBIT																3,469
Add: Depreciation, amortisation and impairments excluding exceptional items		4,195		1,577		1,859			984		256					8,871
Underlying EBITDA		3,658		2,619		5,599			635		(171	)				12,340
Underlying EBITDA – Group production (1)		3,641		2,573		5,607			635		(171	)		12,285
Underlying EBITDA – Third party products (1)		17		46		(8	)		–		–			55

104

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)															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)		29	%		21	%		45	%		5	%			100	%
Margin calculation
Underlying EBITDA margin		54	%		35	%		54	%		14	%			41	%
Margin on third party products		13	%		5	%		(10	)%		–				5	%

Year ended 30 June 2016	Profit/(loss) before taxation US$M			Income tax (expense)/ benefit US$M			%
Adjusted effective tax rate reconciliation
Statutory effective tax rate		(7,259	)		1,052			–
Adjusted for:
Exchange rate movements		–			125
Exceptional items		9,704			(2,053	)
Adjusted effective tax rate		2,445			(876	)		35.8

Year ended 30 June 2015 US$M	Petroleum			Copper			Iron Ore			Coal			Group and unallocated items/ elimination (3)			BHP Group
Revenue		11,447			11,453			14,753			5,885			1,098					44,636
Revenue – Group production (1)		11,378			10,500			14,677			5,878			1,024			43,457
Revenue – Third party products (1)		69			953			76			7			74			1,179
Other income		124			345			69			107			(149	)				496
Depreciation and amortisation expense		(4,738	)		(1,545	)		(1,698	)		(875	)		(302	)				(9,158	)
Net impairments		(3,264	)		(307	)		(18	)		(19	)		(416	)				(4,024	)
Non-exceptional items		(477	)		(307	)		(18	)		(19	)		(7	)		(828	)
Exceptional items attributable to BHP shareholders		(2,787	)		–			–			–			(409	)		(3,196	)

105

Year ended 30 June 2015 US$M	Petroleum			Copper			Iron Ore			Coal			Group and unallocated items/ elimination (3)			BHP Group
Third party commodity purchases		(68	)		(930	)		(86	)		(7	)		(74	)				(1,165	)
All other operating expenses		(4,302	)		(5,838	)		(6,459	)		(4,744	)		(1,320	)				(22,663	)
Expenses excluding net finance costs		(12,372	)		(8,620	)		(8,261	)		(5,645	)		(2,112	)				(37,010	)
Profit/(loss) from equity accounted investments, related impairments and expenses		–			175			371			1			1					548
Subtotal		(801	)		3,353			6,932			348			(1,162	)				8,670
Net finance costs																			(614	)
Profit/(loss) before taxation																			8,056
Total taxation (expense)/benefit																			(3,666	)
Non-exceptional items																	(3,916	)
Exceptional items attributable to non-controlling interest																	(12	)
Exceptional items attributable to BHP shareholders																	262
(Loss)/profit after taxation from Discontinued operations																			(1,512	)
Attributable to non-controlling interests																	61
Attributable to BHP shareholders																	(1,573	)
Profit/(loss) after taxation from Continuing and Discontinued operations																			2,878
Attributable to non-controlling interests																	968
Attributable to BHP shareholders																	1,910
Reconciliation to Underlying attributable profit, Underlying EBITDA and Underlying EBIT
Exceptional items		2,787			–			–			–			409					3,196
Tax effect of exceptional items																			(250	)
Tax effect of exceptional items attributable to non-controlling interests (2)																			(12	)

106

Year ended 30 June 2015 US$M	Petroleum		Copper		Iron Ore			Coal		Group and unallocated items/ elimination (3)			BHP Group
Subtotal: Exceptional items attributable to BHP shareholders															2,934
(Loss)/profit after taxation from Discontinued operations attributable to BHP shareholders															1,573
Profit/(loss) after taxation from Continuing and Discontinued operations attributable to non-controlling interests															(968	)
Underlying attributable profit															6,417
Profit/(loss) after taxation from Continuing and Discontinued operations attributable to non-controlling interests															968
(Loss)/profit after taxation from Discontinued operations attributable to non-controlling interests															(61	)
Tax effect of exceptional items attributable to non-controlling interests (2)															12
Taxation expense from non-exceptional items															3,916
Net finance costs															614
Underlying EBIT															11,866
Add: Depreciation, amortisation and impairments excluding exceptional items		5,215		1,852		1,716			894		309				9,986
Underlying EBITDA		7,201		5,205		8,648			1,242		(444	)			21,852
Underlying EBITDA – Group production (1)		7,200		5,182		8,658			1,242		(444	)		21,838
Underlying EBITDA – Third party products (1)		1		23		(10	)		–		–			14
Basic and Underlying basic earnings per share
Underlying attributable profit (US$M)															6,417
Weighted basic average number of shares (Million)															5,318
Underlying basic earnings per ordinary share (US cents)															120.7

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Year ended 30 June 2015 US$M	Petroleum			Copper			Iron Ore			Coal			Group and unallocated items/ elimination (3)	BHP Group
Adjusted for: Exceptional items attributable to BHP shareholders per share															(55.2	)
Adjusted for: (Loss)/profit after taxation from Discontinued operations attributable to BHP shareholders per share															(29.6	)
Basic earnings/(loss) per ordinary share (US cents)															35.9
Segment contribution to Underlying EBITDA
Segment contribution to the Group’s Underlying EBITDA (4)		32	%		23	%		39	%		6	%			100	%
Margin calculation
Underlying EBITDA margin		63	%		49	%		59	%		21	%			50	%
Margin on third party products		1	%		2	%		(13	)%		–				1	%

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Year ended 30 June 2015	Profit/(loss) before taxation US$M		Income tax (expense)/ benefit US$M			%
Adjusted effective tax rate reconciliation
Statutory effective tax rate		8,056		(3,666	)		45.5
Adjusted for:
Exchange rate movements		–		339
Exceptional items		3,196		(250	)
Adjusted effective tax rate		11,252		(3,577	)		31.8

⁽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’ and note 3 ‘Significant events – Samarco dam failure’ in section 5.

⁽³⁾  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. Exploration and technology activities are recognised within relevant segments.

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

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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
		–			(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	)
Year ended 30 June 2015 US$M	Revenue			Other income and expenses excluding net finance costs			Exceptional items		Depreciation, amortisation and impairments excluding exceptional items		Underlying EBITDA
Potash		–			(184	)		–		6		(178	)
Nickel West		1,393			(1,876	)		409		112		38
Corporate and eliminations		(295	)		(200	)		–		191		(304	)
Total		1,098			(2,260	)		409		309		(444	)

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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	2017 US$M			2016 US$M
Net operating assets
Petroleum		23,181			25,168
Copper		24,100			23,844
Iron Ore		19,175			20,541
Coal		10,136			10,651
Group and unallocated items (1)		2,446			2,723
Total		79,038			82,927
Reconciled to Net assets
Cash and cash equivalents		14,153			10,319
Trade and other receivables (2)		665			939
Other financial assets (3)		980			2,557
Current tax assets		195			567
Deferred tax assets		5,788			6,147
Trade and other payables (4)		(390	)		(421	)
Interest bearing liabilities		(30,474	)		(36,421	)
Other financial liabilities (5)		(1,345	)		(1,768	)
Current tax payable		(2,119	)		(451	)
Deferred tax liabilities		(3,765	)		(4,324	)
Net assets		62,726			60,071

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

⁽²⁾  Represents loans to associates of US$644 million (FY2016: US$897 million) and accrued interest receivable of US$21 million (FY2016: US$42 million) included within other receivables.

⁽³⁾  Represents cross currency and interest rate swaps and available for sale shares and other investments (refer to note 21 ‘Financial risk management’ in section 5) included in other financial assets.

⁽⁴⁾  Represents accrued interest payable included within other payables.

⁽⁵⁾  Represents cross currency and interest rate swaps (refer to note 21 ‘Financial risk management’ in section 5) included in other financial liabilities.

Free cash flow

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

Year ended 30 June	2017 US$M			2016 US$M			2015 US$M
Net operating cash flows		16,804			10,625			19,296
Net investing cash flows		(4,161	)		(7,245	)		(13,154	)
Free cash flow		12,643			3,380			6,142
Net financing cash flows		(9,133	)		284			(8,276	)
Net increase/(decrease) in cash and cash equivalents		3,510			3,664			(2,134	)

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1.12.5    Definition and calculation of alternate performance measures

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

Alternate performance measure	Method of calculation
Underlying attributable profit	Profit/(loss) after taxation attributable to BHP shareholders less exceptional items attributable to BHP shareholders as described in note 2 ‘Exceptional items’ and note 27 ‘Discontinued operations’ 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 alternate 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.
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.

112

Operating assets free cash flow	Net operating cash flows adjusted for dividends received, net interest received/(paid) and net income tax and royalty-related taxation refunded/(paid) less net investing cash flows, dividends received, net interest and net income tax and royalty-related taxation are not allocated to operating asset free cash flow as financing structures and tax regimes differ across the Group’s assets and substantial components of the Group’s interest and tax charges are levied at a Group level rather than an operational level.
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.

1.12.6    Definition and calculation of principal factors

The method of calculation of the principal factors that affect Revenue, Profit/(loss) 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.
Controllable cash costs	Operating cash costs and exploration and business development costs, excluding Discontinued operations. 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.

113

Principal factor	Method of calculation
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.

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1.13    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.

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 alternate 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 1.12.4. For the definition and method of calculation of alternate performance measures, refer to section 1.12.5. For additional information as to the statutory determination of our reportable segments, refer to note 1 ‘Segment reporting’ in section 5.

Unit cash 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.

1.13.1    Petroleum

Detailed below is financial information for our Petroleum assets for FY2017 and FY2016 and an analysis of Petroleum’s financial performance for FY2017 compared with FY2016.

Year ended 30 June 2017 US$M	Revenue (1)			Underlying EBITDA			D&A			Underlying EBIT			Net operating assets (11)			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
Eagle Ford		1,266			771			1,255			(484	)		6,223			274
Permian		332			143			302			(159	)		996			242
Haynesville		272			11			139			(128	)		2,866			50
Fayetteville		273			79			85			(6	)		871			9
Trinidad/Tobago		110			26			33			(7	)		422			81
Algeria		212			167			34			133			22			13
Exploration		–			(473	)		159			(632	)		896			–
Other (5)(6)		133			(42	)		26			(68	)		3,029			101
Total Petroleum from Group production		6,873			4,078			3,500			578			24,024			1,472		805		575
Closed mines (7)		–			(16	)		–			(16	)		(843	)		–		–		–
Third party products		16			4			–			4			–			–
Total Petroleum		6,889			4,066			3,500			566			23,181			1,472		805		575
Adjustment for equity accounted investments (8)		(17	)		(3	)		(3	)		–			–			–		–		–
Total Petroleum statutory result		6,872			4,063			3,497			566			23,181			1,472		805		575

115

Year ended 30 June 2016 US$M	Revenue (1)			Underlying EBITDA			D&A			Underlying EBIT			Net operating assets (10)(11)			Capital expenditure			Exploration gross (2)		Exploration to profit (3)
Australia Production Unit (4)		707			542			349			193			1,166			246
Bass Strait		930			690			174			516			3,082			226
North West Shelf		1,171			830			182			648			1,576			180
Atlantis		652			481			485			(4	)		1,795			328
Shenzi		499			386			245			141			1,133			55
Mad Dog		123			84			44			40			697			128
Eagle Ford		1,508			687			1,710			(1,023	)		7,193			781
Permian		260			52			279			(227	)		1,114			365
Haynesville		299			(67	)		305			(372	)		2,994			44
Fayetteville		246			20			154			(134	)		945			49
Trinidad/Tobago (9)		123			95			22			73			467			(26	)
Algeria		144			41			33			8			44			86
Exploration		–			(273	)		97			(370	)		901			–
Other (5)(6)		119			56			119			(63	)		2,916			55
Total Petroleum from Group production		6,781			3,624			4,198			(574	)		26,023			2,517			590		288
Closed mines (7)		–			20			–			20			(855	)		–			–		–
Third party products		128			17			–			17			–			–
Total Petroleum		6,909			3,661			4,198			(537	)		25,168			2,517			590		288
Adjustment for equity accounted investments (8)		(15	)		(3	)		(3	)		–			–			–			–		–
Total Petroleum statutory result		6,894			3,658			4,195			(537	)		25,168			2,517			590		288

⁽¹⁾  Petroleum revenue from Group production includes: crude oil US$3,625 million (FY2016: US$3,566 million), natural gas US$1,796 million (FY2016: US$1,761 million), LNG US$858 million (FY2016: US$864 million), NGL US$442 million (FY2016: US$383 million) and other US$135 million (FY2016: US$192 million).

⁽²⁾  Includes US$332 million of capitalised exploration (FY2016: US$317 million).

⁽³⁾  Includes US$102 million of exploration expenditure previously capitalised, written off as impaired (included in depreciation and amortisation) (FY2016: US$15 million).

⁽⁴⁾  Australia Production Unit includes Macedon, Pyrenees, Minerva and Stybarrow (ceased production June 2015).

⁽⁵⁾  Predominantly divisional activities, business development, Pakistan (divested in December 2015), the United Kingdom, 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⁾  Goodwill associated with Onshore US of US$3,022 million is included in Other net operating assets (FY2016: US$3,026 million).

⁽⁷⁾  Comprises closed mining and smelting operations in Canada and the United States. Petroleum manages the closed mines due to their geographic location.

⁽⁸⁾  Total Petroleum segment Revenue excludes US$17 million (FY2016: US$15 million) revenue related to the Caesar oil pipeline and the Cleopatra gas pipeline. Total Petroleum segment Underlying EBITDA includes US$3 million (FY2016: US$3 million) D&A related to the Caesar oil pipeline and the Cleopatra gas pipeline.

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⁽⁹⁾  Negative capital expenditure reflects movements in capital creditors.

⁽¹⁰⁾  Petroleum net operating assets have been restated for North West Shelf, Trinidad and Tobago, Exploration and Other to reflect the reallocation of exploration sundry receivable and sundry creditor balances on a consistent basis with FY2017. There is no change to the overall net operating asset position.

⁽¹¹⁾  Refer to section 1.12.4 for a reconciliation of Net operating assets to Net assets and section 1.12.5 for the definition and method of calculation of Net operating assets.

Key drivers of Petroleum’s financial results

Price overview

Overall, oil and gas prices have performed favourably in FY2017. Petroleum commodities were supported by OPEC-led output cuts for crude oil and lower year-on-year production for US gas, while demand was stronger in both markets. Asian liquefied natural gas (LNG) saw stronger demand.

Trends in each of the major markets are outlined below.

Henry Hub gas

Our average realised sales price for gas was US$3.34 per million standard cubic feet (Mscf) (FY2016: US$2.83 per Mscf). Despite an overall mild winter in the US, the domestic gas price strengthened in FY2017 on strong power demand, rising exports and lower year on year production. Natural gas inventories ended the reporting period seven per cent above the five-year average; a significantly lower level than the corresponding period last year. Lower inventory levels and robust demand are likely to support prices in the near term, although additional North East pipelines, increasing Haynesville production and higher associated gas output are risks to this outlook. Longer term, strong demand growth and natural field decline will incentivise investment in new supply. However, the abundance of lower-cost supply is likely to moderate significant price inflation.

Liquefied natural gas

Our average realised sales price for LNG was US$6.84 per Mscf (FY2016: US$7.71 per Mscf). The LNG price rallied towards the end of the first half of FY2017, boosted by a colder than usual start to the northern hemisphere winter and operational issues with a number of nuclear and coal-fired power units in North Asia. This was combined with unexpected supply disruptions. Prices have since eased on the back of supply being restored and the commissioning of new projects. Despite strong demand growth in Asia and Europe, new supply is likely to weigh on the market in the near term. However, in the long run, 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.

Crude oil

Our average realised sales price for crude oil was US$48 per bbl (FY2016: US$39 per bbl). Crude oil prices overall trended higher in FY2017. OPEC reversed course on 30 November 2016 by agreeing to its first production cut since 2008 and the first cooperative deal with non-OPEC producers since 2001. Agreed output quotas were originally planned for six months, but were subsequently extended at the May 2017 meeting. This renewed cooperation and overall strong compliance by OPEC offered price support. However, concerns around near-record OECD inventories, increasing production from OPEC countries exempt from the agreement, and rising US output weighed on price at the end of June. A balanced market is forecast for the near term, although OPEC strategy and the US response to higher prices add significant risk to the outlook. The long-term outlook remains positive, underpinned by rising demand from the developing world and natural field decline.

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Production

Total petroleum production for FY2017 decreased by 13 per cent to 208 MMboe. Onshore US liquids volumes decreased by 29 per cent to 34 MMboe as value accretive deferral of activity in the Black Hawk and natural field decline across all fields were partially offset by increased production from the Permian. 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. Natural gas production decreased by 10 per cent to 668 bcf. Divestment of our Pakistan gas business in December 2015 and lower Onshore US gas volumes as a result of the deferral of development activity for value were partially offset by a strong performance at Bass Strait and Macedon and increased LNG volumes at North West Shelf.

For additional information on individual asset production in FY2017, FY2016 and FY2015, refer to section 6.2.

Financial results

Overall, petroleum revenue remained consistent year-on-year at US$6.9 billion. Onshore US, which includes Eagle Ford, Permian, Haynesville and Fayetteville, decreased by US$170 million to US$2.1 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$405 million to US$4.1 billion. Price impacts, net of price linked costs, increased Underlying EBITDA by US$774 million. Controllable cash costs increased by US$307 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$190 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 as well as some acreage sales in Onshore US.

Conventional unit cash costs increased by two per cent to US$8.82 per barrel due to lower volumes. The calculation of conventional petroleum unit costs is set out in the table below.

Conventional petroleum unit costs (1) US$M	FY2017			FY2016
Revenue		4,722			4,550
Underlying EBITDA		3,132			3,021
Cash costs (gross)		1,590			1,529
Less: exploration expense (2)		471			261
Less: freight		140			152
Less: other (3)		(152	)		(16	)
Cash costs (net)		1,131			1,132
Sales (MMboe, equity share)		128			131
Cash cost per Boe (US$)		8.82			8.63

⁽¹⁾  Conventional petroleum assets exclude Eagle Ford, Permian, Haynesville, Fayetteville and divisional activities recorded in Other.

⁽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.

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Delivery commitments

We have delivery commitments of natural gas and LNG of approximately 1,720 billion cubic feet through FY2031 (74 per cent Australia and Asia, 10 per cent United States and 16 per cent other), Crude and Condensate commitments of 13.6 million barrels through FY2018 (54 per cent United States, 28 per cent Australia and Asia and 18 per cent other) and liquefied petroleum gas (LPG) commitments of 121,500 metric tonnes through FY2018. 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 FY2018, volume commitments to gather and transport are 753 million cubic feet of gas (98 per cent Onshore US and two per cent other) and 33 million barrels of oil (55 per cent Onshore US and 45 per cent Offshore US). The agreements with the gas gatherers and transporters have annual escalation clauses.

Other information

Investment expenditure

Petroleum capital expenditure for FY2017 declined by 42 per cent to US$1.5 billion.

FY2017		Liquids-focused areas						Gas-focused areas
(FY2016)		Eagle Ford			Permian			Haynesville			Fayetteville			Total
Capital expenditure (1)	US$ billion		0.3 (0.8	)		0.2 (0.4	)		0.1 (–	)		– (–	)		0.6 (1.2	)
Rig allocation	At period-end		1 (2	)		1 (2	)		3 (–	)		– (–	)		5 (4	)
Net wells drilled and completed (2)	Period total		51 (89	)		21 (30	)		5 (5	)		2 (11	)		79 (136	)
Net productive wells	At period-end		963 (929	)		126 (107	)		394 (411	)		1,044 (1,086	)		2,527 (2,533	)

⁽¹⁾  Includes land acquisition, site preparation, drilling, completions, well site facilities, mid-stream infrastructure and pipelines.

⁽²⁾  Can vary between periods based on changes in rig activity and the inventory of wells drilled but not yet completed at period-end.

Drilling

The number of wells in the process of drilling and/or completion during the year included:

	Exploratory wells				Development wells				Total
	Gross		Net (1)		Gross		Net (1)		Gross		Net (1)
Australia		–		–		8		1		8		1
United States		–		–		66		30		66		30
Other		1		1		–		–		1		1
Total		1		1		74		31		75		32

⁽¹⁾  Represents our share of the gross well count.

Onshore US

BHP’s Onshore US drilling and development expenditure in FY2017, which is presented on a cash basis within this section, was US$575 million (FY2016: US$1.2 billion). The expenditure was primarily related to drilling and completion activities in our liquids-focused Black Hawk and Permian fields, while deferring development in areas that are predominantly gas. The expenditure related to the following activities:

• Eagle Ford: primarily drilling and completion activities, resulting in 51 net development wells completed during the year. Approximately US$14 million was spent primarily on the installation of more than 30 kilometres of pipeline infrastructure and additional well connections.

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• Permian: primarily drilling and completion activities, resulting in 21 net development wells completed during the year. Approximately US$33 million was spent on the installation of more than 86 kilometres of pipeline infrastructure and additional gas processing facilities.

• Haynesville: primarily drilling and completion activities, resulting in five net development wells completed during the year.

• Fayetteville: primarily related to participation in drilling and completion activities for wells operated by third parties, resulting in two net development wells completed during the year.

Our Onshore US capital investment is expected to increase to US$1.2 billion on a cash basis in FY2018, as we progress high-return development drilling activities and trial programs designed to optimise long-term value, with Eagle Ford and Permian accounting for approximately 68 per cent of the total investment. Our average operated rig count is expected to be nine for FY2018.

Conventional

BHP’s net share of conventional development expenditure in FY2017, which is presented on a cash basis within this section, was US$897 million (FY2016: US$1.3 billion). While the majority of the expenditure incurred in FY2017 was by operating partners at our Australian and Gulf of Mexico assets, we also executed development activity and incurred capital expenditure at operated Australian and Gulf of Mexico assets, and at our Algeria and Trinidad and Tobago assets.

Australia

BHP’s net share of capital development expenditure in FY2017, which is presented on a cash basis within this section, was US$378 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 and Persephone subsea tie back well development.

• Bass Strait: commissioning the Longford Gas Conditioning Plant and further development of pipelines connecting our Longford and Long Island plants.

Gulf of Mexico

BHP’s net share of capital development expenditure in FY2017, which is presented on a cash basis within this section, was US$340 million. The expenditure was primarily related to:

• Atlantis: West Auriga rig return and schedule update that enabled execution of development activity on four wells.

• Mad Dog: initial phases of Phase 2 development, with additional development activity on two wells at Spar A.

Our conventional capital investment in FY2018, which is presented on a cash basis in this section, is expected to be approximately US$0.8 billion. Capital investment activity in FY2018 remains focused on high-return infill drilling opportunities in the Gulf of Mexico, a life extension project at North West Shelf along with investments related to the recently approved Mad Dog Phase 2 project.

Exploration and appraisal

Our Petroleum 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.

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Access

We acquired acreage in the US and Mexico sectors of the Gulf of Mexico during FY2017. In the US sector, we were awarded 12 blocks from Lease sale 248, held in August 2016 (100 per cent working interest and operator on all blocks; 280 square kilometres). In addition, we were awarded four blocks from Lease sale 247, held in March 2017 (100 per cent working interest and operator in two blocks and 28.32 per cent working interest with BP in two blocks; 93 square kilometres).

In the Mexico sector, we acquired a 60 per cent participating interest in and operatorship of blocks AE-0092 and AE-0093 containing the Trion discovery (1,285 square kilometres).

Exploration program expenditure details

Our gross expenditure on exploration was US$805 million in FY2017, of which US$473 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 depth	Status
LeClerc-1	Trinidad and Tobago Block 5	Oil	65% (operator)	21 May 2016	1,800m	5,771m	Hydrocarbons encountered; plugged and abandoned
LeClerc-ST 1	Trinidad and Tobago Block 5	Oil	65% (operator)	6 July 2016	1,800m	6,973m	Hydrocarbons encountered; plugged and abandoned
Caicos-1	Gulf of Mexico GC564	Oil	100% (operator)	21 June 2016	1,288m	9,198m	Hydrocarbons encountered; plugged and abandoned
Burrokeet-1	Trinidad & Tobago Block 23a	Oil	70% (Operator)	8 August 2016	1,923m	3,337m	Plugged and abandoned
Burrokeet-2	Trinidad & Tobago Block 23a	Oil	70% (Operator)	18 August 2016	1,923m	7,348m	Plugged and abandoned
Wildling-1	Gulf of Mexico GC520	Oil	100% (Operator)	8 January 2017	1,230m	5,950m	Plugged and abandoned
Wildling-2	Gulf of Mexico GC520	Oil	100% (Operator)	15 April 2017	1,230m	8,928m	Hydrocarbons encountered; Drilling ahead

In the US Gulf of Mexico, we drilled Caicos on Green Canyon Block 654 during the period. Hydrocarbons were encountered and the well bore was plugged and abandoned. The results of the program are being further evaluated by the Wildling-2 well (which spud in April 2017 on Green Canyon Block 520) after Wildling-1 (which spud in January 2017) encountered technical difficulty and was plugged and abandoned in April 2017. Positive results were reported following the discovery of oil in multiple horizons at Wildling-2 in August 2017. We have commenced a sidetrack on Wildling-2 to further appraise the extent of the discovery. We expect results on the Wildling-2 sidetrack and the Scimitar exploration well to be spud in the September 2017 quarter.

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Seismic data acquisition and reprocessing were completed in order to evaluate prospects in the US and Mexico.

In Western Australia, we participated in reprocessing over the Beagle sub-basin and a regional study that was proposed as a variation for discharging our Good Standing Agreement commitment resulting from the cancellation of exploration permit WA-475-P. This work is ongoing and is expected to complete in FY2018.

In Trinidad and Tobago, we continue to mature prospects utilising the 3D seismic data acquired over Blocks 3, 5, 6, 7, 14, 23a, 23b, 28 and 29. LeClerc-1, the first well of an eight well deepwater program, which spud in May 2016, represents an industry leading three-year timeframe from access to drill test. The well encountered gas in multiple zones and the well bore was plugged and abandoned. Hydrocarbons were encountered and results of the program are being evaluated. Additionally, the Burrokeet-1 well encountered mechanical difficulty shortly after spud and was plugged and abandoned. Non-commercial hydrocarbons were encountered at Burrokeet-2 and analysis is ongoing. This well concluded Phase I of the Trinidad and Tobago deepwater drilling campaign. Phase II is expected to commence in FY2018.

In Brazil, we initiated efforts to relinquish our two blocks in the deepwater Foz do Amazonas Basin in April 2017, prior to the commencement of Exploration Period 2 (two well commitment).

Outlook

Total petroleum production for FY2018 is expected to decrease to between 180 and 190 MMboe, comprising conventional volumes between 119 and 123 MMboe and Onshore US volumes between 61 and 67 MMboe. The expanded rig program is forecast to deliver Onshore US production growth of approximately 35 per cent in FY2019, with investment plans subject to market conditions.

Conventional unit costs for FY2018 are expected to be approximately US$10 per barrel reflecting the impact of lower volumes, partially offset by productivity improvements.

Petroleum capital expenditure of approximately US$2.0 billion is planned in FY2018. This includes conventional capital expenditure of US$0.8 billion discussed earlier in this section. Onshore US capital expenditure is expected to be up to US$1.2 billion. Our focus in the liquids fields is to maximise value by completing trials to increase investable inventory, while in the Haynesville our hedging strategy allows us to reduce price risk and secure average rates of return in excess of 20 per cent.

Our plans consider up to five additional rigs at Onshore US, subject to market conditions. In July 2017, one rig commenced operations in the Hawkville and one additional rig is expected to commence in the Haynesville in the September 2017 quarter. Evaluation of trials in the Black Hawk is expected to be completed in the September 2017 quarter and, subject to approval, one additional rig will commence towards the end of that quarter. In the Permian, two additional rigs also commencing in the September 2017 quarter will focus on completion trials, which will inform a transition to full pad development as early as FY2019. At this point, we do not anticipate any operated development in the Fayetteville; however, we continue to work with joint venture partners to assess the potential of the Moorefield horizon through non-operated activity.

A US$715 million exploration program is planned for FY2018. This program includes one well in the US Gulf of Mexico and three wells in Trinidad and Tobago. Trion exploration expenditure for FY2018 is expected to be approximately US$75 million. In Trinidad and Tobago, we continued appraisal work to assess the potential commercialisation of the gas discovery at LeClerc and to prepare for deepwater oil exploration in Phase 2, which is expected to commence in the second half of FY2018.

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Strategic developments

As part of our ongoing review of our portfolio, the Board and management determined in August 2017 that our Onshore US assets are non-core and options to exit these assets are being actively pursued. We will be flexible with our plans and commercial in our approach. We are examining multiple alternatives but will only divest for value. Execution of these options may take time, which we will use to continue to complete our well trials and acreage swaps, and to investigate mid-stream solutions to increase the value, profitability and marketability of our Onshore US acreage.

Performance for the year ended 30 June 2016 compared with year ended 30 June 2015

Production

Total petroleum production for FY2016 decreased by six per cent to 240 MMboe.

Conventional production increased by one per cent to 131 MMboe as new production wells at Atlantis, Mad Dog and Pyrenees and higher gas demand at Bass Strait, offset natural field decline across the portfolio and the divestment of our gas business in Pakistan. Onshore US production declined by 13 per cent to 109 MMboe largely as a result of the value accretive deferral of activity in the Black Hawk and Hawkville.

Financial results

Petroleum revenue decreased by US$4.6 billion to US$6.9 billion. Onshore US, which includes Eagle Ford, Permian, Haynesville and Fayetteville, decreased by US$1.9 billion to US$2.3 billion. Gulf of Mexico, which includes Atlantis, Shenzi and Mad Dog, decreased by US$945 million to US$1.3 billion. In Australia, Bass Strait and North West Shelf collectively decreased by US$1.1 billion to US$2.1 billion and the Australia Production Unit, which includes Macedon, Pyrenees, Minerva and Stybarrow, decreased by US$296 million to US$707 million.

Underlying EBITDA for Petroleum decreased by US$3.5 billion to US$3.7 billion in FY2016. Price impacts, net of price-linked costs, decreased Underlying EBITDA by US$3.6 billion due to the decrease in average realised prices of crude and condensate oil from US$68/bbl to US$39/bbl, US natural gas from US$3.27/Mscf to US$2.16/Mscf and LNG from US$11.65/Mscf to US$7.71/Mscf. Conventional unit cash costs (excluding inventory movements, freight, third party and exploration expense) decreased by 30 per cent to US$8.63 per barrel as a result of lower lifting, labour and maintenance expenses.

Petroleum capital expenditure declined by 50 per cent to US$2.5 billion in FY2016, which includes a decline of US$2.4 billion of Onshore US drilling and development expenditure. Our Onshore US operated rig count has been reduced to four, however, completion activity in the Black Hawk resumed late in the June 2016 quarter.

Increased shale drilling and completions efficiency during the year was reflected in a significant improvement in drill time and completion techniques in the Black Hawk and Permian. Drilling times improved by 19 per cent to 15 days per well in the Black Hawk and by 22 per cent to 26 days per well in the Permian.

Petroleum exploration expenditure for FY2016 was US$590 million, of which US$273 million was expensed. Activity for the year was largely focused on our core areas in the deepwater Gulf of Mexico, the Caribbean and the Northern Beagle sub-basin off the coast of Western Australia, where we acquired additional acreage, seismic data and increased drilling activity. Our exploration activity has increased in the Gulf of Mexico following the positive exploration well results at Shenzi North. The Group is also encouraged by the early indications from the deepwater LeClerc well in Trinidad and Tobago which encountered gas in multiple zones. While the focus is on a commercial oil discovery, these results support the further appraisal of the basin.

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1.13.2    Copper

Detailed below is financial information for our Copper assets for FY2017 and FY2016 and an analysis of Copper’s financial performance for FY2017 compared with FY2016.

Year ended 30 June 2017 US$M	Revenue			Underlying EBITDA			D&A			Underlying EBIT			Net operating assets (6)			Capital expenditure			Exploration gross			Exploration to profit
Escondida (1)		4,544			2,397			996			1,401			14,972			999
Pampa Norte (2)		1,401			620			314			306			1,662			213
Antamina (3)		1,119			664			114			550			1,265			188
Olympic Dam		1,287			284			224			60			6,367			267
Other (3)(4)		–			(118	)		7			(125	)		(166	)		5
Total Copper from Group production		8,351			3,847			1,655			2,192			24,100			1,672
Third party products		1,103			23			–			23			–			–
Total Copper		9,454			3,870			1,655			2,215			24,100			1,672			44			44
Adjustment for equity accounted investments (5)		(1,119	)		(325	)		(116	)		(209	)		–			(188	)		–			–
Total Copper statutory result		8,335			3,545			1,539			2,006			24,100			1,484			44			44
Year ended 30 June 2016 US$M	Revenue			Underlying EBITDA			D&A			Underlying EBIT			Net operating assets (6)			Capital expenditure			Exploration gross			Exploration to profit
Escondida (1)		4,881			1,743			930			813			14,449			2,268
Pampa Norte (2)		1,098			401			401			–			1,786			321
Antamina (3)		891			439			114			325			1,349			198
Olympic Dam		1,432			385			237			148			6,339			197
Other (3)(4)		–			(158	)		10			(168	)		(79	)		–
Total Copper from Group production		8,302			2,810			1,692			1,118			23,844			2,984
Third party products		838			46			–			46			–			–
Total Copper		9,140			2,856			1,692			1,164			23,844			2,984			65			65
Adjustment for equity accounted investments (5)		(891	)		(237	)		(115	)		(122	)		–			(198	)		(1	)		(1	)
Total Copper statutory result		8,249			2,619			1,577			1,042			23,844			2,786			64			64

⁽¹⁾  Escondida is consolidated under IFRS 10 and reported on a 100 per cent basis.

⁽²⁾  Includes Spence and Cerro Colorado.

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⁽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. Also includes Resolution.

⁽⁵⁾  Total Copper segment Revenue excludes US$1,119 million (FY2016: US$891 million) revenue related to Antamina. Total Copper segment Underlying EBITDA includes US$116 million (FY2016: US$115 million) D&A and US$209 million (FY2016: US$122 million) net finance costs and taxation (expense)/benefit related to Antamina and Resolution that are also included in Underlying EBIT. Copper segment Capital expenditure excludes US$188 million (FY2016: US$198 million) and US$ nil (FY2016: US$1 million) Exploration expenditure related to Antamina.

⁽⁶⁾  Refer to section 1.12.4 for a reconciliation of Net operating assets to Net assets and section 1.12.5 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 FY2017 was US$2.54 per pound (FY2016: US$2.14 per pound). Copper prices remained at relatively subdued levels for the first four months of FY2017, with a broadly accepted view of a well-supplied market with muted demand. In November 2016, improved fundamentals arising from stronger Chinese demand and increased mine disruption saw the commencement of a price rally. This rally gained momentum as improved sentiment saw the entry of investor money, which pushed copper prices into a new, higher range. Disruptions at several large copper mines during the March and June 2017 quarters continued to provide support. In the near term, incremental mine production from committed projects, combined with increased scrap availability, will be sufficient to cover steady growth in copper demand. In the longer term, we expect demand growth to remain solid. China is expected to transition to a consumption-based economy, continued growth is expected from other emerging markets, and technological trends point to greater copper intensities in key sectors. 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.

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.

For additional information on individual asset production in FY2017, FY2016 and FY2015, refer to section 6.2.

Financial results

Copper revenue increased by US$86 million to US$8.3 billion in FY2017.

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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 cash 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 cash 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. 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$M	FY2017		FY2016		FY2017		FY2016
Revenue		7,232		7,411		4,544		4,881
Underlying EBITDA		3,301		2,529		2,397		1,743
Cash costs (gross)		3,931		4,882		2,147		3,138
Less: by-product credits		580		650		213		222
Less: freight		71		85		60		75
Less: treatment and refining charges		302		356		302		356
Cash costs (net)		2,978		3,791		1,572		2,485
Sales (Mlb, equity share)		2,595		3,155		1,691		2,209
Cash cost per pound (US$)		1.15		1.20		0.93		1.12
Cash cost per pound including industrial action (US$) (2)		1.28		–		1.13		–

⁽¹⁾  Operated copper assets include Escondida, Pampa Norte and Olympic Dam.

⁽²⁾  Sales volumes are adjusted to exclude intercompany sales and purchases. Exceptional item relating to the industrial action of US$546 million comprises US$334 million of cash costs and US$212 million of depreciation expense. Industrial action cash cost per pound for FY2017 calculated as: cash costs of US$334 million divided by sales of 1,691 Mlb = US$0.20 per pound.

Outlook

Total copper production is expected to increase to between 1.66 and 1.79 Mt in FY2018. Escondida production is expected to increase to between 1.13 and 1.23 Mt following the ramp-up of the Los Colorados Extension project during the September 2017 quarter, which will enable utilisation of three concentrators. At Olympic Dam, production is expected to decrease to 150 kt as a major smelter maintenance campaign is phased through August to November 2017. Production at Pampa Norte is expected to be higher than the prior year following completion of the Spence Recovery Optimisation project in FY2017. Production at Antamina is expected to decrease to 125 kt as mining continues through a zinc rich ore zone.

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FY2018 unit cash costs at our operated copper assets are expected to remain broadly unchanged at approximately US$1.15 per pound. At Escondida, unit cash costs are expected to rise to approximately US$1.00 per pound, reflecting an expected 10 per cent grade decline, in line with the optimised mine plan, to approximately 0.90 per cent, higher price-linked commodity input costs and an increase in usage of higher cost desalinated water. This will be partially offset by lower mining cost per tonne of material moved expected as a result of continued productivity improvements.

Performance for the year ended 30 June 2016 compared with year ended 30 June 2015

Production

Total copper production for FY2016 decreased by eight per cent to 1.6 Mt. Escondida copper production decreased by 20 per cent to 979 kt. Record cathode production and record material mined, together with the Organic Growth Project 1 reaching full capacity in the June 2016 quarter, was more than offset by an expected 28 per cent decline in grade. Pampa Norte copper production increased by one per cent to 251 kt, supported by record ore milled and higher grades at Spence. Olympic Dam copper production increased by 63 per cent to 203 kt. This reflected higher grades and improved smelter and mill utilisation after the Svedala mill outage in FY2015. Antamina copper production increased by 36 per cent to a record 146 kt due to higher grades and higher mill throughput.

Financial results

Copper revenue decreased by US$3.2 billion to US$8.2 billion, primarily due to Escondida which decreased by US$2.9 billion to US$4.9 billion.

Underlying EBITDA for FY2016 decreased by 50 per cent to US$2.6 billion. Price impacts, net of price-linked costs, decreased Underlying EBITDA by US$2.2 billion due to the decrease in average realised prices for copper from US$2.78/lb to US$2.14/lb. Anticipated grade-related volume decline decreased Underlying EBITDA by a further US$1.6 billion. This was partially offset by US$369 million increase in estimated recoverable copper contained in the sulphide leach pad following the successful completion of the Escondida Bioleach Pad Extension project, US$188 million due to the implementation of the Escondida Voluntary Retirement Program in FY2015, and productivity-led initiatives of US$243 million. A stronger US dollar against the Chilean peso and Australian dollar increased Underlying EBITDA by US$323 million.

Unit cash costs (excluding one-off items, by-product credits, freight and treatment and refining charges) at our copper operated assets increased by nine per cent to US$1.20 per pound during FY2016 due to anticipated grade decline at Escondida. In addition, Olympic Dam unit cash costs declined by 29 per cent to US$1.38 per pound as a result of productivity-led cost improvements and a further reduction in labour and contractor costs.

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1.13.3    Iron Ore

Detailed below is financial information for our Iron Ore assets for FY2017 and FY2016 and an analysis of Iron Ore’s financial performance for FY2017 compared with FY2016.

Year ended 30 June 2017 US$M	Revenue			Underlying EBITDA			D&A			Underlying EBIT			Net operating assets (5)			Capital expenditure			Exploration gross		Exploration to profit
Western Australia Iron Ore		14,395			9,001			1,873			7,128			20,040			716
Samarco (1)		–			–			–			–			(1,049	)		–
Other (2)		148			53			7			46			184			89
Total Iron Ore from Group production		14,543			9,054			1,880			7,174			19,175			805
Third party products (3)		81			23			–			23			–			–
Total Iron Ore		14,624			9,077			1,880			7,197			19,175			805			94		70
Adjustment for equity accounted investments (4)		–			–			–			–			–			–			–		–
Total Iron Ore statutory result		14,624			9,077			1,880			7,197			19,175			805			94		70
Year ended 30 June 2016 US$M	Revenue			Underlying EBITDA			D&A			Underlying EBIT			Net operating assets (5)			Capital expenditure			Exploration gross		Exploration to profit
Western Australia Iron Ore		10,333			5,492			1,855			3,637			21,641			969
Samarco (1)		442			196			46			150			(1,193	)		42
Other (2)		121			(19	)		4			(23	)		93			86
Total Iron Ore from Group production		10,896			5,669			1,905			3,764			20,541			1,097
Third party products (3)		84			(8	)		–			(8	)		–			–
Total Iron Ore		10,980			5,661			1,905			3,756			20,541			1,097			92		74
Adjustment for equity accounted investments (4)		(442	)		(62	)		(46	)		(16	)		–			(36	)		–		–
Total Iron Ore statutory result		10,538			5,599			1,859			3,740			20,541			1,061			92		74

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⁽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. Includes BHP Billiton Brasil Ltda’s share of operating profit prior to the Samarco dam failure but does not include any financial impacts following the dam failure as this has been reported as an exceptional item.

⁽²⁾ Predominantly comprises divisional activities, towage services, business development and ceased operations.

⁽³⁾ Includes inter-segment and external sales of contracted gas purchases.

⁽⁴⁾ Total Iron Ore segment Revenue excludes US$ nil (FY2016: US$442 million) revenue related to Samarco. Total Iron Ore segment Underlying EBITDA includes US$ nil (FY2016: US$46 million) D&A and US$ nil (FY2016: US$16 million) net finance costs and taxation (expense)/benefit related to Samarco that are also included in Underlying EBIT. Iron Ore segment Capital expenditure excludes US$ nil (FY2016: US$36 million) related to Samarco.

⁽⁵⁾ Refer to section 1.12.4 for a reconciliation of Net operating assets to Net assets and section 1.12.5 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 FY2017 was US$58 per wet metric tonne (wmt) (FY2016: US$44 per wmt). The iron ore price increase was driven by higher pig iron production in China and a preference for higher grade materials amid improved steel margins and high coke prices. Additional price support came from coke minimisation strategies to which steel mills resorted when metallurgical coal prices increased rapidly in late CY2016. Seaborne supply continued to increase from mainstream origins such as Australia and Brazil. A supply response was also observed from price sensitive origins, notably India. Iron ore production at private Chinese mines also recovered, incentivised by a higher price. The market is under pressure in the short term with the supply growth from both seaborne and domestic suppliers, and high iron ore inventories sitting at Chinese ports. In the medium and longer term, committed supply projects will ramp-up. Production increases from productivity and de-bottlenecking are likely to translate into a further flattening of the cost curve.

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 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. For further information on the Samarco dam failure, refer to section 1.7.

For additional information on individual asset production in FY2017, FY2016 and FY2015, refer to section 6.2.

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.

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WAIO unit cash 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. The calculation of WAIO unit costs is set out in the table below.

WAIO unit costs (US$M)	FY2017		FY2016
Revenue		14,395		10,333
Underlying EBITDA		9,001		5,492
Cash costs (gross)		5,394		4,841
Less: freight		983		764
Less: royalties		1,035		740
Cash costs (net) (1)		3,376		3,337
Sales (kt, equity share)		231,208		221,578
Cash cost per tonne (US$)		14.60		15.06

⁽¹⁾  Cash costs (net) includes exploration expense of US$0.30 per tonne (FY2016: US$0.34 per tonne).

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 7,900 square kilometres, excluding crown leases and general purpose and miscellaneous licences which are used for infrastructure space and access.

Total exploration expenditure in FY2017 amounted to US$94 million.

Guinea Iron Ore

We have a 41.3 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 is expected to increase to between 239 and 243 Mt, or between 275 and 280 Mt on a 100 per cent basis in FY2018. This reflects continued productivity improvements and improved reliability across the supply chain. Volumes are expected to be weighted to the last three quarters of the financial year, as scheduled port debottlenecking activities and lower stockpile levels, following the fire at the Mt Whaleback screening plant in June 2017, will impact the September 2017 quarter. BHP will continue to work with the relevant authorities in relation to the necessary approvals to increase system capacity to 290 Mtpa (100 per cent basis).

WAIO unit cash costs are expected to decline further to below US$14 per tonne in FY2018.

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Performance for the year ended 30 June 2016 compared with year ended 30 June 2015

Production

Total iron ore production for FY2016 decreased by two per cent to 227 Mt. Record production at Western Australia Iron Ore (WAIO) offset the suspension of operations at Samarco. WAIO production increased by two per cent to 257 Mt (100 per cent basis) as the Jimblebar mining hub operated at full capacity and utilisation at the Newman ore handling plant improved. Samarco production for FY2016 was 11 Mt (100 per cent basis).

Financial results

Total iron ore revenue decreased by US$4.2 billion to US$10.5 billion. The decrease in revenue was due to a 28 per cent decline in the average realised price of iron ore from US$61 per wet metric tonne (FOB) to US$44 per wet metric tonne (FOB).

