UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 6-K

REPORT OF FOREIGN PRIVATE ISSUER

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

UNDER THE SECURITIES EXCHANGE ACT OF 1934

February 20, 2018

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

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20 February 2018
Results for announcement to the market
Name of Companies: BHP Billiton Limited (ABN 49 004 028 077) and BHP Billiton Plc (Registration No. 3196209)
Report for the half year ended 31 December 2017
This statement includes the consolidated results of BHP for the half year ended 31 December 2017 compared with the half year ended 31 December 2016.
This page and the following 55 pages comprise the half year end information given to the ASX under Listing Rule 4.2A and released to the market under UK Disclosure and Transparency Rule 4.2.2R and should be read in conjunction with the 2017 BHP Group annual financial report.
The results are prepared in accordance with IFRS and are presented in US dollars.

US$ Million
Revenue
up
16%
to
21,779
Profit after taxation attributable to the members of the BHP Group
down
37%
to
2,015
Net Tangible Asset Backing:
Net Tangible Asset Backing:
Net tangible assets per fully paid share were US$10.95 as at 31 December 2017, compared with US$10.97 as at 31 December 2016.
Dividends per share:
Interim dividend for current period US 55 cents fully franked (record date 9 March 2018; payment date
27 March 2018)
Interim dividend for previous corresponding period US 40 cents fully franked
This statement was approved by the Board of Directors.
Margaret Taylor
Group Company Secretary
BHP Billiton Limited and BHP Billiton Plc

Release Time IMMEDIATE Date 20 February 2018 Number 3/18 BHP RESULTS FOR THE HALF YEAR ENDED 31 DECEMBER 2017 Safety: We are committed to making our workplaces safer, as we achieve nothing unless we achieve it safely Tragically, we had two fatalities during the period, one at our Permian operations and one at Goonyella Riverside. Maximise cash flow: Strong free cash generation underpinned by higher prices Attributable profit of US$2.0 billion (includes an exceptional loss of US$2.0 billion predominantly related to the US tax reform) and Underlying attributable profit of US$4.1 billion. Underlying EBITDAP (ii) P of US$11.2 billion and Underlying EBITDA marginP (iii) P of 53% reflect higher commodity prices and a solid operating performance. Net operating cash flow of US$7.3 billion and free cash flowP (i) P of US$4.9 billion. A negative productivity movement of US$496 million was largely due to anticipated factors. We remain on track to deliver productivity gains of US$2 billion over the two years to the end of the 2019 financial year, weighted to the second year. Capital discipline: Delivering debt reduction and value accretive investments Net debtP (i) P down by US$0.9 billion from 30 June 2017 to US$15.4 billion reflecting strong free cash flow generation. Capital and exploration expenditureP (v) P increased by 6% to US$2.9 billion. Guidance unchanged at US$6.9 billion for the 2018 financial year and expected to remain below US$8 billion per annum for the 2019 and 2020 financial years. Value and returns: Detailed asset-level plans to increase shareholder value and returns The Board has determined to pay an interim dividend of 55 US cents per share which includes an additional amount of 17 US cents per share above the 50% minimum payout policy (equivalent to US$0.9 billion). Underlying return on capital employedP (iii) P of 12.8% (after tax) with further improvement expected. Onshore US exit for value progressing to plan, with initial bids expected to be received in the June 2018 quarter. Half year ended 31 DecemberP (1) 2017 US$M 2016 US$M Change % Profit from operations 6,736 6,057 11% Attributable profit 2,015 3,204 (37%) Basic earnings per share (cents) 37.9 60.2 (37%) Dividend per share (cents) 55.0 40.0 38% Net operating cash flow 7,343 7,697 (5%) Capital and exploration expenditureP (v) 2,877 2,727 6% Net debtP (i) 15,411 20,057 (23%) Underlying EBITDAP (ii) 11,238 9,896 14% Underlying EBITP (ii) 6,902 5,982 15% Underlying attributable profitP (ii) 4,053 3,244 25% Underlying basic earnings per share (cents)P (iii) 76.1 61.0 25% (1) Where we have used alternate performance measures they are identified by a footnote, and definitions can be found on pages 23 and 24. BHP Chief Executive Officer, Andrew Mackenzie: “Higher commodity prices and a solid operating performance delivered free cash flow of US$4.9 billion. We used this cash to further reduce net debt and increase returns to shareholders through higher dividends. We are on track to deliver further productivity gains of US$2 billion by the end of the 2019 financial year as we secure improvements in both operating and capital productivity, aided by smarter technology application across our value chain. Our capital expenditure program remains focused on high-return, low-risk development opportunities in commodities where we see greatest potential. We remain firm in our resolve to maximise cash flow, maintain discipline and increase shareholder value and returns.”

News Release
Results for the half year ended 31 December 2017
Safety is our highest priority
The health and safety of our employees and contractors, and that of the broader communities in which we operate, are central to the success of our organisation. Tragically, two of our colleagues died during the period, one at our Permian Basin operations in November 2017 and one at Goonyella Riverside in August 2017. Our Total Recordable Injury Frequency (TRIF) was 4.1 per million hours worked in the December 2017 half year, a two per cent decrease from
30 June 2017. We are committed to becoming safer through how we design our facilities and how we plan and execute our work, with an increasing application of technology to remove people from harms’ way.
Making significant progress on the social and environmental remediation programs in Brazil
BHP remains committed to supporting the Renova Foundation with the recovery of communities and ecosystems affected by the Samarco tragedy.
The Renova Foundation’s compensation program is making good progress. Over 260,000 claims for temporary interruption to water supplies immediately following the dam failure have been resolved. The focus of the program is now shifting to compensating for other damages including loss of property, equipment and loss of income. The resettlement of the most impacted communities is progressing, however, at a pace slower than planned due to regulatory and licensing challenges. The river remediation programs continue to stabilise the tailings material, resulting in improvements to water quality and aquatic ecology.
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.
In the December 2017 half year, BHP reported an exceptional loss of US$210 million (after tax) in relation to the Samarco dam failure. This includes funding of US$50 million, direct costs of US$29 million, discount unwinding of US$44 million and other movements in the provision, including foreign exchange, of US$87 million. Additional commentary is included on page 42.
Financial performance
Earnings and margins
Attributable profit of US$2.0 billion includes an exceptional loss of US$2.0 billion (after tax), compared to an attributable profit of US$3.2 billion, including an exceptional loss of US$40 million (after tax), in the prior period. The December 2017 half year exceptional loss is related to the US tax reform and Samarco dam failure. The December 2016 half year exceptional loss was related to the Samarco dam failure, partially offset by the reimbursement received on cancellation of the Caroona exploration licence.
Underlying attributable profit of US$4.1 billion, compared to US$3.2 billion in the prior period.
Profit from operations of US$6.7 billion, compared to US$6.1 billion in the prior period, has increased as a result of higher prices and volumes, partially offset by higher costs.
Underlying EBITDA of US$11.2 billion, with higher prices and volume productivity (in total US$2.6 billion) more than offsetting the impacts of higher costs, unfavourable exchange rate movements, inflation and other net movements (in total US$1.3 billion).
Underlying EBITDA margin of 53 per cent, compared with 54 per cent in the prior period.

BHP Results for the half year ended 31 December 2017 Productivity and costs A negative movement in productivity of US$496 million was recorded reflecting: lower volumes and unfavourable fixed cost dilution at Olympic Dam as a result of the smelter maintenance campaign (US$202 million); the impact of reduced volumes at Queensland Coal and Petroleum (US$225 million); and a favourable change in estimated recoverable copper in the Escondida sulphide leach pad in the prior period (US$206 million); partially offset by an increase in Escondida copper volumes and lower labour and contractor costs at Western Australia Iron Ore (WAIO). Productivity guidance remains unchanged, with US$2 billion of gains expected to be delivered over the two years to the end of the 2019 financial year, weighted to the second year. Full year unit cost guidance(vi) remains unchanged for Petroleum, Copper, Iron Ore and Energy Coal (based on an exchange rate of AUD/USD 0.75 and USD/CLP 663). Queensland Coal unit costs for the 2018 financial year are now expected to be US$66 per tonne (based on an exchange rate of AUD/USD 0.75), an increase from previous guidance of US$59 per tonne, as a result of reduced low-cost Broadmeadow and Blackwater volumes, production from higher cost pits and rising inflationary pressures. Unit costs for the second half of the 2018 financial year are expected to be US$63 per tonne with challenging roof conditions at Broadmeadow expected to continue through the March 2018 quarter. Historical costs and guidance are summarised below: FY18 guidance at FY18e(1) AUD/USD 0.75; AUD/USD 0.78; vs H1 FY18 H1 FY17 FY17 USD/CLP 663(1) USD/CLP 638(2) FY17 Conventional petroleum unit cost (US$ per boe) 10.38 8.42 8.82 ~10 ~11 13% Escondida unit cost (US$ per pound) 1.06 0.91 0.93 ~1 1.02 8% Western Australia Iron Ore unit cost (US$ per tonne) 14.90 15.05 14.60 <14 14.57 (4%) Queensland Coal unit cost (US$ per tonne) 71.21 56.43 59.67 66 69 11% (1) Current FY18 guidance is based on exchange rates of AUD/USD 0.75 and USD/CLP 663. (2) Average exchange rates for H1 FY18 of AUD/USD 0.78 and USD/CLP 638. Production and guidance are summarised below: H1 FY18 vs FY18 Production H1 FY18 H1 FY17 FY17 guidance Petroleum (MMboe) 99 (7%) 208 180 -190 FY18 guidance unchanged. Onshore US (MMboe) 35 (13%) 80 61—67 FY18 guidance unchanged, with volumes expected to be towards upper end of range. Conventional (MMboe) 64 (3%) 128 119—123 FY18 guidance unchanged. Copper (kt) 833 17% 1,326 1,655—1,790 FY18 guidance unchanged. Escondida (kt) 583 29% 772 1,130—1,230 FY18 guidance unchanged, with volumes weighted to the second half of the financial year reflecting full utilisation of the three concentrators. Other copper(1) (kt) 250 (4%) 554 525—560 FY18 guidance unchanged, with Olympic Dam expected to ramp-up to full capacity in the March 2018 quarter. Iron ore(2) (Mt) 117 0% 231 239—243 FY18 guidance unchanged, with volumes weighted to the second half of the financial year. WAIO (100% basis) (Mt) 136 0% 268 275—280 FY18 guidance unchanged. Metallurgical coal (2) (Mt) 20 (4%) 40 41—43 FY18 guidance reduced from 44—46 Mt and reflects lower volumes now expected at Broadmeadow and Blackwater. Energy coal (2) (Mt) 14 4% 29 29—30 FY18 guidance unchanged. (1) Other copper comprises Pampa Norte, Olympic Dam and Antamina. (2) Excludes production from Samarco, Haju (IndoMet Coal) and New Mexico Coal. We expect Group copper equivalent volume growth(vii) of six per cent for the 2018 financial year, down from previous guidance of seven per cent, due to lower volumes now expected at Broadmeadow and Blackwater.

