BHP Results for the Year Ended 30 June 2017

BHP RESULTSFOR THE YEAR ENDED 30 JUNE 2017

· Tragically, we had a fatality at Escondida in October 2016, and more recently at Goonyella Riverside.

· Attributable profit of US$5.9 billion, Underlying EBITDA(ii) of US$20.3 billion, Underlying EBITDA margin(iii) of 55% and Underlying return on capital employed(iii) of 10% (after tax) for the 2017 financial year.

· Productivity gains(iv) of US$1.3 billion achieved for the period, with more than US$12 billion accumulated over the last five years. We expect to deliver a further US$2 billion by the end of the 2019 financial year, with gains weighted to the second year.

· Net operating cash flow of US$16.8 billion and free cash flow(i) of US$12.6 billion were underpinned by higher commodity prices, strong operating performance and improved capital productivity.

· Capital and exploration expenditure(v) reduced by 32% to US$5.2 billion, 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 the 2018 financial year as we focus on our suite of low-risk, high-return latent capacity projects, progress Mad Dog Phase 2 and the Spence Growth Option and ramp-up drilling activity in Onshore US.

· In accordance with our capital allocation framework, we expect capital and exploration expenditure to remain below US$8 billion per annum for the 2019 and 2020 financial years.

· We strengthened our balance sheet, with net debt(i) of US$16.3 billion reflecting strong free cash flow generation and a favourable non-cash movement in net debt of US$0.6 billion.

· The Board has determined to pay a final dividend of 43 US cents per share which is covered by free cash flow generated in the current period. Total dividends of US$4.4 billion determined for the 2017 financial year include US$1.1 billion in additional amounts over and above the 50% minimum payout policy.

· In Petroleum, positive drilling results were reported following the discovery of oil in multiple horizons at the Wildling-2 appraisal well in the Gulf of Mexico this month.

· We have determined that our Onshore US assets are non-core and we are actively pursuing options to exit these assets for value. In the meantime, we will complete well trials, acreage swaps and assess mid-stream solutions to increase the value, profitability and marketability of our acreage.

· In Brazil, progress continues on the social and environmental remediation programs following the Samarco dam failure.

(1) Where we have used alternate performance measures they are identified by a footnote, and definitions can be found on pages 26 and 27.

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Results for the year ended 30 June 2017

BHP Chairman, Jac Nasser, said: "Over the last five years, we have laid the foundations to significantly improve our return on capital and grow long-term shareholder value.

We have reduced unit costs by over 40 per cent and achieved over US$12 billion in productivity gains. Our capital allocation framework provides flexibility at the bottom of the cycle and discipline at the top. We have shifted our focus to low-cost, high-return latent capacity projects which has allowed us to reduce capital expenditure by over 70 per cent. We strengthened our balance sheet and changed our dividend policy to make sure we have stability and flexibility to create value and reward shareholders in a more volatile environment. And we have reshaped our portfolio so that we focus on large, long-life, low-cost assets that will support shareholder returns for decades to come.

At the end of this month, I leave my role as Chairman knowing these strong foundations, proven strategy and core values position BHP well for the future."

BHP Chief Executive Officer, Andrew Mackenzie, said: "We had a very strong financial year. Free cash flow was US$12.6 billion, our second highest on record. We used this cash to reduce net debt by nearly US$10 billion and return US$4.4 billion to shareholders. Productivity gains across our simpler portfolio of tier one assets increased our return on capital to 10 per cent.

This strong momentum will be carried into the 2018 financial year, with volume growth of seven per cent and further productivity gains expected. Our relentless focus on cash flow, capital discipline and value creation should allow us to significantly increase our return on capital by the 2022 financial year."

Health and safety are core to our values and our highest priority. Tragically, two of our colleagues died over the last 14 months, one colleague at Escondida in October 2016 and one colleague at Goonyella Riverside in August 2017. We achieve nothing unless we achieve it safely. Our Total Recordable Injury Frequency was 4.2 per million hours worked in the 2017 financial year, a two per cent decrease compared with the prior year. Our field leadership program was implemented during the year and coupled with ongoing technology initiatives will drive even higher levels of safety across all assets.

BHP remains committed to supporting the Renova Foundation with the recovery of communities and ecosystems affected by the Samarco tragedy. Substantial progress has been made during the period.

Relocation of the communities most severely affected by the dam failure is continuing, with urban planning underway and regulatory approvals being sought. The Renova Foundation's compensation program is in progress and over 82,000 claims have been resolved, the majority of which were for temporary interruption to water supplies immediately following the dam failure. The environmental programs are proceeding well. Turbidity in the Rio Doce has generally returned to pre-dam failure levels and erosion control in priority areas is almost complete.

On 18 January 2017, Samarco and its shareholders, Vale S.A. and BHP Billiton Brasil Ltda, entered into a Preliminary Agreement with the Federal Prosecutors' Office in Brazil in relation to the Samarco dam failure. The final date for negotiation of a settlement has been extended from 30 June 2017 to 30 October 2017.

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 licenses by state and federal authorities, community hearings and an appropriate restructure of Samarco's debt.

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In the 2017 financial year, BHP reported an exceptional loss of US$381 million (after tax) in relation to the Samarco dam failure. This includes funding of US$134 million, direct costs of US$82 million, discount unwinding of US$127 million and other movements of US$38 million. Additional commentary is included on page 41.

Earnings and margins

· Attributable profit of US$5.9 billion includes an exceptional loss of US$842 million (after tax), compared to an attributable loss of US$6.4 billion, including an exceptional loss US$7.6 billion (after tax), in the prior period. The 2017 financial year 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 2016 financial year exceptional loss related to the impairment of our Onshore US assets, the Samarco dam failure and global taxation matters.

· Underlying attributable profit of US$6.7 billion, compared to US$1.2 billion in the prior period.

· Profit from operations of US$11.8 billion, compared to a loss of US$6.2 billion in the prior period, driven by higher revenue due to prices and lower expenses due to impairment charges on our Onshore US assets in the 2016 financial year.

· Underlying EBITDA of US$20.3 billion, with higher prices, operating 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).

· Underlying EBITDA margin of 55 per cent, compared with 41 per cent in the prior period.

· Underlying return on capital employed of 10 per cent (after tax), a significant improvement from 2.4 per cent in the prior period.