Iron ore Underlying EBITDA decreased by US$3.0 billion to US$5.6 billion. Price impact, net of price-linked costs, reduced Underlying EBITDA by US$3.6 billion. Higher volumes and cost efficiencies increased Underlying EBITDA by US$368 million, coupled with a stronger US dollar against the Australian dollar which favourably impacted Underlying EBITDA by US$328 million.

WAIO unit cash costs (excluding freight and royalties) declined by 19 per cent to US$15 per tonne, underpinned by reductions in labour and contractor costs, increased equipment productivity, lower diesel prices and consumption and a stronger US dollar.

1.13.4    Coal

Detailed below is financial information for our Coal assets for FY2017 and FY2016 and an analysis of Coal’s financial performance for FY2017 compared with FY2016.

Year ended 30 June 2017 US$M	Revenue			Underlying EBITDA			D&A			Underlying EBIT			Net operating assets (5)			Capital expenditure			Exploration gross		Exploration to profit
Queensland Coal		6,316			3,256			605			2,651			8,202			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	)		(19	)		–
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)		(849	)		(297	)		(128	)		(169	)		–			(35	)		–		–
Total Coal statutory result		7,578			3,784			734			3,050			10,136			246			9		9

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Year ended 30 June 2016 US$M	Revenue			Underlying EBITDA			D&A			Underlying EBIT			Net operating assets (5)		Capital expenditure			Exploration gross		Exploration to profit
Queensland Coal		3,351			584			723			(139	)		8,423		246
New Mexico (1)		320			114			43			71			45		5
New South Wales Energy Coal (2)		914			133			155			(22	)		1,181		15
Colombia (2)		525			134			96			38			863		31
Other (3)		23			(88	)		95			(183	)		139		36
Total Coal from Group production		5,133			877			1,112			(235	)		10,651		333
Third party products		6			–			–			–			–		–
Total Coal		5,139			877			1,112			(235	)		10,651		333			18		18
Adjustment for equity accounted investments (4)		(621	)		(242	)		(128	)		(114	)		–		(35	)		–		–
Total Coal statutory result		4,518			635			984			(349	)		10,651		298			18		18

⁽¹⁾  Includes the Navajo mine (divested in July 2016) and San Juan mine (divested in January 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 and IndoMet Coal (divested in October 2016).

⁽⁴⁾  Total Coal segment Revenue excludes US$849 million (FY2016: US$621 million) revenue related to Newcastle Coal Infrastructure Group and Cerrejón. Total Coal segment Underlying EBITDA includes US$96 million (FY2016: US$96 million) D&A and US$116 million (FY2016: US$46 million) net finance costs and taxation (expense)/benefit related to Cerrejón, that are also included in Underlying EBIT. Total Coal segment Underlying EBITDA excludes US$32 million (FY2016: US$32 million) D&A and US$53 million (FY2016: US$68 million) total EBIT related to Newcastle Coal Infrastructure Group, that is excluded from Underlying EBIT to reconcile the consolidated business total to the statutory result. Coal segment Capital expenditure excludes US$35 million (FY2016: US$35 million) related to Newcastle Coal Infrastructure Group and Cerrejón.

⁽⁵⁾  Refer to section 1.12.4 for a reconciliation of Net operating assets to Net assets and section 1.12.5 for the definition and method of calculation of Net operating assets.

Key drivers of Coal’s financial results

Price overview

Metallurgical coal

Our average realised sales price for FY2017 was US$180 per tonne for hard coking coal (FY2016: US$83 per tonne) and US$121 per tonne for weak coking coal (FY2016: US$69 per tonne). Metallurgical coal prices increased significantly in the first half of FY2017, reaching a multi-year high in November 2016. This was driven by pronounced constraints in both domestic Chinese supply and seaborne supply, and reflected the impact of China’s 276-working day reform policy and adverse weather conditions in China and Queensland. Prices subsequently declined as supply constraints eased, before increasing significantly again in April 2017 as a result of cyclone-related supply disruptions in Queensland. Over the short term, prices are expected to trend towards marginal cost levels after seaborne supply constraints ease. However, the application of China’s coal supply reform policy remains a source of uncertainty. Over the longer term, emerging markets such as India are expected to support seaborne demand growth, while high-quality metallurgical coals will continue to offer steelmakers value-in-use benefits.

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Energy coal

Our average realised sales price for FY2017 was US$75 per tonne (FY2016: US$48 per tonne). The Global Coal Newcastle price increase was driven by strong growth in Chinese seaborne demand due to the ongoing domestic supply side reforms. This more than offset the slowdown in demand from India. In the short term, Chinese imports are likely to decline due to a rationalisation in domestic supply. In the long term, global demand for energy coal is expected to grow modestly, with Indian and South East Asian demand offsetting weakness in OECD countries.

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.

For additional information pertaining to individual asset production in FY2017, FY2016 and FY2015, refer to section 6.2.

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.

Queensland Coal unit cash 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. 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$M	FY2017		FY2016		FY2017		FY2016
Revenue		6,316		3,351		1,351		914
Underlying EBITDA		3,256		584		525		133
Cash costs (gross)		3,060		2,767		826		781
Less: freight		111		86		–		–
Less: royalties		631		316		94		61
Cash costs (net)		2,318		2,365		732		720
Sales (kt, equity share)		38,846		42,809		17,899		17,770
Cash cost per tonne (US$)		59.67		55.25		40.90		40.52

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Outlook

Metallurgical coal production is expected to increase to between 44 and 46 Mt. Energy coal production is expected to remain broadly unchanged at approximately 29 to 30 Mt in FY2018.

Queensland Coal unit cash costs are expected to be US$59 per tonne, which includes additional contractor stripping fleet costs given forecast higher strip ratios and planned debottlenecking activities. NSWEC unit cash costs are expected to increase to approximately US$46 per tonne in FY2018 as mining progresses through geological constraints, strip ratios rise and pit design initiatives are implemented to reduce costs in future periods.

Performance for the year ended 30 June 2016 compared with year ended 30 June 2015

Production

Metallurgical coal production increased by one per cent to 43 Mt in FY2016. Record metallurgical coal production at five Queensland Coal mines and first production from the Haju mine in Indonesia, offset the cessation of production at the Gregory Crinum mine and a convergence event at the Broadmeadow mine.

Energy coal production decreased by 16 per cent to 34 Mt in FY2016. Production declined following the divestment of the San Juan Mine, operational rescheduling at New South Wales Energy Coal (NSWEC) and unfavourable weather at NSWEC and Cerrejón.

Financial results

Coal revenue for FY2016 decreased by US$1.4 billion to US$4.5 billion. The decrease in revenues was due to a 21 per cent reduction in the average realised price for hard coking coal from US$105/t to US$83/t, a 22 per cent reduction in the average price received for weak coking coal from US$88/t to US$69/t and a 17 per cent reduction in the average realised price for thermal coal from US$58/t to US$48/t.

Underlying EBITDA for FY2016 decreased by US$607 million to US$635 million. Price impacts, net of price-linked costs, decreased Underlying EBITDA by US$917 million. Ceased and sold operations further decreased Underlying EBITDA by US$181 million. This was partially offset by a stronger US dollar against the Australian dollar, which increased Underlying EBITDA by US$404 million, and productivity-led cost efficiencies which increased Underlying EBITDA by US$175 million.

Queensland Coal unit cash costs (excluding freight and royalties) declined by 15 per cent to US$55 per tonne, supported by increased equipment and wash-plant utilisation, lower labour and contractor costs, lower diesel prices and a stronger US dollar. NSWEC unit cash costs decreased by two per cent to US$41 per tonne despite lower volumes.

1.13.5    Other assets

Nickel West

Key drivers of Nickel West’s financial results

Price overview

Our average realised sales price for FY2017 was US$10,184 per tonne (FY2016: US$9,264 per tonne). Nickel prices enjoyed support in the first half of FY2017, with strong stainless steel production combined with increased risks to the supply of nickel ore as the Philippine mine regulator ordered the suspension of operations at several mines and undertook an environmental audit across the mining sector. The announced resumption of exports of nickel ore from Indonesia, as well as a growing belief that the suspension orders in the Philippines would not materially impact supply from that country, saw prices weaken across the second half of the financial year. In the near term, supply of nickel from Indonesia is expected to grow, keeping a cap on prices and delaying the normalisation of stock levels.

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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. Nickel production for FY2018 is expected to remain broadly unchanged from that of FY2017.

For additional information pertaining to individual asset production in FY2017, FY2016 and FY2015, refer to section 6.2.

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.

Performance for the year ended 30 June 2016 compared with year ended 30 June 2015

Production

Nickel West production in FY2016 decreased by 10 per cent to 81 kt, reflecting planned major maintenance outages at the Kalgoorlie smelter and Kwinana refinery during the December 2015 quarter and a reduction in third party ore delivered to the Kambalda concentrator. Higher nickel matte production during the June 2016 quarter was supported by additional third party concentrate purchases. Revenue for Nickel West decreased by 41 per cent to US$819 million predominantly due to lower average realised prices.

Financial results

Underlying EBITDA for Nickel West decreased by US$152 million due to lower average realised prices which more than offset lower operating costs.

Potash

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.

Performance for the year ended 30 June 2016 compared with year ended 30 June 2015

Potash recorded an Underlying EBITDA loss of US$149 million in FY2016 compared to a loss of US$178 million in FY2015. The reduction in loss was due to a decrease in operating cash costs.

1.14    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.

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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:

• taxation;

• inventories;

• exploration and evaluation;

• development expenditure;

• overburden removal costs;

• depreciation of property, plant and equipment;

• property, plant and equipment, intangible assets and 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 1.8.3. 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 2017, is contained in note 21 ‘Financial risk management’ in section 5.1.

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 2017 is provided in note 32 ‘Commitments’ and note 33 ‘Contingent liabilities’ in section 5.1.

Subsidiary information

Information about our significant subsidiaries is included in note 28 ‘Subsidiaries’ in section 5.1 and in Exhibit 8.1 - List of Subsidiaries.

Related party transactions

Related party transactions are outlined in note 31 ‘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 34 ‘Subsequent events’ in section 5.1.

The Strategic Report is made in accordance with a resolution of the Board.

Ken MacKenzie

Chairman

Dated: 7 September 2017

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2     Governance at BHP

2.1     Governance at BHP

2.1.1     Chairman’s letter

Dear Shareholder

It is an honour and a privilege to be able to write this letter as the new Chairman of BHP. At the outset, I want to acknowledge the contribution of my predecessor, Jac Nasser, who has led the Board for the past seven years. I thank Jac for his outstanding service to the Board and BHP during his tenure. While we will miss his leadership and wise counsel, he leaves a lasting legacy at BHP, including strong corporate governance processes.

Priorities

Although I only officially became Chairman on 1 September 2017, I have used the preceding 10-week period to focus on five immediate priorities:

• conducting a ‘listening tour’ – meeting with BHP’s shareholders around the world;

• completing the orderly handover of Chairman responsibilities and engaging with management;

• bringing a fresh perspective to management’s ongoing process of reviewing the portfolio;

• working with management to further strengthen the application of the Capital Allocation Framework;

• reviewing Board composition and the skills and experience required to drive value for shareholders.

The pace of change in the world and in BHP’s markets is significant. A number of factors are contributing to this, including technological advances and greater volatility in the prices of our products. The changing environment in which we operate needs to be taken into account as the Board and management continue to work through these immediate priorities.

Meetings with shareholders

During July and August 2017, I met with over 100 shareholders as well as a number of shareholder advisory firms, from eight countries. The meetings were a valuable opportunity to hear investors’ perspectives on BHP and I plan to engage with investors on a regular basis.

Chairman handover

After almost a year on the Board, I am now familiar with BHP’s governance structures and processes. The handover from Jac to myself was therefore efficient. As part of this process, I have also been meeting regularly with Andrew Mackenzie and members of his senior management team.

Portfolio

Management reviews the Group’s portfolio of assets on an ongoing basis. This evaluation ensures that our assets continue to fit within our long-term strategy. The demerger of South32 shows our existing commitment to value over size, but one of my priorities is to bring a fresh perspective to the existing review process. In August, we announced that our Onshore US assets are no longer aligned with our long-term strategy and are therefore non-core. We are actively pursuing options to exit these assets for value.

Capital allocation

The Group has first-class assets which generate significant amounts of cash in almost all phases of the commodity cycle, and the way we allocate that cash going forward is going to be an important determinant of how much shareholder value is created. The Board strongly supports the capital allocation framework that your CEO, Andrew Mackenzie established at the beginning of 2016. It is, however, a framework, and since its inception, the Board and management team have been working together to strengthen its application.

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Board composition

We take 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. As a result, we have made a number of appointments this year to ensure that we continue to have the right balance on the Board and that the Board continues to be fit-for-purpose. This process is continuous, and we will bring additional focus to ensuring the Board evolves to take account of the rapidly changing external environment and BHP’s circumstances.

From 1 October 2017, the Board will have 11 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 1 October, the average tenure of Directors will be four years and four months. BHP has an aspiration to achieve gender balance across our workforce – and on our Board – by FY2025, and Board diversity remains a focus.

Board refreshment was 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.

On 23 August 2017, we announced the appointment of Terry Bowen and John Mogford to the Board.

Terry Bowen has over 25 years of strategic, operational and financial experience across a range of sectors. He has been the Finance Director of Wesfarmers Limited for the past eight years. (He will retire from that position towards the end of this calendar year.) During his time as Finance Director of Wesfarmers, Mr Bowen has been responsible for the disciplined allocation of capital among its 38 businesses across different industries. Mr Bowen has also had extensive experience transforming and operating businesses in the Wesfarmers structure, with a focus on improved cash flow and cost efficiency.

John Mogford has over 40 years of experience in the oil and gas sector, including 33 years at BP Plc in technical, operational and leadership roles. While at BP, John acquired deep experience across the oil and gas business, working in the areas of exploration, downstream, upstream, safety and technology. Mr Mogford also has investment and strategic experience in the energy sector, holding the roles of Managing Director and Operating Partner at First Reserve Corporation from 2009 to 2015, and as a Senior Adviser to the Head of the Oil and Gas Practice at Nomura Investment Bank from 2010 to 2013.

As part of ongoing planning for Non-executive Director succession, the Board has maintained a skills matrix for several years. We have considered the matrix in light of technological and other changes impacting our industry and the external environment more generally, and have determined that we will undertake a review of the matrix, during FY2018. We believe we have appropriate technical expertise on the Board but will look to continue to enhance this through the next period of succession.

Two Directors retired during FY2017: John Schubert and Pat Davies. Since year-end, owing to concerns expressed by some investors, Grant King decided that he will not stand for election at the 2017 AGMs, and he retired from the Board on 31 August 2017. In addition, given his involvement in ongoing legal proceedings in Italy relating to his prior employment with Shell, Malcolm Brinded has decided that he will not stand for re-election at the 2017 AGMs, and will step down on 18 October 2017. On behalf of all shareholders, I thank John, Pat, Grant and Malcolm for their valuable contributions to the Board and wish them all the best for the future.

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Samarco

The Board has continued to focus on responding to the tragedy at Samarco. In the immediate aftermath of the tragedy, the Board established a sub-committee to assist the Board in its consideration and oversight of matters relating to the failure at Samarco. As the response to the tragedy has now moved from the immediate, emergency stage to a more strategic, structured way of working, we have transitioned the work from the Samarco sub-committee back to the Board and permanent Committees of the Board, in particular the Sustainability Committee. Please see the main body of this Corporate Governance Statement for more information on the work of those committees, and section 1.7 for information on our ongoing response to the Samarco dam failure.

Looking ahead

Since my appointment to the Board in September 2016, I have visited many of our operations around the world: Western Australia Iron Ore in the Pilbara, coal operations in Queensland, the Jansen Potash Project in Canada, onshore and offshore petroleum operations in the United States, and copper assets in Chile. This has reinforced to me the quality of BHP’s assets and people, and the prospects for creating long-term value for our shareholders. I look forward to working with your Board and management, and in continued consultation with shareholders, to achieve this.

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.

BHP governance structure

The diagram below 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 Operations Management Committee (OMC), 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. While the ELT has responsibility for the day-to-day management of the Group, the OMC retains responsibility for planning, controlling and directing the activities of BHP, including key strategic, investment and operational decisions and recommendations to the Board. As such, the OMC members are classified as Key Management Personnel for remuneration reporting purposes.

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

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2.2    Board of Directors and Executive Leadership Team

2.2.1    Board of Directors

Ken MacKenzie BEng, FIEA, FAICD, 53

Chairman and Independent Non-executive Director

Director of BHP Billiton Limited and BHP Billiton Plc since September 2016.

Appointed Chairman of BHP Billiton Limited and BHP Billiton Plc with effect from 1 September 2017.

Skills and experience:

Mr MacKenzie has extensive global and executive experience, and a deeply strategic approach. From 2005 until 2015, he was the Managing Director and Chief Executive Officer of Amcor Limited, a global packaging company with operations in over 40 countries. 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).

• 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), 60

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 in oil and gas, petrochemicals and minerals. He 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 worked at Rio Tinto, where he was Chief Executive of Diamonds and Minerals, and BP, where he held a number of senior roles, including Group Vice President for Technology and Engineering, and Group Vice President for Chemicals.

Other directorships and offices (current and recent):

• Fellow of the Royal Society of London (since May 2014).

• Director of the Grattan Institute (since May 2013).

• Director of the International Council on Mining and Metals (since May 2013).

• Former Non-executive Director of Centrica plc (from September 2005 to May 2013).

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Malcolm Brinded CBE, MA, 64

Independent Non-executive Director

Director of BHP Billiton Limited and BHP Billiton Plc since April 2014.

Skills and experience:

Mr Brinded has extensive experience in energy, governance and sustainability. He served as a member of the Board of Directors of Royal Dutch Shell plc from 2002 to 2012. During his 37-year career with Shell, Mr Brinded held various leadership positions in the United Kingdom, Europe, the Middle East and Asia, including Executive Director of Exploration and Production, Executive Director of Upstream International and Chairman and Upstream Managing Director of Shell UK.

Other directorships and offices (current and recent):

• Former Director of Royal Dutch Shell plc (from July 2002 to March 2012, including as a Director of Royal Dutch Petroleum and Shell Transport and Trading Ltd prior to unification of Shell’s corporate structure).

• Former Director of Shell Petroleum N.V. (from July 2002 to March 2012).

• Director of CH2M Hill Companies, Ltd (since July 2012).

• Former Director of Network Rail Ltd; Network Rail Infrastructure Ltd (from October 2010 to July 2016).

• Chairman of the Shell Foundation (July 2009 to April 2017) and Trustee (since June 2004).

• President of The Energy Institute, UK (since July 2017 and before that, Vice President from October 2013).

• Chairman of Engineering UK (since October 2016).

Board Committee membership:

• Chairman of the Sustainability Committee.

• Member of the Remuneration Committee.

As announced on 23 August 2017, Mr Brinded has decided not to stand for re-election as a Non-executive Director at the 2017 Annual General Meetings of BHP.

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Malcolm Broomhead MBA, BE, FAICD, 65

Independent Non-executive Director

Director of BHP Billiton Limited and BHP Billiton Plc since March 2010.

Skills and experience:

Mr Broomhead has extensive experience in running industrial and mining companies with a global footprint, and broad global experience in project development in many of the countries in which BHP operates. He was Managing Director and Chief Executive Officer of Orica Limited from 2001 until September 2005. Prior to joining Orica, Mr Broomhead 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).

• 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:

• Member of the Sustainability Committee.

• Member of the Risk and Audit Committee.

Anita Frew BA (Hons), MRes, Hon. D.Sc, 60

Independent Non-executive Director

Director of BHP Billiton Limited and BHP Billiton Plc since September 2015.

Skills and experience:

Ms Frew has extensive board, strategy, marketing, governance and risk management experience in the chemicals, engineering, water and finance industries. She is the Chairman of Croda International Plc and Deputy Chairman and Senior Independent Director of Lloyds Banking Group Plc. Ms Frew 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).

• Deputy Chairman (since December 2010) 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).

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• 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 Risk and Audit Committee.

Carolyn Hewson AO, BEc (Hons), MA, FAICD, 62

Independent Non-executive Director

Director of BHP Billiton Limited and BHP Billiton Plc since March 2010.

Skills and experience:

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:

• Member of the Nomination and Governance Committee.

• Chairman of the Remuneration Committee.

Lindsay Maxsted DipBus (Gordon), FCA, FAICD, 63

Independent Non-executive Director

Director of BHP Billiton Limited and BHP Billiton Plc since March 2011.

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Skills and experience:

Mr Maxsted is 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 is the Board’s nominated ‘audit committee financial expert’ for the purposes of the US Securities and Exchange Commission Rules, and the Board is satisfied that he has recent and relevant financial experience for the purposes of the UK Financial Conduct Authority’s Disclosure and Transparency Rules and the UK Corporate Governance Code.

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.

Wayne Murdy BSc (Business Administration), CPA, 73

Independent Non-executive Director

Director of BHP Billiton Limited and BHP Billiton Plc since June 2009.

Skills and experience:

Mr Murdy has a background in finance and accounting, where he has gained comprehensive experience in the financial management of mining, oil and gas companies during his career 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. 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).

• 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.

Shriti Vadera MA, 55

Senior Independent Director, BHP Billiton Plc

Director of BHP Billiton Limited and BHP Billiton Plc since January 2011.

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Skills and experience:

Ms Vadera brings wide-ranging experience in finance, economics and public policy as well as extensive experience of emerging markets and international institutions. 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, 57

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), 60

Chief Executive Officer

(See section 2.2.1 for biography.)

Arnoud Balhuizen BBE, 48

President Marketing and Supply

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, 50

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. Mr Beaven was previously the 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.

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Geoff Healy BEc, LLB, 51

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 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), 51

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 2016, he was President, HSE, Marketing & Technology. His earlier career with BHP included a number of commercial roles covering both Minerals and Petroleum, including the role of Chief Marketing Officer.

Diane Jurgens BSEE, MSEE, MBA, 55

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.

Daniel Malchuk BEng, MBA, 51

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 the organisation, including President Aluminium, Manganese and Nickel; President of Minerals Exploration; Vice President Strategy and Development Base Metals; and has worked in four countries with BHP. He joined BHP in April 2002.

Steve Pastor BSc (Mechanical Engineering), MBA, 51

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.

Laura Tyler BSc (Geology (Hons)), MSc (Mining Engineering), 50

Chief of Staff, Head of Geoscience

Ms Tyler joined BHP in 2004 and was appointed Chief of Staff to the CEO in 2015. Previously, Ms Tyler was Asset President of the Cannington Mine, and held technical and operational roles at the EKATI Diamond Mine in Canada and corporate HSEC in London. Prior to joining BHP, Ms Tyler worked for Western Mining Corporation, Newcrest Mining and Mount Isa Mines in various technical and operational roles, and also spent five years in the civil engineering industry.

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Athalie Williams BA (Hons), FAHRI, 47

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 and the United Kingdom Shareholders Association, and in FY2017, we met with the UK Individual Shareholders Society.

We take a coordinated approach to engagement on corporate governance, and during FY2017, responded to a wide range of shareholders, their representatives and non-governmental organisations. Issues covered included Samarco, human rights, portfolio, environmental, social and governance issues, long-term value creation, culture, diversity, and executive remuneration.

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 Directors are aware of issues raised and have a good understanding of current shareholder views.

Shareholder engagement in FY2017

Topic	Led by	Purpose	FY2017 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 and the UK. Retail shareholder event, held in conjunction with the Australian Shareholders Association in May. The intention is to make this an annual event.

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Topic	Led by	Purpose	FY2017 activity
Investor ‘listening tour’	Chairman-elect	Understand shareholder perspectives on a range of strategic issues prior to assuming the role of Chairman.	Meetings held in Australia and the UK in July, with calls into Canada, Germany, Singapore, South Africa and Sweden. Meetings held in the US in August.
Strategy, governance and remuneration	Senior Independent Director Remuneration Committee Chairman	Discuss strategy, Board succession and remuneration issues.	Meetings held by the Senior Independent Director in the UK in January and March. The Remuneration Committee Chairman met investors in Australia in May/June. In addition, the Chief People Officer led meetings in Australia in July and Group Reward held meetings in the UK in May.
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, China, Japan, Malaysia, Singapore, South Africa, South Korea, Spain, Sweden, Switzerland, the UK and the US. Bondholder meetings held in London in September with investors from China, Denmark, Finland, France, Ireland, the UK and the US. Bondholder teleconferences held after the full-year and half-year results and were attended by investors in Canada, France, Netherlands, 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 HSEC roadshow in March took place in the UK, with additional meetings in Canada, mainland Europe, South Africa and the US by conference call.

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Topic	Led by	Purpose	FY2017 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, and in Scandinavia in May and the US in December. Multiple briefings on Samarco, including a site tour in June for ESG analysts to review the Samarco remediation work.
Climate Change	Head of Sustainability and Climate Change	Update investors on our strategy on climate change.	Meetings held in Australia and the UK throughout the year, and the US in December. This included the London launch of our Portfolio Analysis: Views after Paris document in October.

Understanding 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.

Questions can be registered prior to the meeting. 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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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 organisation.

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	Appointing the CEO and determining the terms of the appointment. Succession planning for direct reports to the CEO. Approving 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. Commitments, capital and non-capital items, acquisitions and divestments above specified thresholds. Dividend policy and determining dividends. Market risk management strategy and limits.
Monitoring	Performance of the CEO and the Group. Board composition processes and performance. Reviewing and monitoring systems of risk management and internal control. Establishing and assessing measurable diversity objectives.
Reporting and regulation	Determining and adopting 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. Determining and approving 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 FY2017

The Board considered a range of matters during FY2017, 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
	Funding (annual budgets, balance sheet management, liquidity management)	•       Two-year budget and annual funding plan •       Euro medium-term note program update •       Liability management •       Liquidity management •       Escondida long-term debt plan •       NCIG debt refinance

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	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 the divestment of Scarborough Project •       Approval of Mad Dog Phase 2: Definition to execution and Mad Dog 2 long-lead equipment funding •       Approval of the WAIO South Flank pre-commitment •       Shareholder activism (environment and Elliott campaign) •       Petroleum strategic review •       Macro environment strategy •       China demand review •       Approval of Samarco plan and funding •       Reviewing the Group Scenarios •       Energy sector update •       Commodity price protocols •       Dam risk review •       Approval of investment – Trion, Mexico •       Review of potential acquisitions •       Approval of capital investment – Jansen •       Copper exploration review •       Organic growth options review •       Shale investment framework
Monitoring and assurance matters	Includes matters and/or documents required by the Group’s constitutional documents, statute or by other external regulation	•       Non-operated minerals joint venture review •       Risk review •       Investor relations reports •       CEO reports •       HSEC reports •       Risk and Audit Committee report-outs •       Sustainability Committee report-outs •       Nomination and Governance Committee report-outs •       Remuneration Committee report-outs •       Samarco sub-committee report-outs

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Chairman’s matters Board composition, succession planning, performance and culture •       Chairman succession   •       Committee succession   •       Board composition and succession   •       Organisational culture   •       Inclusion and Diversity Council FY2017 targets   •       Reviewing Employee 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

2.5    Board membership

The Board currently has nine members. With the appointment of Terry Bowen and John Mogford to the Board effective 1 October 2017, the Board will have 11 members. 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 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.

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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 to ensure 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 stated aim 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 FY2017 measurable objectives and our employee profile more generally, refer to section 1.9.

2.6    Chairman

On 16 June 2017, BHP announced that the Board had elected Ken MacKenzie to succeed 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 is satisfied that Mr MacKenzie will make sufficient time available to serve BHP effectively. More details about the extensive Chairman search process are set out in section 2.13.3.

For the year under review, 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 considers that none of Mr Nasser’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 Nasser made sufficient time available to serve BHP effectively. He retired as Chairman and as a Non-executive Director on 31 August 2017.

BHP does not have a Deputy Chairman, but Shriti Vadera would act as Chairman should the need arise at short notice. Ms Vadera is the Senior Independent Director of BHP Billiton Plc (in accordance with the UK Corporate Governance Code).

2.7    Renewal and re-election

Renewal

Orderly succession is achieved as a result of careful planning, with the composition of the Board under review on an ongoing basis. This planning involves looking out over a five-year period, which provides a robust framework within which to consider Board succession and re-election. In doing this, the Board, with the assistance of the Nomination and Governance Committee:

• considers the diversity of skills, background, knowledge, experience, geographic location, nationality and gender necessary to allow it to meet the corporate purpose as compared to those qualities currently represented;

• identifies any key skills or attributes that could be enhanced on the Board and agrees the process necessary to ensure a candidate is selected who brings those skills and attributes to the Board;

• reviews how Board performance might be enhanced, at an individual Director level and for the Board as a whole.

When considering new appointments to the Board, the Nomination and Governance Committee oversees the preparation of a position specification that is provided to an independent recruitment organisation retained to conduct a global search. External search firms are instructed to consider a wide range of candidates, including taking into account the criteria and attributes set out in the Board Governance Document.

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Once a candidate is identified, the Board, with the assistance of external consultants when necessary, 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 2016 AGMs was that each Director received more than 92 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 will provide 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 considers that a diversity of skills, backgrounds, knowledge, experience, geographic location, nationalities and gender is required in order to effectively govern the business. The Board and the Nomination and Governance Committee work to ensure the Board continues to have the right balance necessary to discharge its responsibilities in accordance with the highest standards of governance.

Non-executive Directors must have a clear understanding of the Group’s overall strategy, together with knowledge about BHP and the industries in which it operates. Non-executive Directors must be sufficiently familiar with BHP’s core business to be effective contributors to the development of strategy and to monitor performance. Part of the required understanding of our strategy and the core business is the requirement to understand the risks BHP faces and the processes in place to mitigate and manage those risks. We operate in an uncertain external environment and BHP is exposed to many material risks across our operations, including some that are systemic, such as financial risks and climate change. All those risks are factored into the Board’s approach to strategy and its assessment of an optimised portfolio. The risk management governance structure is described in section 2.14.

Current Board profile

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.

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Alongside those key attributes, the skills matrix sets out the mix of skills and experience the Board considers necessary or desirable in its Directors and the extent to which they are represented on the Board and its committees.

This skills matrix is not static, and as set out in the Chairman’s letter, we intend to conduct a review of the skills matrix during FY2018 for publication in the FY2018 Annual Report. That review will take account of the skills and experience we believe the Board requires for the next period of BHP’s development, having regard to BHP’s circumstances and the changing external environment, and will also take account of best practice in this area as it has evolved. It is anticipated that following the review, updated and amended definitions will mean that fewer Directors will meet as many of the requirements as is the case with the skills matrix included on the following page.

Board skills and experience – climate change

The strategic issues facing the Board change over time. It is important that 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.

Framed 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 bear in 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.

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 other independent advisers.

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The following table sets out the current mix of skills and experience the Board considers necessary or desirable in its Directors, and the extent to which they are represented on the Board and its committees as at 1 October 2017. The table therefore includes Terry Bowen and John Mogford in the composition of the Board. Their membership of committees will be determined in due course.

Skills and experience	Board			Risk & Audit			Nomination & Governance			Remuneration			Sustainability
Total Directors		11 Directors			4 Directors			4 Directors			4 Directors			3 Directors
Executive leadership
Sustainable success in business at a very senior executive level in a successful career.		100	%		100	%		100	%		100	%		100	%
Global experience
Senior management or equivalent experience in multiple global locations, exposed to a range of political, cultural, regulatory and business environments.		91	%		75	%		100	%		100	%		100	%
Governance
Commitment to the highest standards of governance, including experience with a major organisation that is subject to rigorous governance standards, and an ability to assess the effectiveness of senior management.		100	%		100	%		100	%		100	%		100	%
Strategy/Risk
Track record of developing and implementing a successful strategy, including appropriately probing and challenging management on the delivery of agreed strategic planning objectives. Track record in developing an asset or business portfolio over the long term that remains resilient to systemic risk.		100	%		100	%		100	%		100	%		100	%
Financial acumen
Senior executive or equivalent experience in financial accounting and reporting, corporate finance and internal financial controls, including an ability to probe the adequacies of financial and risk controls.		100	%		100	%		100	%		100	%		100	%
Capital projects
Experience working in an industry with projects involving large-scale capital outlays and long-term investment horizons.		91	%		100	%		75	%		75	%		100	%
Health, safety and environment
Experience related to workplace health and safety, environmental and social responsibility, and community.		91	%		75	%		100	%		100	%		100	%

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Skills and experience	Board			Risk & Audit			Nomination & Governance			Remuneration			Sustainability
Remuneration
Board Remuneration Committee membership or management experience in relation to remuneration, including incentive programs and pensions/superannuation and the legislation and contractual framework governing remuneration.		73	%		100	%		75	%		100	%		66	%
Mining
Senior executive experience in a large mining organisation combined with an understanding of the Company’s corporate purpose to create long-term shareholder value through the discovery, acquisition, development and marketing of natural resources.		27	%		50	%		25	%		25	%		33	%
Oil and gas
Senior executive experience in the oil and gas industry, including in-depth knowledge of the Company’s strategy, markets, competitors, operational issues, technology and regulatory concerns.		36	%		25	%		0	%		50	%		33	%
Marketing
Senior executive experience in marketing and a detailed understanding of the Company’s corporate purpose to create long-term shareholder value through the discovery, acquisition, development and marketing of natural resources.		64	%		100	%		50	%		50	%		100	%
Public policy
Experience in public and regulatory policy, including how it affects corporations.		64	%		75	%		100	%		100	%		100	%

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.

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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.

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.

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 1.8.3 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 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.

Training and development in FY2017

Area	Purpose	FY2017 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.	Operating Model Technology update Petroleum strategic review
Development sessions	Specific topics of relevance.	Climate change Shareholder activism
Site visits	Briefings on the assets, operations and other relevant issues and meetings with key personnel.	Olympic Dam, Copper, Australia Nickel West, Nickel, Australia Western Australia Iron Ore, Iron Ore, Australia BMA, Metallurgical Coal, Australia Jansen Project, Potash, Canada Samarco, Iron Ore, Brazil

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Area	Purpose	FY2017 activity
		Singapore, Marketing and Supply office, Singapore Kuala Lumpur, Global Asset Services Centre, Malaysia Gulf of Mexico, Petroleum, United States Onshore US, Petroleum, United States Antamina and Spence, Copper, Chile Cerrejón, Energy Coal, Colombia
External speakers	Addresses by experts to provide insight into current geopolitical, economic or social themes.	From various external experts, the Board received insights on broad macro-economic themes and the rise of populism, insights into geopolitics with a particular focus on Chile, and insights into climate change and social policy.

2.10    Independence

The Board is committed to ensuring a majority of Directors is independent. The Board considers 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.

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Tenure

As at the end of the year under review, only Jac Nasser had served on the Board for more than nine years. As announced on 16 June 2017, Mr Nasser retired from the role of Chairman and as a Non-executive Director on 31 August 2017. This means that as at 1 September 2017, the average tenure of the Board, including Andrew Mackenzie, was five years and two months, showing the process of renewal that takes place as part of our ongoing succession planning process. With the appointment of Terry Bowen and John Mogford to the Board, the average tenure of the Board as at 1 October will be four years and four months. For further information, refer to section 2.13.3.

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.

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 FY2017 that amounted to related party transactions with Directors or Director-related entities under International Financial Reporting Standards (IFRS) are outlined in note 31 ‘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.

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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.

2.11    Board evaluation

The Board is committed to transparency in determining Board membership and 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, and how the Board works together as a unit.

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;

• 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 FY2017

During FY2017, the Board commenced an internal assessment of the Board committees and an internal assessment of the individual directors. 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. All of these assessments were completed in early FY2018 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 answer a common set of questions on the work, process and overall effectiveness of the relevant committee. In addition, following consultation with the respective committee Chairmen, additional specific, targeted, questions were developed for each committee. These targeted questions reflected the committee’s key areas of focus. Executive management and Directors who regularly attend committee meetings, despite not being members of the committee, also contributed to the evaluation of the relevant committee.

As part of the assessment, the Board considered its compliance with the Board Governance Document and the committees considered their compliance with their terms of reference.

The outcomes of the assessment for each committee are set out in the relevant section below.

Director review

We streamlined the content of the individual Director assessments in FY2017, with a focus 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 Senior Independent Director was also sought.

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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.

Board evaluation in action

A number of improvements were agreed and implemented following the FY2016 Board evaluation. These included refining the approach to Board strategy discussions and improvements to culture, training and development and Board composition.

Two particular actions agreed in the FY2016 Board evaluation that have been implemented are to provide greater opportunity to attend site visits (and to make those visits more focused), and to better tailor induction programs to the particular skills and experience of the Director.

The range of site visits that took place can be seen in section 2.9 Director induction, training and development. Not all Directors attended each site visit, but there was particular emphasis on the attendance of members of the Sustainability Committee.

Part of the site visit schedule related to the individual induction requirements of the new Directors. Ken MacKenzie visited Western Australian Iron Ore, Blackwater, Spence, Onshore US, Gulf of Mexico and Jansen. Grant King visited Onshore US, Gulf of Mexico, Spence and Western Australia Iron Ore. Alongside the standard induction manual and various governance documents, the induction program includes a tailored selection of specific Board papers and minutes for Board and Committees for the prior 12 to 18 months. In addition, specific meetings and briefings were held for the new Directors, those briefings being conducted by a range of stakeholders, including the Chairman, Committee Chairmen, CEO and other ELT members, members of Group Governance and senior management.

2.12    Board meetings and attendance

The Board meets as often as necessary 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 seven of those meetings held in Australia, three in the United Kingdom and one in Chile. 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.

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Attendance at Board and standing Board committee meetings during FY2017 is set out in the table below.

Board and standing Board committee attendance in FY2017

	Board					Risk and Audit					Nomination and Governance				Remuneration				Sustainability				Tenure as at 30 June 2017
	A		B			A		B			A		B		A		B		A		B
Malcolm Brinded		11		11												5		5		4		4	3 years 2 months
Malcolm Broomhead		11		11			12		12											4		4	7 years 3 months
Pat Davies		8		7	(1)											4		4		3		3	Retired on 6 April 2017
Anita Frew		11		11			12		11	(2)													1 year 10 months
Carolyn Hewson		11		11								8		8		5		5					7 years 3 months
Grant King		4		4																			3 months
Andrew Mackenzie		11		11																			4 years 3 months
Ken MacKenzie		8		8																3		3	10 months
Lindsay Maxsted		11		11			12		12														6 years 3 months
Wayne Murdy		11		11			12		12							1		1					8 years
Jac Nasser		11		11								10		10									11 years
John Schubert		5		5								3		3						2		2	Retired on 17 November 2016
Shriti Vadera		11		11								10		10		5		5					6 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.

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.

⁽¹⁾ Mr Davies was unable to attend the meeting on 21 February due to a conflicting engagement.

⁽²⁾  Ms Frew was unable to attend the meeting on 19 January 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.

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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 1.5.2, 1.8.3 and 2.14.

The RAC met 12 times during FY2017. 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.

In addition to the regular business of the year, the Committee discussed matters, including management’s assessment of the appropriateness of the prior period carrying values of the Group’s Onshore US assets, the internal control environment in particular in the context of the Onshore US matter, Economic Contribution Report, whistle-blower best practice, Samarco debt update, external audit tender, and cyber security and other technology risks. Further information is set out in the diagram that follows. The viability statement and the Board’s confirmation that it has carried out a robust risk assessment are at section 1.8.3. Statements relating to tendering of the external audit contract, significant matters relating to the Financial Statements and the process for evaluating the external audit follow. 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 1.7.

Risk and Audit Committee members during the year

Name	Independent	Status	Attendance
Lindsay Maxsted (Chairman) (1)	Yes	Member for whole period	12/12
Malcolm Broomhead	Yes	Member for whole period	12/12
Anita Frew	Yes	Member for whole period	11/12 (2)
Wayne Murdy	Yes	Member for whole period	12/12

⁽¹⁾ Mr Maxsted is the Committee’s financial expert nominated by the Board.

⁽²⁾  Ms Frew was unable to attend the meeting on 19 January due to ill health.

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Committee activities in FY2017

Integrity of Financial Statements and funding matters	External auditor and integrity of the audit process
•       Accounting matters for consideration, materiality limits, half-year and full-year results •       SOX compliance, reserves and resources •       Liquidity buffer, target cash forecasts •       Capital allocation framework	•       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
Effectiveness of systems of internal control	Other governance matters
•       Regular reports on progress against the internal audit plan •       Matters of note arising from internal audits •       Internal and external assessments of performance of the internal audit function •       Group risk profile; insurance; fraud and misappropriation •       Risk management and internal control review •       Onshore US prior period impairment assessment matter	•       Induction, training and development program •       Board committee procedures, including closed sessions •       Performance and leadership of the internal audit function

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 regularly 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.

Significant operational and risk matters raised at Business RAC meetings are reported to the RAC by the Group Financial Controller and the Group Assurance Officer.

Activities undertaken by RAC during FY2017

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. They are required to provide the information necessary for shareholders to assess BHP’s position, performance, business model and strategy.

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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:

• 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’;

• 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;

• 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;

• the Annual Report suite sub-certification incorporates a fair, balanced and understandable declaration;

• 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 2017 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 FY2017 full-year and the half-year, the CEO and CFO have certified that BHP’s financial records have been properly maintained and that the FY2017 Financial Statements present a true and fair view, in all material respects, of our financial condition and operating results and are in accordance with applicable regulatory requirements.

Onshore US – prior period impairment assessment matter

During the period, management identified an issue with the Onshore US impairment assessments conducted for FY2015 and the first half of FY2016. This arose from a failure to distinguish between BHP specific assumptions and market participant assumptions, including the application of deferred income taxes, in determining impairments of certain Onshore US assets. As a result, a review was conducted that confirmed the issue was confined to the valuation of the Onshore US assets and did not require any change to the carrying values of BHP’s Onshore US assets at 31 December 2016 or any prior period. Accordingly, the misinterpretation did not result in a material prior period error and restatement of the financial statements for the relevant periods was neither required nor appropriate.

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Although there was no material prior period error, a review of the Group’s internal control over financial reporting was conducted. In accordance with the reporting requirements under the US Securities Exchange Act of 1934 (as amended), the outcome of the review of internal control over financial reporting was that BHP filed an amendment to BHP’s 2016 US Annual Report on Form 20-F (2016 Form 20-F/A). The 2016 Form 20-F/A restates BHP’s 2016 report on internal controls over financial reporting as management concluded the controls over the determination of which deferred income tax balances to include in the carrying values of the Onshore US assets and market participant assumptions used to measure fair value less costs of disposal were ineffective for impairment assessment purposes as at 30 June 2016 and 30 June 2015.

The control issue that was identified was confined to the valuation of the Onshore US assets and the 2016 Form 20-F/A was required to update the statements from management and the auditor to reflect the identified issue with the internal controls. A remediation plan was implemented during the period and the controls are operating effectively and remediated as at 30 June 2017. Further information is set out under the significant issues section below.

Significant issues

In addition to the Group’s key judgements and estimates disclosed throughout the FY2017 Financial Statements, the Committee also considered the following significant issues:

Onshore US – prior period impairment assessment matter

During the year, deficiencies were identified in our internal controls over financial reporting in relation to the controls and processes that were used to determine the impairments of certain Onshore US assets for the years ended 30 June 2016 and 30 June 2015. The Committee:

• examined management’s assessment that, notwithstanding the control deficiencies, the prior period carrying values of the Group’s Onshore US assets continue to be appropriate and concurred that a restatement of any of the Group’s consolidated financial statements was neither required nor appropriate;

• considered management’s assessment of the severity of the identified control deficiencies and concurred with management’s conclusion that they represented a material weakness in internal control over financial reporting at 30 June 2016 and 30 June 2015.

Carrying value of long-term assets

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, including the annual impairment assessment for goodwill. Specific consideration was given to the most recent short-, medium- and long-term prices, 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 that no impairments or impairment reversals were appropriate.

Conclusions from these reviews are reflected in note 12 ‘Impairment of non-current assets’ 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.

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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 and stabilisation works.

BHP Billiton Brasil has recognised a share of additional losses recorded by Samarco during the year ended 30 June 2017.

Potential direct financial impacts to BHP Billiton Brasil

The Committee considered:

• the accounting implications of funding provided to 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 stabilisation works and the impact of developments in existing and new legal proceedings on 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:

• tax risks (including transfer pricing risks) arising from the Group’s cross-border operations and transactions;

• changes in the foreign tax law, including concessional tax rate available on intra-group dividends paid by the Group’s Chilean entities;

• 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 note 5 ‘Income tax expense’ and note 33 ‘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 reviewed the findings of a global review of the closure cost and valuation process undertaken during the year and the associated updates to the governance framework developed to manage closure risk.

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 14 ‘Closure and rehabilitation provisions’ in section 5.

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Regulator engagement in FY2017

During FY2017, the Group received letters from the UK Financial Reporting Council’s Corporate Reporting Review team (CRRT) and the US Securities and Exchange Commission (SEC). The letters sought clarification of certain significant judgements and estimates and related disclosures in the Group’s 2016 Annual Report, including the impairment charges recognised on the Onshore US assets and, in the case of the CRRT, also on the disclosures relating to closure and rehabilitation provisions.

The RAC examined the responses from management to the CRRT and the SEC, and discussed the matters with the External Auditor. Senior management and the Chairman of the RAC met with the CRRT to discuss the circumstances surrounding the Onshore US prior period impairment matter. At the meeting, discussions focused on the analysis conducted by management, the material weakness identified and the RAC’s and the Board’s examination of the matter.