News Release Cash flow and balance sheet Net operating cash flows of US$7.3 billion reflect higher commodity prices, a solid operating performance and a final corporate income tax payment in Australia of US$1.3 billion related to the prior year. Free cash flow of US$4.9 billion. Our Onshore US assets remain free cash flow positive(iii). We continued to strengthen our balance sheet with a reduction in net debt of US$0.9 billion, to finish the period at US$15.4 billion (30 June 2017: US$16.3 billion; 31 December 2016: US$20.1 billion). This reduction reflects strong free cash generation during the period, offset by an increase in dividends to shareholders, record dividends paid to non-controlling interests of US$0.9 billion and a non-cash fair value adjustment of US$0.7 billion related to interest rate and exchange rate movements(viii). Gearing ratio(i) of 19.9 per cent (30 June 2017: 20.6 per cent; 31 December 2016: 24.3 per cent). We are on track to reach our net debt range of US$10 to US$15 billion before year-end and will maintain a strong balance sheet through the commodity price cycle. We are targeting the lower half of the net debt range while commodity prices remain elevated. 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 the period is 38 US cents per share. Recognising the importance of cash returns to shareholders, the Board has determined to pay an additional amount of 17 US cents per share or US$0.9 billion, taking the interim dividend to 55 US cents per share or US$2.9 billion. This is equivalent to a 72 per cent payout ratio. Capital and exploration Capital and exploration expenditure of US$2.9 billion, up six per cent in the December 2017 half year, included maintenance spend(ix) of US$1.0 billion and exploration of US$0.5 billion. Capital and exploration expenditure guidance is unchanged at US$6.9 billion for the 2018 financial year, as a decrease in Onshore US capital expenditure of US$100 million is offset by unfavourable exchange rate movements. A US$0.9 billion exploration program is planned for the 2018 financial year and includes petroleum exploration expenditure of US$715 million. We expect capital and exploration expenditure to remain below US$8 billion per annum in the 2019 and 2020 financial years, subject to exchange rate movements. Historical capital and exploration expenditure and guidance are summarised below: FY18e H1 FY18 H1 FY17 FY17 US$M US$M US$M US$M Maintenance(1)(2) 2,000 993 590 1,220 Development Minerals 2,200 859 921 1,677 Conventional petroleum (2) 700 225 504 801 Onshore US 1,100 336 273 554 Capital expenditure (purchases of property, plant and equipment) 6,000 2,413 2,288 4,252 Add: exploration expenditure 900 464 439 968 Capital and exploration expenditure 6,900 2,877 2,727 5,220 (1) Includes capitalised deferred stripping of US$433 million for H1 FY18; US$903 million for FY18e (H1 FY17: US$200 million; FY17: US$416 million). (2) Conventional petroleum capital expenditure for FY18e includes US$700 million of development and US$100 million of maintenance. Average annual sustaining capital expenditure over the medium term is unchanged from previous guidance and forecast to be approximately: o US$4 per tonne for WAIO, including the capital cost for South Flank; o US$8 per tonne for Queensland Coal; and o US$5 per tonne for New South Wales Energy Coal (NSWEC). During the December 2017 half year, the BHP Board approved an investment of US$2.5 billion for the development of the Spence Growth Option.

At the end of the December 2017 half year, BHP had four major projects under development in Petroleum, Copper and Potash, with a combined budget of US$7.5 billion over the life of the projects. All four major projects remain on time and on budget. Major projects are summarised below: Capital expenditure(1) Date of initial Business Project and ownership Capacity(1) US$M production Progress Budget Target Projects in execution at 31 December 2017 Copper Spence Growth Option New 95 ktpd concentrator is expected to increase 2,460 FY21 4% complete (Chile) Spence’s payable copper in concentrate production by 100% approximately 185 ktpa in the first 10 years of operation and extend the mining operations by more than 50 years. Petroleum North West Shelf Greater To maintain LNG plant throughput from the North West 314 CY19 66% complete Western Flank-B Shelf operations. (Australia) 16.67% (non-operator) Petroleum Mad Dog Phase 2 New floating production facility with the capacity to 2,154 CY22 10% complete (US Gulf of Mexico) produce up to 140,000 gross barrels of crude oil per 23.9% (non-operator) day. Other projects in progress at 31 December 2017 Potash(2) Jansen Potash (Canada) Investment to finish the excavation and lining of the 2,600 75% complete 100% production and service shafts, and to continue the installation of essential surface infrastructure and utilities. (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$220 million is expected for FY18. Capital allocation framework Adherence to our capital allocation framework aims to balance value creation, cash returns to shareholders and balance sheet strength in a transparent and consistent manner, and is embedded in every capital decision we make. Our balance sheet is strong and remains a fundamental enabler of our strategy. This will protect the Group through periods of heightened volatility and support counter cyclical investments as we move through the cycle. H1 FY18 H1 FY17 FY17 US$B US$B US$B Net operating cash flow (1) 7.3 7.7 16.8 Our priorities for capital Maintenance capital 1.0 0.6 1.2 Strong balance sheet l l l Minimum 50% payout ratio dividend 1.8 0.4 2.0 Excess cash 3.6 6.4 13.0 Balance sheet 1.3 4.7 8.8 Additional dividends 0.5 0.3 0.9 Organic development 1.9 2.1 4.0 Acquisitions/(Divestments) (0.1) (0.7) (0.7) (1) Less dividends to non-controlling interests of US$0.9 billion for H1 FY18 (H1 FY17: US$0.3 billion; FY17 US$0.6 billion).

Outlook
Economic outlook
World economic growth was in the range of three and a half to three and three quarters per cent in the 2017 calendar year. A similar outcome is expected in the 2018 calendar year.
China’s economic growth is expected to slow modestly in the 2018 calendar year, close to the lower end of the official GDP target range of six and a half to seven per cent, as continued strength in infrastructure and resilience in external trade is offset by a cooling of growth rates in the housing and automobile markets.
The US economy should see a near-term boost to growth with the passing of the US Tax Cuts and Jobs Act (the TCJA). 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, supported by positive reform signposts.
Commodities outlook Crude oil prices trended higher during the December 2017 half year. Production discipline by OPEC members and non-OPEC participants (the ‘Vienna Group’) and strong demand growth contributed to a substantial reduction in the inventory overhang. The tighter market, rising geopolitical tensions, unplanned supply outages, plateauing of the US rig count and extension of Vienna Group production cuts aided market sentiment. A roughly balanced market is forecast for the 2018 calendar year.
The US domestic gas price was relatively stable as growth in exports, strong power demand over summer and delays to North East pipeline projects helped eliminate the storage surplus relative to the five-year average. We anticipate that the market will return to surplus in the 2018 calendar year, as record US production is facilitated by the start-up of major North East pipelines.
Copper prices rose over the December 2017 half year. Solid global consumption was underpinned by continued strength in China, in particular from consumer durables. On the supply side, the announcement that China would ban lower-grade copper scrap imports and the potential for supply disruptions due to the large number of upcoming labour negotiations in South America drove sentiment. Over the next few years, the global copper market is expected to remain finely balanced and vulnerable to supply shocks, particularly in the concentrate segment.
The global steel industry continued its recovery in the December 2017 half year, with production growth led by emerging markets. China’s steel supply-side reforms have resulted in a structural improvement in industry profitability. China’s steel production growth is expected to moderate in the 2018 calendar year due to a cooling in the housing and automobile sectors. However, the recovery in the rest of the world is likely to continue, with solid demand conditions and lower Chinese steel exports.
Iron ore prices improved over the December 2017 half year. Demand for high-grade products remained firm on the back of high steel margins, which benefitted from Chinese steel supply-side reforms and winter production restrictions. This has resulted in an elevated price differential between high and low-grade ore price indexes. In the medium to longer term, ongoing Chinese supply-side reforms, the shift of steel capacity to coastal regions and more stringent environmental policies are expected to underpin demand for high-quality seaborne iron ore.
Metallurgical coal prices strengthened in the December 2017 half year. Chinese demand for higher quality metallurgical coal remained firm throughout the period despite the onset of winter emission restrictions. Additionally, domestic supply was constrained due to safety and environmental concerns. High prices have incentivised additional seaborne supply from the US and Mozambique. In the medium term, China’s coal supply-side reforms and environmental considerations will support demand for higher quality metallurgical coal.
Further information on BHP’s economic and commodity outlook can be found at: bhp.com/prospects

Income statement Underlying attributable profit and Underlying EBITDA are presented below. 2017 2016 Half year ended 31 December US$M US$M Underlying attributable profit 4,053 3,244 Exceptional items (after taxation) – refer to pages 10 and 34 (2,038) (40) Attributable profit 2,015 3,204 Profit attributable to non-controlling interests 559 248 Profit after taxation 2,574 3,452 2017 2016 Half year ended 31 December US$M US$M Underlying EBITDA 11,238 9,896 Depreciation and amortisation (4,037) (3,800) Impairments of property, plant and equipment, financial assets and intangibles (299) (114) Exceptional items (before net finance costs and taxation)(1) – refer to pages 10 and 34 (166) 75 Profit from operations 6,736 6,057 Net finance costs (670) (577) Total taxation expense (3,492) (2,028) Profit after taxation 2,574 3,452 (1) Exceptional items of US$(166) million excludes net finance costs of US$(44) million included in the total US$(210) million related to the Samarco dam failure. Profit from operations has increased as a result of favourable realised price movements across all major commodities and higher volumes, partially offset by higher costs, impairment charges predominantly related to conveyors at Escondida and higher depreciation charges following the commissioning of the Escondida Water Supply project.