Productivity and costs

· US$1.3 billion of additional productivity gains delivered, with total annualised productivity gains of more than US$12 billion accumulated over the last five years. Productivity gains were lower than guidance largely as a result of volumes at the lower end of guidance 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 billion of productivity gains over the two years to the end of the 2019 financial year, with gains weighted to the second year.

· Group copper equivalent unit costs(vi) declined by four per cent compared to the 2016 financial year. Escondida and Western Australia Iron Ore (WAIO) unit cash costs(vii) decreased by 17 per cent and three per cent, respectively. Conventional petroleum and Queensland Coal unit costs(vii) increased by two per cent and eight per cent respectively. Escondida unit costs were lower as a result of 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. 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.

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· Historical costs and guidance for the 2018 financial year are summarised below:

(1) 2018 financial year guidance is based on exchange rates of AUD/USD 0.75 and USD/CLP 663.

(2) Excludes impact from revaluation of embedded derivatives in the Trinidad and Tobago gas contract: FY17 US$37 million loss; FY16 US$14 million gain.

(3) 2017 financial year unit cost excludes the impact of the industrial action that was reported as an exceptional item.

Cash flow and balance sheet

· Net operating cash flows of US$16.8 billion reflect higher commodity prices and further cash cost efficiencies.

· Free cash flow of US$12.6 billion. All operating assets were free cash flow positive(iii), reflecting continued improvements in both productivity and capital efficiency.

· 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 (31 December 2016: US$20.1 billion; 30 June 2016: US$26.1 billion). This reduction reflects strong free cash flow generation during the period as well as a non-cash fair value adjustment of US$1.2 billion related to interest rate and exchange rate movements, partially offset by the Kelar finance lease of US$0.6 billion.

· Gearing ratio(i) of 20.6 per cent (31 December 2016: 24.3 per cent; 30 June 2016: 30.3 per cent).

· We will maintain a strong balance sheet through the commodity price cycle. In the medium term, this translates to a net debt range of US$10 to US$15 billion.

Dividends

· The dividend policy provides for a minimum 50 per cent payout of Underlying attributable profit at every reporting period. The minimum dividend payment for second half of the 2017 financial year is 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.

· In total, dividends of US$4.4 billion (83 US cents per share) have been determined for the 2017 financial year, including additional amounts of US$1.1 billion.

Capital and exploration

· Capital and exploration expenditure of US$5.2 billion, down 32 per cent in the 2017 financial year, included maintenance spend(viii) of US$1.2 billion and exploration of US$1.0 billion. Expenditure was seven per cent lower than guidance as a result of the industrial action interruptions to Escondida projects and lower sustaining capital spend at WAIO.

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· Capital and exploration expenditure is now expected to be US$6.9 billion for the 2018 financial year, higher than previous guidance, as a result of Escondida projects spend carried over from the previous year, an increase in Onshore US drilling and development expenditure and unfavourable exchange rate movements. The increase in expenditure compared to the prior year reflects continued investment in high-return latent capacity projects, increased Onshore US drilling activity (completing trials to increase investable inventory and utilising our gas hedging strategy to reduce price risk and secure attractive rates of return) and approval of Mad Dog Phase 2 and the Spence Growth Option. The Group's development expenditure of approximately US$2.5 billion (related to Onshore US, latent capacity and major projects) in the 2018 financial year is expected to have an average rate of return of over 20 per cent.

· A US$0.9 billion exploration program is now planned for the 2018 financial year. This includes petroleum exploration expenditure of US$715 million, a decrease of US$125 million from prior guidance primarily driven by optimisation of the drilling program.

· In accordance with our capital allocation framework, we expect capital and exploration expenditure to remain below US$8 billion per annum in the 2019 and 2020 financial years.

Capital allocation framework

Strict adherence to our capital allocation framework balances value creation, cash returns to shareholders and balance sheet strength in a transparent and consistent manner. Our capital allocation framework is embedded in every capital decision we make to achieve optimal balance between value accretive investments, cash returns and the balance sheet. The transparent competition for capital ensures all investment decisions are tested against additional returns to shareholders.

Our priorities for capital are to:

· first, maintain safe and stable operations;

· second, maintain a strong balance sheet through the cycle;

· third, pay shareholders a minimum of 50 per cent of Underlying attributable profit as dividends; and

· fourth, direct remaining cash to the value-maximising outcome, with debt reduction, paying additional dividend amounts, buying back shares, investing in projects and acquiring assets all competing for capital.

During the 2017 financial year, we invested US$1.2 billion to maintain safe and reliable operations, we preserved our balance sheet strength and we paid out the minimum dividend of US$2 billion. With the remaining US$13 billion, which included US$0.7 billion in portfolio simplification proceeds, we invested US$4 billion in our organic development projects, returned US$0.9 billion in additional dividend amounts to our shareholders and further strengthened our balance sheet, consistent with our bias to debt reduction.

Our balance sheet remains a fundamental enabler of our strategy. Our ongoing focus on debt reduction will protect the Group through periods of heightened volatility and support counter cyclical investments as we move through the cycle. We will focus on further improvements in operational and capital efficiency. We will invest in releasing near-term latent production capacity, which offers attractive returns for low-risk. Where there is a compelling investment case, we will progress our broad suite of medium and long-term development options. While these are timed to meet identified market windows, we will proceed only if they pass our strict capital allocation framework tests. We will remain disciplined, with shareholder value and returns at the centre of everything we do.

World economic growth is likely to be close to the top of the anticipated range of three to three and a half per cent in the 2017 calendar year. A modest lift in international trade has occurred this year despite ongoing political uncertainty.

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China's economic growth is expected to slow modestly in the 2018 financial year, while remaining within the official GDP target range of between six and a half and seven per cent. However, we expect to see a cooling of growth rates in the housing and automobile markets in combination with a continuation of strength in infrastructure.

China's policymakers will 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 address excess capacity and improve balance sheet health in over-indebted sectors. Over the longer term, our view remains that China's economic growth rate will decelerate as the working age population falls and the capital stock matures. China's economic structure will continue to rebalance from industry to services and growth drivers will shift from investment and exports towards consumption.

The medium term outlook for the US economy is uncertain. Progress on growth enhancing infrastructure spending and tax reform has been slow and monetary conditions are expected to tighten further. In Europe and Japan, where the limits of monetary policy effectiveness may have been reached, any upside on growth in the medium term will have to come from external demand sources. India's economy is on a healthy growth trajectory. Meanwhile the 2017 financial year stabilisation of commodity prices has put a floor under growth in resource-exporting emerging markets.