The Group has expanded its disclosures in relation to these matters. The RAC is satisfied that the Group’s 2017 Annual Report disclosures reflect the observations of the reviews conducted by the CRRT⁽¹⁾ and the SEC. The CRRT and the SEC have notified the Group that their respective reviews in relation to these matters are complete.

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. A new UK audit engagement partner was appointed for the FY2013 year-end and therefore FY2017 was scheduled to be his last year as lead audit engagement partner. There has been a transition period to the new engagement partner who took formal responsibility at the start of FY2018.

Audit tender

The previous audit tender was in 2002, at which time BHP had three External Auditors following the implementation of the DLC structure. The tender resulted in KPMG and PricewaterhouseCoopers being appointed as joint auditors for FY2003. A competitive audit review was undertaken in 2003, which resulted in KPMG being appointed as the External Auditor by the Board on the recommendation of the RAC.

Consistent with the UK and EU requirements in regard to audit firm tender and rotation, during the March quarter of FY2017 the Committee commenced a tender process for the appointment of a new External Auditor, as described in the Operational Review for the nine months ended 31 March 2017. In August 2017, the Board announced that it had selected EY, with the planned commencement date of 1 July 2019.

⁽¹⁾  The CRRT’s review was based on the Group’s 2016 Annual Report and did not benefit from detailed knowledge of the Group’s business or the transactions entered into. The closure of the CRRT’s enquiries provides no assurance that the Group’s 2016 Annual Report is correct in all material respects, as the role of the Financial Reporting Council (FRC) is not to verify information but to consider compliance with reporting requirements. The FRC accepts no liability for reliance on its closure letter from the Group or any third party, including but not limited to investors and shareholders.

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Governance

The RAC was responsible for the tender process and took the key decisions, concerning tender timing, approach, evaluation criteria, proposal evaluation and recommendation. A Tender Committee was appointed by the RAC to oversee the tender process, and was chaired by the Chairman of the RAC and also included Peter Beaven, Chief Financial Officer; Arnoud Balhuizen, President, Marketing and Supply; and Graham Tiver, Group Financial Controller. The Tender Committee managed the process day-to-day and reported to the RAC. In addition, senior management responsible for activities of direct relevance to the Group’s External Audit were consulted during the process and participated in firm-led interviews with each tendering firm, and had the opportunity to ask questions, complete a feedback form and review certain aspects of the firms’ written tender submissions.

Evaluation framework

BHP’s requirements of the new External Auditor and applicable evaluation criteria were set out in the Request for Proposal (RFP) that was issued to firms. BHP’s requirements of the new External Auditor and applicable evaluation criteria (including that the firm has the global capability and experience to audit a corporation the size of BHP) were set out in the Request for Proposal (RFP) that was issued to firms. Based on the applicable evaluation criteria, BHP issued the RFP to three Tier One audit firms. KPMG, BHP’s existing Auditor, did not participate due to the EU regulations and the UK Competition and Markets Authority rules, which require a new External Auditor to be in place by 1 July 2023 to conduct the FY2024 audit.

The evaluation framework comprised three key areas: Quality and Capability, Cultural Fit and Relationship, and Terms of Engagement, of which, Quality and Capability was paramount. The evaluation framework was applied consistently throughout all stages of the tender process. Mandatory requirements regarding independence, the review of existing non-audit services work for BHP, insurance, anti-corruption and security were applied, reference checks were performed, and findings in reports published by competent authorities were examined.

Feedback was collected on the firms’ proposals at the completion of each tender activity, including interviews with management, submissions of written proposals, presentations to the RAC, and workshops to agree scope and terms. The quantitative and qualitative feedback was provided to the Tender Committee and the RAC. Each of the three key areas of the evaluation framework was assessed separately.

Evaluation

The RAC was then asked to evaluate each firm and feedback was incorporated into the overall evaluation. Following completion, the RAC provided the Board with a recommendation. After considering the RAC’s recommendation, on 22 August 2017, we announced that the Board had selected EY as BHP’s External Auditor for FY2020 subject to the approval of shareholders at the 2019 AGM. The planned commencement date is 1 July 2019, which provides adequate time for EY to meet all relevant independence criteria before commencement of the appointment.

Compliance with the Competition and Markets Authority Order

BHP confirms that during FY2017 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.

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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;

• 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;

• 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.

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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.

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 above 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 2017.

In addition, the RAC approved no services during the year ended 30 June 2017 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 FY2017 for audit and other services were US$16.5 million, of which 63 per cent comprised audit fees, 33 per cent related to legislative requirements (including US Sarbanes-Oxley of 2002) as amended (SOX) and four per cent was for other services. Details of the fees paid are set out in note 36 ‘Auditors’ 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.

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Internal Audit

The Internal Audit function is carried out by Group Risk Assessment and Assurance (RAA). The role of RAA is to provide assurance as to whether risk management, control and governance processes are adequate and functioning. The Internal Audit function is independent of the External Auditor. The RAC reviews the terms of reference of RAA, 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 role of the Group Assurance Officer includes achievement of the internal audit objectives, risk management policies and insurance strategy. The position was held until 18 April 2017 by Alistair Mytton when Kirsty Wallace assumed the role of Group Assurance Officer. Alistair Mytton reported directly to the RAC, and Kirsty Wallace continues to do so as at the date of this report. During the period, functional oversight of RAA was provided by the Chief External Affairs Officer.

Effectiveness of systems of internal control and risk management

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 business and operational risks and controlling their financial impact on BHP and the operational effectiveness of the policies and procedures related to risk and control;

• budgeting and forecasting systems, financial reporting systems and controls;

• policies and practices put in place by the CEO for detecting, reporting and preventing fraud and serious breaches of business conduct and whistle-blowing procedures;

• procedures for ensuring compliance with relevant regulatory and legal requirements;

• arrangements for protecting intellectual property 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.

For more information on our approach to risk management, refer to sections 1.5.2 and 2.14. Section 1.8.3 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 1.8.4 also provides an explanation of how those risks are managed.

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During FY2017, benchmarking of the design of BHP’s Risk Management Framework to industry best practices and standards found that the Framework meets its legal and governance requirements in all relevant jurisdictions. 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 reviews covered financial, operational and compliance controls and risk assessment. During FY2017, 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 that the effectiveness of the internal controls has been properly reviewed. Further information is set out above in relation to the Onshore US prior period impairment assessment matter.

Management’s assessment of our 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 2017. There were no material weaknesses in BHP’s internal controls over financial reporting identified by management as at 30 June 2017.

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 this Annual Report on Form 20-F as filed with the SEC.

There have been no changes in our internal control over financial reporting during FY2017, other than the remediation of the previously reported material weakness referred to below, 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.

During FY2017, the RAC reviewed our compliance with the obligations imposed by SOX, including evaluating and documenting internal controls as required by section 404 of SOX.

Remediation of previously reported material weakness

As previously reported in our amended 2016 US Annual Report on Form 20-F (2016 Form 20-F/A), management concluded that while isolated to the Onshore US assets, there was a material weakness in our internal control over financial reporting and disclosure controls and procedures. The material weakness arose due to a lack of understanding, by both the process owner and control operator, of how to distinguish between assumptions specific to BHP and those of a market participant, including the application of deferred income taxes, in determining impairment of the Onshore US assets. A remediation plan was implemented and as at 30 June 2017, the Group had completed the documentation and testing of the effectiveness of the remediation actions taken, and management concluded that the previously reported material weakness was remediated.

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Management’s assessment of our 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 2017. 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 foregoing, management, including the CEO and CFO, has concluded that as at 30 June 2017, 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

An internal assessment was conducted with the assistance of an external service provider, Lintstock, during FY2017. The targeted questions focused on overall effectiveness, composition, training, testing management in key areas of responsibility and testing the work of the External Auditor. Key areas of focus for FY2018 include streamlining agenda items and providing additional background and context to certain matters as relevant during the year. In addition, the RAC was satisfied that it had continued to meet its terms of reference in FY2017.

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 members of the OMC, 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 the OMC;

• 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.

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 OMC scorecards and in assessing performance against those measures.

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The Remuneration Committee met five times during FY2017. 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	lndependent	Status	Attendance
Carolyn Hewson (Chairman)	Yes	Member for whole period	5/5
Malcolm Brinded	Yes	Member for whole period	5/5
Pat Davies	Yes	Member until 6 April 2017	4/4
Wayne Murdy	Yes	Member from 6 April 2017	1/1
Shriti Vadera	Yes	Member for whole period	5/5
Committee activities in FY2017
Remuneration policy review		Remuneration of the OMC and the Board
•       Link to strategy; alignment between pay and performance •       Changes to components of the policy •       Level of reward and performance measures		•       Remuneration of CEO and other OMC members •       KPIs; performance levels; award outcomes •       Chairman and Non-executive Director fees
Other remuneration matters		Other governance matters
•       Shareplus; employee incentive outcomes •       Remuneration by gender •       Shareholder consultation		•       Induction, training and development program •       Board committee procedures, including closed sessions

Committee assessment

An internal assessment was conducted with the assistance of an external service provider, Lintstock, during FY2017. The targeted questions focused on quality of information, management engagement, training and development and setting of policy. Key areas of focus for FY2018 include prioritising issues for the Committee, more regular briefings about the external environment and deeper focus on trends. In addition, the Remuneration Committee was satisfied that it had continued to meet its terms of reference in FY2017.

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 the skills, experience, independence and knowledge required on the Board, as well as the attributes required of potential Directors;

• the identification of suitable candidates for appointment to the Board, taking into account the skills, experience and diversity required on the Board and the attributes required of 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 process the Board adopts for its own succession, with the assistance of the Nomination and Governance Committee, refer to section 2.8.

The Nomination and Governance Committee met 10 times during FY2017. Information on meeting attendance by Committee members is included in the next table. In addition to the regular business of the year, the Committee considered the appointments of Ken MacKenzie, Grant King, Terry Bowen and John Mogford as Non-executive Directors, and the appointment of the new Chairman. After year end, the Committee also considered the retirements of Grant King and Malcolm Brinded as set out in more detail below.

Chairman succession

A major part of the Committee’s work in FY2017 was devoted to the Chairman succession process. This process was led by Shriti Vadera, Senior Independent Director, on behalf of the Board. Ms Vadera chaired the Board and the Committee when the Chairman succession process and matters were being discussed.

Jac Nasser announced at the 2016 Plc AGM that he would not seek re-election at the 2017 AGMs. As noted at the time, Mr Nasser held the position longer than he had originally intended, but the Board believed it was important for Mr Nasser to continue on as Chairman to provide stability as BHP responded to Samarco. With the Samarco response framework now in place, the cause report findings having been published and the compensation and remediation programs underway, Mr Nasser decided to announce that he would be retiring, and the formal chairman succession process was instigated.

In framing the succession process, our starting point was the governance considerations of the UK Corporate Governance Code, the ASX Corporate Governance Principles and Recommendations and governance standards in the United States. This was designed to ensure the process reflected best practice and the importance which BHP places on good governance.

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At the outset of the formal process, a set of principles to underpin the succession process was developed and agreed by the Board, as well as a role profile for the new Chairman. The overarching principle governing the process was that the process was owned by the Board, which made all decisions in relation to Chairman succession. Any discussions that were related to the substantive elements of the choice (for example, requirements, priorities, individuals) were discussed and approved at the Board rather than the Nomination and Governance Committee.

The Nomination and Governance Committee, on behalf of the Board, engaged Heidrick & Struggles as advisers to assist with the process. Heidrick & Struggles undertook the following:

• meetings with each member of the Board to understand their perspectives on the Chairman role, in addition to presenting to the Board on a number of occasions;

• a full external search and benchmarking of internal candidates against the brief in the same way as any external candidates;

• preparation of in-depth reports on short-listed candidates following detailed interviews and external referencing.

The selection of the new Chairman was by formal secret ballot conducted by an independent external lawyer as returning officer in accordance with voting procedures approved by the Board.

The Board interviewed each of the candidates and, in the absence of the CEO and the Chairman, met the chosen candidate after the vote and before confirmation to ensure their expectations of the new Chairman were made clear.

Board changes

In addition to the appointment of Ken MacKenzie as a Non-executive Director, and as the new Chairman, the Committee also considered the appointments of Terry Bowen, John Mogford and Grant King.

Mr Bowen has over 25 years of strategic, operational and financial experience across a range of sectors. He has been the Finance Director of Wesfarmers Limited for the past eight years. (He will retire from that position towards the end of this calendar year.) During his time as Finance Director of Wesfarmers, Mr Bowen has been responsible for the disciplined allocation of capital among its 38 businesses across different industries. Mr Bowen has also had extensive experience transforming and operating businesses in the Wesfarmers structure, with a focus on improved cash flow and cost efficiency. He will join the Board on 1 October 2017.

Mr Mogford has over 40 years of experience in the oil and gas sector, including 33 years at BP Plc in technical, operational and leadership roles. While at BP, Mr Mogford acquired deep experience across the oil and gas business, working in the areas of exploration, downstream, upstream, safety and technology. Mr Mogford also has investment and strategic experience in the energy sector, holding the roles of Managing Director and Operating Partner at First Reserve Corporation from 2009 to 2015, and as a Senior Adviser to the Head of the Oil and Gas Practice at Nomura Investment Bank from 2010 to 2013. He will also join the Board on 1 October 2017.

Mr King joined the Board on 1 March 2017 as an independent Non-executive Director. From 2000 until 2016, he served as Managing Director and Chief Executive of Origin Energy, a leading Australian energy retailer with diverse operations spanning the energy supply chain. Mr King is the President of the Business Council of Australia. He has extensive executive experience leading a company that has operated in a volatile and changing global environment, as well as broad oil and gas industry experience.

Owing to concerns expressed by some investors, Mr King decided that he would not stand for election at the 2017 Annual General Meetings of BHP, and he retired from the Board on 31 August 2017.

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On 23 August 2017, we announced that, given his involvement in ongoing legal proceedings in Italy relating to his prior employment with Shell, Malcolm Brinded has decided not to stand for re-election as a Non-executive Director at the 2017 Annual General Meetings of BHP. His final day on the Board of BHP will be 18 October 2017.

John Schubert retired from the Board with effect from 17 November 2016, and Pat Davies retired with effect from 6 April 2017.

Board policy on inclusion and diversity

Our Charter and Our Requirements for Human Resources standard guide management on all aspects of human resource management, including inclusion and diversity. Underpinning 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 to ensure the Board oversees BHP effectively for shareholders.

For the past four years, two executive search firms, JCA Group and Heidrick & Struggles, have produced all-women short lists focused on the United Kingdom, Europe, Australia and the United States. These lists are continually refreshed. The two lists – combined with our skills and experience profile five-year matrix – ensure we maximise the number of female candidates with whom we engage and consider for appointment. Short-listed candidates are considered by the Nomination and Governance Committee. During FY2017, the Chairman met with several potential female candidates from a range of backgrounds.

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 aspiration 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 FY2017 measurable objectives and our employee profile more generally, refer to sections 1.9.2 and 1.9.4.

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
Jac Nasser (Chairman)	Chairman of the Board	Member for whole period	10/10
Carolyn Hewson	Yes	Member from 18 October 2016	8/8
John Schubert	Yes	Member until 17 November 2016	3/3
Shriti Vadera	Yes	Member for whole period	10/10

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Committee activities in FY2017

Chairman succession	Succession planning processes
•       Framing of the succession process •       Appointment of the independent adviser •       Discussion and deliberation in relation to the internal and external candidates	•       Skills and experience matrix •       Identification of suitable Non-executive Director candidates •       Committee composition •       Board and committee succession
Corporate governance practices	Evaluation and Training
•       Independence of Non-executive Directors •       Authorisation of situations of actual or potential conflict •       Corporate Governance Statement	•       Board and Director performance evaluation •       Provision of appropriate training and development opportunities •       Induction
Other governance matters
•       Induction, training and development program •       Board committee procedures, including closed sessions

Committee assessment

An internal assessment was conducted with the assistance of an external service provider, Lintstock, during FY2017. The targeted questions focused on use of the Committee’s time, levels of engagement, overall effectiveness, training and support. Key areas of focus for FY2018 include 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. In addition, the Nomination and Governance Committee was satisfied that it had continued to meet its terms of reference in FY2017.

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);

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• 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 2017.

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 emphasis in setting those targets is on fact-based measurement and quality data and a desire to move BHP to a position of industry leadership.

The Sustainability Committee met four times during FY2017. 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 societal trust in corporations, tax and transparency, climate change and Indigenous Peoples.

Members of the Sustainability Committee also visited a number of operated and non-operated sites during FY2017, including Olympic Dam, Nickel West, Samarco, Gulf of Mexico, Onshore US, Antamina and Cerrejón. During these site visits, Committee members received briefings on relevant HSEC matters and the management of material HSEC risks, and met with key personnel.

The Sustainability Committee continued to assist the Board in its oversight of HSEC issues and performance during FY2017. For a summary of the main areas discussed, refer to the diagram that follows.

Sustainability Committee members during the year

Name	lndependent	Status	Attendance
John Schubert (Chairman) (1)	Yes	Member until 17 November 2016	2/2
Malcolm Brinded (Chairman) (2)	Yes	Member for whole period	4/4
Malcolm Broomhead	Yes	Member for whole period	4/4
Pat Davies	Yes	Member until 6 April 2017	3/3
Ken MacKenzie	Yes	Member from 22 September 2016	3/3

⁽¹⁾  John Schubert was Chairman of the Committee until 21 September 2016.

⁽²⁾  Malcolm Brinded took over the role of Chairman with effect from 22 September 2016.

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Committee activities in FY2017

Assurance and adequacy of HSEC framework and HSEC management system	Compliance and reporting
•       Key HSEC risks, including aviation management, the dam risk review and fatality risk management, BHP’s mental health framework, HSE capability, and HSE assurance processes •       Audit planning and reporting in relation to HSEC risks and processes	•       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
Performance	Other governance matters
•       Performance of BHP in relation to HSEC matters, including the Community sub-function of the External Affairs function •       Considering proposed HSEC KPIs for OMC scorecard and considering performance against such KPIs •       Monitoring performance against the HSEC performance targets •       Approved the FY2018-FY2022 HSEC performance targets •       Reports on HSEC performance •       Updates on Samarco remediation and Fundação Renova •       Incident and near miss investigation outcomes •       Performance and key issues on sustainable development and community relations, including Indigenous Peoples Strategy update •       Climate change updates	•       Induction, training and development •       HSEC benchmarking and emerging trends •       Site visits and site visit reports •       Board committee procedures, including closed sessions

Sustainable development governance

Our approach to HSEC and sustainable development governance is characterised by:

• 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;

• management having primary responsibility for the design and implementation of an effective HSEC Management System;

• management having accountability for HSEC performance;

• the HSE function and Community sub-function providing advice and guidance directly to the Sustainability Committee and the Board;

• the Board, Sustainability Committee and management seeking input and insight from external experts, such as the BHP Billiton Forum on Corporate Responsibility;

• clear links between executive remuneration and HSEC performance.

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The key areas of focus for the Committee, management and the HSE function and Community sub-function are outlined on pages 6 and 7 of the Sustainability Report.

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 FY2017 included receiving updates on BHP’s climate change strategic priorities, updates on BHP’s Low Emissions Technology initiatives, and an update on carbon capture and storage technology. In addition, in October 2016, BHP published the Climate Change: Portfolio Analysis Views after Paris document, which described some of our observations from the past 12 months and their potential portfolio impacts. For more information on our climate change position and how we consider the impacts on our portfolio, refer to section 1.10.6.

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 one per cent of our pre-tax profit, calculated on the average of the previous three years’ pre-tax profit. During FY2017, our voluntary social investment totalled US$80.1 million, comprising US$75.1 million of cash towards community development programs and administrative costs and a US$5 million contribution to the US-based charity, 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 OMC members was based on HSEC performance during FY2017. The Sustainability Committee assists the Remuneration Committee in determining appropriate HSEC metrics to be included in the OMC 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

An internal assessment was conducted with the assistance of an external service provider, Lintstock, during FY2017. The targeted questions focused on Committee composition, process and overall effectiveness and the Committee’s key areas of focus. The assessment indicated that the Committee is operating effectively and is receiving high-quality information. Key areas of focus for FY2018 include background briefings in advance of deep dives and further enhancements to the Director induction and training programs. In addition, the Sustainability Committee was satisfied that it had continued to meet its terms of reference in FY2017.

The terms of reference for the Sustainability Committee are available online at bhp.com/governance.

2.13.5    Samarco sub-committee

On 17 November 2015, following the tragedy at Samarco Mineração S.A., a sub-committee of the Board was established to assist the Board with its consideration and oversight of matters relating to the failure at Samarco. During the period, the Samarco Sub-committee comprised John Schubert (Chairman), Jac Nasser, Lindsay Maxsted and Malcolm Brinded. Malcolm Brinded was appointed Chairman of the Committee with effect from 22 September 2016, and John Schubert remained a member until he retired on 17 November 2016. Specific matters considered by the Committee included BHP’s support of the recovery and response effort by Samarco, investigation of the cause of the dam failure and our engagement with key stakeholders.

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The Sub-committee met four times during FY2017 and also considered certain items out of session. Following a review, it was determined that with effect from 1 January 2017, the work that had been delegated to the Samarco Sub-committee should revert to the Board and formal committees of the Board, in particular the Sustainability Committee.

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 1.5.2.

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.

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 1.5 and 1.8, and includes a broad range of scenarios to assess our portfolio. This process allows us to be able to continually adjust the shape of our portfolio to match energy and commodity demand and meet society’s expectations, while maximising shareholder returns.

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.

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The diagram below outlines the risk reporting process.

Management has put in place a number of key policies, processes, performance requirements and independent 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.

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 Committee (IC) 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 IC 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 OMC, 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.

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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 FY2017. 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    Business conduct

Our Charter and our Code of Business Conduct

Our Charter is central to our business. It articulates the values we uphold, our strategy and how we measure success.

Our BHP Code of Business Conduct (Code) is based on Our Charter values and describes the behaviours that we expect of those who work for or on behalf of BHP. The Code applies to employees, directors, officers and controlled entities. Consultants and contractors are also expected to act in accordance with the Code when working for BHP.

The Code describes the behaviours expected to support a safe, respectful and legally compliant working environment, when interacting with governments and the communities in which we operate, when dealing with third parties and when using BHP resources.

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 employees are required to undertake annual training in relation to the Code to promote awareness and understanding in the behaviours expected of them. Demonstration of the values described in Our Charter and the Code is part of the annual employee performance review process.

Our Code of Business Conduct is available online at bhp.com/ourcode.

EthicsPoint, BHP’s business conduct advisory service

Where an employee or third party has a concern regarding behaviour that may not be consistent with the Code, there are reporting options available which include BHP’s business conduct advisory service, EthicsPoint. EthicsPoint is a worldwide service available to internal and external stakeholders that facilitates the raising, management and resolution of business conduct questions and concerns via a confidential 24-hour, multilingual hotline and online case management system. Reports can be made anonymously and without fear of retaliation. Arrangements are in place to investigate all matters appropriately. Levels of activity and support processes for EthicsPoint are monitored, with activity reports presented to the Board. More information on EthicsPoint can be found in the Code, available online at bhp.com.

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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 a market disclosure and communications document, 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 we are 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 members of the OMC, 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 members of the OMC 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 ourselves, 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:

• 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 7 September 2017 and signed on its behalf by:

Ken MacKenzie

Chairman

7 September 2017

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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 dual listed 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, as explained below.

The UK requirements focus on the remuneration of executive and non-executive directors. At BHP, this is our Board and our 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 our senior executive team who are members of our OMC. The role of the OMC is to make key management decisions under the authorities that have been delegated to it by the Board.

The following individuals have held their positions and were KMP for the whole of FY2017, 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);

• OMC members, as set out in the table below.

Name	Title
Peter Beaven	Chief Financial Officer
Geoff Healy	Chief External Affairs Officer
Mike Henry	President Operations, Minerals Australia
Daniel Malchuk	President Operations, Minerals Americas
Steve Pastor	President Operations, Petroleum
Athalie Williams	Chief People Officer

The information that must be disclosed also differs in the United Kingdom and Australia. 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.

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 outcomes for the Executive Director (the CEO)
	Remuneration for members of the OMC (other than the CEO)
	Remuneration outcomes for Non-executive Directors
	Remuneration governance
	Other statutory disclosures

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Abbreviation	Item
AGM	Annual General Meeting
CEO	Chief Executive Officer
DEP	Dividend Equivalent Payment
DLC	Dual Listed Company
EBITDA	Earnings Before Interest, Tax, Depreciation and Amortisation
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 Shareholder,

I am pleased to introduce BHP’s Remuneration Report for the financial year to 30 June 2017. First, a key focus for the Remuneration Committee this year has been a detailed review of our remuneration policy ahead of it being submitted for shareholder approval at our 2017 AGMs. You will see we are not proposing any significant change, as the Board and Committee believe the current policy remains appropriate and has served all stakeholders well over many years, a view supported by extensive shareholder consultation. Secondly, the Committee has continued its work to achieve remuneration outcomes that fairly reflect the performance of BHP, its businesses and individuals. FY2017 has seen a significant improvement in performance in comparison with last year, and this is reflected in the FY2017 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 those measures 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

The Committee commenced its review of our remuneration policy in mid-2016 with a remuneration risk assessment, together with selected Board, Committee and management interviews. Key items reviewed included the level of remuneration (and of the individual components), measures used in the STIP and LTIP, the method of delivery of LTIP awards, the LTIP vesting schedule and minimum shareholding requirements. In addition, the Committee reviewed the alignment of the policy with the critical need to attract, retain and appropriately reward world-class talent. The Committee has incorporated shareholder feedback into our deliberations on Executive and Non-executive Director pay through shareholder consultations.

The conclusion reached at the end of the review was that significant change was not required, consistent with the Committee’s view that our policy has served us well. This also aligns with the views of our shareholders who have given strong support to our approach to remuneration, with over 97 per cent voting ‘for’ the Remuneration Report at last year’s AGMs, and over 96 per cent support in each of the prior five years.

A minor change has been proposed in the remuneration policy to the LTIP vesting schedule for future LTIP grants, whereby in future, maximum vesting may only occur where BHP’s TSR equals or exceeds the weighted 80th percentile of the relevant comparator group, rather than equalling or exceeding the prior fixed 5.5 per cent per annum, or a compounded 30.7 per cent, outperformance over the five-year performance period. This proposed change is more aligned to contemporary market practice in Australia and the United Kingdom, and back-testing has confirmed that it would not have had any material impact on LTIP vesting outcomes in prior years. In discussions with shareholders earlier in the year, the proposed change was widely supported.

The exercise of appropriate downward discretion where the status quo or a formulaic outcome does not align with the overall shareholder experience has been a feature of BHP’s approach over many years, and this will continue unchanged. Examples in recent years include reducing the CEO’s remuneration package by 25 per cent in 2013, reducing the LTIP award vesting by 35 per cent in 2013, zero STI outcomes for the CEO and Chief Executive Petroleum in 2012 as a result of shale impairments, the reduction in Chairman and Non-executive Director fees in 2015, and the zero STI outcome for the CEO in 2016 as a result of the dam failure at Samarco, and the ongoing decline in commodity markets and the associated negative impact on our performance. We will continue to balance our judgements on remuneration to be fair to all stakeholders and, as a consequence, remuneration outcomes will continue to appropriately reflect the performance of BHP, of businesses and of individuals.

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We are aware of various proposals put forward by some shareholders and other groups to consider alternative remuneration arrangements, particularly in the United Kingdom, but we also note there is not an aligned view on the way forward. While our recent review has confirmed the appropriateness of our current approach, we will continue to monitor the debate, as our shareholders would expect. We are keen to understand any alternate arrangements that simplify remuneration, drive a balanced focus on the short and long-term, align outcomes with Group performance, limit the potential for 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 on these matters.

Remuneration outcomes for the CEO

Andrew Mackenzie, on his appointment as CEO in 2013, supported the view of the Board and Committee that his remuneration package should be rebased downwards relative to that of the former CEO. His base salary has not been increased since then, and again, after review in 2017, it 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) are also unchanged since 2013. Mr Mackenzie is BHP’s only Executive Director.

Mr Mackenzie’s annual STI is focussed on incentivising controllable annual performance and is at-risk with a target of 160 per cent of base salary linked to achieving stretching performance, a maximum of 240 per cent of base salary only realisable in circumstances of significant outperformance, and a minimum outcome of zero.

The scorecard against which his short-term performance is assessed comprises stretching performance measures including HSEC, financial and personal elements. For FY2017, the Remuneration Committee has assessed Mr Mackenzie’s performance and determined a STI outcome of 86 per cent of the target of 100 per cent (or 138 per cent of base salary).

This outcome took into account HSEC performance which primarily reflects the fatality that occurred at Escondida in October 2016, with the Remuneration Committee, after taking advice from the Sustainability Committee, giving the Group’s safety performance the greatest weighting when determining the CEO’s HSEC STI outcome. On other HSEC measures, positive outcomes were achieved, such as lower injury frequency rates, occupational illnesses and significant events with injury potential.

BHP’s overall financial performance was significantly improved in FY2017, however, controllable financial performance was below the stretching financial target set at the commencement of the year. This was mainly due to the negative impacts on production volumes and operating costs at Escondida as a consequence of industrial action in early 2017. While the idle capacity impacts of the industrial action at Escondida have been reported as an exceptional item in the accounts, the Committee concluded the entire negative impact of this event should be included in measuring STI outcomes.

The Committee also considered the CEO’s strong performance against personal objectives, including delivering significant further material productivity and capital expenditure improvements, delivery on key strategic milestones, and an acceleration of BHP’s inclusion and diversity objectives through the public adoption of an aspiration to have gender balance by 2025 and progress made towards this in FY2017.

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 2012, BHP’s five-year TSR performance was negative 32.0 per cent over the five-year period from 1 July 2012 to 30 June 2017. This is below the weighted median TSR of peer companies of negative 23.3 per cent and below the TSR of the MSCI World index of positive 69.0 per cent. This level of performance results in zero vesting for the 2012 LTIP awards, and accordingly the awards have lapsed.

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Overall, Mr Mackenzie’s actual total remuneration for FY2017 was US$4.554 million, compared with US$2.241 million for FY2016. The key driver of this difference is that Mr Mackenzie did not receive any STI in FY2016 as a consequence of the dam failure at Samarco, along with the ongoing decline in commodity markets and its associated impact on our performance, in that year. The LTI outcome in FY2016 was also zero, the same as in FY2017.

In line with the approach for Mr Mackenzie, the base salaries and total target remuneration packages for all other OMC members will also be held constant in FY2018.

FY2018 CEO remuneration

Fixed remuneration	STI	LTI
•       Base salary 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 FY2018	•       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 FY2018 •       Three performance categories: –     HSEC – 25 per cent –     Financial – 45 per cent –     Individual performance – 30 percent	•       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 5 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. Based on the most recent review, a decision has been made to reduce the Chairman’s fee by approximately eight per cent from US$0.960 million to US$0.880 million with effect from 1 July 2017, an outcome supported by the new Chairman, Mr Ken MacKenzie. This follows an earlier reduction, effective 1 July 2015, of approximately 13 per cent from US$1.100 million to US$0.960 million per annum. Base fee levels for Non-executive Directors were also reduced, effective 1 July 2015, by approximately six per cent from US$0.170 million to US$0.160 million per annum and fees will remain at these levels. Prior to the above reductions in fee levels for the Chairman and Non-executive Directors, their fees had remained unchanged since 2011.

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Summary

The remuneration outcomes for FY2017 are aligned with the Group’s performance during the year. In late 2017, our remuneration policy will be put before shareholders at the AGMs for the required three-yearly re-approval. After our review this year, the Committee concluded that, at this time, we should not make any material change to the policy which has been supported strongly by shareholders through their votes at BHP’s AGMs over many years. We remain confident our philosophy, framework and remuneration policy continue to be appropriate and support long-term value creation, but we will continue to look for opportunities to improve it. We welcome shareholder feedback and comments on the review outcomes, or on any other aspect of this Report.

Carolyn Hewson

Chairman, Remuneration Committee

7 September 2017

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3.2    Remuneration policy report

BHP has an overarching remuneration policy that guides the Remuneration Committee’s decisions. The Committee undertook a review of the policy during the past year and determined that the policy remains appropriate and aligned to the delivery of our strategic priorities. This remuneration policy is subject to a binding vote by shareholders at the 2017 AGMs, and if approved, will apply with effect from the November 2017 AGM. This remuneration policy contains no material changes from the previous remuneration policy approved by shareholders in 2014 other than those set out in sections 3.2.3 and 3.2.8.

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.

3.2.2    How remuneration policy is set

The Remuneration Committee sets the remuneration policy for the CEO and 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 KMP remuneration, BHP 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.

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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 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.

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.

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Remuneration component and link to strategy	Operation and performance framework	Maximum (1)
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.
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	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	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)
over BHP shares encourages a longer-term focus aligned to that of shareholders.	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. 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.

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Remuneration component and link to strategy	Operation and performance framework	Maximum (1)
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. 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)	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)
	•     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⁾ The updated remuneration policy for the Executive Director contains no material changes from the previous policy with the exception of the Committee’s revised approach to measuring TSR outperformance when determining whether the award vests at maximum. Maximum vesting will now be determined with reference to a position against each comparator group, instead of specifically measuring TSR relative to the weighted median TSR and index value and a fixed level of outperformance. Consistent with this, the policy wording now describes outperformance more broadly, instead of stipulating it be measured on a per annum basis or on a compounded basis over the five-year period, as was provided for in the 2014 policy. The Committee consulted with shareholders and shareholder groups on these changes and took their feedback into account.

⁽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.

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.

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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.

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$0.090million).

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.

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.

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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 forgone (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 forgone 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 ASX 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 (2) 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 (2) 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.

⁽²⁾  The updated remuneration policy for Non-executive Directors contains no material changes from the previous policy with the exception of the inclusion of pension contributions in total fees and the removal of the spouse/partner travel benefit.

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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.

3.3    Annual report on remuneration

This section of the Report shows the impact of the remuneration policy in FY2017 and how remuneration outcomes are linked to actual performance.

Remuneration outcomes 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 23). 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	FY2017		1,700		90		2,339		0		425		4,554
	FY2016		1,700		116		0		0		425		2,241

⁽¹⁾  Includes private family health insurance, spouse business-related travel and personal tax return preparation in required countries provided during FY2017.

⁽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.

	FY2017	FY2016
STI	STI awarded for FY2017 performance. Half was provided in cash in September 2017, and half deferred in an equity award which is due to vest in FY2020.	Zero STI was awarded for FY2016 performance.
LTI	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.	Based on performance during the five-year period to 30 June 2016, all of Andrew Mackenzie’s 158,290 awards from the 2011 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    FY2017 STI performance outcomes

The Board and Remuneration Committee have reviewed the CEO’s STI outcome in light of the Group’s performance in FY2017, 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 FY2017 is 86 per cent, 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 FY2017 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 FY2016 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, environment 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: Tragically, we lost one of our colleagues in October 2016 at Escondida and this is without question an unacceptable outcome. As a Company, we need to continue to build our focus on safety and fatality prevention through leadership, verification and effective risk management. This was evidenced through a further fatality at our Queensland Coal operations in August 2017, which will impact on the STI determinations for FY2018. No significant environment or community incidents occurred during FY2017. TRIF and occupational illness: Our TRIF performance in FY2017 of 4.2 has improved by 2% across BHP as a whole compared with 4.3 for FY2016. We have continued to significantly reduce the number of high potential injury events and we have recorded positive outcomes on the numbers of occupational illnesses being experienced. Risk management: All operated assets completed reviews of critical control execution and verification tasks for all material HSEC risks and met targets for critical control execution and critical control verification tasks. Health, environment and community initiatives: Greenhouse gas reduction targets set at the commencement of the year were exceeded at all operated assets. Water management projects were completed consistent with the achievement of targets in all assets. All occupational exposure and community targets were also achieved by the assets.

The outcome against the HSEC KPI for FY2017 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 Discontinued operations and exceptional items (see section 1.12.5 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. However, the Remuneration Committee still 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 FY2017, the Board determined a Target for UAP of US$2.2 billion, with a Threshold of US$1.1 billion and a Stretch of US$2.8 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

UAP of US$6.7 billion was reported by BHP for FY2017. Adjusted for the factors outlined below, UAP is US$1.7 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 asset reduced UAP by US$4.6 billion. •       Adjustments for other material items ordinarily made to ensure the outcomes reflect the performance of management for the year reduced UAP by US$0.2 billion, mainly due to the exclusion of the commodity price impacts on non-controlled equity accounted investments and the profit on the sale of Scarborough gas field, partly offset by the exclusion of the impacts of Cyclone Debbie in Queensland on third party service providers. •       Having reviewed all FY2017 exceptional items (as described in section 5.1.6 note 2), the Committee determined that the exceptional item for idle capacity costs in relation to the Escondida industrial action should be considered for the purposes of determining the UAP STI outcome, thus ensuring the full negative financial impact of the Escondida industrial action was taken into account. This adjustment reduced UAP by US$0.2 billion. The key driver of the UAP performance being below Target at US$1.7 billion was the full financial impact of the industrial action at Escondida. Other factors impacting UAP during FY2017 included variable production performance across the different operated assets, with overall volumes below expectations, mainly in iron ore, copper and coal. Cost performance, excluding the impact of exchange rates, was generally aligned with the targets set for the Group at the commencement of the year.

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Financial Scorecard Targets	Performance against Scorecard Targets
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.

The outcome against the UAP KPI for FY2017 was 35 per cent against the target of 45 per cent.

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 FY2017 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
Strategy	•       Strategy implementation. •       Execution of growth aspirations as communicated externally. •       Delivery of latent capacity enhancement projects.	•       Significant portfolio review work undertaken during the year and progressed with the Board. •       Strategic initiatives on track, including US Onshore Hedging; Mad Dog 2 and Spence; and Olympic Dam expansion advanced. •       BHP’s value increased consistent with the plan outlined in 2016, driven not only by commodity price appreciation, but also by management actions on productivity (refer also further below) and other strategic initiatives. •       Latent capacity projects on track to meet expected milestones and benefits.
Productivity	•       Delivery of productivity initiatives.	•       Productivity gains of US$1.3 billion were achieved during FY2017, taking to US$12 billion the annualised productivity gains accumulated over the past five years. •       Basis for further productivity gains through the Maintenance Centre of Excellence, globalised supply function and integrated leadership for General Managers.

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Measures	Individual Scorecard Targets	Performance against Scorecard Targets
Sustainability	•       Positive progress on the Samarco Framework Agreement. •       Enhanced reputation of BHP.	•       Samarco Foundation activity and spend has met the defined schedule. •       Strong representation on key issues such as inclusion and diversity, transparency, taxation, Brexit and Samarco. •       Shareholder engagement strengthened through close communication, regular updates and relationship building. •       Global brand strategy implemented.
People and culture	•       Achievement of culture initiatives (improvement in Company-wide leadership capabilities, employee engagement, diversity and inclusion). •       OMC 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. •       Strong leadership on inclusion and diversity, with the announcement of, and significant progress on, the goal to increase female representation in the workforce globally. •       Continued focus on development of a strong long-term talent pool of candidates for Asset President and OMC 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 FY2017 of 35 per cent against the target of 30 per cent.

3.3.3    LTI performance outcomes

LTI vesting based on performance to June 2017

The five-year performance period for the 2012 LTIP ended on 30 June 2017. The CEO’s 2012 LTI comprised 151,609 awards (inclusive of an uplift of 11,283 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 2012 to 30 June 2017. 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 32.0 per cent over the five-year period from 1 July 2012 to 30 June 2017. This is below the weighted median Peer Group TSR of negative 23.3 per cent and below the Index TSR of positive 69.0 per cent over the same period. This level of performance results in zero vesting for the 2012 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.

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 2012 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.

3.3.4    LTI allocated during FY2017

Following shareholder approval at the 2016 AGMs, an LTI award (in the form of performance rights) was granted to the CEO on 9 December 2016. 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$1.700 million. The fair value of the award is ordinarily calculated by multiplying the face value of the award by the fair value factor of 41 per cent (for the current plan design, as determined by the independent adviser to the Committee). The number of LTI awards is determined using the share price and US$/A$ exchange rate over the 12 months up to and including the prior 30 June. Using a 12-month average share price of A$20.3326 and a 12-month average US$/A$ exchange rate of 0.728415 (each up to and including 30 June 2016), 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 459,190 LTI awards.

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However, in light of the recent history of BHP’s share price, the Board was conscious of shareholder expectations in this respect and on advice from the Committee instead granted 339,753 LTI awards to the CEO in FY2017: the same number that was granted to the CEO in December 2015 and 26 per cent lower than the 459,190 LTI awards determined formulaically as described. The face value of 339,753 LTI awards was US$5.032 million compared with the normal maximum face value of US$6.800 million, a reduction of US$1.768 million, or 26 per cent.

Number of LTI awards	Face value US$(‘000)	Face value % of salary	Fair value US$(‘000)	Fair value % of salary	% of max (1)
339,753	5,032	296	2,063	121	61

⁽¹⁾  The allocation is 61 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 2016 to 30 June 2021.
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 1% to reduce sensitivity to any single peer company. •       For the whole of either portion of the award to vest, BHP’s TSR must exceed the Peer Group TSR or the Index TSR (as applicable) by an average of 5.5% per annum. Threshold vesting (25% of each portion of the award) occurs where BHP’s TSR equals 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 have both been 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 were less relevant comparator companies.

⁽³⁾  Glencore Xstrata replaced Xstrata in the peer group for December 2010 to December 2012 awards after the merger of Glencore and Xstrata in May 2013. Glencore Xstrata was included in its own right 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

Eight-year CEO remuneration

The table below shows the total remuneration earned by Andrew Mackenzie and Marius Kloppers over the last eight 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
Andrew Mackenzie
Total single figure remuneration, US$(‘000)		–		–		–		2,468		7,988		4,582		2,241		4,554
STI (% of maximum)		–		–		–		47		77		57		0		57
LTI (% of maximum)		–		–		–		65		58		0		0		0
Marius Kloppers
Total single figure remuneration, US$(‘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.

Eight-year TSR

The graph below shows BHP’s TSR against the performance of relevant indices over the same eight-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.

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3.3.6    Changes in the CEO’s remuneration in FY2017

The table below sets out the CEO’s base salary, benefits and STI amounts earned in respect of FY2017, with the percentage change from FY2016. The table also shows the average change in each element for current employees in Australia (being approximately 16,000 employees) during FY2017. 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		90			2,339
	% change		0.0		(22.4	)		N/A
Australian employees	% change (average)		0.9		(26.4	)		66.7

The ratio of the total remuneration of the CEO to the median total remuneration of all BHP employees for FY2017 was 38:1 (2016: 19:1) with the increase in FY2017 over FY2016 mainly due to the CEO having earned an STI in FY2017, whereas FY2016 was zero.

3.3.7    Remuneration for the CEO in FY2018

The remuneration for the CEO in FY2018 will be set in accordance with the remuneration policy approved by shareholders at the AGMs in October and November 2017.

Base salary increase in September 2017

Base salary is reviewed annually and increases are applicable from 1 September. The CEO will not receive a base salary increase in September 2017 and it will remain unchanged at US$1.700 million per annum for FY2018.

FY2018 STI performance measures

For FY2018, 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. 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: Operated assets to have identified risks with material safety impacts, evaluated and recorded these risks in a system with controls in place and verified as part of Field Leadership activities. Achieve 88% compliance for Critical Control Verification and Execution tasks. Health, environment 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.

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Performance measure	Weighting		Target performance
UAP		45%	UAP is profit after taxation attributable to members of the BHP Group, excluding Discontinued operations and 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.
Individual performance		30%	The CEO’s individual measures for FY2018 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, including strategy implementation, execution of growth options as communicated externally, continued enhancement of BHP reputation, achievement of culture initiatives (improvement in Group-wide leadership capabilities, employee engagement, diversity and inclusion), delivery of productivity initiatives, delivery of latent capacity enhancement projects, and OMC member development and succession.

FY2018 LTI award

The normal maximum face value of the CEO’s award is US$6.800 million, being 400 per cent of the CEO’s base salary. The number of LTI awards in FY2018 has been determined using the share price and US$/A$ exchange rate over the 12 months up to and including 30 June 2017. Based on this, a grant of 385,075 LTI awards is proposed.

The FY2018 LTI award will use the same performance, service conditions and peer groups as the FY2017 LTI award, except that for all of the award to vest, BHP’s TSR must be at or exceed the weighted 80^th percentile of the Peer Group TSR or the Index TSR (as applicable). Threshold vesting of each portion of the award is unchanged and occurs where BHP’s TSR equals the weighted Peer Group TSR or Index TSR (as applicable). This new approach to maximum vesting moves from a set percentage TSR target for outperformance to a target that considers a percentile ranking of TSR outcomes. Analysis using previous LTIP awards confirms that the new vesting schedule is no less stretching. The Committee consulted with shareholders and shareholder groups on these changes, and took their feedback into account.

Approval for the proposed FY2018 LTI grant of 385,075 LTI awards will be sought from shareholders at the 2017 AGMs. If approved, the award will be granted following the AGMs (i.e. in or around December 2017).

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Remuneration for members of the OMC (other than 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 members of the OMC other than the CEO.

The remuneration policy and structures for the members of the OMC 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 members of the OMC are the same as for the CEO, with any differences described below.

STI

STI performance measures for members of the OMC are similar to those of the CEO; however, the weighting of each performance measure will vary to reflect the focus required from each OMC role.

Individual performance measures are determined at the start of the financial year. These include the OMC member’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 OMC members was reviewed against these measures by the Committee and, on average, was considered ahead of target.

The diagram below represents the STI outcomes against the original scorecard.