Underlying EBITDA The following table and commentary describes the impact of the principal factors(iii) that affected Underlying EBITDA for the December 2017 half year compared with the December 2016 half year: US$M Half year ended 31 December 2016 9,896 Net price impact: Change in sales prices 2,227 Higher average realised prices for all our major commodities. Price-linked costs (21) Increased royalties reflect higher realised prices. 2,206 Change in volumes: Productivity 419 Release of latent capacity at Escondida (ramp-up of Los Colorados Extension project) partially offset by lower volumes from Olympic Dam (smelter maintenance campaign) and Queensland Coal (challenging roof conditions at Broadmeadow and geotechnical issues triggered by wet weather impacts at Blackwater). Growth (170) Lower petroleum volumes due to Hurricane Harvey and Hurricane Nate, and expected natural field decline, more than offset additional wells put on line in the Eagle Ford, Permian and Haynesville. 249 Change in controllable cash costs(iv): Operating cash costs (854) Higher costs reflect: unfavourable fixed cost dilution at Olympic Dam as a result of the smelter maintenance campaign; impact of reduced volumes at Queensland Coal and Petroleum; and a favourable change in estimated recoverable copper in the Escondida sulphide leach pad in the prior period, partially offset by lower labour and contractor costs at WAIO. Exploration and business 64 Lower petroleum exploration expense reflects expensing of the Burrokeet wells in the prior development year. (790) Change in other costs: Exchange rates (353) Impact of the stronger Australian dollar and Chilean peso against the US dollar. Inflation (223) Impact of inflation on the Group’s cost base. Fuel and energy (16) Predominantly higher diesel prices at minerals assets. Non-Cash 229 Higher capitalisation of deferred stripping at Escondida and increased underground mine development capitalisation at Olympic Dam as development extends into the Southern Mine Area. One-off items 105 Reflects the power outage at Olympic Dam in the prior year. (258) Asset sales (201) Reflects divestment of 50 per cent interest in Scarborough and Onshore US acreage in the prior year. Ceased and sold operations 2 Other items 134 Higher average realised prices received by our equity accounted investments and higher sales volumes from Antamina. Half year ended 31 December 2017 11,238 The following table reconciles relevant factors with changes in the Group’s productivity: Half year ended 31 December 2017 US$M Change in controllable cash costs (790) Change in volumes attributed to productivity 419 Change in productivity in Underlying EBITDA (371) Change in capitalised exploration (125) Change attributable to productivity measures (496)

Prices and exchange rates The average realised prices achieved for our major commodities are summarised in the following table: H1 FY18 H1 FY18 H1 FY18 vs vs vs Average realised prices(1) H1 FY18 H1 FY17 H2 FY17 FY17 H1 FY17 H2 FY17 FY17 Oil (crude and condensate) (US$/bbl) 54 45 50 48 20% 8% 13% Natural gas (US$/Mscf)(2) 3.54 3.21 3.48 3.34 10% 2% 6% US natural gas (US$/Mscf) 2.84 2.79 2.98 2.88 2% (5%) (1%) LNG (US$/Mscf) 7.48 6.35 7.37 6.84 18% 1% 9% Copper (US$/lb) 3.20 2.41 2.70 2.54 33% 19% 26% Iron ore (US$/wmt, FOB) 57 55 62 58 4% (8%) (2%) Hard coking coal (HCC) (US$/t) 182 179 180 180 2% 1% 1% Weak coking coal (WCC) (US$/t) 121 122 121 121 (1%) 0% 0% Thermal coal (US$/t)(3) 87 74 75 75 18% 16% 16% Nickel metal (US$/t) 11,083 10,581 9,799 10,184 5% 13% 9% (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. (2) Includes internal sales. (3) Export sales only; excludes Cerrejón. Includes thermal coal sales from metallurgical coal mines. In Copper, the provisional pricing and finalisation adjustments increased Underlying EBITDA by US$246 million in the December 2017 half year. The following exchange rates relative to the US dollar have been applied in the financial information: Average Average Half year ended Half year ended As at As at As at 31 December 31 December 31 December 31 December 30 June 2017 2016 2017 2016 2017 Australian dollar(1) 0.78 0.75 0.78 0.72 0.77 Chilean peso 638 663 615 667 663 (1) Displayed as US$ to A$1 based on common convention. Depreciation, amortisation and impairments Depreciation, amortisation and impairments increased by US$422 million to US$4.3 billion, reflecting impairment charges predominantly related to conveyors at Escondida and higher depreciation following the commissioning of the Escondida Water Supply project in June 2017. Net finance costs Net finance costs increased by US$93 million to US$670 million due to costs related to the September 2017 bond repurchase program and higher benchmark interest rates in the period. This was partially offset by a lower average debt balance following the repayment on maturity of Group debt and the bond repurchase program. Taxation expense Half year ended 31 December 2017 2016 Profit before Income tax Profit before Income tax taxation expense taxation expense US$M US$M % US$M US$M % Statutory effective tax rate 6,066 (3,492) 57.6 5,480 (2,028) 37.0 Adjusted for: Exchange rate movements — (98) — 82 Exceptional items 210 1,828 (9) 49 Adjusted effective tax rate 6,276 (1,762) 28.1 5,471 (1,897) 34.7 The Group’s adjusted effective tax rate(iii), which excludes the influence of exchange rate movements and exceptional items, was 28.1 per cent (31 December 2016: 34.7 per cent). The adjusted effective tax rate reflects the impact of higher profits from equity accounted investments and depletion allowances claimed in the United States. As a result, the adjusted effective tax rate is now expected to be in the range of 30 to 35 per cent for the 2018 financial year. Other royalty and excise arrangements which are not profit based are recognised as operating costs within Profit before taxation. These amounted to US$986 million during the period (31 December 2016: US$963 million).

On 22 December 2017, the US President signed the TCJA into law. The TCJA (effective 1 January 2018) includes a broad range of tax reforms affecting the Group, including, but not limited to, a reduction of the US corporate tax rate from 35 per cent to 21 per cent and changes to international tax provisions. As a result of the TCJA, the Group has recognised an exceptional income tax charge of US$1,828 million (refer exceptional items footnote (2) below for further details). Longer term, we expect US attributable profits to be positively impacted by the lower US corporate tax rate. Exceptional items The following table sets out the exceptional items for the December 2017 half year. Additional commentary is included on page 34. Gross Tax Net Half year ended 31 December 2017 US$M US$M US$M Exceptional items by category Samarco dam failure(1) (210) — (210) US tax reform (2) — (1,828) (1,828) Total (210) (1,828) (2,038) Attributable to non-controlling interests — — — Attributable to BHP shareholders (210) (1,828) (2,038) (1) Financial impact of US$(210) million from the Samarco dam failure relates to US$(50) million share of loss from US$(50) million funding provided during the period, US$(29) million direct costs incurred by BHP Billiton Brasil Ltda and other BHP entities, US$(44) million amortisation of discounting impacting net finance costs and US$(87) million other movements in the Samarco dam failure provision including foreign exchange. Refer to note 2 Exceptional items and note 10 Significant events – Samarco dam failure of the Financial Report for further information. (2) Financial impact of US$(1,828) million from US tax reform relates to US$(898) million re-measurement of the Group’s deferred tax position as a result of the reduced US corporate income tax rate, US$(834) million impairment of foreign tax credits due to reduced forecast utilisation, US$(194) million net impact of tax charges on the deemed repatriation of accumulated earnings of non-US subsidiaries, US$95 million recognition of Alternative Minimum Tax Credits and US$3 million other impacts. Refer to note 2 Exceptional items and note 5 Income tax expense of the Financial Report for further information. Dividend Our Board today determined to pay an interim dividend of 55 US cents per share. The interim dividend to be paid by BHP Billiton Limited will be fully franked for Australian taxation purposes. Events in respect of the interim dividend Date Currency conversion into rand 2 March 2018 Last day to trade cum dividend on Johannesburg Stock Exchange Limited (JSE) 6 March 2018 Ex-dividend Date JSE 7 March 2018 Ex-dividend Date Australian Securities Exchange (ASX), London Stock Exchange (LSE) and 8 March 2018 New York Stock Exchange (NYSE) Record Date (including currency conversion and currency election dates for ASX and LSE) 9 March 2018 Payment Date 27 March 2018 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 7 March and 9 March 2018 (inclusive), nor will transfers between the UK register and the South African register be permitted between the dates of 2 March and 9 March 2018 (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. Our Board has approved the establishment of a Dividend Reinvestment Plan (involving on-market purchase) for implementation for the final dividend in the 2018 financial year. Subject to the terms and conditions of the Plan, shareholders will be able to elect to use their cash dividend for the purchase of BHP shares.

Debt management and liquidity During the December 2017 half year, the Group continued to focus on debt reduction, with no new debt issued and an A$1.0 billion Australian bond repaid at maturity. In addition, a bond repurchase program of US$2.9 billion was completed on 22 September 2017. The total cost in relation to the repurchase program was US$71 million, which has been reported in net finance costs. The program was funded by BHP’s strong cash position and targeted short-dated US dollar, Euro and GBP bonds. The early repayment of the bonds has extended BHP’s average debt maturity profile. The repayment of maturing debt and the bond repurchase program, partially offset by fair value adjustments, contributed to a US$2.8 billion overall decrease in the Group’s gross debt, from US$30.5 billion at 30 June 2017 to US$27.7 billion at 31 December 2017. At the subsidiary level, Escondida issued US$0.5 billion of new long-term debt to fund capital expenditure and for general corporate purposes. 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 31 December 2017, the Group had no outstanding US commercial paper, no drawn amount under the revolving credit facility and US$12.3 billion in cash and cash equivalents. Corporate governance On 23 August 2017, we announced the appointment of Terry Bowen and John Mogford to the BHP Board as independent Non-executive Directors, effective 1 October 2017. We also announced that Grant King decided to not stand for election at the 2017 Annual General Meeting and he would be retiring from the Board on 31 August 2017, and that Malcolm Brinded decided to not stand for re-election at the 2017 Annual General Meeting with 18 October 2017 being his final day on the Board. The current members of the Board’s committees are: Risk and Audit Nomination and Governance Remuneration Sustainability Committee Committee Committee Committee Lindsay Maxsted (Chairman) Ken MacKenzie (Chairman) Carolyn Hewson (Chairman) Malcolm Broomhead (Chairman) Anita Frew Malcolm Broomhead Shriti Vadera Ken MacKenzie Wayne Murdy Carolyn Hewson Wayne Murdy John Mogford Terry Bowen Shriti Vadera The Board and management regularly review the Dual Listed Company (DLC) structure and our portfolio of assets so as to optimise long-term value for all shareholders. We have considered unification of the DLC structure a number of times over the past years, and will keep it under review. We would change the DLC structure if it were in the best interests of all shareholders. Our view on unification of the DLC structure is based on cost and benefit analysis. Currently, we consider that the costs and risks of collapsing the DLC outweigh the potential benefits.