Crude oil prices overall trended higher in the 2017 financial year. OPEC agreed to its first production cut since 2008 as well as a cooperative deal with non-OPEC producers. However, concerns around inventories, increasing production from OPEC countries exempt from the agreement, and rising US output weighed on price near the end of the 2017 financial year. A balanced market is forecast for the near-term. OPEC strategy, US supply and US shale costs are the major uncertainties for the short and medium term. The long-term outlook remains positive, underpinned by rising demand from the developing world and natural field decline.

Despite an overall mild winter in the US, the domestic gas price strengthened in the 2017 financial year on strong power demand, rising exports and lower year on year production. Lower inventory levels and robust demand are likely to support prices in the near-term, although there are risks to this outlook on the supply side. 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 the degree of price inflation.

Copper prices increased in the second half of the 2017 financial year due to stronger Chinese demand and increased mine disruption. In the near-term, incremental mine production from committed projects, combined with increased scrap availability, will be sufficient to meet steady growth in copper demand. In the longer term, demand growth will remain solid, with a deficit expected to emerge early next decade. Grade decline, increased input costs, water constraints and a scarcity of high-quality future development opportunities will require higher prices to attract sufficient investment to balance the market.

Global steel production growth regained momentum in the 2017 financial year led by a recovery in China and steady growth in emerging regions. Steel demand growth in tandem with capacity curtailment in China led to higher capacity utilisation rates and improved profitability. Our views on long run Chinese steel use are unchanged, with a growth rate of approximately one per cent per annum building towards a peak in the mid-2020s. The recovery in the rest of the world is likely to continue after a multi-year stagnation. In the long term, the global steel market will grow modestly, supported mainly by incremental demand from India and other populous emerging markets.

The iron ore price increased in the 2017 financial year. This was driven by higher pig iron production in China and a preference for higher grade materials amid improved steel margins and high coke prices. Seaborne supply continued to increase from Australia and Brazil as well as from some non-traditional origins. In the medium and longer term, committed supply projects will ramp-up and production increases from productivity and de-bottlenecking are likely to translate into a further flattening of the cost curve.

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Metallurgical coal prices increased significantly in the first half of the 2017 financial year, due to China's supply side reform policy and adverse weather conditions in China and Queensland. The future application of China's coal supply reform policy remains a source of uncertainty. As currently constructed, the policy is positive for long-run industry sustainability. The expected further concentration of blast furnace capacity in China towards contestable coastal locations will underpin seaborne metallurgical coal demand growth in excess of total pig iron demand. 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 steel makers value-in-use benefits.

Potash demand has been strong in the calendar year to date, which has put a floor under prices. Higher utilisation rates at existing operations and additional greenfield supply will inhibit price inflation in the near term. Over the long term, we expect annual demand growth of between two and three per cent, with the demand outstripping supply in the mid-2020s.

Historical capital and exploration expenditure and guidance for the 2018 financial year are summarised below:

(1) Includes capitalised deferred stripping of US$416 million for FY17 and US$886 million for FY18e (FY16: US$750 million).

During the 2017 financial year, the BHP Board approved the Mad Dog Phase 2 project in the deepwater Gulf of Mexico and both the Bass Strait Longford Gas Conditioning Plant and the Escondida Water Supply projects were completed. At Jansen, excavation and lining of the shafts are steadily progressing. Both shafts have been safely excavated and lined through the Blairmore aquifer. With a later market window now anticipated, the Jansen project will not be brought to the Board in the 2018 calendar year. In the meantime, we are considering multiple options to maximise the value of the Jansen project, 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.

At the end of the 2017 financial year, BHP had three major projects under development with a combined budget of US$5.1 billion over the life of the projects. All major projects under development remain on time and on budget.

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On 17 August 2017, BHP's Board approved an investment of US$2.5 billion for the development of the Spence Growth Option.

(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 reflects BHP's share.

(2) Potash capital expenditure of approximately US$300 million is expected for the 2018 financial year.

Underlying attributable profit and Underlying EBITDA are presented below.

(1) Exceptional items of US$(636) million excludes net finance costs of US$(127) million included in the total US$(381) million related to the Samarco dam failure. Total exceptional items before tax inclusive of the US$(127) million net finance costs are US$(763) million.

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Profit/(loss) from operations has increased as a result of higher revenue driven by favourable realised price movements across all key commodities and lower expenses primarily due to impairments recognised on our Onshore US assets and the initial recognition of the Samarco dam failure provision in the 2016 financial year.

The following table and commentary describes the impact of the principal factors(iii) that affected Underlying EBITDA for the 2017 financial year compared with the 2016 financial year:

The following table reconciles relevant factors with changes in the Group's productivity:

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The average realised prices achieved for our major commodities are summarised in the following table:

(1) Based on provisional, unaudited estimates. Prices exclude third party product and internal sales, and represent the weighted average of various sales terms (for example: FOB, CIF and CFR), unless otherwise noted. Includes the impact of provisional pricing and finalisation adjustments. In Copper, the adjustment increased Underlying EBITDA by US$27 million in the 2017 financial year.

(2) Includes internal sales.

(3) Export sales only; excludes Cerrejón. Includes thermal coal sales from metallurgical coal mines.

The following exchange rates relative to the US dollar have been applied in the financial information:

(1) Displayed as US$ to A$1 based on common convention.

Depreciation, amortisation and impairments declined by US$964 million to US$7.9 billion, reflecting 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.

Net finance costs increased by US$407 million to US$1.4 billion 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 which was reported as an exceptional item (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.

Total taxation expense, including royalty-related taxation, exceptional items and exchange rate movements, was US$4.1 billion, representing a statutory effective tax rate of 39.7 per cent. In the 2016 financial year, there was a tax benefit primarily due to the impairment of our Onshore US assets resulting in the Group recording a loss before taxation of US$7.3 billion.

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The Group's adjusted effective tax rate(iii), which excludes the influence of exchange rate movements and exceptional items, was 34.0 per cent (2016: 35.8 per cent). The decrease in the 2017 financial year was largely due to the relative lower 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 the prior year. The adjusted effective tax rate is expected to be in the range of 32 to 37 per cent for the 2018 financial year.

Other royalty and excise arrangements which are not profit based are recognised as operating costs within Profit/(loss) before taxation. These amounted to US$2.0 billion during the period (2016: US$1.3 billion).