FY2017 performance measures and outcomes

LTI

LTI awards granted to members of the OMC generally 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). The exception is for Athalie Williams, for whom the maximum face value is 300 per cent of base salary (or a fair value of 123 per cent of base salary).

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Transitional OMC awards

Transitional OMC awards were granted to new OMC members recruited from within BHP to bridge the gap created by the different timeframes of BHP’s long-term incentive program for OMC members (LTIP) and for senior management (MAP).

Peter Beaven and Daniel Malchuk were holding Transitional OMC awards, as set out in the adjacent table, with a service condition to 30 June 2017. As the service condition was satisfied, the Committee then assessed if the performance condition has been met and whether any, all or part of the award will vest. In making that assessment, the Committee considers (but is not limited to) BHP’s TSR over the relevant performance period, the participant’s contribution to Group outcomes and the participant’s personal performance (with guidance on this assessment from the CEO). At the time of grant, the target was 80 per cent vesting of awards granted, with a maximum of 100 per cent and a minimum of zero.

The Committee considered the following information:

• our relative TSR performance was below the weighted median of our peers over the relevant periods;

• Group performance (to which Mr Beaven and Mr Malchuk contributed effectively) has been largely in line with expectations, with positive performance across a range of factors within management’s control, most notably production, costs and capital expenditure across all years and safety performance in FY2014, being offset offset by the five fatalities in FY2015, one fatality in FY2017, and the tragic events at Samarco and the commodity price related impacts in FY2016;

• the CEO’s view that Mr Beaven and Mr Malchuk had performed well in their respective roles.

The Committee exercised its discretion and determined to reduce vesting by 31 per cent for each award, as set out in the table below. The awards which did not vest lapsed.

OMC member	Period	Awards held		Maximum vesting		Actual vesting		Awards vesting
Peter Beaven	1 July 2013 to 30 June 2017		19,641		100%		69%		13,552
Daniel Malchuk	1 July 2013 to 30 June 2017		16,695		100%		69%		11,520

Equity awards provided for pre-OMC service

Members of the OMC 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-OMC roles.

Members of the OMC are eligible to participate in Shareplus. For administrative simplicity, members of the OMC, including the CEO, do not currently participate in Shareplus. No member of the OMC, including the CEO, had any holdings under the Shareplus program during FY2017 while a KMP.

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3.3.9    Remuneration mix

A significant portion of OMC 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 other members of the OMC. 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 member of the OMC 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 members of the OMC have a maximum LTI award with a face value of 350 per cent of base salary as shown in the chart, with the exception of Athalie Williams, who has a maximum LTI award with a face value of 300 per cent of base salary.

3.3.10    Employment contracts

The terms of employment for members of the OMC 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 OMC 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. The OMC member must give six months’ notice for voluntary resignation.

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Remuneration outcomes for Non-executive Directors

The remuneration outcomes described below have been provided in accordance with the remuneration policy approved by shareholders at the 2014 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.

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
Malcolm Brinded (3)		FY2017		229		101		–		330
		FY2016		194		76		–		270
Malcolm Broomhead		FY2017		209		70		11		290
		FY2016		209		64		11		284
Pat Davies (4)		FY2017		165		64		–		229
		FY2016		215		116		–		331
Anita Frew		FY2017		193		68		–		261
		FY2016		141		45		–		186
Carolyn Hewson		FY2017		195		54		10		259
		FY2016		195		63		10		268
Grant King (3) (5)		FY2017		51		37		2		90
Ken MacKenzie (3) (5)		FY2017		138		81		8		227
Lindsay Maxsted		FY2017		209		36		11		256
		FY2016		209		48		11		268
Wayne Murdy		FY2017		199		93		–		292
		FY2016		193		79		–		272
Jac Nasser (3)		FY2017		960		93		–		1,053
		FY2016		960		96		–		1,056
John Schubert (4)		FY2017		72		15		4		91
		FY2016		195		67		10		272
Shriti Vadera		FY2017		236		69		–		305
		FY2016		238		62		–		300

⁽¹⁾ The majority of the amounts disclosed for benefits are travel allowances for each Non-executive Director: amounts of between US$15,000 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$15,000 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 FY2017 in accordance with Australian superannuation legislation.

⁽³⁾ Jac Nasser retired from the Board as Non-executive Director and Chairman on 31 August 2017 and was succeeded by Ken MacKenzie as of 1 September 2017. Malcolm Brinded will retire from the Board on 18 October 2017. Grant King retired from the Board on 31 August 2017.

⁽⁴⁾ The FY2017 remuneration for Pat Davies and John Schubert relates to part of the year only, as they retired from the Board on 6 April 2017 and 17 November 2016, respectively.

⁽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.

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3.3.12    Non-executive Directors’ remuneration in FY2018

In FY2018, 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. Based on the most recent review, a decision has been made to reduce the Chairman’s fee by approximately eight per cent from US$0.960 million to US$0.880 million with effect from 1 July 2017, an outcome supported by the new Chairman, Mr Ken MacKenzie. This is in addition to the reduction of approximately 13 per cent from US$1.100 million to US$0.960 million per annum 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. The adjacent table sets out the annualised fee levels for FY2018.

Levels of fees and travel allowances for Non-executive Directors (in US$)	From 1 July 2017
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 fees
Committee membership:
Risk and Audit		32,500
Remuneration		27,500
Sustainability		27,500
Nomination and Governance		No additional fees
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).

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 members of the OMC 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 consultants.

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Remuneration Committee

The activities of the Remuneration Committee are governed by Terms of Reference (approved by the Board in June 2016), which are available on our website. The Remuneration Committee members comprise Carolyn Hewson (Chairman), Malcolm Brinded, Pat Davies (to 6 April 2017), Wayne Murdy (from 6 April 2017) 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: Jac Nasser (Chairman); 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 advisors

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. The advice of external advisers, and any recommendations they provide where requested, are used as a guide, but do not serve as a substitute for thorough consideration of the issues by each Director.

PricewaterhouseCoopers was appointed by the Committee in March 2016 to act as an independent remuneration adviser. As part of its role, PricewaterhouseCoopers may provide ‘remuneration recommendations’ (as defined in the Australian Corporations Act 2001) to the Committee. 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. Management also appoints external firms from time to time to assist with remuneration benchmarking, data provision and the like. While other external firms can and do provide certain information to management to assist them in deliberations, only PricewaterhouseCoopers may provide remuneration recommendations in relation to KMP.

Advice provided in FY2017

During the year, PricewaterhouseCoopers provided advice and assistance to the Committee on a wide range of matters, including:

• benchmarking of pay of senior executives (including the CEO and other members of the OMC) against comparable roles at a range of relevant comparator companies, including information and commentary on global trends in executive remuneration;

• review of the sector peer group;

• calculation of fair values for accounting and remuneration setting purposes of equity awards and performance analysis for LTI awards;

• advice on Remuneration Report disclosures;

• review of and commentary on management proposals, including in relation to the arrangements for the CEO and other members of the OMC;

• other ad-hoc support and advice as requested by the Committee.

PricewaterhouseCoopers provided no remuneration recommendations during the period 1 July 2016 to 30 June 2017.

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Remuneration recommendations

If PricewaterhouseCoopers were to provide a remuneration recommendation, it would include a declaration that the remuneration recommendation was made free from undue influence by the individual to whom the recommendation relates. Based on the processes outlined above, the constraints incorporated into PricewaterhouseCoopers’ terms of engagement, the implementation of a comprehensive protocol for the engagement of remuneration advisers and a receipt of the declaration of no undue influence, the Board would be in a position to satisfy itself that a remuneration recommendation from PricewaterhouseCoopers was made free from undue influence by any member of the KMP to whom the recommendation related.

Total fees paid to the PricewaterhouseCoopers team advising the Committee on remuneration related matters for the period from 1 July 2016 to 30 June 2017 were £184,700. 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 to the Group for the period from 1 July 2016 to 30 June 2017 were approximately US$20 million.

3.3.14    Statement of voting at the 2016 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 2016 AGMs is shown below.

AGM resolution	Requirement		% vote ‘for’		% vote ‘against’		Votes withheld (1)
Remuneration Report (excluding remuneration policy) (2)		UK		98.9		1.1		14,415,364
Remuneration Report (whole report)		Australia		97.4		2.6		12,391,694
Approval of grants to Executive Director		Australia		96.9		3.1		13,803,863

⁽¹⁾  The sum of votes marked ‘Vote Withheld’ at BHP Billiton Plc’s AGM and votes marked ‘Abstain’ at BHP Billiton Limited’s AGM.

⁽²⁾  The UK requirement for approval of the remuneration policy was met at the 2014 AGMs (where the following outcomes were recorded: a 97.19 per cent vote ‘for’ and a 2.81 per cent vote ‘against’, with 29,834,918 votes withheld). This resolution was not required in 2015 or 2016.

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    OMC remuneration table

The table below has been prepared in accordance with relevant accounting standards and remuneration data for members of the OMC are for the periods of FY2016 and FY2017 that they were KMP. More information on the policy and operation of each element of remuneration is provided in prior sections of this Report.

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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 FY2016 or FY2017. 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 allocated during FY2016 and FY2017, 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		FY2017		1,700		1,170		90		–		425		752		2,955		7,092
		FY2016		1,700		0		116		–		425		874		2,792		5,907
Other OMC members
Peter Beaven		FY2017		1,000		752		11		–		250		531		1,383		3,927
		FY2016		1,000		208		2		–		250		558		1,258		3,276
Geoff Healy		FY2017		1,000		712		52		–		250		553		1,270		3,837
		FY2016		1,000		184		59		–		250		615		987		3,095
Mike Henry		FY2017		1,100		757		12		26		275		555		1,751		4,476
		FY2016		1,100		202		15		53		275		634		1,563		3,842
Daniel Malchuk		FY2017		1,000		584		12		39		250		468		1,326		3,679
		FY2016		1,000		184		10		440		250		534		1,176		3,594
Steve Pastor		FY2017		848		638		–		33		212		360		776		2,867
		FY2016		267		51		–		–		67		83		237		705
Athalie Williams		FY2017		750		516		1		–		188		353		714		2,522
		FY2016		750		144		4		–		188		246		597		1,929

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(1) Base salaries shown in this table reflect the amounts paid over the 12-month period from 1 July 2016 to 30 June 2017 for each executive. Steve Pastor’s base salary was set by the Remuneration Committee in April 2016 at US$0.800 million per annum, which was 20 per cent below that of Steve’s predecessor (Tim Cutt, in the role of President Petroleum) and at a lower level than the base salary of other OMC members with operational roles. It was the Committee’s intention to review this positioning after a year to confirm that Steve was meeting the scope and complexity requirements of the role. The Committee believes this approach to salary increases is in the interests of shareholders, as it saves expenditure not only on base salary, but also on pension contributions, STI and LTI, all of which are tied to the level of base salary, until the appropriate level of performance and contribution has been demonstrated. In April 2017, the Committee assessed Steve’s performance in the President Operations Petroleum role and it was confirmed that Steve was operating as expected and performing consistently with the other OMC members in operational roles. The Committee also considered market factors, job relativities and contribution in role. Accordingly, the Committee increased Steve’s base salary to US$1.000 million per annum with effect from 4 April 2017, which is consistent with the range of base salaries of BHP’s other OMC operational roles (from US$1.000 million to US$1.100 million per annum). There were no other changes to OMC 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 was paid to OMC members 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 FY2017, OMC members earned the following STI awards as a percentage of the maximum (the remaining portion has been forfeited): Andrew Mackenzie 57 per cent, Peter Beaven 63 per cent, Geoff Healy 59 per cent, Mike Henry 57 per cent, Daniel Malchuk 49 per cent, Steve Pastor 63 per cent, and Athalie Williams 57 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) and travel costs.

(4) Other benefits are non-pensionable and for FY2017 include an encashment of annual leave entitlements under the US Annual Leave policy for Steve Pastor, an international relocation benefit provided to Danny Malchuk, and a domestic relocation benefit provided to Mike Henry.

(5) Retirement benefits are 25 per cent of base salary for each OMC member.

(6) The IFRS fair value of both STI and LTI awards is estimated at grant date. Refer to section 5.1.6 Note 23 for further details.

3.3.16    Equity awards

The interests held by OMC members 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. The vesting conditions will include performance and/or service requirements as relevant to the purpose of the award and as described in each of the following sections. BHP Billiton Limited share awards are shown in Australian dollars. BHP Billiton Plc awards are shown in Pounds Sterling. Our Requirements for Securities Dealing 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 OMC members.

Dividend Equivalent Payments

DEP applies to awards provided to OMC members under the STIP and LTIP as detailed in section 3.2.3. No DEP is payable on Transitional OMC awards, GSTIP awards or MAP awards.

Equity awards provided for OMC service

STI awards under the STIP

The STIP applied from FY2014, with awards allocated from December 2014. Awards under the STIP will not deliver any value to the holder for at least two years from the beginning of the financial year in which they are granted (unless the executive’s employment with the Group ends earlier in specific circumstances, such as death, serious injury, disability or illness that prohibits continued employment, or total and permanent disablement).

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LTI awards under the LTIP

The current LTIP is effective for grants from December 2013. The terms and conditions, 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 the BHP website. Awards under the LTIP will not deliver any value to the holder for at least five years from the beginning of the financial year in which they are granted (unless the executive’s employment with the Group ends earlier in specific termination circumstances, such as death, serious injury, disability or illness that prohibits continued employment; or total and permanent disablement).

Transitional OMC awards

The Remuneration Committee may determine that new OMC members recruited from within BHP receive Transitional OMC awards to bridge the gap between MAP awards, which have a three-year service condition and the LTIP awards, which have a five-year service and performance condition.

Transitional OMC awards have two tranches. Tranche one has a three-year service and performance condition. Tranche two has a four-year service and performance condition. The 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) BHP’s TSR 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).

The treatment of Transitional OMC awards on cessation of employment will depend on the circumstances and is similar to those for LTIP awards as described in section 3.2.7.

Equity awards provided for pre-OMC service

STI awards under the GSTIP

STI awards held by executives at the time they were appointed to the OMC or which were allocated for performance and service before they became OMC members were allocated under the GSTIP. The GSTIP has applied for the non-OMC management of BHP since FY2009 (for FY2008 performance).

The terms and conditions of the GSTIP awards are essentially the same as those provided under the STIP. Under each plan, participants must satisfy applicable STl performance conditions to be eligible for any award.

LTI awards under the MAP

LTI awards held by executives at the time they were appointed to the OMC were allocated under the MAP, which has applied for non-OMC management since FY2009. As the primary purpose of the MAP is the retention of key senior management employees, the plan has no performance conditions after awards are granted and the vesting of MAP awards is subject to continued employment with the Group through to the vesting date as shown in the table below. Where a participant resigns or is terminated for cause prior to the vesting date, their unvested MAP awards are forfeited. If a participant’s employment ends due to redundancy, retirement, death, illness or injury, a pro-rata number of unvested awards will vest based on the portion of the relevant vesting period served.

233

Award type

Date of grant

At 1 July 2016

Granted

Vested

Lapsed

Exercised

At 30 June 2017

Award vesting date (1)

Market price on date of:

Gain on awards (’000) (4)

DEP on awards (’000)

Grant (2)

Vesting (3)

Exercise

Andrew Mackenzie

STIP

4 Dec 2015

69,566

–

–

–

–

69,566

Aug 17

A$17.93

–

–

–

–

STIP

19 Dec 2014

73,527

–

73,527

–

–

–

31 Aug 16

A$28.98

A$

20.43

–

A$1,502

A$192

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

Aug 17

£19.98

–

–

–

–

LTIP

5 Dec 2011

158,290

–

–

158,290

–

–

31 Aug 16

£20.12

–

–

–

–

Peter Beaven

STIP

9 Dec 2016

–

10,958

–

–

–

10,958

Aug 18

A$25.98

–

–

–

–

STIP

4 Dec 2015

40,921

–

–

–

–

40,921

Aug 17

A$17.93

–

–

–

–

STIP

19 Dec 2014

39,837

–

39,837

–

–

–

31 Aug 16

A$28.98

A$

20.43

–

A$814

A$104

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

–

–

–

–

19,641

Aug 17

A$35.79

–

–

–

–

Transitional

18 Dec 2013

19,641

–

13,159

6,482

–

–

31 Aug 16

A$35.79

A$

20.43

–

A$269

–

Geoff Healy

STIP

9 Dec 2016

–

9,694

–

–

–

9,694

Aug 18

A$25.98

–

–

–

–

STIP

4 Dec 2015

49,105

–

–

–

–

49,105

Aug 17

A$17.93

–

–

–

–

STIP

19 Dec 2014

42,875

–

42,875

–

–

–

31 Aug 16

A$28.98

A$

20.43

–

A$876

A$112

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

–

–

–

–

Mike Henry

STIP

9 Dec 2016

–

10,663

–

–

–

10,663

Aug 18

A$25.98

–

–

–

–

STIP

4 Dec 2015

45,542

–

–

–

–

45,542

Aug 17

A$17.93

–

–

–

–

STIP

19 Dec 2014

47,575

–

47,575

–

–

–

31 Aug 16

A$28.98

A$

20.43

–

A$

972

A$

124

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

–

–

–

–

234

Award type

Date of grant

At 1 July 2016

Granted

Vested

Lapsed

Exercised

At 30 June 2017

Award vesting date (1)

Market price on date of:

Gain on awards (’000) (4)

DEP on awards (’000)

Grant (2)

Vesting (3)

Exercise

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

Aug 17

£19.98

–

–

–

–

Transitional

5 Dec 2012

21,533

–

15,719

5,814

–

–

31 Aug 16

£19.98

£10.18

–

£160

–

Daniel Malchuk

STIP

9 Dec 2016

–

9,694

–

–

–

9,694

Aug 18

A$25.98

–

–

–

–

STIP

4 Dec 2015

40,921

–

–

–

–

40,921

Aug 17

A$17.93

–

–

–

–

STIP

19 Dec 2014

37,393

–

37,393

–

–

–

31 Aug 16

A$28.98

A$20.43

–

A$764

A$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

–

–

–

–

16,695

Aug 17

A$35.79

–

–

–

–

Transitional

18 Dec 2013

16,695

–

11,520

5,175

–

–

31 Aug 16

A$35.79

A$20.43

–

A$235

–

Steve Pastor

STIP

9 Dec 2016

–

2,697

–

–

–

2,697

Aug 18

A$25.98

–

–

–

–

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

Aug 17

A$23.02

–

–

–

–

GSTIP

3 Nov 2014

11,705

–

11,705

–

–

–

31 Aug 16

A$33.71

A$20.43

–

A$239

–

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

Aug 17

A$33.71

–

–

–

–

MAP

31 Oct 2013

19,862

–

19,862

–

–

–

31 Aug 16

A$37.66

A$20.43

–

A$406

–

Athalie Williams

STIP

9 Dec 2016

–

7,586

–

–

–

7,586

Aug 18

A$25.98

–

–

–

–

STIP

4 Dec 2015

17,692

–

–

–

–

17,692

Aug 17

A$17.93

–

–

–

–

LTIP

9 Dec 2016

–

112,418

–

–

–

112,418

Aug 21

A$25.98

–

–

–

–

LTIP

4 Dec 2015

112,418

–

–

–

–

112,418

Aug 20

A$17.93

–

–

–

–

Transitional

4 Dec 2015

23,420

–

–

–

–

23,420

Aug 19

A$17.93

–

–

–

–

Transitional

4 Dec 2015

23,420

–

–

–

–

23,420

Aug 18

A$17.93

–

–

–

–

GSTIP

4 Dec 2015

4,689

–

–

–

–

4,689

Aug 17

A$17.93

–

–

–

–

GSTIP

3 Nov 2014

7,204

–

7,204

`-

–

–

31 Aug 16

A$33.71

A$20.43

–

A$147

–

MAP

3 Nov 2014

7,805

–

–

–

–

7,805

Aug 17

A$33.71

–

–

–

–

MAP

31 Oct 2013

8,101

–

8,101

–

–

–

31 Aug 16

A$37.66

A$20.43

–

A$166

–

235

⁽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 (Transitional tranche one and MAP), fourth (Transitional tranche two) or fifth (LTIP) financial year after grant. Except for the LTIP awards granted on 5 December 2011 and 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 2011 and 5 December 2012 are non-conditional awards which have an exercise period and an expiry date of the day prior to the fifth anniversary of the vesting date. No price is payable on exercise of these awards. 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 grant date IFRS fair value of the awards is estimated as at the start of the vesting period, being 1 July 2016 for awards granted during FY2017, and is as follows: STIP – A$19.09; LTIP – A$10.80; GSTIP – A$18.41; MAP (vesting date Aug 18) – A$18.41; MAP (vesting date Aug 19) – A$18.08 and MAP (vesting date Aug 20) – A$17.75.

⁽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 amount that vested and were lapsed for the awards during FY2017 is as follows: STIP – 100 per cent vested; LTIP – 100 per cent lapsed; Transitional (Peter Beaven) – 67 per cent vested, 33 per cent lapsed; Transitional (Mike Henry) – 73 per cent vested, 27 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 FY2017 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

		FY2017		FY2016			FY2015			FY2014		FY2013
BHP Billiton Limited	Share price at beginning of year		A$19.09		A$26.58			A$36.00			A$30.94		A$31.72
	Share price at end of year		A$23.28		A$18.65			A$27.05			A$35.90		A$31.37
	Dividends paid		A$0.72		A$1.09			A$3.72	(1)		A$1.29		A$1.10
BHP Billiton Plc	Share price at beginning of year		£9.40		£12.58			£19.45			£17.15		£18.30
	Share price at end of year		£11.76		£9.43			£12.49			£18.90		£16.82
	Dividends paid		£0.44		£0.51			£1.95	(1)		£0.73		£0.73
BHP	Attributable profit /(loss) (US$M, as reported)		5,890		(6,385	)		1,910			13,832		11,223

⁽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 FY2017 were A$27.89 for BHP Billiton Limited shares and £14.81 for BHP Billiton Plc shares. The lowest share prices during FY2017 were A$18.71 and £9.21, respectively.

236

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 OMC member’s family and entities over which either the Director or OMC member 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 23 August 2017 (being not less than one month prior to the date of the notice of the 2017 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 members of the OMC in the ordinary shares of each of BHP Billiton Limited and BHP Billiton Plc as at 30 June 2017 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 2016

Purchased

Received as remuneration (1)

Sold

Held at 30 June 2017

Held at 1 July 2016

Purchased

Received as remuneration (1)

Sold

Held at 30 June 2017

Executive Director

Andrew Mackenzie

16,575

–

82,904

44,279

55,200

266,205

–

–

–

266,205

Other OMC members

Peter Beaven

238,085

–

58,077

29,803

266,359

–

–

–

–

–

Geoff Healy

3,000

–

48,344

24,808

26,536

–

–

–

–

–

Mike Henry

38,039

–

53,643

26,404

65,278

180,543

–

15,719

–

196,262

Daniel Malchuk

86,927

–

53,682

14,079

126,530

–

–

–

–

–

Steve Pastor (2)

9,983

–

31,567

13,869

27,681

–

–

–

–

–

Athalie Williams

21,457

–

15,305

7,855

28,907

–

–

–

–

–

Non-executive Directors

Malcolm Brinded

–

–

–

–

–

60,000

–

–

–

60,000

Malcolm Broomhead

19,000

–

–

–

19,000

–

–

–

–

–

Pat Davies (3)

–

–

–

–

–

27,170

–

–

–

27,170

Anita Frew

–

–

–

–

–

9,000

6,000

–

–

15,000

Carolyn Hewson

19,000

–

–

–

19,000

–

–

–

–

–

Grant King (4)

11,020

8,980

–

–

20,000

–

–

–

–

–

Ken MacKenzie (4)

15,000

–

–

15,000

–

–

–

–

–

Lindsay Maxsted

18,000

–

–

–

18,000

–

–

–

–

–

Wayne Murdy (2)

8,000

–

–

–

8,000

24,000

–

–

–

24,000

Jac Nasser (2)

20,400

–

–

–

20,400

81,200

–

–

–

81,200

John Schubert (3)

23,675

–

–

–

23,675

–

–

–

–

–

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 closing balances for Pat Davies and John Schubert reflect their shareholdings on the date that each ceased being KMP being 6 April 2017 and 17 November 2016, respectively.

⁽⁴⁾  The opening balances for Grant King and Ken MacKenzie reflect their shareholdings on the date that each became KMP being 1 March 2017 and 22 September 2016, respectively.

237

3.3.19    Prohibition on hedging of BHP shares and equity instruments

The CEO and other members of the OMC 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.

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 OMC 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 FY2017:

• 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 three times his annual pre-tax base salary at the end of FY2017;

• the MSR for other members of the OMC was three times annual pre-tax base salary. At the end of FY2017, Peter Beaven and Mike Henry met the MSR, while the remaining members of the OMC did not meet the MSR. No OMC members sold shares during FY2017, other than to satisfy taxation obligations, consistent with the policy.

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 FY2017, 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. Other than the disclosure below in relation to John Schubert, there is nothing to disclose for these payments for FY2017. The Remuneration Committee has adopted a de minimis threshold of US$7,500 for disclosure of payments to past Directors under UK requirements.

Upon John Schubert’s departure from the Board on 17 November 2016, a payment of US$271,633 was made to him, representing his accrued retirement benefits balance in the legacy BHP Billiton Limited Retirement Plan (which was closed on 24 October 2003, as described in the 2016 Remuneration Report).

238

3.3.22    Relative importance of spend on pay

The table below sets out the total spend on employee remuneration during FY2017 (and the prior year) compared with other significant expenditure items. The table includes items as prescribed in the UK requirements and further details and definitions are in sections 5.1.4 and 5.1.6. BHP has included tax payments and purchases of property, plant and equipment being the most significant other outgoings in monetary terms.

US$ million	FY2017		FY2016
Aggregate employee benefits expense		3,867		3,788
Dividends paid to BHP shareholders		2,921		4,130
Share buy-backs		–		–
Income tax paid and royalty-related taxation paid (net of refunds)		2,084		1,645
Purchases of property, plant and equipment		4,252		6,946

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) (2016: US$ nil; 2015: US$ nil). There are no amounts payable at 30 June 2017 (2016: US$ nil). There are US$ nil loans (2016: 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 (2016: US$ nil).

This Remuneration Report was approved by the Board on 7 September 2017 and signed on its behalf by:

Carolyn Hewson

Chairman, Remuneration Committee

7 September 2017

239

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 20
(6)  Waiver of future emoluments	Section 3.3.1
(12) Shareholder waivers of dividends	Section 5, note 23
(13) Shareholder waivers of future dividends	Section 5, note 23

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 FY2017, the results of those operations during FY2017 and the expected results of those operations in future financial years are set out in section 1, in particular in sections 1.1 to 1.7, 1.12 and 1.13 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 FY2017 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 FY2017.

There were no significant changes in BHP’s state of affairs that occurred during FY2017 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 FY2017 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.

4.2    Share capital and buy-back programs

At the Annual General Meetings held in 2015 and 2016, 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 FY2017, 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 2017 Annual General Meetings to renew this authority. As at the date of this Directors’ Report, the Directors have no present intention to exercise the buy-back authority, if granted.

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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 FY2017.

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 2016 to 31 Jul 2016		3,660,980		$    14.93		–		–		211,207,180	(3)
1 Aug 2016 to 31 Aug 2016		850,000		$    15.13		–		–		211,207,180	(3)
1 Sep 2016 to 30 Sep 2016		–		–		–		–		211,207,180	(3)
1 Oct 2016 to 31 Oct 2016		–		–		–		–		211,207,180	(3)
1 Nov 2016 to 30 Nov 2016		–		–		–		–		211,207,180	(3)
1 Dec 2016 to 31 Dec 2016		–		–		–		–		211,207,180	(3)
1 Jan 2017 to 31 Jan 2017		269,466		$    18.44		–		–		211,207,180	(3)
1 Feb 2017 to 28 Feb 2017		–		–		–		–		211,207,180	(3)
1 Mar 2017 to 31 Mar 2017		1,693,289		$    18.53		–		–		211,207,180	(3)
1 Apr 2017 to 30 Apr 2017		176,542		$    17.74		–		–		211,207,180	(3)
1 May 2017 to 31 May 2017		–		–		–		–		211,207,180	(3)
1 Jun 2017 to 30 Jun 2017		56,661		$    16.45		–		–		211,207,180	(3)
Total		6,706,938		$    16.09		–		–		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 will be conducted in accordance with the Australian Corporations Act 2001 and with the ASX Listing Rules.

⁽³⁾  At the Annual General Meetings held during 2015 and 2016, 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$5.9 billion in FY2017, compared with a loss of US$6.4 billion in FY2016.

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 1.4 to 1.8 and 2.14, and note 21 ‘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 FY2017 or up until the date of this Directors’ Report were Jac Nasser, Andrew Mackenzie, Malcolm Brinded, Malcolm Broomhead, Pat Davies, Anita Frew, Carolyn Hewson, Grant King, Ken MacKenzie, Lindsay Maxsted, Wayne Murdy, John Schubert 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 2014 and the period for which each directorship has been held.

John Schubert served as a Non-executive Director of BHP Limited since June 2000 and a Non-executive Director of BHP Billiton Limited and BHP Billiton Plc from June 2001 until his retirement on 17 November 2016.

Pat Davies served as a Non-executive Director of BHP Billiton Limited and BHP Billiton Plc from June 2012 until his retirement on 6 April 2017.

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 elected not to stand for election at the 2017 Annual General Meetings and retired as a Non-executive Director on 31 August 2017.

Ken MacKenzie was appointed as a Non-executive Director of BHP Billiton Limited and BHP Billiton Plc with effect from 22 September 2016. In accordance with the BHP Billiton Limited Constitution and the BHP Billiton Plc Articles of Association, he stood for election, and was elected, at the 2016 Annual General Meetings.

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 has decided not to stand for re-election at the 2017 Annual General Meetings and will retire 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 will seek election 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 will seek election at the 2017 Annual General Meetings.

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.

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4.5    Remuneration and share interests

4.5.1    Remuneration

The policy for determining the nature and amount of emoluments of members of the Operations Management Committee (OMC) (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 OMC (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 FY2017, at the beginning and end of FY2017. 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 2017 are set out in the tables showing interests in incentive plans contained in section 3.3.16. Except for Andrew Mackenzie and Ken 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; and

• rights and options over nil shares in BHP Billiton Plc and 1,118,066 shares in BHP Billiton Limited.

As at the date of this Directors’ Report, Ken MacKenzie indirectly holds 47,856 shares in BHP Billiton Limited.

We have not made available to any Director any interest in a registered scheme.

4.5.3    Operations Management Committee members

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 FY2017 by those senior executives who were members of the OMC (other than the Executive Director) during FY2017. 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 OMC under employee equity plans as at 30 June 2017 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 members of the OMC (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.

OMC member	BHP Billiton entity	As at date of Directors’ Report
Peter Beaven	BHP Billiton Limited BHP Billiton Plc		296,690 –
Geoff Healy	BHP Billiton Limited BHP Billiton Plc		54,298 –
Mike Henry	BHP Billiton Limited BHP Billiton Plc		91,993 196,262
Daniel Malchuk	BHP Billiton Limited BHP Billiton Plc		164,054 –
Steve Pastor	BHP Billiton Limited BHP Billiton Plc		52,953 –
Athalie Williams	BHP Billiton Limited BHP Billiton Plc		47,099 –

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 FY2017, 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, 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.

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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.

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$2,522,787 net during FY2017.

During FY2017, BHP paid defence costs for:

• certain employees and former employees of BHP (Affected Individuals) in relation to the charges filed by the Federal Prosecution 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 10-year bond notes due 2022–2024 between 31 October 2012 and 30 November 2015.

Other than this, 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 FY2017.

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 our organisation reinforces our shared purpose aligned to Our Charter and will result in a more harmonious workplace.

For more information on employee engagement and employee policies, including communications and regarding disabilities, refer to section 1.9.

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 43 US cents per share will be paid on 26 September 2017, resulting in total dividends determined in respect of FY2017 of 83 US cents per share. Details of the dividends paid are set out in note 15 ‘Share capital’ and note 17 ‘Dividends’ in section 5, and details of the Group’s dividend policy are set out in sections 1.5.2, 1.6.2 and 7.7.

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4.11    Auditors

A resolution to reappoint KPMG LLP as the auditor of BHP Billiton Plc will be proposed at the 2017 Annual General Meetings in accordance with section 489 of the UK Companies Act 2006.

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 has selected EY to be appointed as the Group’s external auditor from the financial year beginning 1 July 2019, subject to shareholder approval. The Board intends to put EY forward for shareholder approval at the Annual General Meetings in 2019. 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 2017, 2018 and 2019 financial years, subject to reappointment by shareholders at the 2017 and 2018 Annual General Meetings. Further information on the tender process is outlined in the Risk and Audit Committee Report in section 2.13.1.

During FY2017, 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 note 36 ‘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 FY2017.⁽¹⁾

⁽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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4.14    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 1.8.2, 1.11 to 1.13 and 6.3.

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 ensure the risk of non-compliance is minimised. For more information on BHP’s performance in relation to health, safety and the environment, refer to section 1.10.

Fines and prosecutions

For the purposes of section 299 (1)(f) of the Australian Corporations Act 2001, in FY2017 BHP received three fines in relation to Australian environmental laws and regulations at our operated assets, the total amount payable being US$27,580. One fine of US$12,500 was received at BHP Nickel West Kambalda Nickel Concentrator for failing to maintain a 300 millimetre freeboard at its return water dam. BHP Coal at Peak Downs Coal Mine received two fines related to storage and handling of chemicals and failure to comply with plan of operations.

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. For information on BHP’s total FY2017 greenhouse gas emissions and intensity, refer to sections 1.6.1 and 1.10.6.

For more information on environmental performance, including environmental regulation, refer to section 1.10 and the Sustainability Report 2017, 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 1.4.2 (Where we are)

• Section 4.2 (Share capital and buy-back programs)

• Section 7.3 (Organisational structure)

• Section 7.4 (Material contracts)

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• Section 7.5 (Constitution)

• Section 7.6 (Share ownership)

• Section 7.11 (Government regulations)

• Note 15 ‘Share capital’ and note 23 ‘Employee share ownership plans’ in section 5.

As at the date of this Directors’ Report, there were 16,452,544 unvested equity awards outstanding in relation to BHP Billiton Limited ordinary shares and 544,522 unvested equity awards outstanding in relation to BHP Billiton Plc ordinary shares. The expiry dates of these unvested equity awards range between February 2018 and August 2021 and there is no exercise price. No options over unissued shares or unissued interests in BHP have been granted since the end of FY2017 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 FY2017. Further details are set out in note 23 ‘Employee share ownership plans’ in section 5. Details of movements in share capital during and since the end of FY2017 are set out in note 15 ‘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: 7 September 2017

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5    Financial Statements

Refer to the pages beginning on page F-1 in this annual report.

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6    Additional information

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 reserve 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	Underground Large poly-metallic deposit of iron oxide-copper-uranium-gold mineralisation	Supplied via 275 kV power line from Port Augusta, transmitted by ElectraNet	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

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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 (refer to section 6.2.1) and reserve 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
WAIO
Mt Newman joint venture
Pilbara region, Western Australia Mt Whaleback Orebodies 18, 23, 24, 25, 29, 30 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 and 35 complements production from Mt Whaleback First ore produced at Newman hub in 2009 as part of Rapid Growth Plan 4	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 and secondary crushing and screening plants, heavy media beneficiation plant, stockyard blending facility, single cell rotary car dumper, train-loading facility (nominal capacity 73 Mtpa) Orebody 25: primary and secondary crushing and screening plant (nominal capacity 12 Mtpa)

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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 processing plants, primary crusher and overland conveyor (nominal capacity 80 Mtpa) Ore delivered to 2 train-loading facilities
JW4 joint venture
Pilbara region, Western Australia	Private road	BHP 68% ITOCHU Minerals and Energy of Australia 6.4% Mitsui Iron Ore Corporation 5.6% JFE Steel Australia 20%	BHP	Sublease over part of the Yandi mining lease expired on 1 April 2017	Production began in April 2006 JW4 JV sells all ore to the Yandi JV at the Yandi hub	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	JW4 JV sells ore to Yandi JV, which is then processed at the Yandi hub

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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, stockyards and supporting mining hub infrastructure (nominal capacity 58 Mtpa)

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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 expires on the earlier of termination of the mining lease or end of the Wheelarra Joint Venture	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

254

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, 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	Ore processing plant, primary crusher and overland conveyor (nominal capacity 60 Mtpa)

255

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

256

Coal mining operations

The following table contains additional details of our mining operations. The tables 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 between 2020 and 2043, 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 power source is under 5-year contracts	On-site beneficiation processing facilities Combined nominal capacity: in excess of 65 Mtpa

257

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 2018 and 2035, renewable for further periods as Queensland Government legislation allows Mining is permitted to continue under the legislation during the renewal application period	Production commenced at: Gregory 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	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 power source is under 5-year contracts	On-site beneficiation processing facility Facilities under care and maintenance

258

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 2038, 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	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	South Walker Creek coal beneficiated on-site Nominal capacity: in excess of 5 Mtpa Poitrel mine has Red Mountain joint venture with adjacent Millennium Coal mine to share processing and rail loading facilities Nominal capacity: in excess of 3 Mtpa

259

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 Power Station Export coal transported by third party rail to Newcastle port	BHP 100%	BHP	Various mining leases and licences expire between 2022 and 2037 Renewal is being sought for expired mining leases The original approvals permit mining and other activities to continue during renewal application	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	Local energy providers	Beneficiation facilities: coal handling, preparation, washing plants Nominal capacity: in excess of 23 Mtpa
Other operations
IndoMet Coal
Haju mine, Central Kalimantan, Indonesia	Public road Coal transported by truck to river port and then transported by barge to vessel anchorage (total distance approximately 615 km)	BHP 75% PT Alam Tri Abadi 25%	BHP	Mining leases expire in 2044 and are renewable for further periods as Indonesian Government approval allows	Production commenced in August 2015 Sale of our entire 75 per cent interest in Indomet Coal to Equity Partner PT Alam Tri Abadi was completed in October 2016	Open-cut mine Produces semi soft coking coal and thermal coal	Power is sourced from on-site generators	Beneficiation facilities: crushing facility located at the Muara Tuhup river port Nominal capacity: 1 Mtpa

260

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 reserve and resources 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
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 Australia 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 Australia Government Key leases expire between 2019 and 2034 Renewals at government discretion	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

261

Mine & location	Means of access	Ownership	Operator	Title, leases or options	History	Mine type & mineralisation style	Power source	Facilities, use & condition
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 Australia 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

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 Australia 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

262

Smelter, refinery or processing plant	Location	Ownership	Operator	Title, leases or options	Product	Nominal production capacity	Power source
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	71 ktpa nickel matte	Power is sourced from the local grid, which is supplied under a retail contract

263

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 reserve 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) Two 168 km concentrate pipelines 167 km water pipeline Port facilities at Coloso, Antofagasta

264

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

265

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	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: 102 ktpa copper cathode
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 Capital cost US$2.3 billion (100%)	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

266

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 reserve 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

267

Coal mining operations

The following table contains additional details of our mining operations. The tables 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

268

Mine & location	Means of access	Ownership	Operator	Title, leases or options	History	Mine type & mineralisation style	Power source	Facilities, use & condition
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

269

Petroleum

Petroleum operations

The following table contains additional details of our production operations. This table should be read in conjunction with the production table (refer to section 6.2.2) and reserve 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% Maxus US Exploration 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 Shenzi LLC 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

270

Operation & location	Product	Ownership	Operator	Title, leases or options	Nominal production capacity	Facilities, use & condition
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
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 Working interest withdrawal to be executed 1 August 2017, with 1 January 2017 effective date
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 63% Largest partners include Devon Energy and EF Non OP LLC	BHP operated approximately 37% of approximately 1,519 gross wells	We currently own leasehold interests in approximately 246,000 net acres Leases associated with producing wells remain in place as long as oil and gas is produced in paying quantities	Average daily production during FY2017 175 MMcf/d gas 48 Mbbl/d condensate 25 Mbbl/d NGL	Producing condensate and gas wells and associated pipeline and compression facilities

271

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 91% Residual ownership held by multiple partners	BHP operated approximately 91% of approximately 138 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 is produced in paying quantities	Average daily production during FY2017 52 MMcf/d gas 15 Mbbl/d oil 7 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 36% Largest partners include Chesapeake Energy and QEP Energy	BHP operated approximately 35% of approximately 1,084 gross wells	We currently own leasehold interests in approximately 197,000 net acres Leases associated with producing wells remain in place as long as gas is produced in paying quantities	Average daily production during FY2017 262 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	BHP operated approximately 19% of approximately 4,870 gross wells	We currently own leasehold interests in approximately 268,000 net acres Leases associated with producing wells remain in place as long as gas is produced in paying quantities	Average daily production during FY2017 265 MMcf/d gas	Producing gas wells with associated pipeline and compression infrastructure

272

Operation & location	Product	Ownership	Operator	Title, leases or options	Nominal production capacity	Facilities, use & condition
Australia
Bass Strait
Offshore and onshore Victoria	Oil and gas	Gippsland Basin joint venture (GBJV): BHP 50% Esso Australia (Exxon Mobil subsidiary) 50% Oil Basins Ltd 2.5% royalty interest in 19 production licences 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	200 Mbbl/d oil 1,075 MMcf/d gas 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 (4 gas plants, liquid processing facilities) – Interconnecting pipelines – Long Island Point LPG and oil storage facilities – Ethane pipeline

273

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: 2,500 MMcf/d gas 60 Mbbl/d condensate Goodwyn A platform: 1,450 MMcf/d gas 110 Mbbl/d condensate Angel platform: 960 MMcf/d gas 50 Mbbl/d condensate Withnell Bay gas plant: 600 MMcf/d gas 5-train LNG plant: 52,000 tpd LNG	Production from North Rankin and Perseus processed through the interconnected North Rankin A and North Rankin B platforms Production from Goodwyn and Searipple processed through Goodwyn A platform 4 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

274

Operation & location	Product	Ownership	Operator	Title, leases or options	Nominal production capacity	Facilities, use & condition
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 2018, 2033 and 2035 respectively	Production: 60 Mbbl/d Storage: 1 MMbbl	FPSO unit
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

275

Operation & location	Product	Ownership	Operator	Title, leases or options	Nominal production capacity	Facilities, use & condition
Minerva
Offshore and onshore Victoria	Gas and condensate	BHP 90% Santos (BOL) 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 (1 producing well) Single flow line transports gas to onshore gas processing facility Gas plant located approximately 4 km inland from Port Campbell
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 subsea well completions (17 oil producers, 4 gas producers and 7 gas injectors) 3 gas producers completed in FY2016 with production commenced in September 2017 quarter

276

Operation & location	Product	Ownership	Operator	Title, leases or options	Nominal production capacity	Facilities, use & condition
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 29.5% interest in ROD unitised integrated development ENI 70.5%	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
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 expire in 2018, 2046 and end of life of field	920 MMcf/d gas	Integrated oil and gas platform Keith developed as tie-back to Bruce facilities

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6.2    Production

6.2.1    Minerals

The table below details our mineral and derivative product production for all operations (except Petroleum) for the three years ended 30 June 2017, 2016 and 2015. 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 1.6.3.