Segment summary(1) A summary of performance for the December 2017 and December 2016 half years is presented below. Half year ended Net 31 December 2017 Underlying Underlying Exceptional operating Capital Exploration Exploration US$M Revenue(2) EBITDA(3) EBIT(3) items(4) assets(3) expenditure gross(5) to profit(6) Petroleum 3,583 2,035 188 — 22,290 612 378 208 Copper 6,381 3,195 2,052 — 23,983 993 19 19 Iron Ore 7,221 4,307 3,430 (153) 19,135 470 41 10 Coal 4,047 1,790 1,436 — 9,904 185 7 7 Group and unallocated items (7) 591 (89) (204) (13) 2,492 153 19 19 Inter-segment adjustment(8) (44) — — — — — — — Total Group 21,779 11,238 6,902 (166) 77,804 2,413 464 263 Half year ended Net 31 December 2016 Underlying Underlying Exceptional operating Capital Exploration Exploration US$M Revenue(2) EBITDA(3) EBIT(3) items assets(3) expenditure gross(5) to profit(6) Petroleum 3,302 2,000 360 — 24,331 845 364 260 Copper 4,209 1,744 914 — 24,743 830 17 17 Iron Ore 6,930 4,162 3,230 (55) 20,312 415 50 50 Coal 3,927 2,011 1,628 164 10,335 103 3 3 Group and unallocated items (7) 482 (21) (150) (34) 2,747 95 5 5 Inter-segment adjustment(8) (54) — — — — — — — Total Group 18,796 9,896 5,982 75 82,468 2,288 439 335 (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 of US$318 million (2016: US$267 million) related to equity accounted investments. It excludes exceptional items of US$137 million (2016: US$48 million) related to share of loss from equity accounted investments. Group profit before taxation comprised Underlying EBITDA, exceptional items, depreciation, amortisation and impairments of US$4,336 million (2016: US$3,914 million) and net finance costs of US$670 million (2016: US$577 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$774 million and Underlying EBITDA of US$31 million (2016: US$567 million and US$49 million). (3) We use various alternate performance measures to reflect our underlying performance. Refer to page 7 for a reconciliation of Underlying EBITDA to our statutory results and page 23 for the definitions and calculation methodology of alternate performance measures used in reporting our performance. (4) Exceptional items of US$(166) million excludes net finance costs of US$(44) million included in the total US$(210) million related to the Samarco dam failure. Refer to note 2 Exceptional items for further information. (5) Includes US$272 million capitalised exploration (2016: US$147 million). (6) Includes US$71 million of exploration expenditure previously capitalised, written off as impaired (included in depreciation and amortisation) (2016 US$43 million). (7) Group and unallocated items includes Functions, other unallocated operations including Potash, Nickel West and consolidation adjustments. Revenue not attributable to reportable segments comprises the sale of freight and fuel to third parties. Exploration and technology activities are recognised within the relevant segments. Half year ended 31 December 2017 Underlying Underlying Net operating Capital Exploration Exploration to US$M Revenue EBITDA D&A EBIT assets expenditure gross profit Potash — (76) 2 (78) 3,258 117 — — Nickel West 577 71 39 32 (296) 27 19 19 Half year ended 31 December 2016 Underlying Underlying Net operating Capital Exploration Exploration to US$M Revenue EBITDA D&A EBIT assets expenditure gross profit Potash — (52) 6 (58) 2,983 68 — — Nickel West 472 37 43 (6) (193) 22 5 5 (8) Comprises revenue of US$38 million generated by Petroleum (2016: US$43 million) and US$6 million generated by Iron Ore (2016: US$11 million).

Petroleum Underlying EBITDA for Petroleum increased by US$35 million to US$2.0 billion in the December 2017 half year. US$M Underlying EBITDA for the half year ended 31 December 2016 2,000 Net price impact(1) 534 Change in volumes: growth (170) Change in controllable cash costs (67) Profit on sale of assets (187) Other(2) (75) Underlying EBITDA for the half year ended 31 December 2017 2,035 (1) Average realised price: crude and condensate oil US$54/bbl (2016: US$45/bbl); natural gas US$3.54/Mscf (2016: US$3.21/Mscf); LNG US$7.48/Mscf (2016: US$6.35/Mscf). (2) Other includes: exchange rate; inflation; ceased and sold operations; other items. Other items includes the impact from revaluation of embedded derivatives in Trinidad and Tobago gas contract of US$97 million loss (2016: US$46 million loss). Total petroleum production for the December 2017 half year decreased by seven per cent to 99 MMboe due to the impact of Hurricane Harvey and Hurricane Nate on US petroleum assets and natural field decline. Conventional production declined by three per cent to 64 MMboe and Onshore US production declined by 13 per cent to 35 MMboe. Controllable cash costs increased by US$67 million and includes: US$91 million—unfavourable fixed cost dilution from declining volumes; US$61 million—planned maintenance activity at Atlantis, Macedon and Pyrenees; and US$(81) million—lower exploration expenses due to the Burrokeet wells write-off in the December 2016 half year. Profit on sale of assets decreased by US$187 million reflecting the divestment of a small portion of the Hawkville acreage, completed in the September 2017 quarter, more than offset by the sale of 50 per cent of BHP’s interest in the undeveloped Scarborough area gas fields in the prior period. Conventional unit costs increased by 23 per cent to US$10.38 per barrel of oil equivalent during the December 2017 half year, due to the impact of lower volumes and unfavourable foreign exchange movements. Unit cost guidance for the 2018 financial year remains unchanged at approximately US$10 per barrel (based on an exchange rate of AUD/USD 0.75). Conventional petroleum unit costs(1) H1 FY18 H2 FY17 H1 FY17 FY17 Revenue 2,581 2,436 2,286 4,722 Underlying EBITDA 1,622 1,552 1,580 3,132 Gross costs 959 884 706 1,590 Less: exploration expense(2) 137 256 215 471 Less: freight 68 70 70 140 Less: other(3) 90 (15) (135) (150) Net costs 664 573 556 1,129 Production (MMboe, equity share) 64 62 66 128 Cost per boe (US$)(4) 10.38 9.24 8.42 8.82 (1) Conventional petroleum assets exclude Eagle Ford, Permian, Haynesville, Fayetteville and divisional activities reported 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 revaluation of embedded, derivatives in the Trinidad and Tobago gas contract. (4) H1 FY18 based on exchange rates of AUD/USD 0.78. Guidance for production and unit costs for the 2018 financial year is also detailed on page 3. Capital expenditure and project information is detailed on pages 4 and 5.

Onshore US development activity Onshore US drilling and development expenditure for the December 2017 half year was US$336 million (U$511 million on an activity basis), 23 per cent higher than the same period last year reflecting an increase from three to nine rigs. December 2017 half year Liquids focused areas Gas focused areas (December 2016 half year) Eagle Ford Permian Haynesville Fayetteville Total Capital expenditure(1) US$ billion 0.1 (0.1) 0.1 (0.1) 0.1 (0.0) 0.0 (0.0) 0.3 (0.3) Rig allocation At period end 3 (1) 2 (1) 4 (1) 0 (0) 9 (3) Net wells drilled and completed(2) Period total 9 (43) 10 (15) 10 (0) 0 (2) 29 (60) Net productive wells At period end 931 (942) 136 (118) 405 (394) 1,043 (1,042) 2,515 (2,496) (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. We continue to drill longer laterals and complete larger frac jobs. By changing the well design, we enhanced staggered laterals and demonstrated commerciality of Upper and Lower Eagle Ford co-development and confirmed first year production improvements associated with larger completions in the Permian. These longer and more complex laterals are reflected in an overall increase of our Onshore US drilling and completion costs per well, but are more than offset by the additional well productivity. During the December 2017 half year, our Onshore US assets were free cash flow positive(iii). Cost per well (US$M) H1 FY18 H2 FY17 H1 FY17 FY17 Black Hawk: Drilling cost 2.5 2.4 1.8 2.0 Black Hawk: Completion cost 4.3 2.6 2.7 2.7 Permian: Drilling cost 2.9 3.1 2.9 2.9 Permian: Completion cost 4.2 4.3 2.2 2.8 Haynesville: Drilling cost 3.7 3.1 3.5 3.3 Haynesville: Completion cost 5.8 3.2 2.7 3.0 We expect to lower our rig count during the second half of the 2018 financial year as rig contracts expire and we adjust our capital plans to optimise value for our planned exit. Onshore US production volumes for the 2019 financial year are expected to remain broadly unchanged from previous guidance, as enhanced well performance offsets lower rig activity. We continue to progress a number of alternatives to exit our Onshore US assets for value. We have commenced marketing each of the fields and the data room for the Fayetteville field has been opened. We continue preparing all appropriate documentation ahead of data rooms for the remaining fields being opened in March 2018. We expect to receive trade sale bids during the June 2018 quarter, evaluate and negotiate those bids in the September 2018 quarter and potentially announce completed transactions in the first half of the 2019 financial year. In parallel, we continue to explore potential asset swap opportunities and exit via demerger or Initial Public Offering. Petroleum exploration Petroleum exploration expenditure for the December 2017 half year was US$378 million, of which US$137 million was expensed. Activity for the period was largely focused in the deepwater Gulf of Mexico. In the Gulf of Mexico, no commercial hydrocarbons were encountered at Scimitar. The well was plugged and abandoned in February 2018, with the associated exploration costs to be expensed in the second half of the 2018 financial year. The Wildling-2 well and side track were successfully completed in the September 2017 quarter and found oil in multiple horizons. Evaluation is ongoing to assess the scale of the discovery and we are preparing our appraisal plans for Wildling with the expectation to continue drilling in the 2019 financial year. In Mexico, the Exploration and Appraisal plan has been endorsed by Pemex and approval from Mexico’s National Hydrocarbon Commission was granted in February 2018. Planning continues for exploration and appraisal wells on Trion which are expected to be drilled in the 2019 financial year. In Trinidad and Tobago, we continue appraisal work in the Southern Gas region (known as Magellan) to assess the potential commercialisation of the gas discovery at LeClerc and follow-on potential at the Victoria and Concepcion prospects. Preparations continue for Phase 2 deepwater exploration which is expected to commence in the June 2018 quarter. In Australia, the seismic survey in the Exmouth sub-basin is progressing to plan with processed data to be delivered during the June 2018 quarter.