The following table sets out the exceptional items for the 2017 financial year. Additional commentary is included below and on page 38.

(1) Financial impact 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$(127) million net finance costs and US$(38) million other movements in the Samarco dam failure provision including foreign exchange. Refer to note 1 Exceptional items and note 6 Significant events - Samarco dam failure of the Financial Information for further information.

BHP reported an exceptional loss representing the ongoing financial impact of the November 2015 Samarco dam failure.

Idle capacity costs associated with the Escondida strike action in the March 2017 quarter are reported as an exceptional item as, unlike previous industrial actions, this strike action resulted in a total shutdown of operations over a 44-day period, including work on key expansion projects, which together with the significant costs incurred, is considered material to the Financial Statements.

A net exceptional gain has been recognised following the Group's agreement with the New South Wales Government in August 2016 to cancel the exploration license of the Caroona Coal project.

A one-off intra-group dividend was paid in April 2017 while a concessional tax rate was available in Chile, resulting in an exceptional withholding tax payment.

Our Board today determined to pay a final dividend of 43 US cents per share. The final dividend to be paid by BHP Billiton Limited will be fully franked for Australian taxation purposes.

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BHP Billiton Plc shareholders registered on the South African section of the register will not be able to dematerialise or rematerialise their shareholdings between the dates of 6 September and 8 September 2017 (inclusive), nor will transfers between the UK register and the South African register be permitted between the dates of 1 September and 8 September 2017 (inclusive). American Depositary Shares (ADSs) each represent two fully paid ordinary shares and receive dividends accordingly. Details of the currency exchange rates applicable for the dividend will be announced to the relevant stock exchanges following conversion and will appear on the Group's website.

During the 2017 financial year, the Group continued to focus on debt reduction with no new debt issued and US$3.25 billion of senior debt repaid at maturity. In addition, the Group paid US$2.5 billion on a bond repurchase program which concluded on 23 March 2017. The total cost in relation to the repurchase program was US$107 million, which has been reported in net finance costs. This program was funded by BHP's strong cash position and targeted short dated US dollar bonds maturing before 2023. The early repayment of the bonds has extended BHP's average debt maturity profile and enhanced BHP's capital structure. The decision not to refinance maturing debt and the bond repurchase program contributed to a US$5.9 billion overall decrease in the Group's gross debt, from US$36.4 billion at 30 June 2016 to US$30.5 billion at 30 June 2017.

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 and US$0.4 billion of maturing long-term debt, and to fund capital expenditure associated with key projects.

The Group has a US$6.0 billion commercial paper program backed by a US$6.0 billion revolving credit facility which expires in May 2021. As at 30 June 2017, the Group had no outstanding US commercial paper, no drawn amount under the revolving credit facility and US$14.2 billion in cash and cash equivalents.

On 16 February 2017, we announced the appointment of Grant King to the Board as an independent, Non-executive Director, effective 1 March 2017. We also announced that Pat Davies would be retiring from the Board with effect from 6 April 2017.

On 16 June 2017, the BHP Board elected Ken MacKenzie to succeed Jac Nasser as Chairman. Mr MacKenzie will assume the role of Chairman and Chairman of the Nomination and Governance Committee with effect 1 September 2017, following Mr Nasser's retirement as Chairman, Non-executive Director and Chairman of the Nomination and Governance Committee. Malcolm Broomhead has also been appointed to the Nomination and Governance Committee with effect from 1 October 2017.

As of 1 September 2017, the members of the Board's committees will be:

As previously disclosed, BHP conducted an audit tender during the period. After a comprehensive tender process, the Board has selected EY to be appointed as the Group's auditor from the financial year beginning 1 July 2019, subject to shareholder approval. The Board intends to 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 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. 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.

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Segment summary(1)

A summary of performance for the 2017 and 2016 financial years is presented below.

(1) Group and segment level information is reported on a statutory basis which, in relation to Underlying EBITDA, includes depreciation, amortisation and impairments, net finance costs and taxation (expense)/benefit of US$540 million (2016: US$444 million) related to equity accounted investments. It excludes exceptional items of US$172 million (2016: US$1,227 million) related to share of profit/(loss) from equity accounted investments.

Group profit/(loss) before taxation comprised Underlying EBITDA, exceptional items of US$636 million (2016: US$9,704 million), depreciation, amortisation and impairments of US$7,907 million (2016: US$8,871 million) and net finance costs of US$1,431 million (2016: US$1,024 million).

(2) Revenue is based on Group realised prices and includes third party products. Sale of third party products by the Group contributed revenue of US$1,207 million and Underlying EBITDA of US$50 million (2016: US$1,068 million and US$55 million).

(3) Includes US$356 million capitalised exploration (2016: US$335 million).

(4) Includes US$102 million of exploration expenditure previously capitalised, written off as impaired (included in depreciation and amortisation) (2016: US$15 million).

(5) Group and unallocated items includes Functions, 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 the relevant segments.

(6) Comprises revenue of US$83 million generated by Petroleum (2016: US$118 million) and US$18 million generated by Iron Ore (2016: US$22 million).

(7) Exceptional items of US$(636) million excludes net finance costs of US$(127) million included in the total US$(381) million related to the Samarco dam failure. Total exceptional items before tax inclusive of the US$(127) million net finance costs are US$(763) million. Exceptional items of US$(51) million reported in Group and Unallocated also related to the Samarco dam failure. Refer to note 1 Exceptional items for further information.

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 (8) We use various alternate performance measures to reflect our underlying performance. Refer to page 7 for a reconciliation of Underlying EBITDA to our statutory results and page 26 for the definition and calculation methodology of alternate performance measures used in reporting our performance.

Underlying EBITDA for Petroleum increased by US$405 million to US$4.1 billion in the 2017 financial year.

(1) Average realised price: crude and condensate oil US$48/bbl (2016: US$39/bbl); natural gas US$3.34 /Mscf (2016: US$2.83/Mscf); LNG US$6.84 /Mscf (2016: US$7.71/Mscf).

(2) Other includes: exchange rate; inflation; ceased and sold operations; other items. Other items includes Onshore US rig termination charges of US$6 million (2016: US$76 million) and impact from revaluation of embedded derivatives in Trinidad and Tobago gas contract of US$37 million loss (2016: US$14 million gain).

Total petroleum production for the 2017 financial year decreased by 13 per cent to 208 MMboe reflecting the deferral of development activity in Onshore US for value and natural field decline.