	BHP Group interest %		BHP share of production (1) Year ended 30 June
			2017		2016		2015
Copper (2)
Payable metal in concentrate (’000 tonnes)
Escondida, Chile (3)		57.5		539.6		648.9		916.1
Antamina, Peru (4)		33.75		133.8		146.4		107.7
Total copper concentrate				673.4		795.3		1,023.8
Copper cathode (’000 tonnes)
Escondida, Chile (3)		57.5		232.0		330.3		310.4
Pampa Norte, Chile (5)		100		254.3		251.4		249.6
Olympic Dam, Australia		100		166.3		202.8		124.5
Total copper cathode				652.6		784.5		684.5
Total copper concentrate and cathode				1,326.0		1,579.8		1,708.3
Lead
Payable metal in concentrate (’000 tonnes)
Antamina, Peru (4)		33.75		5.5		3.7		2.1
Total lead				5.5		3.7		2.1
Zinc
Payable metal in concentrate (’000 tonnes)
Antamina, Peru (4)		33.75		87.5		55.4		66.4
Total zinc				87.5		55.4		66.4
Gold
Payable metal in concentrate (’000 ounces)
Escondida, Chile (3)		57.5		111		109		81.5
Olympic Dam, Australia (refined gold)		100		104		117.7		104.8
Total gold				215		226.7		186.3
Silver
Payable metal in concentrate (’000 ounces)
Escondida, Chile (3)		57.5		4,326		5,561		4,786
Antamina, Peru (4)		33.75		5,783		6,711		3,826
Olympic Dam, Australia (refined silver)		100		768		917		724
Total silver				10,877		13,189		9,336
Uranium
Payable metal in concentrate (tonnes)
Olympic Dam, Australia		100		3,661		4,363		3,144
Total uranium				3,661		4,363		3,144
Molybdenum
Payable metal in concentrate (tonnes)
Antamina, Peru (4)		33.75		1,144		1,113		472
Total molybdenum				1,144		1,113		472

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	BHP Group interest %		BHP Group share of production (1) Year ended 30  June
			2017		2016		2015
Iron ore
Western Australia Iron Ore
Production (’000 tonnes) (6)
Newman, Australia		85		68,283		65,941		63,697
Area C Joint Venture, Australia		85		48,744		46,799		49,994
Yandi Joint Venture, Australia		85		65,355		67,375		68,551
Jimblebar, Australia (7)		85		21,950		18,890		16,759
Wheelarra, Australia (8)		85		27,020		22,549		18,994
Total Western Australia Iron Ore				231,352		221,554		217,995
Samarco, Brazil (4)		50		–		5,404		14,513
Total iron ore				231,352		226,958		232,508
Coal
Metallurgical coal
Production (’000 tonnes) (9)
Blackwater, Australia		50		7,296		7,626		6,994
Goonyella Riverside, Australia		50		7,355		8,996		8,510
Peak Downs, Australia		50		6,055		5,031		5,111
Saraji, Australia		50		4,734		4,206		4,506
Gregory Joint Venture, Australia		50		–		1,329		3,294
Daunia, Australia		50		2,560		2,624		2,383
Caval Ridge, Australia		50		3,458		3,601		3,064
Total BHP Billiton Mitsubishi Alliance				31,458		33,413		33,862
South Walker Creek, Australia (10)		80		5,123		5,436		5,293
Poitrel, Australia (10)		80		3,189		3,462		3,466
Total BHP Billiton Mitsui Coal				8,312		8,898		8,759
Total Queensland Coal				39,770		42,311		42,621
IndoMet, Haju, Indonesia (11)		75		129		529		–
Total metallurgical coal				39,899		42,840		42,621
Energy coal
Production (’000 tonnes)
Navajo, United States (12)		100		451		3,999		4,858
San Juan, United States		100		–		3,053		5,165
Total New Mexico Coal				451		7,052		10,023
New South Wales Energy Coal, Australia		100		18,176		17,101		19,698
Cerrejón, Colombia (4)		33.3		10,959		10,094		11,291
Total energy coal				29,586		34,247		41,012
Other assets
Nickel
Saleable production (’000 tonnes)
Nickel West, Australia		100		85.1		80.7		89.9
Total nickel				85.1		80.7		89.9

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	BHP Group interest %		BHP Group share of production (1) Year ended 30  June
			2017		2016		2015
Discontinued operations (13)
Lead
Payable metal in concentrate (’000 tonnes)
Cannington, Australia		100		–		–		151.6
Total lead				–		–		151.6
Zinc
Payable metal in concentrate (’000 tonnes)
Cannington, Australia		100		–		–		60.0
Total zinc				–		–		60.0
Silver
Payable metal in concentrate (’000 ounces)
Cannington, Australia		100		–		–		18,718
Total silver				–		–		18,718
Metallurgical coal
Production (’000 tonnes)
Illawarra Coal, Australia		100		–		–		7,216
Total metallurgical coal				–		–		7,216
Energy coal
Production (’000 tonnes)
Energy Coal South Africa, South Africa (14)		90		–		–		28,677
Total energy coal				–		–		28,677
Nickel
Saleable production (’000 tonnes)
Cerro Matoso, Columbia		99.9		–		–		33.7
Total nickel				–		–		33.7
Alumina
Saleable production (’000 tonnes)
Worsley, Australia		86		–		–		3,181
Alumar, Brazil		36		–		–		1,103
Total alumina				–		–		4,284
Aluminium
Production (’000 tonnes)
Hillside, South Africa		100		–		–		581
Alumar, Brazil		40		–		–		40
Mozal, Mozambique		47		–		–		222
Total aluminium				–		–		843

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	BHP Group interest %		BHP Group share of production (1) Year ended 30  June
			2017		2016		2015
Discontinued operations (13) continued
Manganese ores
Saleable production (’000 tonnes)
Hotazel Manganese Mines, South Africa (15)		44.4		–		–		3,138
GEMCO, Australia (15)		60		–		–		4,086
Total manganese ores				–		–		7,224
Manganese alloys
Saleable production (’000 tonnes)
Metalloys, South Africa (15)(16)		60		–		–		379
TEMCO, Australia (15)		60		–		–		233
Total manganese alloys				–		–		612

⁽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 1.12. Samarco operations are currently suspended following the Samarco dam failure as explained in section 1.7.

⁽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 energy 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.

⁽¹³⁾  Production shown from 1 July 2014 to 30 April 2015. Refer to note 27 ‘Discontinued operations’ in section 5 for more information on the demerger of assets to form South32.

⁽¹⁴⁾  Shown on 100 per cent basis. BHP interest in saleable production is 90 per cent.

⁽¹⁵⁾  Shown on 100 per cent basis. BHP interest in saleable production is 60 per cent, except Hotazel Manganese Mines which is 44.4 per cent.

⁽¹⁶⁾  Production includes medium-carbon ferromanganese.

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6.2.2    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 2017, 2016 and 2015. 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
	2017		2016		2015
Production volumes
Crude oil and condensate (’000 of barrels)
Australia		18,658		20,307		21,397
United States		52,877		65,558		71,626
Other (5)		4,850		4,714		5,559
Total crude oil and condensate		76,385		90,579		98,582
Natural gas (billion cubic feet)
Australia		345.7		325.6		294.8
United States		285.3		375.9		431.7
Other (5)		36.8		43.2		60.1
Total natural gas		667.8		744.7		786.6
Natural gas liquids (1) (’000 of barrels)
Australia		7,423		7,646		7,214
United States		13,152		17,771		18,681
Other (5)		119		43		101
Total NGL (1)		20,694		25,460		25,996
Total production of petroleum products (million barrels of oil equivalent) (2)
Australia		83.5		82.2		77.8
United States		113.7		146.0		162.2
Other (5)		11.2		12.0		15.7
Total production of petroleum products		208.4		240.2		255.7
Average sales price
Crude oil and condensate (US$ per barrel)
Australia		50.59		43.55		76.30
United States		46.52		38.11		64.77
Other (5)		47.96		41.00		72.90
Total crude oil and condensate		47.61		39.48		67.68
Natural gas (US$ per thousand cubic feet)
Australia		5.06		5.22		7.59
United States		2.88		2.16		3.27
Other (5)		2.72		3.20		4.00
Total natural gas		4.00		3.57		4.95
Natural gas liquids (US$ per barrel)
Australia		27.76		24.86		44.93
United States		15.98		11.23		18.35
Other (5)		21.10		20.90		29.55
Total NGL		20.37		15.31		25.69
Total average production cost (US$ per barrel of oil equivalent) (3)(4)
Australia		5.78		6.12		7.08
United States		7.50		6.08		7.73
Other (5)		16.86		13.29		13.32
Total average production cost		7.31		6.46		7.88

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⁽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.

⁽⁴⁾  Total average production costs reported here do not include the costs to transport our produced hydrocarbons to the point of sale. Total production costs, including transportation costs, but excluding ad valorem and severance taxes, were US$10.23 per boe, US$9.73 per boe, and US$11.09 per boe for the years ended 30 June 2017, 2016 and 2015, respectively.

⁽⁵⁾ Other comprises Algeria, Pakistan (divested 31 December 2015), Trinidad and Tobago, and the United Kingdom.

6.3    Reserves

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.

How we estimate and report reserves

Petroleum’s reserves are estimated as of 30 June 2017.

Our proved reserves are estimated and reported according to US Securities and Exchange Commission (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

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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.

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 39 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 three 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

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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 Group Risk Assessment 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.

FY2017 reserves

Production for FY2017 totalled 208 MMboe in sales, which is a decrease of 32 MMboe from FY2016. 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 213 MMboe. The natural decline of production, primarily in our Onshore US fields and mature fields in other locations was the reason for the lower amount produced.

As of 30 June 2017, our proved reserves totalled 1535 MMboe and reflect a net increase of 445 MMboe (after total production) from the 1303 MMboe reported at FY2016. This increase was primarily the result of higher product prices experienced during the reporting period, reductions in unconventional well operating costs and an increase in planned drilling activity which enabled the addition of new proved undeveloped reserves for our Onshore US fields. As of 30 June 2017, 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 172 MMboe to proved reserves during FY2017. This comprised 105 MMboe of extensions related to the decision to proceed and funding of the Phase 2 development of the Mad Dog field and 3 MMboe related to drilling in the Atlantis field in the US Gulf of Mexico along with 65 MMboe related to planned drilling in new locations in our Onshore US operations within the next five years.

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Revisions

Overall, net revisions increased proved reserves by 274 MMboe during FY2017. Of this, the impact of commodity prices using the required SEC price-basis represented an increase of 271 MMboe. Well performance, interest changes and other revisions resulted in a net increase of 3 MMboe. Virtually all of the price-related increase occurred in our Onshore US fields.

In our US operations, the overall increase in proved reserves through revisions totalled 258 MMboe. This included price related additions of 269 MMboe and a net reduction of 19 MMboe related to performance and other revisions in our Onshore US operations. There were also additions of 9 MMboe for better than expected performance and increased prices in the Shenzi, Atlantis and Mad Dog fields in our Gulf of Mexico operations.

In our Australian operations, continued strong performance of the North West Shelf and Minerva fields added a total of 7 MMboe through revisions. This was partially offset by performance and other related reductions of 3 MMboe in Bass Strait fields. Overall, revisions for Australian fields totalled about 4 MMboe.

Operations outside of Australia and the United States also added approximately 12 MMboe in revisions. In the Angostura area fields in Trinidad and Tobago, 6 MMboe was added for better than expected performance. The ROD field in Algeria also added 4 MMboe primarily for better than expected performance. Our fields in the United Kingdom also added 1 MMboe for production during the year.

Sales

The sale of acreage in our Eagle Ford and Permian fields accounted for our reported sales of approximately 1 MMboe. There were no purchases during FY2017.

These results are summarised in the following tables, which detail estimated oil, condensate, NGL and natural gas reserves at 30 June 2017, 30 June 2016 and 30 June 2015, 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 79 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 2017, approximately five per cent of the proved reserves were attributable to such arrangements.

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Millions of barrels	Australia			United States			Other (b)			Total
Proved developed and undeveloped oil and condensate reserves (a)
Reserves at 30 June 2014		136.2			454.2			20.1			610.5
Improved recovery		–			3.4			0.1			3.5
Revisions of previous estimates		3.2			(53.7	)		2.4			(48.1	)
Extensions and discoveries		5.9			52.0			–			58.0
Purchase/sales of reserves		–			(1.0	)		–			(1.0	)
Production		(21.4	)		(71.6	)		(5.6	)		(98.5	)
Total changes		(12.2	)		(70.9	)		(3.1	)		(86.2	)
Reserves at 30 June 2015		124.0			383.3			17.1			524.3
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			26.5			393.4
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			26.0			455.3
Developed
Proved developed oil and condensate reserves
as of 30 June 2014		96.5			237.8			14.7			349.0
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
Developed reserves as of 30 June 2017		76.2			162.3			21.9			260.5
Undeveloped
Proved undeveloped oil and condensate reserves
as of 30 June 2014		39.7			216.4			5.4			261.5
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
Undeveloped reserves as of 30 June 2017		12.4			178.4			4.0			194.8

^(a)  Small differences are due to rounding to first decimal place.

^(b)  ‘Other’ comprises Algeria, Pakistan (divested in FY2015), Trinidad and Tobago and the United Kingdom.

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Millions of barrels	Australia			United States			Other (c)			Total
Proved developed and undeveloped NGL reserves (a)
Reserves at 30 June 2014		82.1			156.6	(d)		–			238.7	(d)
Improved recovery		–			0.3			–			0.3
Revisions of previous estimates		0.6			(62.4	)		0.1			(61.7	)
Extensions and discoveries		1.1			33.1			–			34.2
Purchase/sales of reserves		–			(0.2	)		–			(0.2	)
Production (b)		(7.2	)		(18.7	)		(0.1	)		(26.0	)
Total changes		(5.5	)		(48.0	)		–			(53.5	)
Reserves at 30 June 2015		76.6			108.6	(d)		–			185.2	(d)
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)		–			107.0	(d)
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)		–			124.0	(d)
Developed
Proved developed NGL reserves
as of 30 June 2014		46.0			75.0			–			121.0
as of 30 June 2015		40.1			59.7			–			99.8
as of 30 June 2016		38.0			30.7			–			68.7
Developed reserves as of 30 June 2017		56.6			31.4			–			88.0
Undeveloped
Proved undeveloped NGL reserves
as of 30 June 2014		36.1			81.5			–			117.7
as of 30 June 2015		36.5			48.9			–			85.4
as of 30 June 2016		33.3			4.9			–			38.2
Undeveloped reserves as of 30 June 2017		8.6			27.5			–			36.1

^(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 FY2015), Trinidad and Tobago and the United Kingdom.

^(d) For FY2014, FY2015, FY2016 and FY2017 amounts include 3.9, 4.2, 0.2 and 2.1 million barrels respectively, which are anticipated to be consumed as fuel in operations in the United States.

288

Billions of cubic feet	Australia (c)			United States			Other (d)			Total
Proved developed and undeveloped natural gas reserves (a)
Reserves at 30 June 2014		3,495.4	(e)		5,623.5	(f)		442.6	(g)		9,561.5	(h)
Improved recovery		–			0.8			–			0.8
Revisions of previous estimates		124.3			(2,207.6	)		32.8			(2,050.5	)
Extensions and discoveries		185.4			509.7			–			695.1
Purchase/sales of reserves		–			(195.6	)		–			(195.6	)
Production (b)		(321.8	)		(434.6	)		(64.8	)		(821.1	)
Total changes		(12.0	)		(2,327.3	)		(32.0	)		(2,371.3	)
Reserves at 30 June 2015		3,483.4	(e)		3,296.1	(f)		410.6	(g)		7,190.2	(h)
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)		310.8	(g)		4,813.8	(h)
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)		315.9	(g)		5,731.9	(h)
Developed
Proved developed natural gas reserves
as of 30 June 2014		2,553.7			3,208.3			315.5			6,077.5
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
Developed reserves as of 30 June 2017		2,346.3			1,556.4			315.9			4,218.5
Undeveloped
Proved undeveloped natural gas reserves		941.7			2,415.2			127.1			3,484.0
as of 30 June 2014
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
Undeveloped reserves as of 30 June 2017		523.4			989.9			–			1,513.3

^(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 FY2015), Trinidad and Tobago and the United Kingdom.

^(e)  For FY2014, FY2015, FY2016 and FY2017 amounts include 360, 343, 321 and 295 billion cubic feet respectively, which are anticipated to be consumed as fuel in operations in Australia.

^(f)  For FY2014, FY2015, FY2016 and FY2017 amounts include 185, 154, 75 and 155 billion cubic feet respectively, which are anticipated to be consumed as fuel in operations in the United States.

^(g)  For FY2014, FY2015, FY2016 and FY2017 amounts include 30, 27, 17 and 17 billion cubic feet respectively, which are anticipated to be consumed as fuel in operations in Other areas.

^(h)  For FY2014, FY2015, FY2016 and 2017 amounts include 575, 524, 413 and 467 billion cubic feet respectively, which are anticipated to be consumed as fuel in operations.

289

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 2014		800.9	(e)		1,548.0	(f)		93.9	(g)		2,442.8	(h)
Improved recovery		–			3.8			0.1			3.9
Revisions of previous estimates		24.6			(484.0	)		7.9			(451.5	)
Extensions and discoveries		37.9			170.0			–			208.0
Purchase/sales of reserves		–			(33.8	)		–			(33.8	)
Production (c)		(82.2	)		(162.7	)		(16.5	)		(261.4	)
Total changes		(19.8	)		(506.7	)		(8.4	)		(534.9	)
Reserves at 30 June 2015		781.1	(e)		1,041.3	(f)		85.5	(g)		1,907.9	(h)
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)		78.2	(g)		1,302.7	(h)
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 (c)		(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)		78.6	(g)		1,534.6	(h)
Developed
Proved developed oil, condensate, natural gas and NGL reserves
as of 30 June 2014		568.1			847.6			67.3			1,483.0
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
Developed reserves as of 30 June 2017		523.8			453.1			74.6			1,051.6
Undeveloped
Proved undeveloped oil, condensate, natural gas and NGL reserves
as of 30 June 2014		232.8			700.4			26.6			959.8
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
Undeveloped reserves as of 30 June 2017		108.2			370.8			4.0			483.1

^(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 FY2015), Trinidad and Tobago and the United Kingdom.

^(e)  For FY2014, FY2015, FY2016 and FY2017 amounts include 60, 57, 53 and 49 million barrels equivalent respectively, which are anticipated to be consumed as fuel in operations in Australia.

^(f)  For FY2014, FY2015, FY2016 and FY2017 amounts include 35, 30, 13 and 28 million barrels equivalent respectively, which are anticipated to be consumed as fuel in operations in the United States.

^(g)  For FY2014, FY2015, FY2016 and FY2017 amounts include 5, 4, 3 and 3 million barrels equivalent respectively, which are anticipated to be consumed as fuel in operations in Other areas.

^(h)  For FY2014, FY2015, FY2016 and FY2017 amounts include 100, 91, 69 and 80 million barrels equivalent respectively, which are anticipated to be consumed as fuel in operations.

290

Proved undeveloped reserves

At 30 June 2017, Petroleum had 483 MMboe of proved undeveloped reserves, which represented 31 per cent of year-end 2017 proved reserves of 1535 MMboe. Approximately 263 MMboe or 54 per cent of the proved undeveloped reserves reside in our conventional offshore fields in Australia, the Gulf of Mexico and Trinidad and Tobago, while 220 MMboe or 46 per cent resides in our Onshore US fields. The current proved undeveloped reserves reflect a net increase of 148 MMboe from the 335 MMboe reported at 30 June 2016. This increase was primarily the result of adding 202 MMboe of new proved undeveloped reserves for drilling planned over the next five years in our Onshore US fields and in the Gulf of Mexico where 105 MMboe was added for the Mad Dog Phase 2 project sanction and 3 MMboe was added in the Atlantis field as a result of drilling and reservoir assessments.

These additions were offset by development activities that converted 177 MMboe of proved undeveloped reserves to proved developed reserves. The largest of these conversions occurred in Australia where 111 MMboe were converted to proved developed in the Kipper, Tuna and Turrum fields in the Bass Strait with the start-up of the Longford gas conditioning plant. The start-up and first gas from the Tidepole field in the Greater Western Flank 1 project in the North West Shelf also converted 10 MMboe to proved developed reserves. In Trinidad and Tobago, 23 MMboe was converted to proved developed reserves for the completion of Angostura Phase 3 development. In the United States, drilling and completion activities resulted in the conversion of 15 MMboe to proved developed reserves in the Eagle Ford field, 9 MMboe in the Atlantis and 8 MMboe in the Mad Dog (Spar A) fields in the Gulf of Mexico.

Of the 483 MMboe currently classified as proved undeveloped at 30 June 2017, 76 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 and are scheduled to start producing within the next five years. The largest component of this is in the Atlantis field in the Gulf of Mexico, which contains 17 MMboe, while the Mad Dog field contains 6 MMboe, both of which are actively being drilled. 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. During FY2017, Petroleum continued active development of our inventory of proved undeveloped projects by converting 177 MMboe to proved developed reserves. Over the past three years, the conversion of proved undeveloped reserves to developed has totalled 392 MMboe, averaging 131 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 FY2017, Petroleum spent US$1.4 billion on development activities worldwide.

291

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 2017 (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 2016, 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	US$
Copper	2.60/lb
Gold	1,225/ozt
Nickel	5.79/lb
Silver	17.29/ozt
Lead	0.87/lb
Zinc	0.94/lb
Uranium (1)	31.93/lb
Iron Ore – Fines	63.93/dmt
Iron Ore – Lump	74.76/dmt
Metallurgical Hard Coking Coal	114.88/t
Metallurgical Weak Coking Coal	78.30/t
Thermal Coal Newcastle (1)	65.12/t
Thermal Coal Colombia (1)	58.36/t

⁽¹⁾  Some commodities are traded on a contractual basis for which we are unable to disclose prices due to commercial sensitivity. 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/tonne 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 our 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. All tonnes and grade / quality information has been rounded, hence small differences may be present in the totals.

292

Copper

Ore Reserves in accordance with Industry Guide 7

As at 30 June 2017																																					As at 30 June 2016
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						Mt		%TCu		%SCu						Mt		%TCu		%SCu										Mt		%TCu		%SCu
Copper
Escondida (5)		Oxide		95		0.69		–						203		0.60		–						298		0.63		–						53		57.5		300		0.66		–						58
		Sulphide		3,480		0.73		–						1,780		0.65		–						5,260		0.70		–										5,670		0.67		–
		Sulphide Leach		1,600		0.41		–						538		0.39		–						2,140		0.40		–										2,500		0.43		–
Cerro Colorado		Oxide		36		0.57		0.40						40		0.60		0.40						76		0.59		0.40						6.0		100		90		0.55		0.39						7.2
		Supergene Sulphide		16		0.63		0.11						23		0.70		0.12						39		0.67		0.12										47		0.64		0.11
Spence		Oxide		34		0.64		0.44						1.4		0.84		0.66						35		0.65		0.45						7.8		100		35		0.72		0.51						8.0
		Oxide Low Solubility		16		0.85		0.37						8.7		0.63		0.26						25		0.77		0.33										24		0.76		0.33
		Supergene Sulphide		94		0.82		0.11						18		0.64		0.12						112		0.79		0.11										125		0.82		0.11
		ROM		–		–		–						9.4		0.37		0.14						9.4		0.37		0.14										13		0.42		0.11
			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		Sulphide		161		2.07		0.63		0.68		5		347		1.95		0.56		0.74		4		508		1.99		0.58		0.72		4		52		100		505		1.96		0.58		0.71		4		51
		Low-grade		9.2		1.18		0.38		0.50		3		28		1.11		0.35		0.51		3		37		1.13		0.36		0.51		3						35		1.03		0.35		0.47		2
			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		Sulphide Cu only		110		1.04		0.15		8		390		187		1.02		0.19		8		320		297		1.03		0.17		8		350		10		33.75		317		1.01		0.16		8		340		11
		Sulphide Cu-Zn		56		0.96		2.11		17		80		184		0.82		2.01		13		80		240		0.85		2.03		14		80						256		0.89		2.03		14		80

293

⁽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). Sulphide ore is processed in the concentrator plants as a result of optimised mine plans 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 in the dump leaching plant as an alternative to the concentrator process.
Cerro Colorado	Oxide & Supergene Sulphide	³ 0.30%TCu
Spence	Oxide, Oxide Low Solubility & Supergene Sulphide	³ 0.30%TCu
	ROM	³ 0.10%TCu
Olympic Dam	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, 2.3g/tAg, 138ppmMo and 6,700t/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, 0.72%Zn, 12.1g/tAg and 6,500t/hr mill throughput.

Antamina – All metals used in net value calculations for the Antamina 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 x 30m Sulphide: 50m x 50m Sulphide Leach: 60m x 60m	Oxide: 45m x 45m Sulphide: 90m x 90m Sulphide Leach: 115m x 115m
Cerro Colorado	45m to 55m	120m
Spence	Oxide & Oxide Low Solubility: maximum 50m x 50m Supergene Sulphide: maximum 70m x 70m	Maximum 100m x 100m for all Ore Types
Olympic Dam	20m to 30m	30m to 70m
Antamina	25m to 40m	40m to 75m

⁽³⁾  Ore delivered to process plant.

294

⁽⁴⁾  Metallurgical recoveries for the operations were:

Deposit	Metallurgical Recovery
Escondida	Oxide: 62% Sulphide: 82% Sulphide Leach: 32%
Cerro Colorado	Oxide & Supergene Sulphide: 72%
Spence	Oxide: 80% Oxide Low Solubility: 80% Supergene Sulphide: 82% 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 81%, Ag 63%, Mo 0%

⁽⁵⁾  Escondida – Sulphide and Sulphide Leach Ore Reserves have decreased in response to a decrease in the copper price reducing the Life of Asset mine plan. Inherent within the Reserve Life calculation were Oxide and Sulphide Leach, which have a Reserve Life of 13 years and 32 years respectively.

295

Iron Ore ⁽¹⁾

Ore Reserves in accordance with Industry Guide 7

As at 30 June 2017																																										As at 30 June 2016
		Proven Reserves												Probable Reserves												Total Reserves												Reserve Life (years)		BHP Interest %		Total Reserves												Reserve Life (years)
Commodity Deposit (2)(3)(4)(5)	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 (6)(7)(8)(9)	BKM		1,120		62.7		0.12		3.2		2.2		4.2		1,770		61.2		0.13		4.3		2.4		5.1		2,890		61.8		0.12		3.9		2.3		4.7		14		88		2,600		61.9		0.12		3.8		2.3		4.7		14
	BKM Bene		20		58.3		0.11		9.3		3.4		2.1		30		57.9		0.10		10.3		3.2		2.0		50		58.0		0.11		9.9		3.3		2.0						50		57.4		0.10		11.3		3.1		1.9
	CID		390		56.8		0.04		6.1		1.5		10.6		70		57.2		0.04		6.1		1.5		10.3		460		56.9		0.04		6.1		1.5		10.6						670		56.5		0.05		6.3		1.8		10.7
	MM		310		62.5		0.07		2.8		1.6		5.7		410		60.4		0.07		4.1		2.1		6.6		720		61.3		0.07		3.6		1.9		6.2						660		60.9		0.07		4.0		2.0		6.2

⁽¹⁾ Samarco JV – 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 2017. 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 72% (tonnage basis).

⁽⁴⁾ The reserve 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: WAIO 50–58%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 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 reserves are selected 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⁾ BKM Ore Reserves have increased due to classification upgrades at Newman JV and Mining Area C. CID Ore Reserves have decreased after a processing capability re-evaluation of lower CID. Reserve life remains the same due to an increase in nominated production rate from 275Mtpa to 293Mtpa.

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Metallurgical Coal

Coal Reserves in accordance with Industry Guide 7

As at 30 June 2017																																					As at 30 June 2016
			Proven Reserves		Probable Reserves		Total Reserves		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	OC	Met		563		19		582		443		9.1		22.8		0.53		14		10.9		23.1		0.57		457		9.2		22.8		0.53		41		50		469		9.2		22.8		0.53		42
Broadmeadow	UG	Met		73		119		192		53		8.0		23.6		0.53		76		9.9		23.5		0.55		129		9.1		23.5		0.54						129		9.1		23.5		0.54
Peak Downs	OC	Met		423		339		762		261		10.6		22.3		0.60		208		10.6		22.7		0.65		469		10.6		22.5		0.62		27		50		483		10.6		22.5		0.62		29
Caval Ridge (6)	OC	Met		281		95		376		168		11.0		22.4		0.57		52		11.0		22.0		0.58		220		11.0		22.3		0.58		30		50		228		11.0		22.3		0.58		35
Saraji (7)	OC	Met		397		44		441		235		10.2		17.9		0.64		22		11.2		19.0		0.78		257		10.3		18.0		0.66		24		50		234		10.2		18.0		0.64		23
Norwich Park (8)(9)	OC	Met		111		37		148		82		10.3		16.8		0.68		25		10.3		16.4		0.69		107		10.3		16.7		0.68		42		50		73		10.3		16.8		0.68		29
Blackwater (10)	OC	Met/Th		152		143		295		143		8.1		26.6		0.43		135		8.8		26.9		0.44		278		8.4		26.7		0.43		15		50		325		8.9		26.4		0.44		21
Daunia	OC	Met		76		50		126		62		8.0		20.8		0.35		42		9.1		19.9		0.34		104		8.4		20.4		0.35		23		50		111		8.4		20.4		0.35		24
Gregory JV
Gregory (9)	OC	Met		3.1		–		3.1		2.6		7.4		36.3		0.59		–		–		–		–		2.6		7.4		36.3		0.59		1.0		50		2.6		7.4		36.3		0.59		1.0
BHP Mitsui Coal
South Walker Creek (11)	OC	Met		109		42		151		87		9.2		13.5		0.30		33		9.2		13.4		0.29		120		9.2		13.4		0.30		19		80		108		9.2		13.2		0.29		17
Poitrel (12)	OC	Met		36		19.0		55		28		8.8		23.8		0.34		15.0		8.8		23.8		0.34		43		8.8		23.8		0.34		11		80		30		8.8		22.9		0.33		7.7
Indonesia
IndoMet Coal (13)
Haju	OC	Met		–		–		–		–		–		–		–		–		–		–		–		–		–		–		–		–		–		4		6.1		38.5		0.93		4.4
	OC	Th		–		–		–		–		–		–		–		–		–		–		–		–		–		–		–						0.4		9.2		37.9		1.68

⁽¹⁾  Cut-off criteria applied were: Goonyella Riverside, Peak Downs, Caval Ridge, Norwich Park, Gregory, South Walker Creek, Poitrel ³ 0.5m seam thickness; Saraji ³ 0.4m seam thickness; Blackwater, Daunia 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 Broadmedow) were used to classify the reserves. Drill hole spacings vary between seams and geological domains and were determined in conjunction with geostatistical analyses where applicable. The range of maximum spacings was:

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 3,600m
Norwich Park	500m to 1,400m	1,000m to 2,800m
Blackwater	750m	750m to 1,400m
Daunia	650m	1,200m
Gregory	850m	–
South Walker Creek	500m to 800m	1,000m to 1,500m
Poitrel	300m to 950m	550m to 1,850m

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⁽³⁾  Product recoveries for the operations were:

Deposit	Product Recovery
Goonyella Riverside Broadmeadow	72%
Peak Downs	61%
Caval Ridge	58%
Saraji	58%
Norwich Park	71%
Blackwater	95%
Daunia	83%
Gregory	81%
South Walker Creek	79%
Poitrel	75%

⁽⁴⁾  Total Coal Reserves were at the moisture content when mined (4% CQCA JV, Gregory JV, BHP Mitsui Coal). Total Marketable Coal Reserves were at a product specific moisture content (9.5-10% Goonyella Riverside Broadmeadow; 9.5% Peak Downs; 10% Caval Ridge; 10% Saraji; 7.5-11.5% Blackwater; 9.5-10% Daunia; 10-11% Norwich Park; 7.5% Gregory; 9% South Walker Creek; 10-12% Poitrel) and at an air-dried quality basis, for sale after beneficiation of the Total Coal Reserves.

⁽⁵⁾  Coal delivered to handling plant.

⁽⁶⁾  Caval Ridge – The decrease in Reserve Life was due to a change in the nominated production rate from 11Mtpa to 12.4Mtpa.

⁽⁷⁾  Saraji – The increase in Coal Reserves was due to a reserves re-estimation and updated economic assumptions (changes in prices, costs and foreign exchange rates).

⁽⁸⁾  Norwich Park – The increase in Coal Reserves was due to revised Modifying Factors and economic assumptions (changes in prices, costs and foreign exchange rates), which also affected the Reserve Life.

⁽⁹⁾  Norwich Park and Gregory – Remain on care and maintenance.

⁽¹⁰⁾  Blackwater – The Total Marketable Coal Reserves decreased due to being uneconomic after testing with the 3-year average historical coal price. The decrease in Reserve Life was due to an increase in nominated production rate from 16.6Mtpa to 20Mtpa.

⁽¹¹⁾  South Walker Creek – The Coal Reserves increased due to inclusion of new areas in the mine plan.

⁽¹²⁾  Poitrel – The Coal Reserves and Reserve Life increased due to revised economic assumptions (changes in prices, costs and foreign exchange rates) and inclusion of material in R40/50 Levee area.

⁽¹³⁾  Haju – Divestment of IndoMet Coal completed on 14 October 2016.

298

Energy Coal

Coal Reserves in accordance with Industry Guide 7

As at 30 June 2017																																													As at 30 June 2016
Commodity Deposit (1)(2)(3)(4)	Mining Method		Coal Type		Proven Reserves		Probable Reserves		Total Reserves		Proven Marketable Reserves										Probable Marketable Reserves										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		423		191		614		334		17.7		31.2		0.58		6,210		146		17.5		30.8		0.52		6,170		480		17.6		31.1		0.56		6,200		22		100		758		16.9		30.3		0.54		6,450		30
Colombia
Cerrejón (7)(8)		OC		Th		473		71		544		459		9.3		32.7		0.58		6,070		69		9.0		32.7		0.55		6,090		528		9.2		32.7		0.57		6,072		16		33.33		599		8.7		32.8		0.58		6,090		16
New Mexico (9)
Navajo		OC		Th		–		–		–		–		–		–		–		–		–		–		–		–		–		–		–		–		–		–		–		–		10		21.8		–		0.76		4,900		2.0

⁽¹⁾  Cut-off criteria:

Deposit	Coal Reserves
Mt Arthur Coal	³ 0.3m seam thickness and £ 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	77%
Cerrejón	98%

⁽⁴⁾  Total Coal Reserves were at the moisture content when mined (8.7% Mt Arthur Coal; 13.0% Cerrejón). Total Marketable Coal Reserves were at a product specific moisture content (9.9% Mt Arthur Coal; 13.1% Cerrejón) and at an air-dried quality basis for Mt Arthur Coal and at a total moisture quality basis for Cerrejón, for sale after the beneficiation of the Total Coal Reserves.

⁽⁵⁾  Mt Arthur Coal – Coal delivered to handling plant.

⁽⁶⁾  Mt Arthur Coal – The Total Marketable Coal Reserves decreased due to reserve re-estimation based on a new geological model, which redefined some Probable Reserves, and a revised reserve footprint. The Coal Reserves were uneconomic after testing with the 3-year average historical coal price.

⁽⁷⁾  Cerrejón – Marketable Coal Reserves decreased due to geotechnical adjustment of pit slopes and lower product sales price.

⁽⁸⁾  Cerrejón – While there was no suspension of any Cerrejón permit as of 30 June 2017 in response to ongoing local community legal challenges, BHP continues to monitor the situation for potential impact on mining.

⁽⁹⁾ Navajo – Divestment completed in December 2013. BHP remained the mine manager and operator until 31 December 2016.

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Other assets

Ore Reserves in accordance with Industry Guide 7

As at 30 June 2017																		As at 30 June 2016
		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		1.7		1.2		0.25		0.92		1.9		1.2		2.0		100		2.7		1.2		2.2
	SP		0.16		1.2		–		–		0.16		1.2						0.15		1.1
Mt Keith	OC		21		0.65		0.28		0.49		21		0.65		3.0		100		38		0.61		4.2
	SP		6.4		0.49		3.8		0.45		10		0.48						7.2		0.47

⁽¹⁾  Cut-off criteria – Leinster: ³ 0.60%Ni and Mt Keith: variable ranging from 0.35-0.40% Ni and ³ 0.18% recoverable Ni.

⁽²⁾  Approximate drill hole spacings used to classify the reserves were:

Deposit	Proven Reserves	Probable Reserves
Leinster	25m x 25m	25m x 50m
Mt Keith	60m x 40m	80m x 80m

⁽³⁾  Ore delivered to process plant.

⁽⁴⁾  Metallurgical recoveries for the operations were:

Deposit	Metallurgical Recovery
Leinster	83%
Mt Keith	64%

⁽⁵⁾  Leinster – The increase in Ore Reserves after depletion for Leinster OC was due to deepening of the ultimate pit, enabled by reduced mining cost.

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6.4    Major projects

At the end of FY2017, BHP had three major projects under development with a combined budget of US$5.1 billion over the life of the projects.

During FY2017, we approved an investment of US$2,154 million for the Mad Dog Phase 2 petroleum project.

Capital and exploration expenditure declined by 32 per cent during FY2017 to US$5.2 billion and is expected to increase to US$6.9 billion in FY2018.

Projects which delivered first production during FY2017

Business	Project and ownership	Capacity (1)	Date of initial production				Capital expenditure (US$M) (1)
			Actual		Target		Budget
Petroleum	Bass Strait Longford Gas Conditioning Plant (Australia) 50% (non-operator)	Designed to process approximately 400 million cubic feet per day of high CO2 gas		Q4 CY2016		CY2016		520
Copper	Escondida Water Supply (Chile) 57.5%	New desalination facility to ensure continued water supply to Escondida		Q1 CY2017		CY2017		3,430
								3,950

Projects in execution at the end of FY2017

Business	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 47% complete			CY2019		314
Petroleum	Mag 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 3% complete			CY2022		2,154
							2,468

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Other projects in progress at the end of FY2017

			Capital expenditure (US$M) (1)
Business	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		2,600
				2,600

⁽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.

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

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$6.1 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.

On 2 March 2016, BHP Billiton Brasil, together with Vale and Samarco, entered into an 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 to remediate and provide compensation for damage caused by the Samarco dam failure (Framework Agreement).

302

The Framework Agreement outlines a comprehensive set of actions, measures and programs, including 17 environmental and 22 socio-economic programs to restore and compensate the communities and environment affected by the dam failure. A private foundation named Fundação Renova, maintained by BHP Billiton Brasil, Vale and Samarco manages and implements all projects and measures within the scope of programs.

The Framework Agreement has a term of 15 years, renewable for periods of one year successively until all the obligations under the Framework Agreement have been performed.

Under the Framework Agreement, Samarco is responsible for funding Fundação Renova with calendar year contributions as follows:

• R$2 billion (US$599 million) in 2016;

• R$1.2 billion (approximately US$365 million) in 2017;

• R$1.2 billion (approximately US$365 million) in 2018;

• R$500 million (approximately US$150 million) for a special project to be spent on sewage treatment and landfill works from 2016 to 2018.

Annual contributions for each of the years 2019, 2020 and 2021 will be in the range of R$800 million (approximately US$245 million) and R$1.6 billion (approximately US$485 million), depending on the remediation and compensation projects which are to be undertaken in the 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 BHP Billiton Brasil and Vale has funding obligations under the Framework Agreement in proportion to its 50 per cent shareholding in Samarco.

As a formal suspension of the public civil claim, the Framework Agreement is subject to Court ratification. On 5 May 2016, the Framework Agreement was ratified by the Conciliation Chamber of the Federal Court of Appeals in Brasilia suspending this public civil claim. The Federal Prosecutor’s Office appealed the ratification of the Framework Agreement and on 30 June 2016, the Superior Court of Justice in Brazil issued a preliminary order (Interim Order) suspending the 5 May 2016 ratification decision of the Conciliation Chamber of the Federal Court of Appeals, and reinstating this public civil claim before the first instance court, including the R$2 billion (approximately US$605 million) injunction. BHP Billiton Brasil, Vale and Samarco and the Federal Government appealed the Interim Order. On 4 November 2016, the 12th Federal Court of Belo Horizonte reduced the R$2 billion injunction to R$1.2 billion (approximately US$365 million).

While a final decision by the Court on the issue of ratification of the Framework Agreement is pending, the Preliminary Agreement (referred to below) suspends the R$1.2 billion (approximately US$365 million) injunction order under this public civil claim.

The Preliminary Agreement also requests suspension of this public civil claim with a decision from the Court pending. The R$1.2 billion (approximately US$365 million) injunction order may be reinstated if a final settlement arrangement is not agreed by 30 October 2017.

While a final decision on ratification of the Framework Agreement is pending and negotiation of a settlement of this public civil claim and the R$155 billion (approximately US$47 billion) Federal Public Prosecution Office claim (referred to below) under the Preliminary Agreement are ongoing, the Framework Agreement remains binding between the parties and the Foundation will continue to implement the programs under the Framework Agreement.

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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$6.1 billion) public civil claim and the R$155 billion (approximately US$47 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, Vale or Samarco, but will be considered in the negotiation of a final settlement arrangement with the Federal Prosecutors.

Under the Preliminary Agreement, BHP Billiton Brasil, Vale and Samarco agreed interim security (Interim Security) comprising:

• R$1.3 billion (approximately US$395 million) in insurance bonds;

• R$100 million (approximately US$30 million) in liquid assets;

• a charge of R$800 million (approximately US$245 million) over Samarco’s assets;

• R$200 million (approximately US$60 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.

On 29 June 2017, the Court extended the final date for negotiation of a settlement until 30 October 2017, allowing for the continuation of the Interim Security arrangements and the provision of ongoing expert advice to the Federal Prosecutors in respect of the programs under the Framework Agreement. The parties will use best efforts to achieve a final settlement arrangement by 30 October 2017 under the timeframe established in the Preliminary Agreement. On 16 March 2017, the Court partially ratified the Preliminary Agreement and suspended 11 public civil actions.

R$155 billion public civil claim commenced by the Federal Public Prosecution Service

On 3 May 2016, the Federal Public Prosecution Office Service 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 defendants⁽¹⁾ by the Court) – seeking R$155 billion (approximately US$47 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$2.3 billion) in a special company account and provide guarantees equivalent to R$155 billion (approximately US$47 billion). The injunctions also seek to prohibit BHP Billiton Brasil, Vale and Samarco from distributing dividends and selling certain assets (among other things).

BHP Billiton Brasil has filed two petitions to the 12th Federal Court of Belo Horizonte requesting the dismissal of the injunction requests made by the Federal Public Prosecution Service. On 7 July 2016, a first decision was made by the Court that, among other issues, postponed the analysis of the injunction requests, ordered Samarco to present, within 30 days, its plan and measures regarding tailings containment, and scheduled a hearing for conciliation for 13 September 2016. The Court has not made any decisions in relation to these injunctions applications.

⁽¹⁾  Currently, solely the companies, the Federal Government and the State of Minas Gerais are defendants.

304

On 26 January 2016, with regard to the Preliminary Agreement, the Court suspended this public civil claim, including the R$7.7 billion (approximately US$2.3 billion) injunction request.

However, proceedings may be resumed if a final settlement arrangement is not agreed by 30 October 2017.

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.

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$90 million) in Samarco’s bank accounts. The Court granted the injunction freezing R$300 million (approximately US$90 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$6,000) payment to each displaced family;

• a R$100,000 (approximately US$30,000) payment to each of the families of those deceased, as advance compensation.

There have been multiple hearings and injunctions 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$9,000) 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. 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.

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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$3 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.

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$605 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$305 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$305 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.

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$3 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$305 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.

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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 1.7.

Samarco has been named as a defendant in more than 16,000 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$300) to R$10,000 (approximately US$3,000). 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 13,000 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 (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.

Under the criminal charges against BHP Billiton Brasil, Vale and Samarco and certain individuals, the Federal Prosecutors requested a range of provisional measures, including a R$20 billion (approximately US$6.1 billion) asset freezing order application. On 14 July 2017, the Federal Criminal Court of Ponte Nova denied all of the provisional measures requested by the Federal Prosecutors, including the application for an asset freezing order.

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.

The amount of damages sought by the plaintiff on behalf of the putative class is unspecified. 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.

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 and BHP Billiton Plc.

Class action complaint – 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 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 US federal securities laws and indicates that the plaintiff will seek certification to proceed as a class action.

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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 current and former 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.

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.

Tax and royalty matters

The Group presently has unresolved tax and royalty matters for which the timing of resolution and potential economic outflow are uncertain. For details of those matters, refer to note 5 ‘Income tax expense’ in section 5.

Anti-corruption investigations

In May 2015, the Group announced the resolution of the previously disclosed investigation by the SEC into potential breaches of the US Foreign Corrupt Practices Act. The US Department of Justice has also completed its investigation into BHP without taking any action.

The matter was resolved with the SEC pursuant to an administrative order, which imposed a US$25 million civil penalty. Under the SEC order, BHP was also required to self-report on its compliance program to the SEC for a period of 12 months following the date of the SEC order (20 May 2015). This obligation has now been satisfied.

As previously disclosed, the Australian Federal Police (AFP) announced an investigation in 2013 relating to matters the subject of section 70.2 of the Commonwealth Criminal Code. The AFP has advised that it has finalised its investigation and does not intend to take any further action at this time.

6.6    Glossary

6.6.1    Mining, oil and gas-related terms

Term	Definition
2D	Two dimensional.
3D	Three dimensional.
Beneficiation	The process of physically separating ore from gangue (waste material) prior to subsequent processing of the beneficiated ore.
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 that occurs in two isomeric forms. Where sold separately, is largely butane gas that has been liquefied through pressurisation. One tonne of butane is approximately equivalent to 14 thousand cubic feet of gas.

308

Term	Definition
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 is defined an Ore Reserve. 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.
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 thousand cubic feet of gas.
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).

309

Term	Definition
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.
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 thousand 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 during pyroprocessing.
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.

310

Term	Definition
Marketable Coal Reserves	Tonnes of coal available, at specified moisture content and air-dried qualities, for sale after beneficiation of Coal Reserves.
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).
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.
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 thousand cubic feet of gas.

311

Term	Definition
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.
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 Ore Reserves and Probable Ore Reserves.
UG (underground)	Below the surface mining activities.

312

Term	Definition
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. 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

Term	Definition
ADR (American Depositary Receipt)	An instrument evidencing American Depositary 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 assets 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

313

Term	Definition
	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.
Australian Tax Treaty	A tax convention between Australia and the United States relating to the avoidance of double taxation.
BHP	Being both companies in the DLC structure, BHP Billiton Limited, BHP Billiton Plc and their respective subsidiaries.
BHP Billiton Limited Group	Being 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	Being 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 and were not included in the demerger of South32.
Discontinued operations	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 Limited 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.

314

Term	Definition
EBIT	Earnings before net finance costs and taxation.
EBITDA	Earnings before depreciation, amortisation and impairments, net finance costs and taxation.
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.
EMTN (Euro Medium Term Note)	BHP’s EUR 20,000,000,000 Euro Medium-Note Programme.
Equalisation DLC Dividend Share	A share that has been authorised to be issued to enable a distribution dividend to be made by the BHP Billiton Plc Group to the BHP Billiton Limited Group or by the BHP Billiton Limited Group to the BHP Billiton Plc Group (as applicable), should this be required under the terms of the DLC merger.
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).
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.
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 our senior executive team who are members of our OMC (Operations Management Committee).
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.
Major capital projects	Projects where the investment commitment exceeds the Group approval threshold or complexity, or associated reputational risk or exposure necessitates review at a Group level (and within the Group investment process).