Financial information for Petroleum for the December 2017 and December 2016 half years is presented below. Half year ended Net 31 December 2017 Underlying Underlying operating Capital Exploration Exploration US$M Revenue(1) EBITDA D&A EBIT assets expenditure gross(2) to profit(3) Australia Production Unit(4) 291 206 135 71 828 2 Bass Strait 666 512 288 224 2,701 19 North West Shelf 663 497 116 381 1,573 80 Atlantis 355 245 198 47 1,361 71 Shenzi 264 212 94 118 845 5 Mad Dog 118 84 28 56 787 47 Eagle Ford 591 352 580 (228) 5,681 113 Permian 156 77 133 (56) 1,017 135 Haynesville 126 9 81 (72) 2,845 82 Fayetteville 119 29 37 (8) 854 4 Trinidad/Tobago 64 (60) 19 (79) 290 6 Algeria 101 78 14 64 18 3 Exploration — (136) 98 (234) 1,174 — Other(5)(6) 57 (59) 28 (87) 3,161 45 Total Petroleum from Group production 3,571 2,046 1,849 197 23,135 612 378 208 Closed mines(7) — (11) — (11) (845) — — — Third party products 20 2 — 2 — — — — Total Petroleum 3,591 2,037 1,849 188 22,290 612 378 208 Adjustment for equity accounted investments(8) (8) (2) (2) — — — — — Total Petroleum statutory result 3,583 2,035 1,847 188 22,290 612 378 208 Half year ended Net 31 December 2016 Underlying Underlying operating Capital Exploration Exploration US$M Revenue(1) EBITDA D&A EBIT assets(9) expenditure gross(2) to profit (3) Australia Production Unit(4) 308 263 142 121 1,025 15 Bass Strait 543 410 95 315 3,073 85 North West Shelf 604 581 102 479 1,529 109 Atlantis 288 230 206 24 1,641 76 Shenzi 244 183 100 83 1,085 35 Mad Dog 90 70 27 43 685 35 Eagle Ford 562 336 567 (231) 6,820 135 Permian 165 56 155 (99) 1,036 120 Haynesville 148 11 75 (64) 2,889 13 Fayetteville 136 45 37 8 919 5 Trinidad/Tobago 46 (21) 13 (34) 432 136 Algeria 104 76 18 58 99 10 Exploration — (217) 72 (289) 894 — Other(5)(6) 57 (32) 33 (65) 3,044 71 Total Petroleum from Group production 3,295 1,991 1,642 349 25,171 845 364 260 Closed mines(7) — 8 — 8 (840) — — — Third party products 14 3 — 3 — — — — Total Petroleum 3,309 2,002 1,642 360 24,331 845 364 260 Adjustment for equity accounted investments(8) (7) (2) (2) — — — — — Total Petroleum statutory result 3,302 2,000 1,640 360 24,331 845 364 260 (1) Petroleum revenue from Group production includes: crude oil US$1,903 million (2016: US$1,701 million), natural gas US$920 million (2016: US$892 million), LNG US$423 million (2016: US$419 million), NGL US$244 million (2016: US$208 million) and other US$73 million (2016: US$68 million). (2) Includes US$241 million of capitalised exploration (2016: US$147 million). (3) Includes US$71 million of exploration expenditure previously capitalised, written off as impaired (included in depreciation and amortisation) (2016: US$43 million). (4) Australia Production Unit includes Macedon, Pyrenees and Minerva. (5) Predominantly divisional activities, business development, UK, Neptune and Genesis. Also includes the Caesar oil pipeline and the Cleopatra gas pipeline, which are equity accounted investments. The financial information for the Caesar oil pipeline and the Cleopatra gas pipeline presented above, with the exception of net operating assets, reflects BHP’s share. (6) Goodwill associated with Onshore US of US$3,009 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 mines due to their geographic location. (8) Total Petroleum statutory result Revenue excludes US$8 million (2016: US$7 million) revenue related to the Caesar oil pipeline and the Cleopatra gas pipeline. Total Petroleum statutory result Underlying EBITDA includes US$2 million (2016: US$2 million) D&A related to the Caesar oil pipeline and the Cleopatra gas pipeline. (9) Petroleum net operating assets have been restated for Trinidad and Tobago, Exploration and Other to reflect the reallocation of exploration sundry receivable and sundry creditor balance on a consistent basis with the 31 December 2017 half year. There is no change to the overall net operating asset position.

Copper Underlying EBITDA for the December 2017 half year increased by US$1.5 billion to US$3.2 billion. US$M Underlying EBITDA for the half year ended 31 December 2016 1,744 Net price impact(1) 1,348 Change in volumes: productivity 453 Change in controllable cash costs (610) Change in other costs: Exchange rates (135) Inflation (110) Non-cash(2) 253 One-off items (3) 105 Other(4) 147 Underlying EBITDA for the half year ended 31 December 2017 3,195 (1) Average realised price: copper US$3.20/lb (2016: US$2.41/lb). (2) Non-cash includes: development stripping capitalisation and depletion. (3) One-off items reflects the state-wide power outage and resultant shutdown at Olympic Dam in the December 2016 half year. (4) Other includes: fuel and energy; other items (including profit from equity accounted investments). Total copper production for the December 2017 half year increased by 17 per cent to 833 kt due to increased volumes at Escondida (ramp-up of the Los Colorados Extension project), which more than offset reduced volumes at Olympic Dam (planned smelter maintenance campaign recently completed). Operations at Olympic Dam continue to ramp-up to full-capacity during the March 2018 quarter, with production guidance unchanged at 150 kt for the 2018 financial year. Controllable cash costs increased by US$610 million and includes: US$114 million—unfavourable fixed cost dilution at Olympic Dam as a result of the smelter maintenance campaign; US$106 million—increased labour and contractor costs at Olympic Dam, primarily to support operating stability projects and expansion studies; US$206 million – a change in estimated recoverable copper contained in the Escondida sulphide leach pad which benefited costs in the prior period; and US$195 million—ore inventory movements at Escondida and Pampa Norte. Non-cash costs (including development stripping) decreased by US$253 million reflecting: increased waste movement at Escondida and Pampa Norte reflected in higher capitalised stripping; and increased underground mine capitalisation at Olympic Dam as mining expands into the Southern Mine Area. As a result, unit costs at our operated copper assets increased by 17 per cent to US$1.27 per pound during the December 2017 half year including a 16 per cent increase at Escondida to US$1.06 per pound partially due to unfavourable exchange rate movements. Escondida unit cost guidance for the 2018 financial year remains unchanged at approximately US$1.00 per pound (based on an exchange rate of USD/CLP 663). Escondida unit costs (US$M) H1 FY18 H2 FY17 H1 FY17 FY17 Revenue 4,322 2,077 2,467 4,544 Underlying EBITDA 2,518 1,140 1,257 2,397 Gross costs 1,804 937 1,210 2,147 Less: by-product credits 196 91 122 213 Less: freight 50 29 31 60 Less: treatment and refining charges 210 117 185 302 Net costs 1,348 700 872 1,572 Sales (kt, equity share) 578 330 437 767 Sales (Mlb, equity share) 1,273 728 963 1,691 Cost per pound (US$)(1) 1.06 0.96 0.91 0.93 (1) H1 FY18 based on exchange rates of AUD/USD 0.78 and USD/CLP 638. Guidance for production and unit costs for the 2018 financial year is also detailed on page 3. Capital expenditure and project information is detailed on pages 4 and 5.

Financial information for Copper for the December 2017 and December 2016 half years is presented below. Half year ended Net 31 December 2017 Underlying Underlying operating Capital Exploration Exploration US$M Revenue EBITDA D&A EBIT assets expenditure gross to profit Escondida(1) 4,322 2,518 900 1,618 14,580 466 Pampa Norte(2) 860 428 143 285 1,686 191 Antamina(3) 746 495 57 438 1,254 103 Olympic Dam 479 27 97 (70) 6,657 334 Other(3)(4) — (83) 4 (87) (194) 2 Total Copper from Group production 6,407 3,385 1,201 2,184 23,983 1,096 Third party products 720 23 — 23 — — Total Copper 7,127 3,408 1,201 2,207 23,983 1,096 19 19 Adjustment for equity accounted investments(5) (746) (213) (58) (155) — (103) — — Total Copper statutory result 6,381 3,195 1,143 2,052 23,983 993 19 19 Half year ended Net 31 December 2016 Underlying Underlying operating Capital Exploration Exploration US$M Revenue EBITDA D&A EBIT assets expenditure gross to profit Escondida(1) 2,467 1,257 546 711 15,362 592 Pampa Norte(2) 624 255 174 81 1,812 128 Antamina(3) 517 296 59 237 1,261 109 Olympic Dam 611 123 107 16 6,400 110 Other(3)(4) — (61) 4 (65) (92) — Total Copper from Group production 4,219 1,870 890 980 24,743 939 Third party products 507 33 — 33 — — Total Copper 4,726 1,903 890 1,013 24,743 939 17 17 Adjustment for equity accounted investments(5) (517) (159) (60) (99) — (109) — — Total Copper statutory result 4,209 1,744 830 914 24,743 830 17 17 (1) Escondida is consolidated under IFRS 10 and reported on a 100 per cent basis. (2) Includes Spence and Cerro Colorado. (3) Antamina and Resolution are equity accounted investments and their financial information presented above, with the exception of net operating assets, reflects BHP’s share. (4) Predominantly comprises divisional activities, greenfield exploration and business development. Includes Resolution. (5) Total Copper statutory result Revenue excludes US$746 million (2016: US$517 million) revenue related to Antamina. Total Copper statutory result Underlying EBITDA includes US$58 million (2016: US$60 million) D&A and US$155 million (2016: US$99 million) net finance costs and taxation expense related to Antamina and Resolution that are also included in Underlying EBIT. Total Copper statutory result Capital expenditure excludes US$103 million (2016: US$109 million) related to Antamina.