Total petroleum production for the 2018 financial year 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 the 2019 financial year, with investment plans subject to market conditions.

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.

Conventional unit cash costs increased by two per cent to US$8.82 per barrel due to lower volumes, however a reduction in workover scopes, lower lifting expenses and optimised maintenance programs resulted in unit costs being 12 per cent below guidance. Unit costs for the 2018 financial year are expected to be approximately US$10 per barrel reflecting the impact of lower volumes, partially offset by productivity improvements.

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.

Petroleum capital expenditure for the 2017 financial year declined by 42 per cent to US$1.5 billion. This included US$554 million of Onshore US drilling and development expenditure. Our Onshore US operated rig count was five as at 30 June 2017, with three rigs in the Haynesville, one in the Black Hawk and one in the Permian.

(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 (18 net drilled and uncompleted wells at the end of the 2017 financial year).

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During the second half of the 2017 financial year, Onshore US drilling and completion costs per well increased in most fields primarily as a result of changes to the basis of well design to longer laterals and larger frac jobs. By changing the well design, we anticipate increased recoveries and improved well returns despite higher costs. For example, in the Permian we anticipate increased recoveries of more than 60 per cent over the full well life, including a 20 per cent increase in the first year of production. Our Onshore US assets were free cash flow positive for the 2017 financial year, reflecting improvements in both operating and capital efficiency.

As part of our ongoing review of our portfolio, the Board and management have determined 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, acreage swaps and investigate mid-stream solutions to increase the value, profitability and marketability of our Onshore US acreage. In the near term, the sale of a portion of Hawkville is progressing and is anticipated to be executed in the September 2017 quarter.

Petroleum capital expenditure of approximately US$2.0 billion is planned in the 2018 financial year. This includes Conventional capital expenditure of US$0.8 billion which is 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.

Onshore US capital expenditure is expected to be up to US$1.2 billion for the 2018 financial year. 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, 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 are expected to be completed in the September 2017 quarter and, subject to approval, one additional rig will commence toward 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 the 2019 financial year. 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.

Petroleum exploration expenditure for the 2017 financial year was US$805 million, of which US$473 million was expensed. Activity for the period was largely focused on our core areas in the deepwater Gulf of Mexico, both the US and Mexican side, the Caribbean and the Northern Beagle sub-basin off the coast of Western Australia.

In the Gulf of Mexico, positive drilling results were reported following the discovery of oil in multiple horizons at the Wildling-2 appraisal well in August 2017. Evaluation is ongoing to assess the scale of the resource following the successful Shenzi North and Caicos wells. The Scimitar exploration well is expected to commence drilling in the September 2017 quarter.

In Mexico, BHP was the successful bidder to acquire a 60 per cent participating interest in, and operatorship of, the Trion discovered resource. A contract with Pemex has been executed and a Minimum Work Program consisting of one appraisal well, one exploration well and the acquisition of additional seismic data is expected to be completed by the end of the 2019 financial year. Trion exploration expenditure for the 2018 financial year is expected to be approximately US$75 million.

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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 the 2018 financial year.

In Australia, BHP has completed its evaluation of the WA-480-P permit in the Northern Beagle sub-basin and has elected to exit this exploration permit. Acquisition of the seismic survey in the Exmouth sub-basin was completed on 1 May 2017. Processed data will be delivered during the June 2018 quarter.

A US$715 million exploration program is now planned for the 2018 financial year, a decrease of US$125 million from prior guidance primarily driven by optimisation of the drilling program. This program includes one well in the US Gulf of Mexico and three wells in Trinidad and Tobago.

Petroleum reserves

BHP has confirmed the addition of 446 MMboe to proved oil, NGL and gas reserves during the 2017 financial year, which represents a reserves replacement of 209 percent.

In Onshore US, 314 MMboe was added as a result of improved commodity prices, reduced operating costs, and an increase in planned drilling over the next five years. A further 105 MMboe of proved undeveloped reserves was added following the approval of the Mad Dog Phase 2 project in the Gulf of Mexico. As of 30 June 2017 Petroleum proved reserves totalled 1,535 MMboe on a net interest basis.

During the 2017 financial year, several large development projects were completed that converted a total of 177 MMboe of proved undeveloped reserves to proved developed producing reserves. The largest of these conversions occurred in Australia where 111 MMboe was converted to proved developed in the Kipper-Tuna-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 North West Shelf Greater Western Flank-A project also converted 10 MMboe to proved developed. In Trinidad and Tobago, 23 MMboe was converted to proved developed for the completion of Angostura Phase 3 development. In the US, drilling and completion activities resulted in the conversion of 15 MMboe to proved developed 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.

(1) Rounded to the nearest MMboe.

(2) Other regions include Algeria, Trinidad & Tobago, and UK.

Petroleum's reserves are as of 30 June 2017 and have been estimated with deterministic methodology, with the exception of the North West Shelf gas operation in Australia where probabilistic methodology has been utilised to estimate and aggregate reserves for the reservoirs dedicated to the gas project only. The probabilistic based portion of these reserves totals 39 MMboe (total boe conversion is based on the following: 6,000 scf of natural gas equals 1 boe) and represents approximately three per cent of our total reported proved reserves. Aggregation of proved reserves beyond the field/project level has been performed by arithmetic summation. Due to portfolio effects, aggregates of proved reserves may be conservative. The custody transfer point(s) or point(s) of sale applicable for each field or project are the reference point for reserves. Reserves replacement was calculated by dividing net additions of 446 MMboe (excluding sales of 0.6 MMboe) by annual production of 213 MMboe. Proved reserves at 30 June 2017 included 80 MMboe anticipated to be consumed as fuel during operations, while production included 5 MMboe in non-sales amounts.

The Petroleum Reserves Group (PRG) is a dedicated group that provides oversight of the reserves assessment and reporting processes. The manager of the PRG, Abhijit Gadgil, is a full-time employee of BHP and is the individual responsible for overseeing and supervising the preparation of the reserve estimates and compiling the information for inclusion in this Results Announcement. 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 and 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 and he has reviewed and agrees with the reserves information included herein 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.

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Financial information for Petroleum for the 2017 and 2016 financial years is presented below.

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 (1) Petroleum revenue from Group production includes: crude oil US$3,625 million (2016: US$3,566 million), natural gas US$1,796 million (2016: US$1,761 million), LNG US$858 million (2016: US$864 million), NGL US$442 million (2016: US$383 million) and other US$135 million (2016: US$192 million).