315

Term	Definition
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.
Non-operated assets	Non-operated assets include interests that are owned as a joint venture but not operated by BHP.
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)	The Operations Management Committee has responsibility for planning, directing and controlling the activities of BHP under the authorities that have been delegated to it by the Board. This includes key strategic, investment and operational decisions, and recommendations to the Board. Members of the OMC are the Chief Executive Officer; the Chief Financial Officer; the Chief External Affairs Officer; the Chief People Officer; the President, Operations, Minerals Australia; the President, Operations, Minerals Americas; and the President Operations, Petroleum.
Onshore US	BHP’s Petroleum asset in four prolific 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 operation and operated by BHP.
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

316

Term	Definition
	across BHP. Previously called Group Level Documents (GLDs), Our Requirements reflect a simpler organisation with the purpose of being more user-friendly and easier to read.
Petroleum asset group	A group of conventional and unconventional 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 agricultural 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. 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 change in share price and any dividends paid. 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)	The 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).

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Term	Definition
Underlying attributable profit	Profit/(Loss) after taxation attributable to owners of the BHP Group less exceptional items as described in note 2 ‘Exceptional items’ in section 5 and excludes Discontinued operations. Refer to section 1.12 for further information.
Underlying EBIT	Calculated as Underlying EBITDA, including depreciation, amortisation and impairments. Refer to section 1.12 for further information.
Underlying EBITDA	Calculated as earnings before net finance costs, depreciation, amortisation and impairments, taxation expense, Discontinued operations and exceptional items. Refer to section 1.12 for further information.
Unit cash costs	One of the financial measures BHP uses to monitor the performance of individual assets. Unit cash costs are calculated as revenue less Underlying EBITDA. Conventional petroleum unit cash costs exclude inventory movements, freight, and third party and exploration expense; WAIO, Queensland Coal and New South Wales Energy Coal unit cash costs exclude freight and royalties; Escondida unit cash costs exclude freight and treatment and refining charges and are net of by-product credits. FY2017 unit cost guidance is 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

Term	Definition
Ag	silver
AI2O3	alumina
Ash	inorganic material remaining after combustion
Au	gold
Cu	copper
CV	calorific value
Fe	iron
LOI	loss on ignition
Met	metallurgical coal
Mo	molybdenum
Ni	nickel
P	phosphorous
Pb	lead
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

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6.6.4    Units of measure

Term	Definition
%	percentage or per cent
bbl	barrel (containing 42 US gallons)
bbl/d	barrels per day
Bcf	billion cubic feet (measured at 60’F, 14.73 psia)
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
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
Mt	million tonnes
Mtpa	million tonnes per annum
MW	megawatt
ozt	Ounce troy. One troy ounce is equivalent to 31.1034768 grams
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 Exhibit 8 – List of Subsidiaries.

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.

• 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’ that follows.

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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;

• 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.

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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 DLC Dividend Shares, refer to section 7.5. The detailed rights attaching to and terms of DLC Dividend Shares are set out in 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.

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.

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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

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.

Demerger Implementation Deed

BHP Billiton Limited, BHP Billiton Plc and South32 Limited entered into an Implementation Deed on 17 March 2015 to facilitate the demerger of South32 Limited from BHP.

The Implementation Deed sets out:

• the conditions to the demerger;

• certain steps required to be taken by each of BHP Billiton Limited, BHP Billiton Plc and South32 Limited to implement the demerger.

Implementation of the demerger was completed on 25 May 2015 and resulted in the formation of an independent listed company, South32 Limited, with a portfolio of assets producing alumina, aluminium, coal, manganese, nickel, silver, lead and zinc.

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In accordance with the Implementation Deed, the demerger was effected through a distribution of South32 shares to eligible shareholders of BHP Billiton Limited and BHP Billiton Plc by way of an in-specie dividend by each of BHP Billiton Limited and BHP Billiton Plc. Each eligible shareholder of BHP Billiton Limited and BHP Billiton Plc received one South32 share for each share in BHP Billiton Limited or BHP Billiton Plc (as applicable) that it held as at the applicable record date for the demerger.

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.

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.

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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;

• 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.

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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.

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 further on).

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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.

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.

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• 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.

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 a 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.

7.5.11    Changes to rights of shareholders

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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7.5.12    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.

7.5.13    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.

7.5.14    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 15 ‘Share capital’ in section 5 and remain current as at 24 August 2017.

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 Operations Management Committee (OMC).

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.

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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 2017. ⁽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

2017

2016

2015

Ordinary shares

BlackRock Group

19 December 2016

15 December 2016

160,784,672

5.00%

<5.0%

5.08

⁽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 2017 and 24 August 2017.

⁽²⁾  The percentages quoted are based on the total voting rights conferred by ordinary shares in BHP Billiton Limited as at 24 August 2017 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 2017. ⁽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

2017

2016

2015

Ordinary shares

Aberdeen Asset Managers Limited

8 October 2015

7 October 2015

103,108,283

4.88%

4.88%

6.06%

Ordinary shares

BlackRock, Inc.

3 December 2009

1 December 2009

213,014,043

10.08%

10.08%

10.08%

Ordinary shares

Public Investment Corporation Soc Limited

24 January 2017

23 January 2017

66,684,446

3.16%

–

–

⁽¹⁾  There has been one change 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 2017 and 24 August 2017. On 16 August 2017, Elliott Capital Advisors, L.P. advised that following a change on 14 August 2017, the number of ordinary shares it owned was 106,448,721 or, 5.04 per cent of total voting rights.

⁽²⁾  The percentages quoted are based on the total voting rights conferred by ordinary shares in BHP Billiton Plc as at 24 August 2017 of 2,112,071,796.

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Twenty largest shareholders as at 24 August 2017 (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		805,864,838		25.09
2.	J P Morgan Nominees Australia Limited		446,216,755		13.89
3.	Citicorp Nominees Pty Ltd		175,835,886		5.47
4.	Citicorp Nominees Pty Limited <Citibank NY ADR DEP A/C>		150,184,200		4.68
5.	National Nominees Limited		121,164,019		3.77
6.	BNP Paribas Nominees Pty Ltd <Agency Lending DRP A/C>		74,702,073		2.33
7.	BNP Paribas Noms Pty Ltd <DRP>		47,382,331		1.48
8.	Citicorp Nominees Pty Limited <Colonial First State INV A/C>		32,775,934		1.02
9.	HSBC Custody Nominees (Australia) Limited <NT-Comnwlth Super Corp A/C>		17,587,159		0.55
10.	Australian Foundation Investment Company Limited		13,990,941		0.44
11.	Computershare Nominees Ci Ltd <ASX SHAREPLUS CONTROL A/C>		13,085,828		0.41
12.	AMP Life Limited		12,664,277		0.39
13.	Argo Investments Limited		8,428,904		0.26
14.	HSBC Custody Nominees (Australia) Limited <Euroclear Bank SA NV A/C>		7,429,702		0.23
15.	Navigator Australia Ltd <MLC Investment Sett A/C>		4,581,486		0.14
16.	IOOF Investment Management Limited <IPS Super A/C>		3,852,038		0.12
17.	Solium Nominees (Australia) Pty Ltd <VSA A/C>		3,666,615		0.11
18.	Milton Corporation Limited		3,636,921		0.11
19.	BNP Paribas Noms (NZ) Ltd <DRP>		3,226,602		0.10
20.	Nulis Nominees (Australia) Limited <Navigator Mast Plan Sett A/C>		3,133,831		0.10
			1,949,410,340		60.70

BHP Billiton Plc		Number of fully paid shares		% of issued capital
1.	PLC Nominees (Proprietary) Limited (2)		329,738,394		15.61
2.	National City Nominees Limited		117,394,189		5.56
3.	State Street Nominees Limited <OM02>		110,954,713		5.25
4.	The Bank of New York (Nominees) Limited		62,833,089		2.97
5.	State Street Nominees Limited <OM04>		58,738,089		2.78
6.	State Street Nominees Limited <OD64>		56,020,875		2.65
7.	Chase Nominees Limited		52,662,211		2.49
8.	BNY (OCS) Nominees Limited <259567>		48,384,344		2.29
9.	Nortrust Nominees Limited		47,721,318		2.26
10.	Lynchwood Nominees Limited <2006420>		45,108,376		2.14
11.	Vidacos Nominees Limited <13559>		44,456,404		2.10
12.	Government Employees Pension Fund – PIC		43,625,998		2.07
13.	Vidacos Nominees Limited <CLRLUX2>		34,723,567		1.64
14.	Industrial Development Corporation of South Africa		33,804,582		1.60
15.	Nutraco Nominees Limited <781221>		31,583,180		1.50
16.	HSBC Global Custody Nominee (UK) Limited <357206>		29,421,328		1.39
17.	Chase Nominees Limited <BBHLEND>		26,402,316		1.25
18.	Hanover Nominees Limited <CITIG>		23,678,000		1.12
19.	Vidacos Nominees Limited <CLRLUX>		21,686,105		1.03
20.	Hanover Nominees Limited <UBS03>		20,801,121		0.98
			1,239,738,199		58.66

⁽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 2017

	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		1,688		0.30		4,257,185			0.13		83		0.49		255,753			0.01
ADR holders		1,550		0.28		150,184,200	(1)		4.68		216		1.27		117,394,188	(2)		5.56

⁽¹⁾  These shares translate to 75,092,100 ADRs.

⁽²⁾  These shares translate to 58,697,094 ADRs.

Geographical distribution of shareholders and shareholdings as at 24 August 2017

	BHP Billiton Limited								BHP Billiton Plc
	Number of Shareholders		%		Number of shares		%		Number of Shareholders		%		Number of shares		%
Registered address
Australia		539,831		96.50		3,148,188,580		98.02		1,608		9.49		2,245,928		0.11
New Zealand		10,814		1.93		27,678,459		0.86		31		0.18		48,306		0.01
United Kingdom		2,804		0.50		7,992,704		0.25		11,360		67.04		1,757,294,975		83.20
United States		1,688		0.30		4,257,185		0.13		83		0.49		255,753		0.01
South Africa		127		0.02		269,309		0.01		2,260		13.33		348,174,908		16.48
Other		4,120		0.75		23,304,868		0.73		1,604		9.47		4,051,926		0.19
Total		559,384		100.00		3,211,691,105		100.00		16,946		100.00		2,112,071,796		100.00

Distribution of shareholdings by size as at 24 August 2017

	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)		237,880		42.53		53,990,808		1.68		8,809		51.98		1,872,842		0.09
501 – 1,000		109,376		19.55		84,766,926		2.64		3,177		18.75		2,350,168		0.11
1,001 – 5,000		165,612		29.61		373,857,278		11.64		3,138		18.52		6,408,697		0.30
5,001 – 10,000		27,380		4.90		193,645,009		6.03		370		2.18		2,654,799		0.13
10,001 – 25,000		14,391		2.57		216,823,028		6.75		320		1.89		5,058,090		0.24
25,001 – 50,000		3,101		0.55		106,064,680		3.30		216		1.27		7,874,474		0.37
50,001 – 100,000		1,081		0.19		74,257,556		2.31		218		1.29		15,772,309		0.75
100,001 – 250,000		411		0.07		58,856,482		1.83		246		1.45		38,912,578		1.84
250,001 – 500,000		71		0.01		23,591,225		0.73		141		0.83		50,688,509		2.40
500,001 – 1,000,000		33		0.01		24,423,557		0.76		88		0.52		62,558,677		2.96
1,000,001 and over		48		0.01		2,001,414,556		62.32		223		1.32		1,917,920,653		90.81
Total		559,384		100.00		3,211,691,105		100.00		16,946		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$26.60 as at 24 August 2017 was 8,330.

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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		157,784		28.21		2,275,443,312		70.85		6,624		39.09		2,102,244,060		99.53
Private		401,600		71.79		936,247,793		29.15		10,322		60.91		9,827,736		0.47
Total		559,384		100.00		3,211,691,105		100.00		16,946		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 FY2017, refer to section 1.12.1.

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 1.5.2.

In FY2017, 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 are 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 eliminate 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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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$
FY2013			39.00		30.18		80.46		57.38
FY2014			39.38		30.94		72.81		56.32
FY2015			39.68		26.90		73.50		40.71
FY2016	First quarter		27.10		21.61		41.29		30.48
	Second quarter		25.60		16.27		37.76		23.62
	Third quarter		18.55		14.20		29.17		19.38
	Fourth quarter		21.05		15.98		32.53		23.92
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
		Ordinary shares				American Depositary Shares (1)
BHP Billiton Limited		High A$		Low A$		High US$		Low US$
Month of January 2017			27.89		25.06		41.68		35.78
Month of February 2017			27.08		24.99		41.41		37.82
Month of March 2017			25.75		23.55		39.06		35.64
Month of April 2017			25.73		23.65		38.39		35.01
Month of May 2017			24.63		22.62		36.89		33.82
Month of June 2017			24.07		22.10		35.61		33.67
Month of July 2017			25.85		23.23		41.66		36.18
Month of August 2017			27.38		25.39		43.50		40.07

⁽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 2017 was A$85.4 billion (US$67.5 billion equivalent), which represented approximately 4.73 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$26.60.

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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$
FY2013			2,236.00		1,673.00		72.07		51.27
FY2014			1,995.00		1,666.50		66.73		62.35
FY2015			2,096.00		1,249.00		71.02		39.56
FY2016	First quarter		1,272.50		964.10		39.87		29.44
	Second quarter		1,194.50		669.30		36.44		20.72
	Third quarter		897.80		580.90		25.80		17.07
	Fourth quarter		997.00		727.50		29.13		20.68
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
		Ordinary shares				American Depositary Shares (1)
BHP Billiton Plc		High UK pence		Low UK pence		High US$		Low US$
Month of January 2017			1,480.50		1,306.50		37.20		31.46
Month of February 2017			1,442.50		1,297.50		36.85		32.49
Month of March 2017			1,362.50		1,197.00		33.84		30.63
Month of April 2017			1,316.00		1,153.50		33.32		30.22
Month of May 2017			1,215.50		1,117.00		31.88		29.12
Month of June 2017			1,207.50		1,140.00		30.91		28.94
Month of July 2017			1,378.00		1,214.50		36.41		31.34
Month of August 2017			1,476.50		1,336.00		38.13		34.79

⁽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 2017 was £29.92 billion (US$38.30 billion equivalent), which represented approximately 1.24 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 £14.17.

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.

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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 Billiton net reimbursement of US$1.4 million in FY2017 for ADR program-related expenses for both of BHP Billiton’s ADR programs (FY2016 US$2.1 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 FY2017, amounting to less than US$0.03 million, which are associated with the administration of the ADR programs (FY2016 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 2017, there were 75,092,100 ADRs on issue and outstanding in the BHP Billiton Limited ADR program and 58,697,094 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.

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.

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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).

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 Australia-US Tax Convention, is not a trust or estate for Australian tax purposes, and the dividend is effectively connected with that permanent establishment (in which case any franking credits may be creditable against their Australian income tax liability).

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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 Australian sourced and 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; or

• they are eligible for benefits under the Australian Tax Treaty but the gain constitutes any of the following:

– 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 either not Australian sourced or is not of an income nature, 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

• 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 currently includes mining, quarrying or prospecting rights in respect of minerals, petroleum or quarry materials situated in Australia – and may be extended to associated information and goodwill); 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, 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 if 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;

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• 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 voting 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.

If a partnership 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.

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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 US source ordinary income or loss for foreign tax credit limitation purposes.

Subject to certain limitations, Australian tax withheld in accordance with the Australian 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 refund of the tax withheld is available to a US holder under Australian law or under the Australian Treaty, the amount of tax withheld 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 or, for certain taxpayers, ‘general category’ income, which are treated separately from each other 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.

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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.

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 voting 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 a partnership 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 US source ordinary income or loss for foreign tax credit limitation purposes.

Dividends will be income from sources outside the US, and generally will be ‘passive category’ income or, for certain taxpayers, ‘general category’ income, which are treated separately from each other 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.

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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.

Accordingly, it is possible that US holders of BHP Billiton Plc shares may be subject to South African Dividends Tax on any dividends received in respect of the BHP Billiton Plc shares listed on the JSE. 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.

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. Shareholders that are not South African tax residents also do not qualify for an exemption from South African Dividends Tax. However, South Africa is a party to Double Taxation Agreements that may provide full or partial relief from South African Dividends Tax, if the requisite reduced rate declarations and written undertakings are provided to the regulated intermediaries making the cash dividend payments before they are paid.

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.

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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 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, 18 per cent for individuals, and 36 per cent for trusts.

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 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.

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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.

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. For more information on these types of obligations, refer to section 1.10.

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 FY2017. BHP believes that these activities are not sanctionable and are 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, and BHP believes the activities thereunder are authorised by the U.S. Department of the Treasury under OFAC licence No. IA-2013-302799-4. This licence expires on 30 September 2017. In anticipation of the OFAC license expiring and/or being renewed, BHP commenced efforts in FY2017 to reduce reliance on US persons for Bruce-Rhum Agreement-related activities and maintain compliance with applicable sanctions laws and requirements.

347

For FY2017, BHP GB received a total US$4.6 million in cost recovery in accordance with the terms of the Bruce-Rhum Agreement, which we expect to book as a reduction in operating expenses in the Bruce field.

BHP intends to continue the activities in connection with the Bruce-Rhum Agreement, provided such activities remain subject to a continuing OFAC licence or are otherwise authorised or in compliance with applicable sanctions.

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.

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.

348

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. A lower approval threshold (generally 10 per cent) applies where the foreign person is a foreign government investor for the purposes of the FATA.

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 he 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);

• 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);

349

• 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’s ordinary shares, 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.

ADR holders wishing to receive a hard copy of the Annual Report 2017 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.

350

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
26 September 2017	Final dividend payment date
19 October 2017	BHP Billiton Plc Annual General Meeting in London Venue: The QEII Centre Broad Sanctuary Westminster London SW1P 3EE United Kingdom Time: 12 noon (local time) Details of the business of the meeting are contained in the separate Notice of Meeting
16 November 2017	BHP Billiton Limited Annual General Meeting in Melbourne Venue: Margaret Court Arena Melbourne & Olympic Parks Olympic Boulevard Melbourne Australia Time: 11.00am (local time) Details of the business of the meeting are contained in the separate Notice of Meeting
20 February 2018	Interim results announced
9 March 2018	Interim dividend record date
27 March 2018	Interim dividend payment date

351

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

352

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.

353

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

354

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 Implementation Deed entered into on 17 March 2015 between BHP Billiton Ltd, BHP Billiton Plc and South32 Limited ⁽⁵⁾

4.12 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 28 September 2017

*12.2 Certification by Chief Financial Officer, Mr Peter Beaven, dated 28 September 2017

355

Exhibit 13    Certifications (section 906)

*13.1 Certification by Chief Executive Officer, Mr Andrew Mackenzie, dated 28 September 2017

*13.2 Certification by Chief Financial Officer, Mr Peter Beaven, dated 28 September 2017

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

Exhibit 95    Mine Safety Health Administration

*95.1 Disclosure of Mine Safety and Health Administration (“MSHA”) Safety Data.

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.

(5) Previously filed as an exhibit to BHP’s annual report on Form 20-F for the year ended 30 June 2015 on 21 September 2015.

(P) Previously filed on paper form.

356

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: 28 September 2017

5    Financial Statements

Contents of Financial Statements
About these Financial Statements		F-1
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
5.1.6	Notes to the Financial Statements	F-11
Performance		F-11
1	Segment reporting	F-11
2	Exceptional items	F-14
3	Significant events – Samarco dam failure	F-17
4	Expenses and other income	F-29
5	Income tax expense	F-30
6	Earnings per share	F-34
Working capital		F-35
7	Trade and other receivables	F-35
8	Trade and other payables	F-36
9	Inventories	F-36
Resource assets		F-38
10	Property, plant and equipment	F-38
11	Intangible assets	F-43
12	Impairment of non-current assets	F-44
13	Deferred tax balances	F-49
14	Closure and rehabilitation provisions	F-51
Capital structure		F-53
15	Share capital	F-53
16	Other equity	F-55
17	Dividends	F-56
18	Provisions for dividends and other liabilities	F-58
Financial management		F-59
19	Net debt	F-59
20	Net finance costs	F-62
21	Financial risk management	F-62
Employee matters		F-71
22	Key management personnel	F-71
23	Employee share ownership plans	F-72
24	Employee benefits, restructuring and post-retirement employee benefits provisions	F-75
25	Pension and other post-retirement obligations	F-77
26	Employees	F-79
Group and related party information		F-80
27	Discontinued operations	F-80
28	Subsidiaries	F-81
29	Investments accounted for using the equity method	F-82
30	Interests in joint operations	F-86
31	Related party transactions	F-87

Unrecognised items and uncertain events		F-88
32	Commitments	F-88
33	Contingent liabilities	F-89
34	Subsequent events	F-90
Other items		F-90
35	Acquisitions and disposals of subsidiaries, operations, joint operations and equity accounted investments	F-90
36	Auditor’s remuneration	F-91
37	Not required for US reporting	F-92
38	Deed of Cross Guarantee	F-92
39	New and amended accounting standards and interpretations issued but not yet effective	F-94
5.2	Not required for US reporting	F-96
5.3	Directors’ declaration	F-97
5.4	Statement of Directors’ responsibilities in respect of the Annual Report and the Financial Statements	F-98
5.5	Not required for US reporting	F-98
5.6	Reports of Independent Registered Public Accounting Firms	F-99
5.7	Supplementary oil and gas information – unaudited	F-101

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 31 ‘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 7 September 2017. 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 2017

	Notes		2017			2016			2015
			US$M			US$M			US$M
Continuing operations
Revenue		1		38,285			30,912			44,636
Other income		4		736			444			496
Expenses excluding net finance costs		4		(27,540	)		(35,487	)		(37,010	)
Profit/(loss) from equity accounted investments, related impairments and expenses		29		272			(2,104	)		548
Profit/(loss) from operations				11,753			(6,235	)		8,670
Financial expenses				(1,574	)		(1,161	)		(702	)
Financial income				143			137			88
Net finance costs		20		(1,431	)		(1,024	)		(614	)
Profit/(loss) before taxation				10,322			(7,259	)		8,056
Income tax (expense)/benefit				(3,933	)		1,297			(2,762	)
Royalty-related taxation (net of income tax benefit)				(167	)		(245	)		(904	)
Total taxation (expense)/benefit		5		(4,100	)		1,052			(3,666	)
Profit/(loss) after taxation from Continuing operations				6,222			(6,207	)		4,390
Discontinued operations
Loss after taxation from Discontinued operations		27		–			–			(1,512	)
Profit/(loss) after taxation from Continuing and Discontinued operations				6,222			(6,207	)		2,878
Attributable to non-controlling interests				332			178			968
Attributable to BHP shareholders				5,890			(6,385	)		1,910
Basic earnings/(loss) per ordinary share (cents)		6		110.7			(120.0	)		35.9
Diluted earnings/(loss) per ordinary share (cents)		6		110.4			(120.0	)		35.8
Basic earnings/(loss) from Continuing operations per ordinary share (cents)		6		110.7			(120.0	)		65.5
Diluted earnings/(loss) from Continuing operations per ordinary share (cents)		6		110.4			(120.0	)		65.3
Dividends per ordinary share – paid during the period (cents)		17		54.0			78.0			124.0
Dividends per ordinary share – determined in respect of the period (cents)		17		83.0			30.0			124.0

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 2017

	Notes		2017			2016			2015
			US$M			US$M			US$M
Profit/(loss) after taxation from Continuing and Discontinued operations				6,222			(6,207	)		2,878
Other comprehensive income
Items that may be reclassified subsequently to the income statement:
Available for sale investments:
Net valuation (losses)/gains taken to equity				(1	)		2			(21	)
Net valuation losses/(gains) transferred to the income statement				–			1			(115	)
Cash flow hedges:
Gains/(losses) taken to equity				351			(566	)		(1,797	)
(Gains)/losses transferred to the income statement				(432	)		664			1,815
Exchange fluctuations on translation of foreign operations taken to equity				(1	)		(1	)		(2	)
Exchange fluctuations on translation of foreign operations transferred to income statement				–			(10	)		–
Tax recognised within other comprehensive income		5		24			(30	)		29
Total items that may be reclassified subsequently to the income statement				(59	)		60			(91	)
Items that will not be reclassified to the income statement:
Remeasurement gains/(losses) on pension and medical schemes				36			(20	)		(28	)
Tax recognised within other comprehensive income		5		(26	)		(17	)		(17	)
Total items that will not be reclassified to the income statement				10			(37	)		(45	)
Total other comprehensive (loss)/income				(49	)		23			(136	)
Total comprehensive income/(loss)				6,173			(6,184	)		2,742
Attributable to non-controlling interests				332			176			973
Attributable to BHP shareholders				5,841			(6,360	)		1,769

The accompanying notes form part of these Financial Statements.

F-3

5.1.3    Consolidated Balance Sheet as at 30 June 2017

	Notes		2017			2016
			US$M			US$M
ASSETS
Current assets
Cash and cash equivalents		19		14,153			10,319
Trade and other receivables		7		2,836			3,155
Other financial assets		21		72			121
Inventories		9		3,673			3,411
Current tax assets				195			567
Other				127			141
Total current assets				21,056			17,714
Non-current assets
Trade and other receivables		7		803			867
Other financial assets		21		1,281			2,680
Inventories		9		1,095			764
Property, plant and equipment		10		80,497			83,975
Intangible assets		11		3,968			4,119
Investments accounted for using the equity method		29		2,448			2,575
Deferred tax assets		13		5,788			6,147
Other				70			112
Total non-current assets				95,950			101,239
Total assets				117,006			118,953
LIABILITIES
Current liabilities
Trade and other payables		8		5,551			5,389
Interest bearing liabilities		19		1,241			4,653
Other financial liabilities		21		394			5
Current tax payable				2,119			451
Provisions		3, 14, 18, 24		1,959			1,765
Deferred income				102			77
Total current liabilities				11,366			12,340
Non-current liabilities
Trade and other payables		8		5			13
Interest bearing liabilities		19		29,233			31,768
Other financial liabilities		21		1,106			1,778
Deferred tax liabilities		13		3,765			4,324
Provisions		3, 14, 18, 24		8,445			8,381
Deferred income				360			278
Total non-current liabilities				42,914			46,542
Total liabilities				54,280			58,882
Net assets				62,726			60,071
EQUITY
Share capital – BHP Billiton Limited				1,186			1,186
Share capital – BHP Billiton Plc				1,057			1,057
Treasury shares				(3	)		(33	)
Reserves		16		2,400			2,538
Retained earnings				52,618			49,542
Total equity attributable to BHP shareholders				57,258			54,290
Non-controlling interests		16		5,468			5,781
Total equity				62,726			60,071

The accompanying notes form part of these Financial Statements.

The Financial Statements were approved by the Board of Directors on 7 September 2017 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 2017

	Notes		2017			2016			2015
			US$M			US$M			US$M
Operating activities
Profit/(loss) before taxation from Continuing operations				10,322			(7,259	)		8,056
Adjustments for:
Non-cash or non-operating exceptional items				350			9,645			3,196
Depreciation and amortisation expense				7,719			8,661			9,158
Impairments of property, plant and equipment, financial assets and intangibles				188			210			828
Net finance costs				1,304			1,024			614
Share of operating profit of equity accounted investments				(444	)		(276	)		(548	)
Other				290			459			503
Changes in assets and liabilities:
Trade and other receivables				315			1,714			1,431
Inventories				(679	)		527			151
Trade and other payables				337			(1,661	)		(990	)
Provisions and other assets and liabilities				(325	)		(373	)		(779	)
Cash generated from operations				19,377			12,671			21,620
Dividends received				636			301			740
Interest received				164			128			86
Interest paid				(1,149	)		(830	)		(627	)
Settlement of cash management related instruments				(140	)		–			–
Net income tax and royalty-related taxation refunded				501			641			348
Net income tax and royalty-related taxation paid				(2,585	)		(2,286	)		(4,373	)
Net operating cash flows from Continuing operations				16,804			10,625			17,794
Net operating cash flows from Discontinued operations		27		–			–			1,502
Net operating cash flows				16,804			10,625			19,296
Investing activities
Purchases of property, plant and equipment				(4,252	)		(6,946	)		(11,947	)
Exploration expenditure				(968	)		(765	)		(816	)
Exploration expenditure expensed and included in operating cash flows				612			430			670
Net investment and funding of equity accounted investments				(234	)		40			117
Proceeds from sale of assets				648			107			74
Proceeds from divestment of subsidiaries, operations and joint operations, net of their cash		35		186			166			256
Other investing				(153	)		(277	)		144
Net investing cash flows from Continuing operations				(4,161	)		(7,245	)		(11,502	)
Net investing cash flows from Discontinued operations		27		–			–			(1,066	)
Cash disposed on demerger of South32		27		–			–			(586	)
Net investing cash flows				(4,161	)		(7,245	)		(13,154	)
Financing activities
Proceeds from interest bearing liabilities				1,577			7,239			3,440
Proceeds/(settlements) from debt related instruments				36			156			(33	)
Repayment of interest bearing liabilities				(7,120	)		(2,788	)		(4,135	)
Proceeds from ordinary shares				–			–			9
(Distributions)/contributions to/from non-controlling interests				(16	)		–			53
Purchase of shares by Employee Share Ownership Plan (ESOP) Trusts				(108	)		(106	)		(355	)
Dividends paid				(2,921	)		(4,130	)		(6,498	)
Dividends paid to non-controlling interests				(581	)		(87	)		(554	)
Net financing cash flows from Continuing operations				(9,133	)		284			(8,073	)
Net financing cash flows from Discontinued operations		27		–			–			(203	)
Net financing cash flows				(9,133	)		284			(8,276	)
Net increase/(decrease) in cash and cash equivalents from Continuing operations				3,510			3,664			(1,781	)
Net increase in cash and cash equivalents from Discontinued operations		27		–			–			233
Cash and cash equivalents, net of overdrafts, at the beginning of the financial year				10,276			6,613			8,752
Cash disposed on demerger of South32		27		–			–			(586	)
Foreign currency exchange rate changes on cash and cash equivalents				322			(1	)		(5	)
Cash and cash equivalents, net of overdrafts, at the end of the financial year		19		14,108			10,276			6,613

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 2017

	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 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
Balance as at 1 July 2014		1,186		1,069			(51	)		(536	)		2,927			74,548			79,143			6,239			85,382
Total comprehensive income		–		–			–			–			(96	)		1,865			1,769			973			2,742
Transactions with owners:
Shares cancelled		–		(12	)		–			501			12			(501	)		–			–			–
Purchase of shares by ESOP Trusts		–		–			(232	)		(123	)		–			–			(355	)		–			(355	)
Employee share awards exercised net of employee contributions and other adjustments		–		–			264			99			(461	)		101			3			–			3
Employee share awards forfeited		–		–			–			–			(13	)		13			–			–			–
Accrued employee entitlement for unexercised awards		–		–			–			–			247			–			247			–			247
Distribution to option holders		–		–			–			–			(1	)		–			(1	)		(1	)		(2	)
Dividends		–		–			–			–			–			(6,596	)		(6,596	)		(639	)		(7,235	)
In-specie dividend on demerger – refer to note 27 ‘Discontinued operations’		–		–			–			–			–			(9,445	)		(9,445	)		–			(9,445	)
Equity contributed		–		–			–			–			1			–			1			52			53
Transfers within equity on demerger		–		–			–			–			(59	)		59			–			–			–
Conversion of controlled entities to equity accounted investments		–		–			–			2			–			–			2			(847	)		(845	)
Balance as at 30 June 2015		1,186		1,057			(19	)		(57	)		2,557			60,044			64,768			5,777			70,545

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 2017:

• 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 2016. 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 28 ‘Subsidiaries’, note 29 ‘Investments accounted for using the equity method’ and note 30 ‘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 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
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, 11 and 12	Property, plant and equipment, Intangible assets and Impairments of non-current assets – recoverable amount
14	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 FY2017, 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

The segment reporting information for FY2015 has been presented on a Continuing operations basis to exclude the contribution from assets that were demerged with South32.

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 2017 US$M	Petroleum			Copper			Iron Ore			Coal			Group and unallocated items/ eliminations			Group total
Revenue		6,789			8,335			14,606			7,578			977			38,285
Inter-segment revenue		83			–			18			–			(101	)		–
Total revenue		6,872			8,335			14,624			7,578			876			38,285
Underlying EBITDA		4,063			3,545			9,077			3,784			(173	)		20,296
Depreciation and amortisation		(3,395	)		(1,525	)		(1,828	)		(719	)		(252	)		(7,719	)
Impairment losses		(102	)		(14	)		(52	)		(15	)		(5	)		(188	)
Underlying EBIT		566			2,006			7,197			3,050			(430	)		12,389
Exceptional items (1)		–			(546	)		(203	)		164			(51	)		(636	)
Net finance costs																	(1,431	)
Profit before taxation																	10,322
Capital expenditure (cash basis)		1,472			1,484			805			246			245			4,252
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		28,984			26,743			22,781			11,996			26,502			117,006
Total liabilities		5,803			2,643			3,606			1,860			40,368			54,280

F-11

Year ended 30 June 2016 US$M	Petroleum			Copper			Iron Ore			Coal			Group and unallocated items/ eliminations			Group total
Revenue		6,776			8,249			10,516			4,518			853			30,912
Inter-segment revenue		118			–			22			–			(140	)		–
Total revenue		6,894			8,249			10,538			4,518			713			30,912
Underlying EBITDA		3,658			2,619			5,599			635			(171	)		12,340
Depreciation and amortisation		(4,147	)		(1,560	)		(1,817	)		(890	)		(247	)		(8,661	)
Impairment losses		(48	)		(17	)		(42	)		(94	)		(9	)		(210	)
Underlying EBIT		(537	)		1,042			3,740			(349	)		(427	)		3,469
Exceptional items (1)		(7,184	)		–			(2,388	)		–			(132	)		(9,704	)
Net finance costs																	(1,024	)
Loss before taxation																	(7,259	)
Capital expenditure (cash basis)		2,517			2,786			1,061			298			284			6,946
Profit/(loss) from equity accounted investments, related impairments and expenses		(7	)		155			(2,244	)		(9	)		1			(2,104	)
Investments accounted for using the equity method		280			1,388			–			901			6			2,575
Total assets		30,476			26,143			24,330			12,754			25,250			118,953
Total liabilities		5,308			2,299			3,789			2,103			45,383			58,882
Year ended 30 June 2015 US$M	Petroleum			Copper			Iron Ore			Coal			Group and unallocated items/ eliminations			Group total
Revenue		11,180			11,453			14,649			5,885			1,469			44,636
Inter-segment revenue		267			–			104			–			(371	)		–
Total revenue		11,447			11,453			14,753			5,885			1,098			44,636
Underlying EBITDA		7,201			5,205			8,648			1,242			(444	)		21,852
Depreciation and amortisation		(4,738	)		(1,545	)		(1,698	)		(875	)		(302	)		(9,158	)
Impairment losses		(477	)		(307	)		(18	)		(19	)		(7	)		(828	)
Underlying EBIT		1,986			3,353			6,932			348			(753	)		11,866
Exceptional items		(2,787	)		–			–			–			(409	)		(3,196	)
Net finance costs																	(614	)
Profit before taxation																	8,056
Capital expenditure (cash basis)		5,023			3,822			1,930			729			443			11,947
Profit/(loss) from equity accounted investments, related impairments and expenses		–			175			371			1			1			548
Investments accounted for using the equity method		287			1,422			1,044			956			3			3,712
Total assets		40,325			26,340			26,808			14,182			16,925			124,580
Total liabilities		6,722			2,639			2,854			2,413			39,407			54,035

⁽¹⁾  Exceptional items of US$(51) million (FY2016: US$(62) million) reported in Group and unallocated also related to the Samarco dam failure. Refer to note 2 ‘Exceptional items’ for further information.

F-12

Geographical information

	Revenue by location of customer
	2017		2016		2015
	US$M		US$M		US$M
Australia		2,037		1,846		2,205
Europe		1,641		1,161		2,465
China		18,875		13,177		16,337
Japan		3,086		2,941		4,863
India		1,938		1,478		1,680
South Korea		2,296		1,919		2,688
Rest of Asia		3,195		2,833		4,734
North America		4,345		4,470		7,990
South America		681		899		1,342
Rest of world		191		188		332
		38,285		30,912		44,636
	Non-current assets by location of assets
	2017		2016		2015
	US$M		US$M		US$M
Australia		46,949		49,465		52,109
North America		22,860		23,943		33,091
South America		16,363		15,965		15,831
Rest of world		2,709		3,038		3,160
Unallocated assets (1)		7,069		8,828		4,020
		95,950		101,239		108,211

⁽¹⁾  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.

Underlying EBITDA is the key alternate 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.

Prior to FY2016, we reported Underlying EBIT as a key alternate performance measure of operating results. Management believes focusing on Underlying EBITDA more closely reflects the operating cash generative capacity and hence the underlying performance of the Group’s business. Management also uses this measure because financing structures and tax regimes differ across the Group’s assets and substantial components of the Group’s tax and interest charges are levied at a Group level rather than an operational level.

F-13

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 net of 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 21 ‘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.

2    Exceptional items

Exceptional items are those items 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 for the year are detailed below:

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	)

F-14

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.

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	)
Impairment of Onshore US assets		(7,184	)		2,300			(4,884	)
Global taxation matters		(70	)		(500	)		(570	)
Total		(9,704	)		2,053			(7,651	)
Attributable to non-controlling interests – Impairment of Onshore US assets		(80	)		29			(51	)
Attributable to BHP shareholders		(9,624	)		2,024			(7,600	)

F-15

Samarco Mineração S.A. (Samarco) dam failure

The 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.

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.

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.

Year ended 30 June 2015	Gross			Tax			Net
	US$M			US$M			US$M
Exceptional items by category
Impairment of Onshore US assets		(2,787	)		829		(1,958)
Impairment of Nickel West assets		(409	)		119		(290)
Repeal of Minerals Resource Rent Tax legislation		–			(698	)	(698)
Total		(3,196	)		250		(2,946)
Attributable to non-controlling interests – Repeal of Minerals Resource Rent Tax legislation		–			(12	)	(12)
Attributable to BHP shareholders		(3,196	)		262		(2,934)

Impairment of Onshore US assets

The Group recognised an impairment charge of US$1,958 million (after tax benefit) in relation to its Onshore US assets. The gas-focused Hawkville field accounts for the substantial majority of this charge reflecting its geological complexity, product mix, acreage relinquishments and amended development plans. The remainder relates to the impairment of goodwill associated with the Petrohawk acquisition.

F-16

Impairment of Nickel West assets

The Group announced on 12 November 2014 that the review of its Nickel West business was complete and the preferred option, the sale of the business, was not achieved on an acceptable basis. As a result of operational decisions made subsequent to the conclusion of this process, an impairment charge of US$290 million (after tax benefit) was recognised in the year ended 30 June 2015.

Repeal of Minerals Resource Rent Tax legislation

The legislation to repeal the Minerals Resource Rent Tax (MRRT) in Australia took effect on 30 September 2014. As a result, the Group derecognised a MRRT deferred tax asset of US$809 million and corresponding taxation charges of US$698 million related to Continuing operations and US$111 million related to Discontinued operations were recognised in the year ended 30 June 2015.

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 1.7 ‘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.

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 2017 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 29 ‘Investments accounted for using the equity method’, along with the summary financial information related to Samarco as at 30 June 2017.

Financial impacts of Samarco dam failure	2017			2016
	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)		(82	)		(70	)
Loss from equity accounted investments, related impairments and expenses:
Share of loss relating to the Samarco dam failure (2)(3)		(134	)		(655	)
Impairment of the carrying value of the investment in Samarco (3)		–			(525	)
Samarco dam failure provision (2)(3)		(38	)		(1,200	)
Loss from operations		(254	)		(2,450	)

F-17

Financial impacts of Samarco dam failure	2017			2016
	US$M			US$M
Net finance costs		(127	)		–
Loss before taxation		(381	)		(2,450	)
Income tax benefit		–			253
Loss after taxation		(381	)		(2,197	)
Balance sheet movement
Trade and other payables		(3	)		(11	)
Investments accounted for using the equity method		–			(1,180	)
Deferred tax assets		–			(158	)
Provisions		143			(1,200	)
Deferred tax liabilities		–			411
Net assets/(liabilities)		140			(2,138	)

			2017					2016
			US$M					US$M
Cash flow statement
Loss before taxation				(381	)				(2,450	)
Comprising:
Costs incurred directly by BHP Billiton Brasil and other BHP entities in relation to the Samarco dam failure (1)(2)	(82	)				(70	)
Share of loss relating to the Samarco dam failure (2)(3)	(134	)				(655	)
Impairment of the carrying value of the investment in Samarco (3)	–					(525	)
Samarco dam failure provision (2)(3)	(38	)				(1,200	)
Net finance costs	(127	)				–
Non-cash or non-operating exceptional items				302					2,391
Net operating cash flows				(79	)				(59	)
Net investment and funding of equity accounted investments (4)				(442	)				–
Net investing cash flows				(442	)				–
Net decrease in cash and cash equivalents				(521	)				(59	)

⁽¹⁾  Includes legal and advisor costs incurred.

⁽²⁾  Financial impacts of US$(381) million from the Samarco dam failure relates to US$(134) million share of loss from US$(134) million funding provided during the period, US$(82) million direct costs incurred by BHP Billiton Brasil Ltda and other BHP entities, US$(127) million amortisation of discounting impacting net finance costs and US$(38) million other movements in the Samarco dam failure provision including foreign exchange.

⁽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$(134) million funding provided during the period and US$(308) million utilisation of the Samarco dam failure provision, of which US$(278) million allowed for the continuation of reparatory and compensatory programs in relation to the Framework Agreement and a further US$(30) million for dam stabilisation.

F-18

Equity accounted investment in Samarco

BHP Billiton Brasil’s investment in Samarco remains at US$ nil. BHP Billiton Brasil provided US$134 million funding under a working capital facility during the period and recognised additional share of losses of US$134 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.

Provision for Samarco dam failure

			2017				2016
			US$M				US$M
At the beginning of the financial year				1,200				–
Provision recognition, comprising:
Share of loss relating to the Samarco dam failure				–				572
Samarco dam failure provision expense				–				628
Movement in provision				(143	)			–
Comprising:
Utilised	(308	)
Adjustments charged to the income statement:						–
Amortisation of discounting impacting net finance costs	127					–
Other (1)	38					–
At the end of the financial year				1,057				1,200
Comprising:
Current				310				300
Non-current				747				900
At the end of the financial year				1,057				1,200

⁽¹⁾  US$38 million relates to other movements in the Samarco dam failure provision including foreign exchange.

Dam failure provisions and contingencies

As at 30 June 2017, 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 to remediate and provide compensation for damage caused by the Samarco dam failure. On 5 May 2016, the Framework Agreement was ratified by the Federal Court of Appeal.

The Federal Prosecutor’s Office appealed the ratification of the Framework Agreement and on 30 June 2016, the Superior Court of Justice in Brazil issued a preliminary order (Interim Order) suspending the 5 May 2016 ratification of the Framework Agreement.

F-19

BHP Billiton Brasil, Vale and Samarco have appealed the Interim Order before the Superior Court of Justice. While a final decision on ratification is pending, and negotiations, under the Preliminary Agreement (defined below), towards a settlement of the R$20 billion (approximately US$6.1 billion) public civil claim and R$155 billion (approximately US$47 billion) Federal Public Prosecution Office claim are ongoing, the Framework Agreement remains binding between the parties and Fundação Renova will continue to implement the programs under 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 with calendar year contributions as follows:

• R$2 billion (US$599 million) in 2016;

• R$1.2 billion (approximately US$365 million) in 2017;

• R$1.2 billion (approximately US$365 million) in 2018;

• R$500 million (approximately US$150 million) for a special project to be spent on sewage treatment and landfill works from 2016–2018.

Annual contributions for each of the years 2019, 2020 and 2021 will be in the range of R$800 million (approximately US$245 million) and R$1.6 billion (approximately US$485 million), depending on the remediation and compensation projects which are to be undertaken in the 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.

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 2017, BHP Billiton Brasil has recognised a provision of US$1.1 billion before tax and after discounting (30 June 2016: US$1.2 billion), in respect of its obligations under the Framework Agreement.

The measurement of the provision requires the use of estimates and assumptions and may be affected by, amongst other factors, potential changes in scope of work and funding amounts required under the Framework Agreement including further technical analysis required under the Preliminary Agreement, the outcome of the ongoing negotiations with Federal Prosecutors, 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. 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 to the amount of the provision in future reporting periods.

As at 30 June 2017, BHP Billiton Brasil has paid US$278 million to allow for the continuation of reparatory and compensatory programs in relation to the Framework Agreement and a further US$30 million for dam stabilisation, with the total US$308 million offset against the provision for the Samarco dam failure.

On 30 June 2017, BHP Billiton Brasil approved a further US$174 million to support Fundação Renova, 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.

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$6.1 billion) public civil claim and R$155 billion (approximately US$47 billion) Federal Public Prosecution Office claim relating to the dam failure.

F-20

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, Vale or Samarco but will be considered in the negotiation of a final settlement arrangement with the Federal Prosecutors.

Under the Preliminary Agreement, BHP Billiton Brasil, Vale and Samarco agreed interim security (Interim Security) comprising R$1.3 billion (approximately US$395 million) in insurance bonds, R$100 million (approximately US$30 million) in liquid assets, a charge of R$800 million (approximately US$245 million) over Samarco’s assets, and R$200 million (approximately US$60 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 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. On 29 June 2017, the Court extended the final date for negotiation of a settlement until 30 October 2017, allowing for the continuation of the Interim Security arrangements and the provision of ongoing expert advice to the Federal Prosecutors in respect of the programs. The parties will use best efforts to achieve a final settlement arrangement by 30 October 2017 under the timeframe established in the Preliminary Agreement.