Iron Ore Underlying EBITDA for the December 2017 half year increased by US$145 million to US$4.3 billion. US$M Underlying EBITDA for the half year ended 31 December 2016 4,162 Net price impact(1) 143 Change in volumes: productivity (1) Change in controllable cash costs 137 Change in other costs: Exchange rates (60) Inflation (41) Other(2) (33) Underlying EBITDA for the half year ended 31 December 2017 4,307 (1) Average realised price: iron ore US$57/wmt, FOB (2016: US$55/wmt, FOB). (2) Other includes: fuel and energy; non-cash; asset sales. Total iron ore production for the December 2017 half year was in line with the prior period at 117 Mt(x), as record production at Jimblebar and Mining Area C was offset by the impact of lower opening stockpile levels following the Mt Whaleback fire in June 2017 and planned maintenance. BHP received regulatory approval to increase capacity at its Port Hedland operations to 290 Mtpa (100 per cent basis) on 16 February 2018 and expects to reach this run rate by the end of the 2019 financial year. Controllable cash costs decreased by US$137 million, primarily due to continued reductions in labour and contractor costs. WAIO unit costs declined by one per cent to US$14.90 per tonne during the December 2017 half year, despite the impact of a stronger Australian dollar. In local currency terms, WAIO unit costs declined by six per cent. Unit cost guidance for the 2018 financial year remains unchanged at less than US$14 per tonne (based on an exchange rate of AUD/USD 0.75). In the medium term, we expect to lower our unit costs to less than US$13 per tonne. WAIO unit costs (US$M) H1 FY18 H2 FY17 H1 FY17 FY17 Revenue 7,117 7,587 6,808 14,395 Underlying EBITDA 4,265 4,884 4,117 9,001 Gross costs 2,852 2,703 2,691 5,394 Less: freight 626 517 466 983 Less: royalties 504 556 479 1,035 Net costs(1) 1,722 1,630 1,746 3,376 Sales (kt, equity share) 115,543 115,200 116,008 231,208 Cost per tonne (US$)(2) 14.90 14.15 15.05 14.60 (1) Includes exploration expense of US$0.08 per tonne (December 2016: US$0.41 per tonne) and private royalties of US$0.73 per tonne (December 2016: US$0.67 per tonne). (2) H1 FY18 based on exchange rate of AUD/USD 0.78. South Flank feasibility study is progressing, with the project expected to be submitted for Board approval in the middle of the 2018 calendar year. The capital cost for the 80 Mtpa (100 per cent basis) sustaining mine is now expected to be around US$45 per tonne, reflecting a stronger Australian dollar and updated estimates as the project planning has progressed. The capital cost fits within WAIO’s previously indicated average sustaining capital expenditure of US$4 per tonne (plus or minus 50 per cent in any given year) over the medium term. The South Flank project, which will leverage and expand the existing Mining Area C hub, will increase WAIO’s average Fe grade from 61 per cent to 62 per cent and lump proportion for our overall product mix from approximately 25 per cent to 35 per cent, supporting WAIO’s ability to benefit from sustained higher premiums for lump and higher quality fines. Guidance for production and unit costs for the 2018 financial year is also detailed on page 3. Capital expenditure and project information is detailed on pages 4 and 5.

Financial information for Iron Ore for the December 2017 and December 2016 half years is presented below. Half year ended Net 31 December 2017 Underlying Underlying operating Capital Exploration Exploration US$M Revenue EBITDA D&A EBIT assets expenditure gross to profit Western Australia Iron Ore 7,117 4,265 873 3,392 19,959 446 Samarco(1) — — — — (1,025) — Other(2) 76 36 4 32 201 24 Total Iron Ore from Group production 7,193 4,301 877 3,424 19,135 470 Third party products(3) 28 6 — 6 — — Total Iron Ore 7,221 4,307 877 3,430 19,135 470 41 10 Adjustment for equity accounted investments — — — — — — — — Total Iron Ore statutory result 7,221 4,307 877 3,430 19,135 470 41 10 Half year ended Net 31 December 2016 Underlying Underlying operating Capital Exploration Exploration US$M Revenue EBITDA D&A EBIT assets expenditure gross to profit Western Australia Iron Ore 6,808 4,117 929 3,188 21,246 357 Samarco(1) — — — — (1,094) — Other(2) 75 31 3 28 160 58 Total Iron Ore from Group production 6,883 4,148 932 3,216 20,312 415 Third party products(3) 47 14 — 14 — — Total Iron Ore 6,930 4,162 932 3,230 20,312 415 50 50 Adjustment for equity accounted investments — — — — — — — Total Iron Ore statutory result 6,930 4,162 932 3,230 20,312 415 50 50 (1) Samarco is an equity accounted investment and its financial information presented above, with the exception of net operating assets, reflects BHP Billiton Brasil Ltda’s share. All financial impacts following the Samarco dam failure have been reported as exceptional items in both reporting periods. (2) Predominantly comprises divisional activities, towage services, business development and ceased operations. (3) Includes inter-segment and external sales of contracted gas purchases.

Coal Underlying EBITDA for the December 2017 half year decreased by US$221 million to US$1.8 billion. US$M Underlying EBITDA for the half year ended 31 December 2016 2,011 Net price impact(1) 137 Change in volumes: productivity (38) Change in controllable cash costs (191) Change in other costs: Exchange rates (99) Inflation (35) Other(2) 5 Underlying EBITDA for the half year ended 31 December 2017 1,790 (1) Average realised price: hard coking coal US$182/t (2016: US$179/t); weak coking coal US$121/t (2016: US$122/t); thermal coal US$87/t (2016: US$74/t). (2) Other includes: fuel and energy; asset sales; ceased and sold operations; other items (including profit from equity accounted investments). Metallurgical coal production decreased by four per cent to 20 Mt(x) as record production at four Queensland Coal mines was offset by lower volumes at Broadmeadow (roof conditions; expected to continue through the March 2018 quarter) and Blackwater (geotechnical issues triggered by wet weather). Guidance for the 2018 financial year has been reduced to between 41 and 43 Mt. Energy coal production increased by four per cent to 14 Mt(x) as a strong performance at New South Wales Energy Coal (NSWEC) was offset by the impacts of wet weather at Cerrejón. Controllable cash costs increased by US$191 million and includes: US$134 million – primarily reflects unfavourable fixed cost dilution from reduced volumes at Broadmeadow and Blackwater, and compensatory increased production from higher cost pits, at BHP Billiton Mitsubishi Alliance (BMA); and US$11 million—increased contractor activity partially offset by improved ultra-class truck productivity at NSWEC. Queensland Coal unit costs increased by 26 per cent to US$71 per tonne in the December 2017 half year, including the impact of a stronger Australian dollar. Unit costs for the 2018 financial year are now expected to be US$66 per tonne (based on an exchange rate of AUD/USD 0.75), an increase from previous guidance of US$59 per tonne, reflecting reduced Broadmeadow and Blackwater volumes, increased production from higher cost pits and rising inflationary pressures. Unit costs for the second half of the 2018 financial year are expected to be US$63 per tonne. In the medium term, we expect to lower our unit costs to approximately US$54 per tonne. NSWEC unit costs increased by four per cent to US$48 per tonne in the December 2017 half year due to the impact of a stronger Australian dollar. Unit cost guidance for the 2018 financial year remains unchanged at US$46 per tonne (based on an exchange rate of AUD/USD 0.75). In the medium term, we expect to lower our unit costs further to approximately US$40 per tonne. Queensland Coal unit costs (US$M) H1 FY18 H2 FY17 H1 FY17 FY17 Revenue 3,350 2,935 3,381 6,316 Underlying EBITDA 1,504 1,433 1,823 3,256 Gross costs 1,846 1,502 1,558 3,060 Less: freight 64 57 54 111 Less: royalties 321 296 335 631 Net costs 1,461 1,149 1,169 2,318 Sales (kt, equity share) 20,516 18,130 20,716 38,846 Cost per tonne (US$)(1) 71.21 63.38 56.43 59.67 (1) H1 FY18 based on an exchange rate of AUD/USD 0.78. Guidance for production and unit costs for the 2018 financial year is also detailed on page 3. Capital expenditure and project information is detailed on pages 4 and 5.

Financial information for Coal for the December 2017 and December 2016 half years is presented below. Half year ended Net 31 December 2017 Underlying Underlying operating Capital Exploration Exploration US$M Revenue EBITDA D&A EBIT assets expenditure gross to profit Queensland Coal 3,350 1,504 294 1,210 7,987 176 New Mexico — — — — — — New South Wales Energy Coal (2) 750 304 92 212 1,035 10 Colombia(2) 403 201 47 154 905 39 Other(3) — (53) 2 (55) (23) (1) Total Coal from Group production 4,503 1,956 435 1,521 9,904 224 Third party products — — — — — — Total Coal 4,503 1,956 435 1,521 9,904 224 7 7 Adjustment for equity accounted investments(4)(5) (456) (166) (81) (85) — (39) — — Total Coal statutory result 4,047 1,790 354 1,436 9,904 185 7 7 Half year ended Net 31 December 2016 Underlying Underlying operating Capital Exploration Exploration US$M Revenue EBITDA D&A EBIT assets expenditure gross to profit Queensland Coal 3,381 1,823 315 1,508 8,360 80 New Mexico(1) 3 (6) 3 (9) — 1 New South Wales Energy Coal (2) 584 187 77 110 1,120 5 Colombia(2) 364 180 49 131 875 19 Other(3) 8 (29) 4 (33) (20) 18 Total Coal from Group production 4,340 2,155 448 1,707 10,335 123 Third party products — — — — — — Total Coal 4,340 2,155 448 1,707 10,335 123 3 3 Adjustment for equity accounted investments(4)(5) (413) (144) (65) (79) — (20) — — Total Coal statutory result 3,927 2,011 383 1,628 10,335 103 3 3 (1) Includes the Navajo mine (divested in July 2016). (2) Newcastle Coal Infrastructure Group and Cerrejón are equity accounted investments and their financial information presented above, with the exception of net operating assets, reflects BHP’s share. (3) Predominantly comprises divisional activities and IndoMet Coal (divested in October 2016). (4) Total Coal statutory result Revenue excludes US$403 million (2016: US$364 million) revenue related to Cerrejón. Total Coal statutory result Underlying EBITDA includes US$47 million (2016: US$49 million) D&A and US$56 million (2016: US$57 million) net finance costs and taxation expense related to Cerrejón, that are also included in Underlying EBIT. Total Coal statutory result Capital expenditure excludes US$39 million (2016: US$19 million) related to Cerrejón. (5) Total Coal statutory result Revenue excludes US$53 million (2016: US$49 million) revenue related to Newcastle Coal Infrastructure Group. Total Coal statutory result excludes US$63 million (2016: US$38 million) Underlying EBITDA, US$34 million (2016: US$16 million) D&A and US$29 million (2016: US$22 million) Underlying EBIT related to Newcastle Coal Infrastructure Group until future profits exceed accumulated losses. Total Coal statutory result Capital expenditure excludes US$ nil (2016: US$1 million) related to Newcastle Coal Infrastructure Group.