(2) Includes US$332 million of capitalised exploration (2016: US$317 million).

(3) Includes US$102 million of exploration expenditure previously capitalised, written off as impaired (included in depreciation and amortisation) (2016: 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), UK, Neptune and Genesis. Also includes the Caesar oil pipeline and the Cleopatra gas pipeline which are equity accounted investments. The financial information for the Caesar oil pipeline and the Cleopatra gas pipeline presented above, with the exception of net operating assets, reflects BHP's share.

(6) Goodwill associated with Onshore US of US$3,022 million is included in Other net operating assets (2016: US$3,026 million).

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

(8) Total Petroleum segment Revenue excludes US$17 million (2016: US$15 million) revenue related to the Caesar oil pipeline and the Cleopatra gas pipeline. Total Petroleum segment Underlying EBITDA includes US$3 million (2016: US$3 million) D&A related to the Caesar oil pipeline and the Cleopatra gas pipeline.

(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 the 2017 financial year. There is no change to the overall net operating asset position.

Underlying EBITDA for the 2017 financial year increased by US$926 million to US$3.5 billion.

(1) Average realised price: copper US$2.54/lb (2016: US$2.14/lb).

(2) Non-cash includes: development stripping capitalisation and depletion.

(3) One-off items reflects industrial action at Escondida (214 kt volume impact) and the power outage at Olympic Dam.

(4) Other includes: fuel and energy; asset sales; other items (including profit from equity accounted investments).

Total copper production for the 2017 financial year decreased by 16 per cent to 1,326 kt primarily due to reduced volumes following industrial action at Escondida, and the power outage and unplanned maintenance at Olympic Dam.

Production is forecast to increase to between 1,655 and 1,790 kt in the 2018 financial year.

· Escondida production is expected to increase to between 1,130 and 1,230 kt following the ramp-up of the Los Colorados Extension (LCE) project during the September 2017 quarter, which will enable utilisation of three concentrators.

· Pampa Norte production is expected to be higher than the prior year following completion of the Spence Recovery Optimisation project in the December 2016 quarter.

· Olympic Dam production is expected to decrease to 150 kt as a major smelter maintenance campaign is phased through August to November 2017. Following completion of the maintenance campaign, improved operating performance will underpin an expected increase in production to approximately 215 kt in the 2019 financial year.

· Antamina production is expected to decrease to 125 kt as mining continues through a zinc rich zone.

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We continue to release latent capacity across our copper assets. The Spence Recovery Optimisation project was completed in the December 2016 quarter and the Escondida LCE project is expected to ramp-up in the September 2017 quarter. At Olympic Dam, development into the Southern Mining Area is progressing well with first ore expected in the September 2017 quarter. In the medium term, the Olympic Dam Brownfield Expansion project has the potential to increase capacity to 280 kt.

On 17 August 2017, BHP's Board approved the development of the Spence Growth Option (SGO) which will extend the mine life by more than 50 years. The development includes building a 95 ktpd concentrator with first production expected in the 2021 financial year. In the first 10 years, we anticipate average incremental production of approximately 185 ktpa of payable copper in concentrate and 4 ktpa of payable molybdenum. The project is expected to cost US$2.5 billion, based on updated foreign exchange rate assumptions, and at mid-case consensus prices has an expected internal rate of return of 16 per cent. The current copper cathode stream will continue until the 2025 financial year. In addition, SGO will require a new 1,000 litre per second desalination plant located at Mejillones Bay and a 154 km water pipeline from the plant to the Spence mine site. These will be built and operated by a third party under a Build, Own, Operate and Transfer contract.

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 LCE project, a US$160 million ore inventory drawdown as a result of extending the operation of Los Colorados by four months in the 2016 financial year 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 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 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, in line with revised guidance, excluding the idle capacity and other strike-related costs incurred as a result of the industrial action at Escondida. In the 2018 financial year, unit cash costs at our copper operated assets are expected to remain broadly unchanged at approximately US$1.15 per pound.

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. This was seven per cent lower than guidance due to continued productivity improvements and favourable inventory movements. If costs related to the industrial action were included, unit costs would have been US$1.13 per pound. Escondida unit cash costs are expected to rise to approximately US$1.00 per pound in the 2018 financial year, reflecting an expected 10 per cent mine-plan grade decline, to approximately 0.90 per cent, higher price-linked commodity input costs and an increase in usage of higher cost desalinated water. Notwithstanding, a lower mining cost per tonne of material moved is expected as a result of continued productivity improvements.

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(1) 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 the 2017 financial year calculated as: cash costs of US$334 million divided by sales of 1,691 Mlb = US$0.20 per pound.

Financial information for Copper for the 2017 and 2016 financial years is presented below.

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

(2) Includes Spence and Cerro Colorado.

(3) Antamina and Resolution are equity accounted investments and their financial information presented above with the exception of net operating assets reflects BHP's share.

(4) Predominantly comprises divisional activities, greenfield exploration and business development. Includes Resolution.

 (5) Total Copper segment Revenue excludes US$1,119 million (2016: US$891 million) revenue related to Antamina. Total Copper segment Underlying EBITDA includes US$116 million (2016: US$115 million) D&A and US$209 million (2016: 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 (2016: US$198 million) and US$ nil (2016: US$1 million) Exploration expenditure related to Antamina.

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Underlying EBITDA for the 2017 financial year increased by US$3.5 billion to US$9.1 billion.

(1) Average realised price: iron ore US$58/wmt, FOB (2016: US$44/wmt, FOB).

(2) Other includes: fuel and energy; non-cash; asset sales; other items. Other items includes profit/(loss) from the equity accounted investment in Samarco prior to the dam failure, but does not include any financial impacts following the Samarco dam failure which has been reported as an exceptional item.

Total iron ore production for the 2017 financial year increased by four per cent to 231 Mt(ix) following record annual production at Western Australia Iron Ore (WAIO) which reflected strong productivity improvements across the supply chain as well as the commissioning of a new primary crusher and additional conveying capacity at Jimblebar.

WAIO production is expected to increase to between 239 and 243 Mt(ix), or between 275 and 280 Mt(ix) on a 100 per cent basis, in the 2018 financial year. This reflects continued productivity improvements and improved reliability across the supply chain. Volumes are expected 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).

Mining and processing operations at Samarco remain suspended following the failure of the Fundão tailings dam and Santarém water dam on 5 November 2015.