Legal

The following matters are disclosed as contingent liabilities:

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. 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.

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.

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, is 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$6.1 billion) in aggregate for clean-up costs and damages.

On 2 March 2016, BHP Billiton Brasil, together with Samarco and Vale, entered into the Framework Agreement. Ratification of the Framework Agreement by the Federal Court of Appeal on 5 May 2016 suspended this public civil claim. However, it was reinstated on 30 June 2016 upon issue of the Interim Order by the Superior Court of Justice in Brazil.

While a final decision by the Court on the issue of ratification of the Framework Agreement is pending, the Preliminary Agreement suspends a R$1.2 billion (approximately US$365 million) injunction order under the public civil claim.

F-21

The Preliminary Agreement also requests suspension of the public civil claim with a decision from the Court pending. The R$1.2 billion (approximately US$365 million) injunction order may be reinstated if a final settlement arrangement is not agreed by 30 October 2017.

As noted above, BHP Billiton Brasil has recognised a provision as of 30 June 2017 of US$1.1 billion before tax and after discounting (30 June 2016: US$1.2 billion) in respect of its obligations under the Framework Agreement. While a final decision on ratification of the Framework Agreement is pending, and negotiation of a settlement of the R$20 billion (approximately US$6.1 billion) public civil claim and R$155 billion (approximately US$47 billion) Federal Public Prosecution Office claim (noted below) under the Preliminary Agreement are ongoing, the Framework Agreement remains binding between the parties and Fundação Renova will continue to implement the programs under the Framework Agreement.

Given the status of these proceedings, 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.

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$47 billion) for reparation, compensation and moral damages in relation to the Samarco dam failure.

With regard to the Preliminary Agreement the 12th Federal Court suspended the Federal Public Prosecution Office claim, including a R$7.7 billion (approximately US$2.3 billion) injunction request.

However, proceedings may be resumed if a final settlement arrangement is not agreed by 30 October 2017.

Given the status of these proceedings, 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.

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 U.S. federal securities laws and indicates that the plaintiff will seek certification to proceed as a class action.

The amount of damages sought by the plaintiff on behalf of the putative class is unspecified. 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.

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 and BHP Billiton Plc.

Class action complaint – 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 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.

F-22

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.

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.

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.

Under the criminal charges against BHP Billiton Brasil, Vale and Samarco and certain individuals, a R$20 billion (approximately US$6.1 billion) asset freezing order application was made by the Federal Prosecutors. In July 2017, the Federal Court of Ponte Nova denied the Federal Prosecutors’ application for an asset freezing order.

Given the 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 for BHP Billiton Brasil.

Other claims

The civil public actions filed by State Prosecutors in Minas Gerais (claiming damages of approximately R$7.5 billion, US$2.3 billion), State Prosecutors in Espírito Santo (claiming damages of approximately R$2 billion, US$605 million), and public defenders in Minas Gerais (claiming damages of approximately R$10 billion, US$3 billion), have been consolidated before the 12th Federal Court. All of those civil public actions except the latter have also been suspended by the 12th Federal Court. Given the preliminary status of these proceedings, and the duplicative nature of the damages sought in these proceedings and the R$20 billion (approximately US$6.1 billion) and R$155 billion (approximately US$47 billion) claims 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.

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.

BHP’s 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 such matters.

BHP insurance

BHP has third party liability insurance for claims related to the Samarco dam failure made directly against BHP Billiton Brasil or other BHP entities. External insurers have been advised of the Samarco dam failure and a formal claim has been prepared and submitted. At 30 June 2017, an insurance receivable has not been recognised for any potential recoveries under insurance arrangements.

F-23

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 2017, BHP Billiton Brasil has provided US$134 million funding to support Samarco’s operations and a further US$30 million for dam stabilisation, with undrawn amounts of US$67 million expiring as at 30 June 2017. On 30 June 2017, BHP Billiton Brasil made available a new short-term facility of up to US$76 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 2017.

Any additional requests for funding or future investment provided would be subject to a future decision, accounted for at that time.

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 2017, 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 to remediate and provide compensation for damage caused by the Samarco dam failure. On 5 May 2016, the Framework Agreement was ratified by the Federal Court of Appeal.

The Federal Prosecutor’s Office appealed the ratification of the Framework Agreement and on 30 June 2016, the Superior Court of Justice in Brazil issued a preliminary order (Interim Order) suspending the 5 May 2016 ratification of the Framework Agreement.

Samarco, Vale and BHP Billiton Brasil have appealed the Interim Order before the Superior Court of Justice. While a final decision on ratification is pending, and negotiations, under the Preliminary Agreement, towards a settlement of the R$20 billion (approximately US$6.1 billion) public civil claim and R$155 billion (approximately US$47 billion) Federal Public Prosecution Office claim are ongoing, the Framework Agreement remains binding between the parties and Fundação Renova will continue to implement the programs under 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 with calendar year contributions as follows:

• R$2 billion (approximately US$599 million) in 2016;

• R$1.2 billion (approximately US$365 million) in 2017;

• R$1.2 billion (approximately US$365 million) in 2018;

• R$500 million (approximately US$150 million) for a special project to be spent on sewage treatment and landfill works from 2016–2018.

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Annual contributions for each of the years 2019, 2020 and 2021 will be in the range of R$800 million (approximately US$245 million) and R$1.6 billion (approximately US$485 million), depending on the remediation and compensation projects which are to be undertaken in the particular year. Annual contributions may be reviewed under the Framework Agreement.

As at 30 June 2017, Samarco has a provision of US$2.1 billion before tax and after discounting (30 June 2016: US$2.4 billion), in relation to its obligations under the Framework Agreement based on currently available information.

The measurement of the provision requires the use of estimates and assumptions and may be affected by, amongst other factors, potential changes in scope of work and funding amounts required under the Framework Agreement including further technical analysis required under the Preliminary Agreement, the outcome of ongoing negotiations with Federal Prosecutors, 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. 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 to the amount of 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 negotiations towards a settlement regarding the R$20 billion (approximately US$6.1 billion) public civil claim and R$155 billion (approximately US$47 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$395 million) in insurance bonds, R$100 million (approximately US$30 million) in liquid assets, a charge of R$800 million (approximately US$245 million) over Samarco’s assets, and R$200 million (approximately US$60 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. On 29 June 2017, the Court extended the final date for negotiation of a settlement until 30 October 2017, allowing for the continuation of the Interim Security arrangements and the provision of ongoing expert advice to the Federal Prosecutors in respect of the programs. The parties will use best efforts to achieve a final settlement arrangement by 30 October 2017 under the timeframe established in the Preliminary Agreement.

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Other

As at 30 June 2017, Samarco has recognised provisions of US$0.3 billion (30 June 2016: US$0.2 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

Samarco has been named as defendant in a number of legal proceedings initiated by individuals, NGOs, corporations and governmental entities in Brazilian federal and state courts following the Samarco dam failure. These 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. It is not possible at this time to provide a range of possible outcomes or a reliable estimate of potential future exposures for Samarco.

In addition, government investigations of the Samarco dam failure by numerous agencies of the Brazilian government have commenced and are ongoing.

Public civil claim

Among the claims brought against Samarco, is 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$6.1 billion) in aggregate for clean-up costs and damages.

On 2 March 2016, Samarco, together with Vale and BHP Billiton Brasil, entered into the Framework Agreement. Ratification of the Framework Agreement by the Federal Court of Appeal on 5 May 2016 suspended this public civil claim. However, it was reinstated on 30 June 2016 upon issue of the Interim Order by the Superior Court of Justice in Brazil.

While a final decision by the Court on the issue of ratification of the Framework Agreement is pending, the Preliminary Agreement suspends a R$1.2 billion (approximately US$365 million) injunction order under the public civil claim.

The Preliminary Agreement also requests suspension of the public civil claim with a decision from the Court pending. The R$1.2 billion (approximately US$365 million) injunction order may be reinstated if a final settlement arrangement is not agreed by 30 October 2017.

As noted above, Samarco has recognised a provision as of 30 June 2017 of US$2.1 billion before tax and after discounting (30 June 2016: US$2.4 billion) in respect of its obligations under the Framework Agreement. While a final decision on ratification of the Framework Agreement is pending, and negotiation of a settlement of the R$20 billion (approximately US$6.1 billion) public civil claim and R$155 billion (approximately US$47 billion) Federal Public Prosecution Office claim (noted below) under the Preliminary Agreement are ongoing, the Framework Agreement remains binding between the parties and Fundação Renova will continue to implement the programs under the Framework Agreement.

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Given the status of these proceedings, it is not possible at this time to provide a range of possible outcomes or a reliable estimate of potential future exposures for Samarco.

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$47 billion) for reparation, compensation and moral damages in relation to the Samarco dam failure.

With regard to the Preliminary Agreement, the 12th Federal Court suspended the Federal Public Prosecution Office claim, including a R$7.7 billion (approximately US$2.3 billion) injunction request.

However, proceedings may be resumed if a final settlement arrangement is not agreed by 30 October 2017.

Given the status of these proceedings, it is not possible at this time to provide a range of possible outcomes or a reliable estimate of potential future exposures for Samarco.

Class action complaint – 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 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.

The amount of damages sought by the plaintiffs 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 Samarco.

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.

Under the criminal charges against Samarco, Vale and BHP Billiton Brasil and certain individuals, a R$20 billion (approximately US$6.1 billion) asset freezing order application was made by the Federal Prosecutors. In July 2017, the Federal Court of Ponte Nova denied the Federal Prosecutors’ application for an asset freezing order.

Given the 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 for Samarco.

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Other claims

The civil public actions filed by State Prosecutors in Minas Gerais (claiming damages of approximately R$7.5 billion, US$2.3 billion), State Prosecutors in Espírito Santo (claiming damages of approximately R$2 billion, US$605 million), and public defenders in Minas Gerais (claiming damages of approximately R$10 billion, US$3 billion), have been consolidated before the 12th Federal Court. All of those civil public actions except the latter have also been suspended by the 12th Federal Court. Given the preliminary status of these proceedings, and the duplicative nature of the damages sought in these proceedings and the R$20 billion (approximately US$6.1 billion) and R$155 billion (approximately US$47 billion) claims it is not possible at this time to provide a range of possible outcomes or a reliable estimate of potential future exposures for Samarco.

Other pending lawsuits and investigations are at the early stages of proceedings. Until further facts are developed; court rulings clarify the issues in dispute, liability and damages; trial activity nears, or other actions such as possible settlements occur, it is not possible to arrive at a range of outcomes, or a reliable estimate of Samarco’s obligations arising from these matters and therefore Samarco has not recognised a provision or quantified a contingent liability.

Additional claims may be brought against Samarco. A provision has not been made by Samarco for claims yet to be filed. Given the significant uncertainties surrounding possible outcomes it is not possible for Samarco to arrive at a range of outcomes or a reliable estimate of the liability for any unfiled claims.

Samarco insurance

Samarco has standalone insurance policies in place with Brazilian and global insurers. Samarco has notified insurers, including those covering 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 2017.

Samarco commitments

At 30 June 2017, Samarco has commitments of US$1.5 billion (30 June 2016: 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.

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 the proceedings, the timing of resolution and potential economic outflow are uncertain. BHP has no legal obligation in relation to these matters as no BHP entity is a party to any claim.

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$4.9 billion (approximately US$1.5 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$4.1 billion (approximately US$1.2 billion).

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4    Expenses and other income

	2017			2016			2015
	US$M			US$M			US$M
Employee benefits expense:
Wages, salaries and redundancies		3,474			3,414			4,537
Employee share awards		106			140			203
Social security costs		3			2			2
Pension and other post-retirement obligations		284			232			358
Less employee benefits expense classified as exploration and evaluation expenditure		(80	)		(86	)		(129	)
Changes in inventories of finished goods and work in progress		(745	)		294			139
Raw materials and consumables used		3,908			4,063			4,667
Freight and transportation		2,284			2,226			2,644
External services		4,765			4,984			6,284
Third party commodity purchases		1,157			1,013			1,165
Net foreign exchange losses/(gains)		103			(153	)		(469	)
Government royalties paid and payable		1,986			1,349			1,708
Exploration and evaluation expenditure incurred and expensed in the current period		612			430			670
Depreciation and amortisation expense		7,931			8,661			9,158
Net impairments:
Property, plant and equipment		160			7,377			3,445
Goodwill and other intangible assets		33			17			570
Available for sale financial assets		–			–			9
Operating lease rentals		469			528			636
All other operating expenses		1,090			996			1,413
Total expenses		27,540			35,487			37,010
(Gains)/losses on disposal of property, plant and equipment		(359	)		13			7
Other income		(377	)		(457	)		(503	)
Total other income		(736	)		(444	)		(496	)

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.

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5    Income tax expense

	2017			2016			2015
	US$M			US$M			US$M
Total taxation expense/(benefit) comprises:
Current tax expense		4,288			2,456			3,168
Deferred tax (benefit)/expense		(188	)		(3,508	)		498
		4,100			(1,052	)		3,666

	2017			2016			2015
	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/(loss) before taxation		10,322			(7,259	)		8,056
Tax on profit/(loss) at Australian prima facie tax rate of 30 per cent		3,097			(2,178	)		2,417
Tax on remitted and unremitted foreign earnings		478			(376	)		58
Non-tax effected operating losses and capital gains		259			671			143
Amounts under/(over) provided in prior years		199			(28	)		138
Foreign exchange adjustments		88			125			339
Tax rate changes		25			14			137
Investment and development allowance		(53	)		(36	)		(190	)
Tax effect of profit/(loss) from equity accounted investments, related impairments and expenses (1)		(82	)		631			(164	)
Recognition of previously unrecognised tax assets		(106	)		(36	)		(212	)
Impact of tax rates applicable outside of Australia		(189	)		(620	)		(301	)
Other		217			536			397
Income tax expense/(benefit)		3,933			(1,297	)		2,762
Royalty-related taxation (net of income tax benefit)		167			245			904
Total taxation expense/(benefit)		4,100			(1,052	)		3,666

⁽¹⁾ 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.

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Income tax recognised in other comprehensive income is as follows:

	2017			2016			2015
	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 (losses)/gains taken to equity		–			(1	)		1
Net valuation losses/(gains) transferred to the income statement		–			–			34
Cash flow hedges:
Gains/(losses) taken to equity		(105	)		170			539
(Gains)/losses transferred to the income statement		129			(199	)		(545	)
Income tax credit/(charge) relating to items that may be reclassified subsequently to the income statement		24			(30	)		29
Items that will not be reclassified to the income statement:
Remeasurement gains/(losses) on pension and medical schemes		(12	)		5			14
Employee share awards transferred to retained earnings on exercise		(14	)		(22	)		(31	)
Income tax (charge)/credit relating to items that will not be reclassified to the income statement		(26	)		(17	)		(17	)
Total income tax (charge)/credit relating to components of other comprehensive income (1)		(2	)		(47	)		12

⁽¹⁾  Included within total income tax relating to components of other comprehensive income is US$12 million relating to deferred taxes and US$(14) million relating to current taxes (2016: US$(25) million and US$(22) million; 2015: US$43 million and US$(31) million).

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;	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.

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Current tax	Deferred tax	Royalty-related taxation
	•       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.

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 adequately provided for at 30 June 2017. Matters without a probable economic outflow and / or presently incapable of being measured reliably are contingent liabilities and disclosed in note 33 ‘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.

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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$278 million (A$362 million) (inclusive of interest and penalties). In May 2016, the Group received further amended assessments totalling US$413 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 finalisation 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$90 million (A$117 million). 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. As a result of the objections being determined, it is estimated the primary tax subject to dispute for the 2006–2010 income years will total US$33 million (A$43 million). The Group has sought review of the disallowed objections. Between May 2016 and May 2017, the Group received amended assessments for primary tax of US$30 million (A$39 million) relating to the 2012–2015 income years, and interest of US$4 million (A$5 million) (with nil penalties). The Group has formally objected to the amended assessments.
Royalty reassessments dispute with Queensland Office of State Revenue	The Group has commenced proceedings in the Supreme Court of Queensland pertaining to disputed royalty reassessments issued by the Queensland Office of State Revenue (OSR) in relation to its share of BHP Billiton Mitsubishi Alliance (BMA) coal. The dispute relates primarily to the basis for calculating the value of coal for royalty purposes under Queensland law. The reassessments relate to the period from 1 July 2005–30 September 2015. The reassessments total US$173 million (A$225 million) in royalties and US$80 million (A$104 million) in interest (BHP share).
Samarco tax assessments	Details of uncertain tax and royalty matters relating to Samarco are disclosed in note 3 ‘Significant events – Samarco dam failure’.

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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 and the recognition of deferred tax assets of capital allowances in Australia, on a consistent basis, using assumptions and projected cash flows as applied in the Group impairment reviews 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 are 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 33 ‘Contingent liabilities’).

6    Earnings per share

	2017		2016			2015
Earnings/(loss) attributable to BHP shareholders (US$M)
– Continuing operations		5,890		(6,385	)		3,483
– Total		5,890		(6,385	)		1,910
Weighted average number of shares (Million)
– Basic		5,323		5,322			5,318
– Diluted		5,336		5,322			5,333
Basic earnings/(loss) per ordinary share (US cents)
– Continuing operations		110.7		(120.0	)		65.5
– Total		110.7		(120.0	)		35.9
Diluted earnings/(loss) per ordinary share (US cents)
– Continuing operations		110.4		(120.0	)		65.3
– Total		110.4		(120.0	)		35.8

Refer to note 27 ‘Discontinued operations’ for basic earnings per share and diluted earnings per share for Discontinued operations.

F-34

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 13 million dilutive shares has been taken into account for the year ended 30 June 2017 (2016: nil; 2015: 15 million shares). 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 23 ‘Employee share ownership plans’. Diluted earnings per share calculation excludes instruments which are considered antidilutive.

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 2017, there are no instruments which are considered antidilutive (2015: 160,116 antidilutive shares).

Working capital

7    Trade and other receivables

	2017		2016
	US$M		US$M
Trade receivables		1,855		1,730
Loans to equity accounted investments		644		897
Other receivables		1,140		1,395
Total		3,639		4,022
Comprising:
Current		2,836		3,155
Non-current		803		867

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.

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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 assessed for impairment where indicators of such impairment exist. 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 2017, trade receivables are stated net of provisions for doubtful debts of US$ nil (2016: US$ nil). As of 30 June 2017, trade receivables of US$19 million (2016: US$12 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.

8    Trade and other payables

	2017		2016
	US$M		US$M
Trade creditors		3,996		3,662
Other creditors		1,560		1,740
Total		5,556		5,402
Comprising:
Current		5,551		5,389
Non-current		5		13

9    Inventories

	2017		2016		Definitions
	US$M		US$M
Raw materials and consumables		1,241		1,394	Spares, consumables and other supplies yet to be utilised in the production process or in the rendering of services.
Work in progress		2,852		2,149	Commodities currently in the production process that require further processing by the Group to a saleable form.
Finished goods		675		632	Commodities held-for-sale and not requiring further processing by the Group.
Total (1)		4,768		4,175
Comprising:
Current		3,673		3,411	Inventories classified as non-current are not expected to be utilised or sold within 12 months after the reporting date.
Non-current		1,095		764

⁽¹⁾  Inventory write-downs of US$112 million were recognised during the year (2016: US$118 million; 2015: US$182 million). Inventory write-downs of US$19 million made in previous periods were reversed during the year (2016: US$118 million; 2015: US$42 million).

F-36

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.

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.

F-37

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 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	)
Net book value – 30 June 2016
At the beginning of the financial year		8,762			48,361			21,069			14,502			1,378			94,072
Additions (1)(2)		4			(89	)		750			5,337			344			6,346
Depreciation for the year		(574	)		(6,780	)		(1,090	)		–			4			(8,440	)
Impairments, net of reversals		(49	)		(2,892	)		(4,432	)		–			(4	)		(7,377	)
Disposals		(15	)		(64	)		(8	)		(13	)		(10	)		(110	)
Divestment and demerger of subsidiaries and operations		(39	)		(120	)		(5	)		(3	)		–			(167	)
Exchange variations taken to reserve		–			2			–			–			–			2
Transfers and other movements		916			9,348			(342	)		(10,262	)		(11	)		(351	)
At the end of the financial year		9,005			47,766			15,942			9,561			1,701			83,975
– Cost		12,425			98,688			30,924			9,562			2,612			154,211
– Accumulated depreciation and impairments		(3,420	)		(50,922	)		(14,982	)		(1	)		(911	)		(70,236	)

⁽¹⁾  Includes net foreign exchange gains/(losses) related to the closure and rehabilitation provisions. Refer to note 14 ‘Closure and rehabilitation provisions’.

⁽²⁾  Property, plant and equipment of US$593 million (2016: US$ nil; 2015: US$10 million) was acquired under finance lease. This is a significant non-cash investing transaction that has been excluded from the Consolidated Cash Flow Statement.

F-38

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 32 ‘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.

F-39

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.

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.

F-40

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.

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 interburden 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 benefit arising from the improved access to future ore production will be realised;

F-41

	Production stripping activity
		– 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.
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.

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.

Depreciation

The estimation of useful lives, residual values and depreciation methods require significant management judgement and are reviewed annually. Any changes to useful lives may affect prospective depreciation rates and asset carrying values.

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.

F-42

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

11    Intangible assets

	2017									2016
	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		3,273			846			4,119			3,274			1,018			4,292
Additions		–			81			81			–			78			78
Amortisation for the year		–			(195	)		(195	)		–			(221	)		(221	)
Impairments for the year		–			(33	)		(33	)		(1	)		(16	)		(17	)
Disposals		(4	)		–			(4	)		–			(10	)		(10	)
Other		–			–			–			–			(3	)		(3	)
At the end of the financial year		3,269			699			3,968			3,273			846			4,119
– Cost		3,269			1,722			4,991			3,273			1,813			5,086
– Accumulated amortisation and impairments		–			(1,023	)		(1,023	)		–			(967	)		(967	)

F-43

Recognition and measurement

Goodwill

Other intangibles

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.

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.

12    Impairment of non-current assets

Year ended 30 June 2017

Year ended 30 June 2016

Cash generating unit

Segment

Property, plant and equipment

Goodwill and other intangibles

Total

Cash generating unit

Segment

Property, plant and equipment

Goodwill and other intangibles

Total

US$M

US$M

US$M

US$M

US$M

US$M

Fayetteville

Petroleum

1,913

–

1,913

Haynesville

Petroleum

2,585

–

2,585

Black Hawk

Petroleum

1,861

–

1,861

Hawkville

Petroleum

825

–

825

7,184

–

7,184

Other

Various

160

33

193

Other

Various

193

17

210

Total impairment of non-current assets

160

33

193

Total impairment of non-current assets

7,377

17

7,394

Reversal of impairment

–

–

–

Reversal of impairment

–

–

–

Net impairment of non-current assets

160

33

193

Net impairment of non-current assets

7,377

17

7,394

F-44

Recognition and measurement

Impairment tests are carried out annually for goodwill. In addition, impairment tests for all assets are performed when there is an indication of impairment. 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 fair value and consequently the VIU calculation is likely to give a different result (usually lower) to a fair value calculation.

Impairment of non-current assets (excluding goodwill)

Impairments of Petroleum CGUs of US$ nil (2016: US$7,184 million) have been recognised during the year. Property, plant and equipment including other intangible asset impairments of US$193 million (2016: US$210 million) were recognised during the year.

Petroleum – year ended 30 June 2016
What has been recognised?	The Group recognised an impairment charge of US$7,184 million (US$4,884 million after tax benefit) against the carrying value of individual Onshore US CGUs.
What were the drivers of impairment?	As a result of significant volatility and weaker prices experienced in the oil and gas industry, management adjusted its medium-term and long-term price assumptions and discount rates, which had a significant flow through impact on asset valuations.

F-45

Petroleum – year ended 30 June 2016
How were the valuations calculated?	Using these updated assumptions, valuations of the relevant Onshore US CGUs were calculated using FVLCD methodology, applying discounted cash flow techniques. The recoverable amount in each instance is equal to its estimated FVLCD. Calculations are based primarily on Level 3 inputs as defined in note 21 ‘Financial risk management’.
What were the significant assumptions and estimates used in the valuations?	The valuations are most sensitive to changes in crude oil and natural gas prices, estimated future production volumes and discount rates. Key judgements and estimates used in determining FVLCD are disclosed below.

Impairment test for goodwill

The carrying amount of goodwill has been allocated to the CGUs, or groups of CGUs, as follows:

	2017		2016
	US$M		US$M
Onshore US		3,022		3,026
Other		247		247
Total		3,269		3,273

For the purpose of impairment testing, goodwill has been allocated to CGUs or groups of CGUs, that are expected to benefit from the synergies of previous business combinations, which represent the level at which management will monitor and manage goodwill. Onshore US goodwill is the most significant goodwill balance and has been tested for impairment after an assessment of the individual CGUs that it comprises.

Onshore US goodwill
Carrying value	US$3,022 million (2016: US$3,026 million).
Impairment test conclusion as at 30 June 2017	No impairment charge is required as at 30 June 2017 (30 June 2016: US$ nil). The recoverable amount of Onshore US CGUs is estimated to exceed the carrying amount of the CGUs at 30 June 2017 by US$4,305 million (30 June 2016: US$1,141 million).
How did the goodwill arise?	Goodwill arose on the Petrohawk acquisition in August 2011 and is attributable to synergies associated with the Group’s US unconventional petroleum assets (Onshore US). This comprises the Permian, Haynesville, Fayetteville, Black Hawk and Hawkville group of CGUs, which includes the Group’s natural gas and liquid reserves and resources, production wells and associated infrastructure, including gathering systems and processing facilities in Texas and Louisiana (US).
Segment	Onshore US is part of the Petroleum reportable segment.
How were the valuations calculated?	FVLCD methodology using discounted cash flow techniques has been applied in determining the recoverable value of the Onshore US business.
Level of fair value hierarchy	Calculations are based primarily on Level 3 inputs as defined in note 21 ‘Financial risk management’.

F-46

Onshore US goodwill

Significant assumptions and sensitivities

The calculation of FVLCD for Onshore US is most sensitive to changes in a market participant’s perspective of crude oil and natural gas prices, production volumes and discount rates. Key accounting judgements and estimates used in forming the valuations are disclosed below. Reasonably possible changes in circumstances may affect significant assumptions and the estimated fair value. Isolated changes in these significant assumptions could result in an impairment charge being recognised against goodwill. The reasonably possible changes that would result in the estimated recoverable amount being equal to the carrying amount of Onshore US, including goodwill are: •       A production volume decrease of 11.0 per cent from estimates contained in management’s long-term plans; •       A decrease in crude oil prices of 20.4 per cent from prices assumed in the valuations; or •       A decrease in natural gas prices of 23.7 per cent from prices assumed in the valuations. Crude oil and natural gas price assumptions used in FVLCD impairment testing are consistent with the range of prices published by market commentators, as set out within the following key judgements and estimates section. The isolated increase in the discount rate that would result in the estimated recoverable amount being equal to the carrying amount of Onshore US, including goodwill, is not considered to be reasonably possible. Typically changes in any one of the aforementioned assumptions (including operating performance) would be accompanied by a change in another assumption which may have an offsetting impact. Action is usually taken to respond to adverse changes in assumptions to mitigate the impact of any such change.

Other goodwill

Goodwill held by other CGUs is US$247 million (2016: US$247 million). This represents less than one per cent of net assets at 30 June 2017 (2016: less than one per cent). This goodwill has been allocated across a number of CGUs in different reportable segments. There was no impairment of other goodwill in the year to 30 June 2017 (2016: US$1 million).

Key judgements and estimates

Recoverable amount testing

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.

F-47

The most significant estimates impacting asset recoverable amount valuations for Onshore US assets, including goodwill are:

Crude oil and natural gas prices

Crude oil and natural gas prices used in valuations were consistent with the following range of prices published by market commentators:

	2017		2016
West Texas Intermediate crude oil price (US$/bbl)		51.48 – 89.31		49.00 – 81.00
Henry Hub natural gas price (US$/MMBtu)		2.68 – 4.44		2.74 – 5.55

Oil and gas prices were derived from consensus and long-term views of global supply and demand, built upon past experience of the industry and consistent with external sources. Prices are adjusted based upon premiums or discounts applied to global price markers based on the location, nature and quality produced at a field, or to take into account contracted oil and gas prices.

Future production volumes

Estimated production volumes were based on detailed data for the fields and took into account development plans for the fields established by management as part of the long-term planning process. Production volumes are dependent on variables, such as the recoverable quantities of hydrocarbons, the production profile of the hydrocarbons, the cost of the development of the infrastructure necessary to recover the hydrocarbons, the production costs and the contractual duration of the production leases. As each producing field has specific reservoir characteristics and economic circumstances, the cash flows of the fields were computed using appropriate individual economic models and key assumptions established by management. When estimating FVLCD, assumptions reflect all reserves and resources that a market participant would consider when valuing the Onshore US business, which in some cases are broader in scope than the reserves that would be used in a VIU test. In determining FVLCD, risk factors may be applied to reserves and resources which do not meet the criteria to be treated as proved.

Impact of oil and gas reserves and future anticipated production levels on testing for impairment

Production volumes and prices used in estimating FVLCD valuations may not be consistent with those disclosed as proved reserves under SEC Rule 4-10(a) of Regulation S-X in section 6.3.1 ‘Petroleum reserves’. Section 6.3.1 ‘Petroleum reserves’ is unaudited and does not form part of these Financial Statements. FVLCD requires the use of assumptions and estimates that a typical market participant would assume, which include having regard to future forecast oil and gas prices and anticipated field production estimates. This contrasts with SEC requirements to use unweighted 12-month average historical prices for reserve definitions.

Under SEC requirements, certain previously reported proved reserves may temporarily not meet the definition of proved reserves due to decreases in price in the previous 12 months. This does not preclude these reserves from being reinstated as proved reserves in future periods when prices recover.

Short-term changes in SEC reported oil and gas reserves do not affect the Group’s perspective on underlying project valuations due to the long lives of the assets and future forecast prices.

Discount rates

A real post-tax discount rate of 7.0 per cent (2016: 6.5 per cent) was applied to post-tax cash flows. The discount rate is derived using the weighted average cost of capital methodology and has increased from the prior year due to volatility in oil and gas markets.

F-48

13    Deferred tax balances

The movement for the year in the Group’s net deferred tax position is as follows:

	2017		2016			2015
	US$M		US$M			US$M
Net deferred tax asset/(liability)
At the beginning of the financial year		1,823		(1,681	)		(670	)
Income tax credit/(charge) recorded in the income statement		188		3,508			(864	)
Income tax credit/(charge) recorded directly in equity		12		(25	)		9
Other movement (1)		–		21			(156	)
At the end of the financial year		2,023		1,823			(1,681	)

⁽¹⁾  Includes deferred tax assets divested as part of the demerger of South32 for the year ended 30 June 2015.

For recognition and measurement refer to note 5 ‘Income tax expense’.

The composition of the Group’s net deferred tax assets and liabilities recognised in the balance sheet and the deferred tax expense (credited)/charged to the income statement is as follows:

	Deferred tax assets						Deferred tax liabilities						(Credited)/charged to the income statement
	2017			2016			2017			2016			2017			2016			2015
	US$M			US$M			US$M			US$M			US$M			US$M			US$M
Type of temporary difference
Depreciation		(3,454	)		(3,223	)		1,411			1,259			391			(2,282	)		204
Exploration expenditure		543			656			–			–			(22	)		(3	)		117
Employee benefits		379			342			3			(6	)		(37	)		56			58
Closure and rehabilitation		1,809			1,711			(230	)		(177	)		(151	)		36			41
Resource rent tax		559			661			1,614			1,905			(189	)		(8	)		925
Other provisions		131			145			(1	)		(1	)		14			8			103
Deferred income		(2	)		–			(10	)		(11	)		3			(49	)		17
Deferred charges		(443	)		(470	)		322			372			(77	)		62			66
Investments, including foreign tax credits		1,145			1,327			648			844			(17	)		(284	)		(58	)
Foreign exchange gains and losses		(87	)		(77	)		69			156			(77	)		(310	)		210
Tax losses		5,352			5,006			–			–			(381	)		(809	)		(945	)
Other		(144	)		69			(61	)		(17	)		355			75			126
Total		5,788			6,147			3,765			4,324			(188	)		(3,508	)		864

The Group recognises the benefit of tax losses amounting to US$5,352 million (2016: US$5,006 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’.

F-49

The composition of the Group’s unrecognised deferred tax assets and liabilities is as follows:

	2017		2016
	US$M		US$M
Unrecognised deferred tax assets
Tax losses and tax credits (1)		2,687		2,549
Investments in subsidiaries (2)		856		1,185
Deductible temporary differences relating to PRRT (3)		2,293		2,048
Mineral rights (4)		2,293		2,279
Other deductible temporary differences (5)		478		460
Total unrecognised deferred tax assets		8,607		8,521
Unrecognised deferred tax liabilities
Investments in subsidiaries (2)		2,500		2,615
Taxable temporary differences relating to unrecognised deferred tax asset for PRRT (3)		694		614
Total unrecognised deferred tax liabilities		3,194		3,229

⁽¹⁾  At 30 June 2017, the Group had income and capital tax losses with a tax benefit of US$1,844 million (2016: US$1,781 million) and tax credits of US$843 million (2016: US$768 million), which are not recognised as deferred tax assets.

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		1,199
Later than one year and not later than two years		747
Later than two years and not later than five years		1,288
Later than five years and not later than 10 years		365
Later than 10 years and not later than 20 years		1,358
Unlimited		848
		5,805
Capital tax losses
Not later than one year		238
Later than two years and not later than five years		144
Unlimited		3,389
Gross amount of tax losses not recognised		9,576
Tax effect of total losses not recognised		1,844

Of the US$843 million of tax credits, US$775 million expires not later than 10 years and US$68 million expires later than 10 years and not later than 20 years.

⁽²⁾ The Group had deferred tax assets of US$856 million at 30 June 2017 (2016: US$1,185 million) and deferred tax liabilities of US$2,500 million (2016: US$2,615 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.

F-50

⁽³⁾ The Group had US$2,293 million of unrecognised deferred tax assets relating to Australian Petroleum Resource Rent Tax (PRRT) at 30 June 2017 (2016: US$2,048 million relating to Australian PRRT), with a corresponding unrecognised deferred tax liability for income tax purposes of US$694 million (2016: US$614 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$2,293 million at 30 June 2017 (2016: US$2,279 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$478 million at 30 June 2017 (2016: US$460 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.

14    Closure and rehabilitation provisions

	2017			2016
	US$M			US$M
At the beginning of the financial year		6,502			6,701
Capitalised amounts for operating sites:
Change in estimate		71			(58	)
Exchange translation		99			(112	)
Adjustments charged/(credited) to the income statement:
Increases to existing and new provisions		127			18
Exchange translation		9			(8	)
Released during the year		(120	)		(81	)
Other adjustments to the provision:
Amortisation of discounting impacting net finance costs		330			305
Expenditure on closure and rehabilitation activities		(132	)		(111	)
Exchange variations impacting foreign currency translation reserve		(1	)		(1	)
Divestment and demerger of subsidiaries and operations		(146	)		(138	)
Transfers and other movements		(1	)		(13	)
At the end of the financial year		6,738			6,502
Comprising:
Current		255			171
Non-current		6,483			6,331
Operating sites		5,462			5,241
Closed sites		1,276			1,261

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.

F-51

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.

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 charged to the income statement in the period identified. This amounted to US$33 million in the year ended 30 June 2017 (2016: US$18 million).

F-52

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 production life at the individual site. Remaining production lives range from 3-128 years with an average for all sites, weighted by current closure provision, of approximately 26 years. A 0.5 per cent decrease in the real discount rates applied at 30 June 2017 would result in an increase to the closure and rehabilitation provision of US$632 million, an increase in property, plant and equipment of which US$542 million relating to operating sites and an income statement charge of US$90 million in respect of closed sites. In addition, the change would result in an increase of approximately US$52 million to depreciation expense and an immaterial reduction in net finance costs for the year ending 30 June 2018.

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

15    Share capital

	BHP Billiton Limited									BHP Billiton Plc
	2017 shares			2016 shares			2015 shares			2017 shares			2016 shares			2015 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			2,136,185,454
Purchase of shares by ESOP Trusts		(6,481,292	)		(6,538,404	)		(6,798,803	)		(225,646	)		(17,000	)		(3,623,582	)
Employee share awards exercised following vesting		6,945,570			6,846,091			7,443,935			940,070			966,473			2,945,980
Movement in treasury shares under Employee Share Plans		(464,278	)		(307,687	)		(645,132	)		(714,424	)		(949,473	)		677,602
Treasury shares cancelled (1)		–			–			–			–			–			(24,113,658	)
Closing number of shares (2)		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		3,211,623,973			3,211,159,695			3,210,852,008			2,111,997,680			2,111,283,256			2,110,333,783
Treasury shares		67,132			531,410			839,097			74,116			788,540			1,738,013
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			–			–			–			–

F-53

⁽¹⁾ BHP Billiton Plc cancelled 24,113,658 ordinary shares of US$0.50 each held as treasury shares on 28 August 2014.

⁽²⁾ 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 2017 to 7 September 2017.

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.

Equalisation share	DLC Dividend share	Treasury shares
An Equalisation share (US$0.50 par value) has been authorised to be issued to enable a distribution to be made by BHP Billiton Plc to BHP Billiton Limited should this be required under the terms of the DLC merger. The Directors have the ability to issue the Equalisation share if required under those terms. The Constitution of BHP Billiton Limited allows the Directors of that company to issue a similar Equalisation share. No shares have been issued.	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 22 March 2017, BHP Billiton Limited paid a dividend of US$440 million under the DLC dividend share arrangements. This dividend is 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-54

16    Other equity

	2017		2016		2015		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		40		41		52	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		214		293		372	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		153		210		141	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		10		11		9	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 reserve.
Non-controlling interest contribution reserve		1,288		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		2,400		2,538		2,557

F-55

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:

	2017							2016
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		2,107							2,033
Non-current assets		14,528							14,241
Current liabilities		(1,339	)						(2,240	)
Non-current liabilities		(4,300	)						(2,316	)
Net assets		10,996							11,718
Net assets attributable to NCI		4,673			795		5,468		4,980			801			5,781
Revenue		4,576							5,071
Profit after taxation		516							505
Other comprehensive income		–							(5	)
Total comprehensive income		516							500
Profit after taxation attributable to NCI		219			113		332		214			(36	)		178
Other comprehensive income attributable to NCI		–			–		–		(2	)		–			(2	)
Net operating cash flow		1,964							1,868
Net investing cash flow		(999	)						(2,268	)
Net financing cash flow		(968	)						507
Dividends paid to NCI		507			74		581		–			87			87

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.

17    Dividends

	Year ended 30 June 2017				Year ended 30 June 2016				Year ended 30 June 2015
	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		14.0		749		62.0		3,299		62.0		3,292
Interim dividend		40.0		2,130		16.0		855		62.0		3,304
		54.0		2,879		78.0		4,154		124.0		6,596

⁽¹⁾  5.5 per cent dividend on 50,000 preference shares of £1 each determined and paid annually (2016: 5.5 per cent; 2015: 5.5 per cent).

F-56

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 22 August 2017, BHP Billiton Limited and BHP Billiton Plc determined a final dividend of 43.0 US cents per share (US$2,289 million), which will be paid on 26 September 2017 (30 June 2016: final dividend of 14.0 US cents per share – US$746 million; 30 June 2015: final dividend of 62.0 US cents per share – US$3,301 million).

BHP Billiton Limited dividends for all periods presented are, or will be, fully franked based on a tax rate of 30 per cent.

	2017		2016		2015
	US$M		US$M		US$M
Franking credits as at 30 June		10,155		9,640		11,295
Franking credits/(debits) arising from the payment /(refund) of current tax		1,239		81		(428	)
Total franking credits available (1)		11,394		9,721		10,867

⁽¹⁾  The payment of the final 2017 dividend determined after 30 June 2017 will reduce the franking account balance by US$592 million.

F-57

18    Provisions for dividends and other liabilities

The disclosure below excludes closure and rehabilitation provisions (refer to note 14 ‘Closure and rehabilitation provisions’), employee benefits, restructuring and post-retirement employee benefits provisions (refer to note 24 ‘Employee benefits, restructuring and post-retirement employee benefits provisions’) and the Samarco dam failure provision (refer to note 3 ‘Significant events – Samarco dam failure’).

	2017			2016
	US$M			US$M
Movement in provision for dividends and other liabilities
At the beginning of the financial year		930			364
Dividends determined		2,871			4,154
Charge/(credit) for the year:
Underlying		316			709
Discounting		5			–
Exchange variations		53			(28	)
Released during the year		(122	)		(82	)
Utilisation		(223	)		(141	)
Dividends paid		(2,921	)		(4,130	)
Transfers and other movements		75			84
At the end of the financial year (1)		984			930
Comprising:
Current		332			306
Non-current		652			624

⁽¹⁾  Includes unpaid dividend determined to non-controlling interest of US$105 million (2016: US$85 million).

F-58

Financial management

19    Net debt

The Group’s corporate purpose is to own and operate large, long-life, low-cost, expandable, upstream assets diversified by commodity, geography and market. The Group will invest capital in assets where they fit its strategy.

The Group monitors capital using a gearing ratio, being the ratio of net debt to net debt plus net assets.

	2017					2016
US$M	Current		Non-current			Current		Non-current
Interest bearing liabilities
Bank loans		192		2,089			1,240		796
Notes and debentures		771		26,270			3,280		30,515
Finance leases		82		815			40		306
Bank overdraft and short-term borrowings		45		–			43		–
Other		151		59			50		151
Total interest bearing liabilities		1,241		29,233			4,653		31,768
Less cash and cash equivalents
Cash		882		–			491		–
Short-term deposits		13,271		–			9,828		–
Total cash and cash equivalents		14,153		–			10,319		–
Net debt				16,321					26,102
Net assets				62,726					60,071
Gearing				20.6	%				30.3	%

Cash and short-term deposits are disclosed in the cash flow statement net of bank overdrafts and interest bearing liabilities at call.

	2017			2016			2015
	US$M			US$M			US$M
Total cash and cash equivalents		14,153			10,319			6,753
Bank overdrafts and short-term borrowing		(45	)		(43	)		(140	)
Total cash and cash equivalents, net of overdrafts		14,108			10,276			6,613

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$180 million (2016: US$248 million) restricted by legal or contractual arrangements.

F-59

Interest bearing liabilities and cash and cash equivalents include balances denominated in the following currencies:

	Interest bearing liabilities				Cash and cash equivalents
	2017		2016		2017		2016
	US$M		US$M		US$M		US$M
USD		14,035		19,600		7,980		10,083
EUR		10,324		10,419		4,663		–
GBP		3,520		3,886		1,318		37
AUD		1,987		1,870		9		38
CAD		608		646		77		89
Other		–		–		106		72
Total		30,474		36,421		14,153		10,319

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 throughout FY2017. They affirmed this rating and changed their outlook on 20 January 2017 from negative to stable. Moody’s maintained their credit rating for the Group of A3 throughout FY2017 and improved their outlook from stable to positive on 3 May 2017.

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 investments such as 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 cash investments.

Investments 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-60

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$6.0 billion. As at 30 June 2017, US$ nil commercial paper was drawn (2016: 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:

2017 US$M	Bank loans, debentures and other loans		Expected future interest payments		Derivatives related to net debt		Other derivatives		Obligations under finance leases		Trade and other payables		Total
Due for payment:
In one year or less or on demand		1,157		686		267		144		135		5,417		7,806
In more than one year but not more than two years		2,471		1,022		245		4		132		5		3,879
In more than two years but not more than five years		8,279		2,611		503		7		343		–		11,743
In more than five years		16,706		6,248		1,975		–		705		–		25,634
Total		28,613		10,567		2,990		155		1,315		5,422		49,062
Carrying amount		29,577		–		1,345		155		897		5,422		37,396
2016 US$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		4,568		826		118		5		49		5,125		10,691
In more than one year but not more than two years		938		1,151		409		3		66		1		2,568
In more than two years but not more than five years		9,447		3,014		837		7		155		5		13,465
In more than five years		18,847		7,250		1,997		–		115		7		28,216
Total		33,800		12,241		3,361		15		385		5,138		54,940
Carrying amount		36,075		–		1,768		15		346		5,138		43,342

F-61

20    Net finance costs

	2017			2016			2015
	US$M			US$M			US$M
Financial expenses
Interest on bank loans, overdrafts and all other borrowings		1,131			971			526
Interest capitalised at 3.25% (2016: 2.61%; 2015: 1.94%) (1)		(113	)		(123	)		(148	)
Discounting on provisions and other liabilities		462			313			333
Fair value change on hedged loans		(1,185	)		1,444			372
Fair value change on hedging derivatives		1,244			(1,448	)		(358	)
Exchange variations on net debt		(23	)		(24	)		(63	)
Other financial expenses		58			28			40
		1,574			1,161			702
Financial income
Interest income		(143	)		(137	)		(88	)
Net finance costs		1,431			1,024			614

⁽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$34 million (2016: US$37 million; 2015: US$42 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.

21    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-62

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 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. 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.	• •	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.
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 investments 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 2017, 90 per cent of the Group’s borrowings were exposed to floating interest rates inclusive of the effect of swaps (2016: 91 per cent).

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 fair values section of this note.

Based on the net debt position as at 30 June 2017, 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$92 million (2016: decrease of US$156 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.