Group and unallocated items Underlying EBITDA loss for Group and unallocated items increased by US$68 million to US$89 million in the December 2017 half year, as a strong performance at Nickel West was more than offset by increased corporate spend on technology projects and unfavourable exchange rate impacts on corporate provision balances. Nickel West’s Underlying EBITDA increased by 92 per cent to US$71 million for the December 2017 half year, predominantly due to higher prices and improved mill utilisation and concentrator recoveries.

The Financial Report on pages 27 to 48 has been prepared in accordance with IAS 34 ‘Interim Financial Reporting’. 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 December 2017 half year compared with the December 2016 half year, unless otherwise noted. Operations includes operated and non-operated assets, unless otherwise noted. The following abbreviations may have been used throughout this report: barrels (bbl); billion cubic feet (bcf); barrels of oil equivalent (boe); billion tonnes (Bt); 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 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 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 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. Underlying attributable profit is Profit after taxation attributable to owners of the BHP Group (also referred to as ‘Attributable profit’) excluding any exceptional items attributable to the owners of the BHP Group. Underlying EBITDA is Earnings before net finance costs, depreciation, amortisation and impairments, taxation expense, and exceptional items. Underlying EBITDA includes net finance costs and taxation expense, depreciation, amortisation and impairments related to equity accounted investments of US$318 million (2016: US$267 million) and excludes exceptional items of US$137 million (2016: US$48 million) related to share of loss from equity accounted investments. Underlying EBIT is Underlying EBITDA, including depreciation, amortisation and impairments of US$4,336 million for the December 2017 half year (2016: US$3,914 million). Underlying EBIT includes net finance costs and taxation expense of US$211 million (2016: US$156 million) related to equity accounted investments and excludes exceptional items of US$137 million (2016: US$48 million) related to share of loss from equity accounted investments. (iii) Further alternate performance measures are defined as follows: Adjusted effective tax rate – comprises Total taxation expense excluding exceptional items and exchange rate movements included in taxation expense divided by Profit 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 reporting periods. The method of calculation of the Principal factors that affect Underlying EBITDA is as follows: References to operation/s in each Principal factor excludes equity accounted investments which are included within ‘Other’. 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). 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) 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. (vii) Copper equivalent production based on 2017 financial year average realised prices. (viii) Balances relating to hedging derivatives of external debt included within net other financial assets/(liabilities) for the half year ended 31 December 2017 was US$0.1 billion (30 June 2017: US$(0.7) billion).The movement of US$0.8 billion includes a non-cash fair value adjustment of US$0.7 billion, which offsets in net debt, and US$0.1 billion of other cash movements. (ix) Maintenance capital includes non-discretionary spend for the following purposes: deferred development and production stripping; risk reduction, compliance and asset integrity. (x) 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. 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. BHP and its subsidiaries In this release, 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 as defined in note 28 ‘Subsidiaries’ in section 5.1 of BHP’s 30 June 2017 Annual Report on Form 20-F and in note 13 ‘Related undertaking of the Group’ in section 5.2 of BHP’s 30 June 2017 Annual Report on Form 20-F.

News Release 26 Further information on BHP can be found at: 33Tbhp.com Media Relations Email: [email protected] Investor Relations Email: [email protected] Australia and Asia Ben Pratt Tel: +61 3 9609 3672 Mobile: +61 419 968 734 United Kingdom and South Africa Neil Burrows Tel: +44 20 7802 7484 Mobile: +44 7786 661 683 North America Judy Dane Tel: +1 713 961 8283 | Mobile: +1 713 299 5342 Australia and Asia Tara Dines Tel: +61 3 9609 2222 Mobile: +61 499 249 005 United Kingdom and South Africa Rob Clifford Tel: +44 20 7802 4131 Mobile: +44 7788 308 844 Americas James Wear Tel: +1 713 993 3737 Mobile: +1 347 882 3011 BHP Billiton Limited ABN 49 004 028 077 LEI WZE1WSENV6JSZFK0JC28 Registered in Australia Registered Office: Level 18, 171 Collins Street Melbourne Victoria 3000 Australia Tel +61 1300 55 4757 Fax +61 3 9609 3015 BHP Billiton Plc Registration number 3196209 LEI 549300C116EOWV835768 Registered in England and Wales Registered Office: Nova South, 160 Victoria Street London SW1E 5LB United Kingdom Tel +44 20 7802 4000 Fax +44 20 7802 4111

BHP Financial Report Half year ended 31 December 2017

Financial Report 28 Contents Half Year Financial Statements Page Consolidated Income Statement for the half year ended 31 December 2017 29 Consolidated Statement of Comprehensive Income for the half year ended 31 December 2017 29 Consolidated Balance Sheet as at 31 December 2017 30 Consolidated Cash Flow Statement for the half year ended 31 December 2017 31 Consolidated Statement of Changes in Equity for the half year ended 31 December 2017 32 Notes to the Financial Information 33 33T1. Basis of preparation 33 33T2. Exceptional items 34 33T3. Interests in associates and joint venture entities 35 33T4. Net finance costs 35 33T5. Income tax expense 36 33T6. Deferred tax balances 37 33T7. Earnings per share 38 33T8. Dividends 38 33T9. Financial risk management Fair values 39 33T10. Significant events Samarco dam failure 42 33T11. Impairment of non current assets Onshore US 47 33T12. Subsequent events 48 Directors’ Report 49 Directors’ Declaration of Responsibility 51 Lead Auditor’s Independence Declaration under Section 307C of the Corporations Act 2001 52 Independent Review Report 53

Consolidated Income Statement for the half year ended 31 December 2017 Half year Half year Year ended ended ended 31 Dec 31 Dec 30 June 2017 2016 2017 Notes US$M US$M US$M Revenue 21,779 18,796 38,285 Other income 137 510 736 Expenses excluding net finance costs (15,393) (13,387) (27,540) Profit from equity accounted investments and related expenses 3 213 138 272 Profit from operations 6,736 6,057 11,753 Financial expenses (749) (639) (1,574) Financial income 79 62 143 Net finance costs 4 (670) (577) (1,431) Profit before taxation 6,066 5,480 10,322 Income tax expense (3,448) (1,902) (3,933) Royalty-related taxation (net of income tax benefit) (44) (126) (167) Total taxation expense 5 (3,492) (2,028) (4,100) Profit after taxation 2,574 3,452 6,222 Attributable to non-controlling interests 559 248 332 Attributable to BHP shareholders 2,015 3,204 5,890 Basic earnings per ordinary share (cents) 7 37.9 60.2 110.7 Diluted earnings per ordinary share (cents) 7 37.7 60.0 110.4 Dividends per ordinary share – paid during the period (cents) 8 43.0 14.0 54.0 Dividends per ordinary share – determined in respect of the period (cents) 8 55.0 40.0 83.0 The accompanying notes form part of this financial information. Consolidated Statement of Comprehensive Income for the half year ended 31 December 2017 Half year Half year Year ended ended ended 31 Dec 31 Dec 30 June 2017 2016 2017 US$M US$M US$M Profit after taxation 2,574 3,452 6,222 Other comprehensive income Items that may be reclassified subsequently to the income statement: Available for sale investments: Net valuation gains/(losses) taken to equity 10 1 (1) Cash flow hedges: Gains/(losses) taken to equity 666 (666) 351 (Gains)/losses transferred to the income statement (623) 586 (432) Exchange fluctuations on translation of foreign operations taken to equity (1) 1 (1) Tax recognised within other comprehensive income (15) 21 24 Total items that may be reclassified subsequently to the income statement 37 (57) (59) Items that will not be reclassified to the income statement: Remeasurement gains/(losses) on pension and other post-retirement obligations 2 (18) 36 Tax recognised within other comprehensive income (3) (12) (26) Total items that will not be reclassified to the income statement (1) (30) 10 Total other comprehensive income/(loss) 36 (87) (49) Total comprehensive income 2,610 3,365 6,173 Attributable to non-controlling interests 561 246 332 Attributable to BHP shareholders 2,049 3,119 5,841 The accompanying notes form part of this financial information.

Consolidated Balance Sheet as at 31 December 2017 31 Dec 2017 30 June 2017 Notes US$M US$M ASSETS Current assets Cash and cash equivalents 12,322 14,153 Trade and other receivables 3,542 2,836 Other financial assets 51 72 Inventories 4,020 3,673 Current tax assets 97 195 Other 111 127 Total current assets 20,143 21,056 Non-current assets Trade and other receivables 319 803 Other financial assets 1,501 1,281 Inventories 1,019 1,095 Property, plant and equipment 78,849 80,497 Intangible assets 3,873 3,968 Investments accounted for using the equity method 2,456 2,448 Deferred tax assets 6 4,355 5,788 Other 67 70 Total non-current assets 92,439 95,950 Total assets 112,582 117,006 LIABILITIES Current liabilities Trade and other payables 5,999 5,551 Interest bearing liabilities 2,033 1,241 Other financial liabilities 217 394 Current tax payable 1,438 2,119 Provisions 1,780 1,959 Deferred income 63 102 Total current liabilities 11,530 11,366 Non-current liabilities Trade and other payables 6 5 Interest bearing liabilities 25,700 29,233 Other financial liabilities 633 1,106 Non-current tax payable 2 134 — Deferred tax liabilities 6 3,526 3,765 Provisions 8,542 8,445 Deferred income 350 360 Total non-current liabilities 38,891 42,914 Total liabilities 50,421 54,280 Net assets 62,161 62,726 EQUITY Share capital – BHP Billiton Limited 1,186 1,186 Share capital – BHP Billiton Plc 1,057 1,057 Treasury shares (8) (3) Reserves 2,391 2,400 Retained earnings 52,351 52,618 Total equity attributable to BHP shareholders 56,977 57,258 Non-controlling interests 5,184 5,468 Total equity 62,161 62,726 The accompanying notes form part of this financial information.