In June 2017, BHP approved initial funding of US$184 million (BHP share) for the South Flank sustaining mine project. The initial funding will be used primarily for the expansion of accommodation facilities to support construction and future operational workforce requirements. The capital cost for South Flank is expected to be in the range of US$30 to US$40 per tonne, with expenditure fitting within WAIO's previously indicated average annual sustaining capital expenditure of US$4 per tonne over the next five years.

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, a stock write-off at Yandi of US$0.15 per tonne and additional costs related to the accelerated rail renewal and maintenance program of US$0.20 per tonne, which was completed in May 2017. In the 2018 financial year, unit costs are expected to decline further to below US$14 per tonne.

(1) Includes exploration expense of US$0.30 per tonne (2016: US$0.34 per tonne).

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Financial information for Iron Ore for the 2017 and 2016 financial years is presented below.

(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 which 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 (2016: US$442 million) revenue related to Samarco. Total Iron Ore segment Underlying EBITDA includes US$ nil (2016: US$46 million) D&A and US$ nil (2016: 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 (2016: US$36 million) related to Samarco.

Underlying EBITDA for the 2017 financial year increased by US$3.1 billion to US$3.8 billion.

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(1) Average realised price: hard coking coal US$180/t (2016: US$83/t); weak coking coal US$121/t (2016: US$69/t); thermal coal US$75/t (2016: US$48/t).

(2) One-off items reflects: Cyclone Debbie impacts and royalty matters.

(3) Other includes: fuel and energy; asset sales; other items (including profit/(loss) from equity accounted investments).

Metallurgical coal production decreased by six per cent to 40 Mt(ix) and energy coal production increased by seven per cent to 29 Mt(ix) in the 2017 financial year.

· Metallurgical coal production decreased as a result of damage caused by Cyclone Debbie to third party rail infrastructure, partially offset by record annual production at Peak Downs and Saraji.

· Energy coal production increased following a stronger performance at Cerrejón and as New South Wales Energy Coal (NSWEC) benefitted from a lower strip ratio and additional bypass coal.

Metallurgical coal production is expected to increase to between 44 and 46 Mt(ix) and energy coal production is expected to remain broadly unchanged at approximately 29 to 30 Mt(ix) in the 2018 financial year.

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. In the 2018 financial year, unit 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 costs of US$41 per tonne(vii) were in line with the prior year as a reduction in labour costs and favourable inventory movements were offset by a stronger Australian dollar. Unit costs are expected to increase to approximately US$46 per tonne in the 2018 financial year as mining progresses through geological constraints (the monocline transition), strip ratios rise and pit design initiatives are implemented to reduce costs in future periods. These initiatives are expected to mitigate the impacts of the monocline and reduce unit costs from the 2020 financial year onwards.

Average annual sustaining capital expenditure is forecast to be approximately US$8 per tonne for Queensland Coal and US$5 per tonne for NSWEC over the next five years. In August 2016, BHP agreed with the New South Wales Government to cancel the exploration licence and cease progression of the Caroona Coal project for A$220 million.

Financial information for Coal for the 2017 and 2016 financial years is presented below.

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(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 (2016: US$621 million) revenue related to Newcastle Coal Infrastructure Group and Cerrejón. Total Coal segment Underlying EBITDA includes US$96 million (2016: US$96 million) D&A and US$116 million (2016: 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 (2016: US$32 million) D&A and US$53 million (2016: 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 (2016: US$35 million) related to Newcastle Coal Infrastructure Group and Cerrejón.

Underlying EBITDA loss increased by US$2 million to US$173 million in the 2017 financial year as a strong performance at Nickel West was offset by unfavourable exchange rate impacts on corporate provision balances and increased spend on technology projects.

Nickel West returned to positive Underlying EBITDA of US$44 million as production rates increased across the supply chain following the triennial statutory shutdowns in the prior year. The benefit of higher prices was offset by a stronger Australian dollar. Debottlenecking activities at the Kwinana refinery delivered record refined metal production.

The financial information on pages 31 to 47 has been prepared in accordance with IFRS. This news release including the financial information is unaudited. Variance analysis relates to the relative financial and/or production performance of BHP and/or its operations during the 2017 financial year compared with the 2016 financial year, unless otherwise noted.

The following abbreviations may have been used throughout this report: barrels (bbl); billion cubic feet (bcf); barrels of oil equivalent (boe); cost and freight (CFR); cost, insurance and freight (CIF), dry metric tonne unit (dmtu); free on board (FOB); grams per tonne (g/t); kilograms per tonne (kg/t); kilometre (km); metre (m); million barrels of oil equivalent (MMboe); million barrels of oil equivalent per day (MMboe/d); thousand cubic feet equivalent (Mcfe); million cubic feet per day (MMcf/d); million ounces per annum (Mozpa); million pounds (Mlb); million tonnes (Mt); million tonnes per annum (Mtpa); ounces (oz); pounds (lb); thousand barrels of oil equivalent (Mboe); thousand ounces (koz); thousand ounces per annum (kozpa); thousand standard cubic feet (Mscf); thousand tonnes (kt); thousand tonnes per annum (ktpa); thousand tonnes per day (ktpd); tonnes (t); and wet metric tonnes (wmt).

The following footnotes apply to this Results Announcement:

(i) We use other financial measures (each of which is calculated with reference to IFRS measures) to assess our performance, which are defined below:

· Free cash flow - comprises net operating cash flows less net investing cash flows.

· Gearing ratio - represents the ratio of net debt to net debt plus net assets.

· Net debt - comprises Interest bearing liabilities less Cash and cash equivalents for the total operations within the Group at the reporting date.

(ii) We use various alternate performance measures to reflect our underlying performance. Our two primary measures of performance are Underlying attributable profit and Underlying EBITDA.

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.

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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 BHP 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 attributable profit is Profit/(loss) after taxation attributable to BHP shareholders (also referred to as 'Attributable profit/(loss)') excluding discontinued operations and any exceptional items attributable to BHP shareholders.

· Underlying EBITDA is Earnings before net finance costs, depreciation, amortisation and impairments, taxation expense, Discontinued operations and exceptional items. Underlying EBITDA includes net finance costs and taxation (expense)/benefit, depreciation, amortisation and impairments related to equity accounted investments of US$540 million (2016: US$444 million) and excludes exceptional items of US$172 million (2016: US$1,227 million) related to share of profit/(loss) from equity accounted investments.