F-63

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 and the Chilean peso; however, 86 per cent (2016: 91 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 2017, a weakening of the US dollar against these currencies (one cent strengthening in Australian dollar 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$16 million (2016: decrease of US$15 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.

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 the majority of 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. Due to the nature of the economic returns from our shale assets, from time to time the Group enters into natural gas futures contracts to manage price risk on gas production. 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.

F-64

Financial instruments with commodity price risk are forward commodity and other derivative contracts with a net assets fair value of US$358 million (2016: US$229 million). Significant items are primarily derivatives embedded in physical commodity purchase and sales contracts of gas in Trinidad and Tobago with a net assets fair value of US$370 million (2016:US$220 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$62 million (2016: US$34 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 2017 to the impact of movements in commodity prices upon provisionally invoiced sales and purchases volumes was predominately around copper.

The Group had 213,000 tonnes of copper exposure at 30 June 2017 (2016: 277,000 tonnes) that was provisionally priced. The final price of these sales or purchases will be determined during the first half of FY2018. 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$90 million (2016: US$98 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 19 ‘Net debt’ for details on the Group liquidity risk.

Credit risk

Refer to note 7 ‘Trade and other receivables’ for details on the Group credit risk.

Financial assets and liabilities

The financial assets and liabilities are presented by class in the tables page F-69 at their carrying amounts, which generally approximate to fair value.

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.

F-65

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 securities

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 financial assets are measured at fair value. Gains and losses on the remeasurement of trading investments are recognised directly in the income statement. Gains and losses on the remeasurement of available for sale securities and investments 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. Borrowings are subsequently measured at amortised cost using the effective interest method. Borrowings 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 a financial 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.

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.

F-66

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 and forward commodity; and exchange rates. Quoted market prices or dealer quotes for similar instruments are used for long-term debt instruments held.
How are changes in fair value accounted for?	The following changes in the fair value are recognised immediately in the income statement: –       the gains or losses on both the derivative or financial instrument and hedged asset or liability attributable to the hedged risk; –       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.

F-67

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.

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.

F-68

The financial assets and liabilities are presented by class in the table on page F-69 at their carrying amounts, which generally approximate to fair value. In the case of US$3,019 million (2016: US$3,020 million) of fixed rate debt not swapped to floating rate, the fair value at 30 June 2017 was US$3,523 million (2016: US$3,539 million).

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)

–

–

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)

–

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 (5)

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)(6)

–

–

144

–

–

144

Non-current cross currency and interest rate swaps

–

–

42

1,053

–

1,095

Non-current other derivative contracts (2)(6)

–

–

4

7

–

11

Total other financial liabilities

–

–

186

1,314

–

1,500

Trade and other payables (7)

–

–

502

–

4,920

5,422

Bank overdrafts and short-term borrowings (8)

–

–

–

–

45

45

Bank loans (8)

–

–

–

–

2,281

2,281

Notes and debentures (8)

–

–

–

–

27,041

27,041

Finance leases (8)

–

–

–

–

897

897

Other (8)

–

–

–

–

210

210

Total financial liabilities

–

–

688

1,314

35,394

37,396

Non-financial liabilities

16,884

Total liabilities

54,280

F-69

2016 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

–

–

43

–

–

43

Current other derivative contracts (2)

–

–

42

–

–

42

Current available for sale shares and other investments (3)

–

–

36

–

–

36

Non-current cross currency and interest rate swaps

–

–

2,291

(54

)

–

2,237

Non-current other derivative contracts (2)

–

–

202

–

–

202

Non-current available for sale shares and other investments (3)(4)

–

25

216

–

–

241

Total other financial assets

–

25

2,830

(54

)

–

2,801

Cash and cash equivalents

10,319

–

–

–

–

10,319

Trade and other receivables (5)

1,978

–

835

–

–

2,813

Loans to equity accounted investments

897

–

–

–

–

897

Total financial assets

13,194

25

3,665

(54

)

–

16,830

Non-financial assets

102,123

Total assets

118,953

Current cross currency and interest rate swaps

–

–

–

–

–

–

Current other derivative contracts (2)(6)

–

–

5

–

–

5

Non-current cross currency and interest rate swaps

–

–

166

1,602

–

1,768

Non-current other derivative contracts (2)(6)

–

–

10

–

–

10

Total other financial liabilities

–

–

181

1,602

–

1,783

Trade and other payables (7)

–

–

256

–

4,882

5,138

Bank overdrafts and short-term borrowings (8)

–

–

–

–

43

43

Bank loans (8)

–

–

–

–

2,036

2,036

Notes and debentures (8)

–

–

–

–

33,795

33,795

Finance leases (8)

–

–

–

–

346

346

Other (8)

–

–

–

–

201

201

Total financial liabilities

–

–

437

1,602

41,303

43,342

Non-financial liabilities

15,540

Total liabilities

58,882

F-70

⁽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.

⁽²⁾  Includes other derivative contracts of US$365 million (2016: US$236 million) categorised as Level 3.

⁽³⁾ Includes other investments held at fair value through profit or loss (US Treasury Notes) of US$97 million categorised as Level 1 (2016: US$54 million).

⁽⁴⁾  Includes shares and other investments available for sale of US$70 million (2016: US$25 million) categorised as Level 3.

⁽⁵⁾  Excludes input taxes of US$262 million (2016: US$312 million) included in other receivables. Refer to note 7 ‘Trade and other receivables’.

⁽⁶⁾  Includes US$7 million (2016: US$ nil) natural gas futures contracts used by the Group to mitigate price risk designated as cash flow hedges.

⁽⁷⁾  Excludes input taxes of US$134 million (2016: US$264 million) included in other payables. Refer to note 8 ‘Trade and other payables’.

⁽⁸⁾  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 money market deposits and 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 on page F-69 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.

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.

Employee matters

22    Key management personnel

Key management personnel compensation comprises:

	2017		2016		2015
	US$		US$		US$
Short-term employee benefits		16,439,948		14,979,983		26,663,069
Post-employment benefits		1,895,828		2,356,594		2,920,007
Share-based payments		13,747,355		16,837,179		20,783,959
Total		32,083,131		34,173,756		50,367,035

F-71

Transactions and outstanding loans/amounts with key management personnel

There were no purchases by key management personnel from the Group during the financial year (2016: US$ nil; 2015: US$ nil).

There were no amounts payable by key management personnel at 30 June 2017 (2016: US$ nil; 2015: US$ nil).

There were no loans receivable from or payable to key management personnel at 30 June 2017 (2016: US$ nil; 2015: 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 2017 (2016: US$ nil; 2015: US$ nil).

For more information on remuneration and transactions with key management personnel, refer to section 3.

23    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 Operations Management Committee (OMC) 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.

The table below provides a description of each of the plans.

Plan	STIP and GSTIP	LTIP and MAP	Transitional OMC 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 OMC and the GSTIP is a plan for non-OMC management. 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 the OMC and awards are granted annually. The MAP is a plan for non-OMC management. The number of share rights awarded is determined by a participant’s role and organisational level.	Awards are granted to new OMC members recruited from within the Group to bridge the gap created by the different timeframes of the vesting of MAP awards, granted in their non-OMC role, and LTIP awards, granted to OMC members.	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.

F-72

Plan	STIP and GSTIP	LTIP and MAP	Transitional OMC awards	Shareplus
Vesting conditions	Service conditions only.	LTIP: Service conditions and performance conditions. For awards granted from December 2010 onwards, BHP’s TSR(1) performance relative to the Peer Group Total Shareholder Return (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.
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 granted prior to 1 July 2013 – 5 years MAP – none	None	None

⁽¹⁾  BHP’s TSR is the weighted average of the TSRs of BHP Billiton Limited and BHP Billiton Plc.

F-73

Employee share awards

2017	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		849,090		61,538		412,994		–		497,634		–		0.3
GSTIP awards		2,787,420		775,991		1,487,147		74,681		2,001,583		30,164		0.5
LTIP awards		4,881,058		1,309,048		291,880		1,218,713		4,679,513		67,414		2.7
Transitional OMC awards		266,820		–		70,740		58,886		137,194		–		0.7
MAP awards		6,767,037		3,701,768		2,596,657		523,720		7,348,428		57,468		1.9
Shareplus		5,736,504		2,873,800		2,093,519		518,268		5,998,517		–		1.2
Employee Share Plan shares (legacy plan)		406,618		–		67,735		–		338,883		338,883		n/a
BHP Billiton Plc
GSTIP awards		264,195		37,665		211,217		6,393		84,250		19,253		0.4
LTIP awards		660,183		–		56,069		217,202		386,912		78,655		0.1
Transitional OMC awards		21,533		–		15,719		5,814		–		–		n/a
MAP awards		1,069,828		132,435		552,142		53,678		596,443		54,502		0.6
Shareplus		320,719		171,317		123,385		32,543		336,108		–		1.2

Fair value and assumptions in the calculation of fair value for awards issued

2017	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		18.85		n/a			3 years		A$19.09		n/a			1.81	%
GSTIP awards		16.82		n/a			3 years		A$19.09		n/a			1.81	%
LTIP awards		8.08		1.65	%		5 years		A$19.09		33.0	%		1.81	%
MAP awards (1)		14.72		n/a			1-2-3 years		A$19.09 / A$24.04		n/a			1.81 3.80	% /  %
Shareplus		15.58		1.72	%		3 years		A$16.94		n/a			1.81	%
BHP Billiton Plc
GSTIP awards		14.96		n/a			3 years		£9.40		n/a			1.58	%
MAP awards		12.00		n/a			1-2-3 years		£9.40		n/a			1.58	%
Shareplus		11.93		0.35	%		3 years		£7.72		n/a			1.58	%

⁽¹⁾  Includes MAP awards granted on 31 March 2017.

Employee share awards expense is US$106.214 million (2016: US$140.445 million; 2015: US$202.955 million).

F-74

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 considers 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.

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 on page F-74 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.

24    Employee benefits, restructuring and post-retirement employee benefits provisions

	2017		2016
	US$M		US$M
Employee benefits (1)		1,177		1,145
Restructuring (2)		10		17
Post-retirement employee benefits		438		352
Total provisions		1,625		1,514
Comprising:
Current		1,062		988
Non-current		563		526

F-75

2017	Employee benefits			Restructuring			Post- retirement employee benefits			Total
	US$M			US$M			US$M			US$M
At the beginning of the financial year		1,145			17			352			1,514
Charge/(credit) for the year:
Underlying		973			13			57			1,043
Discounting		–			–			41			41
Net interest expense		–			–			(23	)		(23	)
Exchange variations		24			–			–			24
Released during the year		(13	)		(7	)		–			(20	)
Remeasurement gains taken to retained earnings		–			–			(36	)		(36	)
Utilisation		(823	)		(13	)		(80	)		(916	)
Divestment and demerger of subsidiaries and operations		(2	)		–			–			(2	)
Transfers and other movements		(127	)		–			127			–
At the end of the financial year		1,177			10			438			1,625

⁽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.

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.

F-76

Provision

Description

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.

25    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$247 million during the financial year (2016: US$232 million; 2015: US$462 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 pensions 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).

F-77

Schemes/obligations	Description
Defined benefit post-retirement medical schemes	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. In some schemes there is no funding of the benefits before retirement. These schemes are recognised on the same basis as described for defined benefit pension schemes. The Group operates a number of post-retirement medical schemes in the United States, Canada and Europe. Full actuarial valuations are prepared by local actuaries for all 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.

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.

F-78

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
	2017			2016			2017		2016
	US$M			US$M			US$M		US$M
Present value of funded defined benefit obligation		665			733			–		–
Present value of unfunded defined benefit obligation		256			115			204		214
Fair value of defined benefit scheme assets		(687	)		(710	)		–		–
Scheme deficit		234			138			204		214
Unrecognised surplus		–			–			–		–
Unrecognised past service credits		–			–			–		–
Adjustment for employer contributions tax		–			–			–		–
Net liability recognised in the Consolidated Balance Sheet		234			138			204		214

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.

26    Employees

	2017		2016		2015
	Number		Number		Number
Average number of employees (1)
Australia		15,906		15,834		16,839
South America		6,361		6,509		7,421
North America		2,786		3,601		4,188
Asia		1,019		822		1,022
Europe		74		61		83
Africa		–		–		117
Total average number of employees from Continuing operations		26,146		26,827		29,670
Total average number of employees from Discontinued operations		–		–		13,159
Total average number of employees		26,146		26,827		42,829

⁽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.

F-79

Group and related party information

27    Discontinued operations

The Group announced on 25 May 2015 that it completed the demerger of a selection of its aluminium, coal, manganese, nickel and silver-lead-zinc assets to create an independent metals and mining company, South32. This included the Group’s interests in its integrated Aluminium business, Energy Coal South Africa, Illawarra metallurgical coal, the Manganese business, the Cerro Matoso nickel operation and the Cannington silver-lead-zinc mine. The contribution of Discontinued operations included within the Group’s profit until the loss of control is detailed below:

Income statement – Discontinued operations

	2015
	US$M
Profit/(loss) after taxation from operating activities		642
Gain on loss of control of Manganese business		2,146
Impairment of South32 assets upon classification as held-for-distribution		(1,749	)
Loss on demerger net of transaction costs (1)		(2,319	)
Derecognition of deferred tax assets		(232	)
Net loss on demerger of South32 after taxation		(2,154	)
(Loss)/profit after taxation		(1,512	)
Attributable to non-controlling interests		61
Attributable to BHP shareholders		(1,573	)
Basic loss per ordinary share (cents)		(29.6	)
Diluted loss per ordinary share (cents)		(29.5	)

⁽¹⁾  The Group recognised the demerger in the Financial Statements as a dividend, reducing retained earnings by the fair value of South32’s shares. The US$1,795 million loss on demerger is the difference between the fair value of South32’s shares and the book value of the assets distributed and the reclassification of reserves relating to South32 to the income statement. Transaction costs of US$524 million (after tax benefit) comprised stamp duty, professional fees and separation and establishment costs.

The total comprehensive loss attributable to BHP shareholders from Discontinued operations was US$1,685 million during the financial year ended 30 June 2015.

Cash flows from Discontinued operations

	2015
	US$M
Net operating cash flows		1,502
Net investing cash flows		(1,066	)
Net financing cash flows		(203	)
Net increase in cash and cash equivalents from Discontinued operations		233
Cash disposed on demerger of South32		(586	)
Net decrease in cash and cash equivalents from Discontinued operations		(353	)

F-80

28    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	2017 %		2016 %
Coal
BHP Billiton Mitsui Coal Pty Ltd	Australia	Coal mining		80		80
Hunter Valley Energy Coal Pty Ltd	Australia	Coal mining		100		100
PT Lahai Coal (1)	Indonesia	Coal mining		–		75
Copper
BHP Billiton Olympic Dam Corporation Pty Ltd	Australia	Copper and uranium mining		100		100
Compañia Minera Cerro Colorado Limitada	Chile	Copper mining		100		100
Minera Escondida Limitada (2)	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 (3)	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
BHP Billiton Shared Services Malaysia Sdn Bhd	Malaysia	Service company		100		100
WMC Finance (USA) Limited	Australia	Finance		100		100

⁽¹⁾  The Group divested its 75 per cent Group interest in IndoMet Coal in October 2016.

⁽²⁾  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.

⁽³⁾  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.

F-81

29    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.

Shareholdings in associates and joint ventures	Country of incorporation/ principal place of business	Associate or joint venture	Principal activity	Reporting date	Ownership interest
					2017 %		2016 %
Carbones del Cerrejón LLC (Cerrejón)	Anguilla/ Colombia	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 2017 US$M	Investment in associates			Investment in joint ventures			Total equity accounted investments
At the beginning of the financial year		2,575			–			2,575
Profit/(loss) from equity accounted investments, related impairments and expenses (1)		444			(172	)		272
Investment in equity accounted investments		47			134			181
Dividends received from equity accounted investments		(620	)		–			(620	)
Other		2			38			40
At the end of the financial year		2,448			–			2,448

⁽¹⁾  US$(172) million represents US$(134) million share of loss from US$(134) million funding provided during the period and US$(38) million other movements in the Samarco dam failure provision including foreign exchange.

F-82

Refer to note 3 ‘Significant events – Samarco dam failure’ for further information.

The following table summarises the financial information relating to each of the Group’s significant equity accounted investments. The unrecognised share of profit for the period was US$21 million (2016: US$33 million), which decreased the cumulative losses to US$140 million (2016: decrease to US$161 million). BHP Billiton Brasil’s 50 per cent portion of Samarco’s commitments, for which BHP Billiton Brasil has no funding obligation, is US$750 million (2016: US$741 million).

	Associates									Joint ventures
2017 US$M	Antamina			Cerrejón			Individually immaterial			Samarco (1)			Individually immaterial		Total
Current assets		995			782						174	(2)
Non-current assets		4,273			2,540						6,128
Current liabilities		(530	)		(364	)					(5,236	) (3)
Non-current liabilities		(993	)		(621	)					(3,482	) (4)
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	(5)
Impairment of the carrying value of the investment in Samarco		–			–						(525	) (6)
Additional share of Samarco losses		–			–						1,332	(7)
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	) (8)
Share of operating profit/(loss) of equity accounted investments		341			129						(760	)
Additional share of Samarco losses		–			–						588	(7)
Profit/(loss) from equity accounted investments, related impairments and expenses		341			129			(26	)		(172	) (7)		–		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-83

	Associates									Joint ventures
2016 US$M	Antamina			Cerrejón			Individually immaterial			Samarco (1)			Individually immaterial		Total
Current assets		1,017			706						323	(2)
Non-current assets		4,279			2,717						6,460
Current liabilities		(362	)		(126	)					(4,722	) (3)
Non-current liabilities		(939	)		(875	)					(2,954	) (4)
Net assets/(liabilities) – 100%		3,995			2,422						(893	)
Net assets/(liabilities) – Group share		1,348			807						(447	)
Adjustments to net assets related to accounting policy adjustments		1			86						400	(5)
Impairment of the carrying value of the investment in Samarco		–			–						(525	) (6)
Additional share of Samarco losses		–			–						572	(6)
Carrying amount of investments accounted for using the equity method		1,349			893			333			–			–		2,575
Revenue – 100%		2,639			1,575						937
Profit/(loss) from Continuing operations – 100%		606			(73	)					(2,182	) (8)
Share of operating profit/(loss) of equity accounted investments		203			(24	)		(39	)		(1,091	) (9)		–		(951	)
Samarco dam failure provision expense		–			–			–			(628	) (6)		–		(628	)
Impairment of the carrying value of the investment in Samarco		–			–			–			(525	) (6)		–		(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

F-84

	Associates								Joint ventures
2015 US$M	Antamina		Cerrejón			Individually immaterial			Samarco			Individually immaterial			Total
Revenue – 100%		2,530		2,156						2,810
Profit from Continuing operations – 100%		765		(62	)					1,283	(8)
Profit/(loss) from equity accounted investments, related impairments and expenses (10)		229		(20	)		(30	)		371			(26	)		524
Comprehensive income – 100%		765		(62	)					1,283
Share of comprehensive income/(loss) – Group share in equity accounted investments		229		(20	)		(30	)		371			(26	)		524
Dividends received from equity accounted investments (11)		191		99			37			396			342			1,065

⁽¹⁾  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.

⁽²⁾  Includes cash and cash equivalents of US$29 million (2016: US$138 million).

⁽³⁾  Includes current financial liabilities (excluding trade and other payables and provisions) of US$4,581 million (2016: US$3,870 million).

⁽⁴⁾ Includes non-current financial liabilities (excluding trade and other payables and provisions) of US$1 million (2016: US$3 million).

⁽⁵⁾  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.

⁽⁶⁾ 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.

⁽⁷⁾  BHP Billiton Brasil has recognised accumulated additional share of Samarco losses of US($1,332) million resulting from US$(172) million loss from equity accounted investments recognised for the year ended 30 June 2017 and US$(1,160) million (including US$(588) million of additional share of Samarco losses) relating to obligations under the Framework Agreement.

⁽⁸⁾  Includes depreciation and amortisation of US$88 million (2016: US$148 million; 2015: US$236 million), interest income of US$57 million (2016: US$43 million; 2015: US$86 million), interest expense of US$473 million (2016: US$209 million; 2015: US$227 million) and income tax (expense)/benefit of US$(851) million (2016: US$564 million; 2015: US$(275) million).

⁽⁹⁾  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.

⁽¹⁰⁾  Includes share of operating losses of equity accounted investments from Discontinued operations for the year ended 30 June 2015 of US$24 million.

⁽¹¹⁾  Includes dividend received from equity accounted investments from Discontinued operations of US$342 million for the year ended 30 June 2015.

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30    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 complete list of the Group’s investments in joint operations, refer to Exhibit 8.1 – List of Subsidiaries.

			Group interest (1)
Significant joint operations	Country of operation	Principal activity	2017 %		2016 %
Bass Strait	Australia	Hydrocarbons production		50		50
Greater Angostura	Trinidad and Tobago	Hydrocarbons production		45		45
Eagle Ford (2)	US	Hydrocarbons exploration and production		<1–100		<1–100
Fayetteville (2)	US	Hydrocarbons exploration and production		<1–100		<1–100
Gulf of Mexico	US	Hydrocarbons exploration and production		23.9–44		23.9–44
Haynesville (2)	US	Hydrocarbons exploration and production		<1–100		<1–100
Macedon (2)	Australia	Hydrocarbons exploration and production		71.43		71.43
North West Shelf	Australia	Hydrocarbons production		12.5–16.67		8.33–16.67
Permian (2)	US	Hydrocarbons exploration and production		<1–100		<1–100
Pyrenees (2)	Australia	Hydrocarbons exploration and production		40–71.43		40–71.43
ROD Integrated Development (3)	Algeria	Hydrocarbons exploration and production		29.50		38
Mt Goldsworthy (4)	Australia	Iron ore mining		85		85
Mt Newman (4)	Australia	Iron ore mining		85		85
Yandi (4)	Australia	Iron ore mining		85		85
Central Queensland Coal Associates	Australia	Coal mining		50		50

⁽¹⁾  Ranges reflect the Group’s interest in multiple joint arrangements within the joint operation.

⁽²⁾  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.

⁽³⁾  Group interest reflects the working interest and may vary year-on-year based on the Group’s effective interest in producing wells.

⁽⁴⁾  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.

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Assets held in joint operations subject to significant restrictions are as follows:

	Group share
	2017		2016
	US$M		US$M
Current assets		2,755		3,442
Non-current assets		51,446		56,491
Total assets (1)		54,201		59,933

⁽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.

31    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 22 ‘Key management personnel’. Transactions between each parent company and its subsidiaries are eliminated on consolidation and are not disclosed in this note.

• All transactions from/to 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 between 16 August 2017 and 31 August 2031.

• 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 2017 (2016: US$ nil), other than those with post-employment benefit plans for the benefit of Group employees. These are shown in note 25 ‘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
	2017			2016		2017		2016		2017			2016
	US$M			US$M		US$M		US$M		US$M			US$M
Sales of goods/services		–			–		–		–		–			–
Purchases of goods/services		–			–		–		–		1,052.885			786.789
Interest income		1.850			1.673		–		–		34.911			56.777
Interest expense		0.010			0.011		–		–		0.006			–
Dividends received		–			–		–		–		619.894			292.813
Net loans (repayments from)/made to related parties		(82.701	)		74.043		–		–		(272.276	)		(102.106	)

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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
	2017		2016		2017		2016		2017		2016
	US$M		US$M		US$M		US$M		US$M		US$M
Trade amounts owing to related parties		–		–		–		–		217.803		117.700
Loan amounts owing to related parties		118.288		36.907		–		–		39.097		38.097
Trade amounts owing from related parties		–		–		–		–		3.083		0.749
Loan amounts owing from related parties		20.144		21.464		–		–		647.918		919.194

Unrecognised items and uncertain events

32    Commitments

The Group’s commitments for capital expenditure were US$2,084 million as at 30 June 2017 (2016: US$1,737 million). The Group’s other commitments are as follows:

	Commitments under finance leases						Commitments under operating leases
	2017			2016			2017		2016
	US$M			US$M			US$M		US$M
Due not later than one year		135			49			420		371
Due later than one year and not later than five years		475			221			672		888
Due later than five years		705			115			660		887
Total		1,315			385			1,752		2,146
Future financing liability		(418	)		(39	)
Right to reimbursement from joint operations partner		–			–
Finance lease liability		897			346

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.

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33    Contingent liabilities

	2017		2016
	US$M		US$M
Associates and joint ventures
Tax and other matters (1)		1,784		1,508
Subsidiaries and joint operations
Tax and other matters (1)		1,825		1,933
Bank guarantees		1		1
Total		3,610		3,442

⁽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 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’.

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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 2017.
Investigation by the Australian Federal Police	As previously disclosed, the Australian Federal Police (AFP) announced an investigation in 2013 relating to matters the subject of section 70.2 of the Commonwealth Criminal Code. The AFP has advised that it has finalised its investigation and does not intend to take any further action at this time.
Bank guarantees	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.

34    Subsequent events

On 17 August 2017, we announced that the Board of Directors had approved an investment of US$2.5 billion for the development of the Spence Growth Option, including construction of a copper concentrator that will extend the Spence mine life by more than 50 years.

On 22 August 2017, we announced that the Board of Directors had approved a multi-currency bond repurchase plan with a global aggregate cap of up to US$2.5 billion. The plan will target 2021, 2022 and 2023 US dollar denominated notes and 2018, 2020, 2022 and 2024 Euro denominated notes and 2024 Sterling denominated notes. Subsequently, we announced that we have increased the value of the global aggregate cap to US$2.9 billion.

On 22 August 2017, we announced that, as part of our ongoing review of our portfolio, the Board of Directors and management have determined that our Onshore US assets are non-core and options to exit these assets are being actively pursued. Execution of these options may take time and, as such, we are not able to estimate the financial effect of any future transaction.

These events have no impact on the Financial Statements for the year ended 30 June 2017. Other than the matters outlined above or elsewhere 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

35    Acquisitions and disposals of subsidiaries, operations, joint operations and equity accounted investments

Acquisitions

There were no acquisitions made during the years ended 30 June 2017, 2016 and 2015.

Divestments

Excluding Discontinued operations, the Group disposed of the following subsidiaries, operations, joint operations and equity accounted investments during the year ended:

30 June 2017

• BHP Navajo Coal Company

• IndoMet Coal

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30 June 2016

• Pakistan gas business

• San Juan Mine

30 June 2015

• North Louisiana conventional onshore assets

• Pecos field

	2017			2016			2015
	US$M			US$M			US$M
Net assets disposed		189			153			241
Gross cash consideration		186			168			256
Less cash and cash equivalents disposed		–			(2	)		–
Total consideration		186			166			256
Other effects (1)		–			1			–
Net (loss)/gain on disposal recognised in other income		(3	)		14			15

⁽¹⁾  Other effects include deferred consideration of US$ nil for 30 June 2017 (2016: US$1 million; 2015: US$ nil).

Sale of non-controlling interests in subsidiaries

There was no sale of interests in subsidiaries to non-controlling interests (NCI) for the years ending 30 June 2017, 30 June 2016 and 30 June 2015.

36    Auditor’s remuneration

	2017		2016		2015
	US$M		US$M		US$M
Fees payable to the Group’s auditors for assurance services
Audit of the Group’s Annual Report		3.381		3.126		4.299
Audit of subsidiaries, joint ventures and associates		7.040		7.715		11.185
Audit-related assurance services		3.597		3.493		5.377
Other assurance services		1.849		1.508		1.557
Total assurance services		15.867		15.842		22.418
Fees payable to the Group’s auditors for other services
Other services relating to corporate finance		0.042		0.276		6.871
All other services		0.589		0.815		1.093
Total other services		0.631		1.091		7.964
Total fees		16.498		16.933		30.382

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.

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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-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 acquisitions, divestments and debt raising transactions.

All other services comprise non-statutory assurance based procedures, advice on accounting matters, as well as tax compliance services of US$0.027 million (2016: US$0.089 million; 2015: US$ nil).

37    Not required for US reporting

38    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 2017 and 30 June 2016 are as follows:

Consolidated Statement of Comprehensive Income and Retained Earnings	2017			2016
	US$M			US$M
Revenue		19,394			4,687
Other income		4,988			6,192
Expenses excluding net finance costs		(12,085	)		(6,203	)
Net finance costs		(591	)		(320	)
Income tax expense		(2,351	)		(220	)
Profit after taxation		9,355			4,136
Total other comprehensive income		18			20
Total comprehensive income		9,373			4,156
Retained earnings at the beginning of the financial year		40,462			40,768
Net effect on retained earnings of entities added to/removed from the Deed		(1,699	)		–
Profit after taxation for the year		9,355			4,136
Transfers to and from reserves		33			56
Dividends		(2,172	)		(4,498	)
Retained earnings at the end of the financial year		45,979			40,462

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Consolidated Balance Sheet	2017			2016
	US$M			US$M
ASSETS
Current assets
Cash and cash equivalents		1			–
Trade and other receivables		3,541			1,163
Loans to related parties		14,081			10,049
Inventories		1,536			639
Current tax assets		–			790
Other		72			58
Total current assets		19,231			12,699
Non-current assets
Trade and other receivables		76			63
Loans to related parties		335			–
Inventories		278			161
Property, plant and equipment		30,579			15,324
Intangible assets		550			679
Investments in Group companies		27,816			29,261
Deferred tax assets		402			667
Other		59			17
Total non-current assets		60,095			46,172
Total assets		79,326			58,871
LIABILITIES
Current liabilities
Trade and other payables		2,762			1,270
Loans from related parties		15,978			4,922
Interest bearing liabilities		202			61
Current tax payable		1,318			112
Provisions		683			377
Deferred income		8			9
Total current liabilities		20,951			6,751
Non-current liabilities
Trade and other payables		3			4
Loans from related parties		7,660			7,504
Interest bearing liabilities		251			293
Deferred tax liabilities		613			619
Provisions		2,479			1,785
Deferred income		21			23
Total non-current liabilities		11,027			10,228
Total liabilities		31,978			16,979
Net assets		47,348			41,892
EQUITY
Share capital – BHP Billiton Limited		1,186			1,186
Treasury shares		(1	)		(7	)
Reserves		184			251
Retained earnings		45,979			40,462
Total equity		47,348			41,892

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39    New and amended accounting standards and interpretations issued but not yet effective

There are no new accounting standards or interpretations that have been adopted for the first time in these Financial Statements. The following new accounting standards and interpretations are not yet effective, but may have an impact on the Group in financial years commencing on or after 1 July 2017:

Title of standard / interpretation	Summary of impact on the Financial Statements	Application date of standard / interpretation	Application date for the financial year commencing
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. The core principle is that an entity recognises revenue to depict the transfer of promised goods and services to the customer of an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Work to date has focused on understanding the standard contractual arrangements across the Group’s principal revenue streams, particularly key terms and conditions which may impact revenue recognition. To date, no significant measurement differences have been identified. IFRS 15 requires separate disclosure of the impacts of provisional pricing. Where applicable, system and process changes are being made to appropriately measure and capture this data for disclosure. Revenue from freight and shipping services provided by the Group, currently recognised upon loading, may be required to be treated as a separate performance obligation and recognised over time. The impact of this is not expected to be material. Work in FY2018 will include a further review of individual contracts and development of the Group’s accounting guidance. The Group expects to apply the full retrospective transition approach. Application of this approach results in the restatement of comparative information where applicable.	1 January 2018	1 July 2018
IFRS 9/AASB 9 ‘Financial Instruments’	This standard modifies the classification and measurement of financial assets. It includes: –       a single, principles-based approach for the classification of financial assets, which is driven by cash flow characteristics and the business model in which an asset is held; –       a new expected credit loss impairment model requiring expected losses to be recognised when financial assets are first recognised;	1 January 2018	1 July 2018

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Title of standard / interpretation	Summary of impact on the Financial Statements	Application date of standard / interpretation	Application date for the financial year commencing
	–       a modification of hedge accounting to align the accounting treatment with risk management practices of an entity. This may result in the increased application of hedge accounting. In order to gain an understanding of the likely impacts of IFRS 9, implementation activities to date have focused on the Group’s Treasury operations, which hold the majority of the Group’s financial instruments. Further detailed analysis in FY2018 will focus on changes to the calculation of impairment losses on financial assets and application of the revised hedge accounting model. The Group is considering available options for transition. Based on work performed to date, the Group does not currently expect the impact of these changes to be significant.
IFRIC 22 ‘Foreign Currency Transactions and Advance Consideration’	This interpretation clarifies the exchange rate to be used upon recognition of an asset, liability, expense or income in circumstances when a related advance payment has been received or disbursed. The Group is currently assessing the impact of the interpretation on its Financial Statements.	1 January 2018	1 July 2018
IFRS 16/AASB 16 ‘Leases’	This standard requires lessees to account for leases under an on-balance sheet model, with the distinction between operating and finance leases being removed. The standard provides certain exemptions from recognising leases on the balance sheet, including where the underlying asset is of low value or the lease term is 12 months or less. Under the new standard, the Group will be required to; –       recognise right of use lease assets and lease liabilities on the balance sheet. Liabilities are measured based on the present value of future lease payments over the lease term. The right of use lease asset generally reflects the lease liability; –       recognise depreciation of right of use lease assets and interest on lease liabilities over the lease term; –       separately present the principal amount of cash paid and interest in the cash flow statement as a financing activity.	1 January 2019	1 July 2019

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Title of standard / interpretation	Summary of impact on the Financial Statements	Application date of standard / interpretation	Application date for the financial year commencing
	The Group has commenced work to understand the impact of the new standard. This has included preliminary diagnostics to identify key characteristics of existing contractual arrangements and scoping of impacts to financial reporting, systems and processes. Work in FY2018 will include detailed review of contracts to support the quantification of financial impacts and assessment of likely system requirements and processes. The Group is considering available options for 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 32 ‘Commitments’.

These standards have not been applied in the preparation of these Financial Statements. IFRS 16 and IFRIC 22 have not been endorsed by the EU and hence are not available for early adoption in the EU.

5.2    Not required for US reporting

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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 2017 and of their performance for the year ended 30 June 2017;

(b) the Financial Statements also complies 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.

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 2017.

Signed in accordance with a resolution of the Board of Directors.

Ken MacKenzie

Chairman

Andrew Mackenzie

Chief Executive Officer

Dated this 7th day of September 2017

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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; and

• 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.

5.5    Not required for US reporting

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5.6    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:

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 2017 and 30 June 2016, and 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 2017. 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 conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the Financial Statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the Financial Statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall Financial Statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the Consolidated Financial Statements referred to above present fairly, in all material respects, the financial position of the BHP Group as of 30 June 2017 and 2016, and the results of its operations and its cash flows for each of the years in the three-year period ended 30 June 2017, 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), the BHP Group’s internal control over financial reporting as of 30 June 2017, 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 28 September 2017 expressed an unqualified opinion on the effectiveness of the BHP Group’s internal control over financial reporting.

/s/ KPMG LLP	/s/ KPMG
KPMG LLP	KPMG
London, United Kingdom	Melbourne, Australia
28 September 2017	28 September 2017

F-99

Report of Independent Registered Public Accounting Firms

To the members of BHP Billiton Plc and BHP Billiton Limited:

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 2017, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). 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 BHP Group’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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 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.

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.

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.

In our opinion, the BHP Group maintained, in all material respects, effective internal control over financial reporting as of 30 June 2017, 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), the Consolidated Balance Sheets of the BHP Group as of 30 June 2017 and 30 June 2016, and 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 2017, and our report dated 28 September 2017 expressed an unqualified opinion on those Consolidated Financial Statements.

/s/ KPMG LLP	/s/ KPMG
KPMG LLP	KPMG
London, United Kingdom	Melbourne, Australia
28 September 2017	28 September 2017

F-100

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 1.13.1 ‘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’.

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’.

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 allowances.

	Australia			United States			Other (1)			Total
	US$M			US$M			US$M			US$M
Capitalised cost
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 allowances		(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 allowances		(8,364	)		(28,664	)		(1,938	)		(38,966	)
Net capitalised costs		7,497			17,339			553			25,389
2015
Unproved properties		385			8,117			99			8,601
Proved properties		15,125			37,341			2,443			54,909
Total costs		15,510			45,458			2,542			63,510
Less: Accumulated depreciation, depletion, amortisation and valuation allowances		(7,727	)		(19,100	)		(2,094	)		(28,921	)
Net capitalised costs		7,783			26,358			448			34,589

⁽¹⁾  Other is primarily comprised of Algeria, Pakistan (divested 31 December 2015), Trinidad and Tobago and the United Kingdom.

F-101

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		Other (3)		Total
	US$M		US$M		US$M		US$M
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
2015
Acquisitions of proved property		–		–		–		–
Acquisitions of unproved property		–		37		–		37
Exploration (1)		127		281		248		656
Development		429		4,036		52		4,517
Total costs (2)		556		4,354		300		5,210

⁽¹⁾  Represents gross exploration expenditure, including capitalised exploration expenditure, in addition to exploration and evaluation costs charged to income as incurred.

⁽²⁾  Total costs include US$1,744 million (2016: US$2,256 million; 2015: US$4,603 million) capitalised during the year.

⁽³⁾  Other is primarily comprised of Algeria, Pakistan (divested 31 December 2015), Trinidad and Tobago and the United Kingdom.

F-102

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			Other (7)			Total
	US$M			US$M			US$M			US$M
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	)
2015
Oil and gas revenue (1)		4,184			6,334			661			11,179
Production costs		(662	)		(2,220	)		(168	)		(3,050	)
Exploration expenses		(124	)		(242	)		(241	)		(607	)
Depreciation, depletion, amortisation and valuation provision (2)		(651	)		(6,597	)		(170	)		(7,418	)
Production taxes (3)		(232	)		–			(8	)		(240	)
		2,515			(2,725	)		74			(136	)
Accretion expense (4)		(63	)		(24	)		(8	)		(95	)
Income taxes		(608	)		1,080			(146	)		326
Royalty-related taxes (5)		(388	)		–			4			(384	)
Results of oil and gas producing activities (6)		1,456			(1,669	)		(76	)		(289	)

F-103

⁽¹⁾  Includes sales to affiliated companies of US$83 million (2016: US$118 million; 2015: US$267 million).

⁽²⁾ Includes valuation provision of US$102 million (2016: US$7,232 million; 2015: US$2,681 million).

⁽³⁾ Includes royalties and excise duty.

⁽⁴⁾ Represents the unwinding of the discount on the closure and rehabilitation provision. Comparative information has been restated to include the accretion expense in the results of operations from oil and gas producing activities.

⁽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⁾ 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 purpose of this disclosure is to provide data with respect to the estimated future net cash flows from future production of proved developed and undeveloped reserves of crude oil, condensate, natural gas liquids and natural gas.

The Standardised measure is based on the Group’s estimated proved reserves (as presented in section 6.3.1 ‘Petroleum reserves’) and this data should be read in conjunction with that disclosure, which is hereby incorporated by reference into this section. The Standardised measure is prepared on a basis which presumes that year-end economic and operating conditions will continue over the periods in which year-end proved reserves would be produced. The effects of future inflation, future changes in exchange rates, expected future changes in technology, taxes, operating practices and any regulatory changes have not been included.

The Standardised measure is prepared by projecting the estimated future annual production of proved reserves owned at period-end and pricing that future production to derive future cash inflows. Estimates of future cash flows for 2017, 2016 and 2015 are computed using the average first-day-of-the-month price during the 12-month period. Future price increases for all periods presented are considered only to the extent that they are provided by fixed and determinable contractual arrangements in effect at year-end and are not dependent upon future inflation or exchange rate changes.

Future cash inflows for all periods presented are then reduced by future costs of producing and developing the year-end proved reserves based on costs in effect at year-end without regard to future inflation or changes in technology or operating practices. Future development costs include the costs of drilling and equipping development wells and construction of platforms and production facilities to gain access to proved reserves owned at year-end. They also include future costs, net of residual salvage value, associated with the abandonment of wells, dismantling of production platforms and rehabilitation of drilling sites. Future cash inflows are further reduced by future income taxes based on tax rates in effect at year-end and after considering the future deductions and credits applicable to proved properties owned at year-end. The resultant annual future net cash flows (after deductions of operating costs including resource rent taxes, development costs and income taxes) are discounted at 10 per cent per annum to derive the Standardised measure.

F-104

There are many important variables, assumptions and imprecisions inherent in developing the Standardised measure, the most important of which are the level of proved reserves and the rate of production thereof. The Standardised measure is not an estimate of the fair market value of the Group’s oil and gas reserves. 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 prices, costs and exchange rates, anticipated future changes in secondary tax and income tax rates and alternative discount factors representing the time value of money and adjustments for risks inherent in producing oil and gas.

	Australia			United States			Other (1)			Total
	US$M			US$M			US$M			US$M
Standardised measure
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
2015
Future cash inflows		35,660			39,088			2,668			77,416
Future production costs		(9,617	)		(15,303	)		(526	)		(25,446	)
Future development costs		(5,952	)		(7,694	)		(413	)		(14,059	)
Future income taxes		(7,879	)		(3,009	)		(959	)		(11,847	)
Future net cash flows		12,212			13,082			770			26,064
Discount at 10 per cent per annum		(4,236	)		(4,384	)		(200	)		(8,820	)
Standardised measure		7,976			8,698			570			17,244

⁽¹⁾  Other is primarily comprised of Algeria, Pakistan (divested 31 December 2015), Trinidad and Tobago and the United Kingdom.

F-105

Changes in the Standardised measure are presented in the following table. The beginning of the year and end of the year totals are shown after reduction for income taxes and these, together with the changes in income tax amounts, are shown as discounted amounts (at 10 per cent per annum). All other items of change represent discounted amounts before consideration of income tax effects.

	2017			2016			2015
	US$M			US$M			US$M
Changes in the Standardised measure
Standardised measure at the beginning of the year		8,987			17,244			29,164
Revisions:
Prices, net of production costs		(96	)		(14,146	)		(15,186	)
Changes in future development costs		275			1,342			3
Revisions of quantity estimates (1)		2,961			(2,870	)		(5,996	)
Accretion of discount		1,147			2,547			4,438
Changes in production timing and other		(1,611	)		1,280			761
		11,663			5,397			13,184
Sales of oil and gas, net of production costs		(4,301	)		(3,936	)		(7,889	)
Acquisitions of reserves-in-place		–			–			–
Sales of reserves-in-place		(15	)		(114	)		(83	)
Previously estimated development costs incurred		718			1,823			3,169
Extensions, discoveries, and improved recoveries, net of future costs		(401	)		84			1,877
Changes in future income taxes		578			5,733			6,986
Standardised measure at the end of the year		8,242			8,987			17,244

⁽¹⁾ Changes in reserves quantities are shown in the Petroleum reserves tables in section 6.3.1.

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 2017, 30 June 2016 and 30 June 2015.

	2017			2016			2015
	US$M			US$M			US$M
Movement in capitalised exploratory well costs
At the beginning of the year		770			484			388
Additions to capitalised exploratory well costs pending the determination of proved reserves		258			304			121
Capitalised exploratory well costs charged to expense		(69	)		(18	)		(21	)
Capitalised exploratory well costs reclassified to wells, equipment, and facilities based on the determination of proved reserves		(155	)		–			(4	)
Other		(136	)		–			–
At the end of the year		668			770			484

F-106

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.

	2017		2016		2015
	US$M		US$M		US$M
Ageing of capitalised exploratory well costs
Exploratory well costs capitalised for a period of one year or less		120		262		44
Exploratory well costs capitalised for a period greater than one year		548		508		440
At the end of the year		668		770		484
	2017		2016		2015
Number of projects that have been capitalised for a period greater than one year		14		23		14

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 2017
Australia		–		–		–		–		–		–		–
United States		–		–		–		80		–		80		80
Other (1)		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		137		2		139		140
Other (1)		–		–		–		1		–		1		1
Total		1		–		1		140		2		142		143
Year ended 30 June 2015
Australia		–		–		–		3		–		3		3
United States		–		–		–		304		1		305		305
Other (1)		–		–		–		–		–		–		–
Total		–		–		–		307		1		308		308

⁽¹⁾  Other is primarily comprised of Algeria and Trinidad and Tobago.

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.

F-107

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 2017. 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 2017 was as follows:

	Crude oil wells				Natural gas wells				Total
	Gross		Net		Gross		Net		Gross		Net
Australia		352		177		135		49		487		226
United States		1,001		558		6,679		1,993		7,680		2,551
Other (1)		62		23		36		7		98		30
Total		1,415		758		6,850		2,049		8,265		2,807

⁽¹⁾  Other is primarily comprised of Algeria, Trinidad and Tobago and the United Kingdom

Of the productive crude oil and natural gas wells, 38 (net: 16) operated wells had multiple completions.

Developed and undeveloped acreage (including both leases and concessions) held at 30 June 2017 was as follows:

	Developed acreage				Undeveloped acreage
Thousands of acres	Gross		Net		Gross		Net
Australia		2,151		823		8,059		4,659
United States		1,180		673		1,395		1,143
Other (1)(2)		175		64		4,166		3,132
Total		3,506		1,560		13,620		8,934

⁽¹⁾  Developed acreage in Other primarily consists of Algeria and the United Kingdom.

⁽²⁾  Undeveloped acreage in Other primarily consists of acreage in Brazil and Trinidad and Tobago. It also includes the addition of Trion.

Approximately 220 thousand gross acres (75 thousand net acres), 7,023 thousand gross acres (4,023 thousand net acres) and 210 thousand gross acres (100 thousand net acres) of undeveloped acreage will expire in the years ending 30 June 2018, 2019 and 2020 respectively, if the Group does not establish production or take any other action to extend the terms of the licences and concessions.

F-108