· Underlying EBIT is Underlying EBITDA, including depreciation, amortisation and impairments of US$7,907 million for the 2017 financial year (2016: US$8,871 million). Underlying EBIT includes net finance costs and taxation (expense)/benefit of US$325 million (2016: US$184 million) related to equity accounted investments and excludes exceptional items of US$172 million (2016: US$1,227 million) related to share of profit/(loss) from equity accounted investments.

 (iii) Further alternate performance measures are defined as follows and comparatives exclude discontinued operations unless otherwise stated:

· Adjusted effective tax rate - comprises 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.

· Net operating assets - represents 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.

· Operating assets free cash flow - comprises 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.

· Underlying basic earnings per share - represents underlying attributable profit divided by the weighted average number of basic shares.

· Underlying EBITDA margin - comprises Underlying EBITDA excluding third party product EBITDA, divided by revenue excluding third party product revenue.

· Underlying return on capital employed (ROCE) - represents annualised attributable profit after tax excluding exceptional items and net finance costs (after tax) divided by average capital employed. Average capital employed is calculated as the average of net assets less net debt for the last two financial years.

The method of calculation of the Principal factors that Underlying EBITDA is as follows:

· 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. Used to determine changes in productivity in footnote (iv).

· 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 - comprises operating cash costs and exploration and business development costs. Management believes this measure provides useful information regarding the Group's financial performance because it considers these expenses to be the principal operating and overhead expenses that are most directly under the Group's control. Used to determine changes in productivity in footnote (iv).

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· 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 Company's selling prices are denominated in US dollars and so there is little impact of exchange rate changes on Revenue.

· Inflation - 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.

· Other - Share of operating profit from equity accounted investments for the period minus share of operating profit from equity accounted investments in the corresponding period and variances not explained by the above factors.

(iv) Represents changes in controllable cash costs (refer to footnote (iii)), changes in volumes attributed to productivity (refer to definition of 'productivity volumes' in footnote (iii)) and changes in capitalised exploration. Changes in capitalised exploration is capitalised exploration in the current period less capitalised exploration in the prior period.

(v) Capital and exploration expenditure represents purchases of property, plant and equipment plus exploration expenditure from the Consolidated Cash Flow Statement.

(vi) Operating cost per copper equivalent tonne presented on a continuing operations basis excluding royalties and BHP's share of volumes from equity accounted investments; copper equivalent production based on 2017 financial year average realised prices.

(vii) Conventional petroleum unit cash costs exclude inventory movements, freight, and third party and exploration expense; WAIO, Queensland Coal and NSWEC unit cash costs exclude freight and royalties; Escondida unit cash costs include the grade decline and exclude freight and treatment and refining charges and are net of by-product credits. 2018 financial year 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.

(viii) Maintenance capital includes non-discretionary spend for the following purposes: deferred development and production stripping; risk reduction, compliance and asset integrity.

(ix) Iron ore production and guidance excludes production from Samarco; Energy Coal production and guidance excludes production from New Mexico Coal following divestments; Metallurgical coal production and guidance excludes production from Haju following the divestment of IndoMet Coal.

Forward-looking statements

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

Forward-looking statements can be identified by the use of terminology such as 'intend', 'aim', 'project', 'anticipate', 'estimate', 'plan', 'believe', 'expect', 'may', 'should', 'will', 'continue', 'annualised' or similar words. These statements discuss future expectations concerning the results of operations or financial condition, or provide other forward-looking statements.

These forward-looking statements are not guarantees or predictions of future performance, and involve known and unknown risks, uncertainties and other factors, many of which are beyond our control, and which may cause actual results to differ materially from those expressed in the statements contained in this release. Readers are cautioned not to put undue reliance on forward-looking statements.

For example, our future revenues from our operations, projects or mines described in this release will be based, in part, upon the market price of the minerals, metals or petroleum produced, which may vary significantly from current levels. These variations, if materially adverse, may affect the timing or the feasibility of the development of a particular project, the expansion of certain facilities or mines, or the continuation of existing operations.

Other factors that may affect the actual construction or production commencement dates, costs or production output and anticipated lives of operations, mines or facilities include our ability to profitably produce and transport the minerals, petroleum and/or metals extracted to applicable markets; the impact of foreign currency exchange rates on the market prices of the minerals, petroleum or metals we produce; activities of government authorities in some of the countries where we are exploring or developing these projects, facilities or mines, including increases in taxes, changes in environmental and other regulations and political uncertainty; labour unrest; and other factors identified in the risk factors discussed in BHP's filings with the U.S. Securities and Exchange Commission (the "SEC") (including in Annual Reports on Form 20-F) which are available on the SEC's website at www.sec.gov.

Except as required by applicable regulations or by law, the Group does not undertake any obligation to publicly update or review any forward-looking statements, whether as a result of new information or future events.

Past performance cannot be relied on as a guide to future performance.

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Non-IFRS financial information

BHP results are reported under International Financial Reporting Standards (IFRS). This release may also include certain non-IFRS (also referred to as alternate performance measures) and other measures including Underlying attributable profit, Underlying EBITDA, Underlying EBIT, Adjusted effective tax rate, Controllable cash costs, Free cash flow, Gearing ratio, Net debt, Net operating assets, Operating assets free cash flow, Principal factors that affect Underlying EBITDA, Underlying basic earnings per share, Underlying EBITDA margin and Underlying return on capital employed (ROCE). These measures are used internally by management to assess the performance of our business and segments, make decisions on the allocation of our resources and assess operational management. Non-IFRS and other measures have not been subject to audit or review and should not be considered as an indication of or alternative to an IFRS measure of profitability, financial performance or liquidity.

No offer of securities

Nothing in this release should be construed as either an offer, or a solicitation of an offer, to buy or sell BHP securities in any jurisdiction, or be treated or relied upon as a recommendation or advice by BHP.

Reliance on third party information

The views expressed in this release contain information that has been derived from publicly available sources that have not been independently verified. No representation or warranty is made as to the accuracy, completeness or reliability of the information. This release should not be relied upon as a recommendation or forecast by BHP.

No financial or investment advice - South Africa

BHP does not provide any financial or investment 'advice' as that term is defined in the South African Financial Advisory and Intermediary Services Act, 37 of 2002, and we strongly recommend that you seek professional advice.

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BHP

Financial Information

Year ended

30 June 2017

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Contents

Financial Information