Consolidated Cash Flow Statement for the half year ended 31 December 2017 Half year Half year Year ended ended ended 31 Dec 31 Dec 30 June 2017 2016 2017 US$M US$M US$M Operating activities Profit before taxation 6,066 5,480 10,322 Adjustments for: Non-cash or non-operating exceptional items 183 (48) 350 Depreciation and amortisation expense 4,037 3,800 7,719 Impairments of property, plant and equipment, financial assets and intangibles 299 114 188 Net finance costs 626 511 1,304 Share of operating profit of equity accounted investments (350) (186) (444) Other 307 67 290 Changes in assets and liabilities: Trade and other receivables (702) (638) 315 Inventories (271) (505) (679) Trade and other payables 297 28 337 Provisions and other assets and liabilities (107) (138) (325) Cash generated from operations 10,385 8,485 19,377 Dividends received 370 340 636 Interest received 80 77 164 Interest paid (558) (534) (1,149) Settlement of cash management related instruments (275) — (140) Net income tax and royalty-related taxation refunded 39 353 501 Net income tax and royalty-related taxation paid (2,698) (1,024) (2,585) Net operating cash flows 7,343 7,697 16,804 Investing activities Purchases of property, plant and equipment (2,413) (2,288) (4,252) Exploration expenditure (464) (439) (968) Exploration expenditure expensed and included in operating cash flows 192 292 612 Net investment and funding of equity accounted investments 271 (168) (234) Proceeds from sale of assets 107 541 648 Proceeds from divestment of subsidiaries, operations and joint operations, net of their cash — 189 186 Other investing (139) (49) (153) Net investing cash flows (2,446) (1,922) (4,161) Financing activities Proceeds from interest bearing liabilities 500 1,200 1,577 (Settlements)/proceeds from debt related instruments (227) — 36 Repayment of interest bearing liabilities (4,010) (2,200) (7,120) Distributions to non-controlling interests (6) (8) (16) Purchase of shares by Employee Share Ownership Plan (ESOP) Trusts (96) (68) (108) Dividends paid (2,276) (748) (2,921) Dividends paid to non-controlling interests (944) (300) (581) Net financing cash flows (7,059) (2,124) (9,133) Net (decrease)/increase in cash and cash equivalents (2,162) 3,651 3,510 Cash and cash equivalents, net of overdrafts, at the beginning of period 14,108 10,276 10,276 Foreign currency exchange rate changes on cash and cash equivalents 331 1 322 Cash and cash equivalents, net of overdrafts, at end of period 12,277 13,928 14,108 The accompanying notes form part of this financial information.

Consolidated Statement of Changes in Equity for the half year ended 31 December 2017 Attributable to BHP shareholders Share capital Treasury shares Total equity BHP BHP BHP BHP attributable Non- Billiton Billiton Billiton Billiton Retained to BHP controlling Total Limited Plc Limited Plc Reserves earnings shareholders interests equity Balance as at 1 July 2017 1,186 1,057 (2) (1) 2,400 52,618 57,258 5,468 62,726 Total comprehensive income — — — — 35 2,014 2,049 561 2,610 Transactions with owners: Purchase of shares by ESOP Trusts — — (87) (9) — — (96) — (96) Employee share awards exercised net of employee contributions — — 81 10 (100) 9 — — — Employee share awards forfeited — — — — (1) 1 — — — Accrued employee entitlement for unexercised awards — — — — 57 — 57 — 57 Distribution to non-controlling interests — — — — — — — (6) (6) Dividends — — — — — (2,291) (2,291) (839) (3,130) Balance as at 31 December 2017 1,186 1,057 (8) — 2,391 52,351 56,977 5,184 62,161 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 — — — — (57) 3,176 3,119 246 3,365 Transactions with owners: Purchase of shares by ESOP Trusts — — (66) (2) — — (68) — (68) Employee share awards exercised net of employee contributions and other adjustments — — 69 21 (119) 29 — — — Employee share awards forfeited — — — — (17) 17 — — — Accrued employee entitlement for unexercised awards — — — — 51 — 51 — 51 Distribution to non-controlling interests — — — — — — — (8) (8) Dividends — — — — — (743) (743) (215) (958) Divestment of subsidiaries, operations and joint operations — — — — — — — (28) (28) Balance as at 31 December 2016 1,186 1,057 (4) (7) 2,396 52,021 56,649 5,776 62,425 The accompanying notes form part of this financial information.

Notes to the Financial Information 1. Basis of preparation This general purpose financial report for the half year ended 31 December 2017 is unaudited and has been prepared in accordance with IAS 34 ‘Interim Financial Reporting’ as issued by the International Accounting Standards Board (IASB) and as adopted by the European Union (EU), AASB 134 ‘Interim Financial Reporting’ as issued by the Australian Accounting Standards Board (AASB) and the Disclosure and Transparency Rules of the Financial Conduct Authority in the United Kingdom and the Australian Corporations Act 2001 as applicable to interim financial reporting. The half year financial statements represent a ‘condensed set of financial statements’ as referred to in the UK Disclosure and Transparency Rules issued by the Financial Conduct Authority. Accordingly, they do not include all of the information required for a full annual report and are to be read in conjunction with the most recent annual financial report. The comparative figures for the financial year ended 30 June 2017 are not the statutory accounts of the Group for that financial year. Those accounts, which were prepared under IFRS, have been reported on by the Company’s auditor and delivered to the registrar of companies. The auditor has reported on those accounts; the report was unqualified, did not include a reference to any matters to which the auditors drew attention by way of emphasis without qualifying their report and did not contain statements under Section 498 (2) or (3) of the UK Companies Act 2006. The half year financial statements have been prepared on the basis of the accounting policies and methods of computation consistent with those applied in the 30 June 2017 annual financial statements contained within the Annual Report of the Group. The directors have made an assessment of the Group’s ability to continue as a going concern and consider it appropriate to adopt the going concern basis of accounting in preparing the half year financial statements. The following new significant accounting standards are not yet effective, but may have an impact on the Group in financial years commencing on or after 1 January 2018: Application date for the Application date financial year Title of standard Summary of impact on the Financial Statements of standard commencing IFRS 15/AASB 15 Initial implementation activities focused on understanding the 1 January 2018 1 July 2018 ‘Revenue from standard contractual arrangements across the Group’s principal Contracts with revenue streams, particularly key terms and conditions which Customers’ may impact revenue recognition. During FY2018, detailed reviews of individual contracts across the Group’s key commodities has commenced. To date, no significant measurement differences have been identified in addition to those outlined in the Group’s Annual Report for the year ended 30 June 2017. IFRS 9/AASB 9 Implementation activities to date have focused on the Group’s 1 January 2018 1 July 2018 ‘Financial Treasury and Marketing operations, which hold the majority of Instruments’ the Group’s financial instruments. During FY2018, detailed analysis has commenced focusing on changes to the calculation of credit loss provisions on financial assets, with no significant impacts being identified to date. Application of the revised hedge accounting model and other impacts of the standard continue to be assessed. IFRS 16/AASB 16 A detailed review of contracts has commenced to identify leases 1 January 2019 1 July 2019 ‘Leases’ and support the quantification of financial impacts. An assessment of likely system requirements and processes is ongoing. In addition to the above, other accounting standards, amendments and interpretations that have been issued and will be applicable in future periods are subject to ongoing assessment, however no significant impacts have been identified to date. These standards have not been applied in the preparation of these half year financial statements. All amounts are expressed in US dollars unless otherwise stated. The Group’s presentation currency and the functional currency of the majority of its operations is US dollars as this is the principal currency of the economic environment in which it operates. Amounts in this financial information have, unless otherwise indicated, been rounded to the nearest million dollars.

2. Exceptional items Exceptional items are those gains or losses where their nature, including the expected frequency of the events giving rise to them, and amount is considered material to the Financial Statements. Such items included within the Group’s profit for the half year are detailed below: Gross Tax Net Half year ended 31 December 2017 US$M US$M US$M Exceptional items by category Samarco dam failure (210) — (210) US tax reform — (1,828) (1,828) Total (210) (1,828) (2,038) Attributable to non-controlling interests — — — Attributable to BHP shareholders (210) (1,828) (2,038) Samarco Mineração SA (Samarco) dam failure The exceptional loss of US$210 million related to the Samarco dam failure in November 2015 comprises the following: Half year ended 31 December 2017 US$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 (29) Loss from equity accounted investments and related expenses: Share of loss relating to the Samarco dam failure (50) Samarco dam failure provision (87) Net finance costs (44) Total (1) (210) (1) Refer to note 10 Significant events – Samarco dam failure for further information. US tax reform On 22 December 2017, the US President signed the Tax Cuts and Jobs Act (the TCJA) into law. The TCJA (effective 1 January 2018) includes a broad range of tax reforms affecting the Group, including, but not limited to, a reduction in the US corporate tax rate from 35 per cent to 21 per cent and changes to international tax provisions. Following enactment of the TCJA, the Group has recognised an exceptional income tax charge of US$1,828 million, primarily relating to the reduced US corporate income tax rate, which resulted in re-measurement of the Group’s deferred tax position and impairment of foreign tax credits due to reduced forecast utilisation, together with tax charges on the deemed repatriation of accumulated earnings of non-US subsidiaries. Half year ended 31 December 2017 US$M Re-measurement of deferred taxes as a result of reduced US corporate income tax rate (898) Impairment of foreign tax credits (834) Net impact of tax charges on deemed repatriation of accumulated earnings of non-US subsidiaries(1) (194) Recognition of Alternative Minimum Tax Credits 95 Other impacts 3 Total (2) (1,828) (1) Includes US$(134) million to be settled over a period greater than 12 months and classified as a non-current tax payable on the face of the balance sheet. (2) Refer to note 5 Income tax expense for further information. Gross Tax Net Half year ended 31 December 2016 US$M US$M US$M Exceptional items by category Samarco dam failure (155) — (155) Cancellation of the Caroona exploration licence 164 (49) 115 Total 9 (49) (40) Attributable to non-controlling interests — — — Attributable to BHP shareholders 9 (49) (40)

2. Exceptional items (continued) Gross Tax Net Year ended 30 June 2017 US$M US$M US$M Exceptional items by category Samarco dam failure (381) — (381) Escondida industrial action (546) 179 (367) Cancellation of the Caroona exploration licence 164 (49) 115 Withholding tax on Chilean dividends — (373) (373) Total (763) (243) (1,006) Attributable to non-controlling interests – Escondida industrial action (232) 68 (164) Attributable to BHP shareholders (531) (311) (842) 3. Interests in associates and joint venture entities The Group’s major shareholdings in associates and joint venture entities, including their profit/(loss), are listed below: Ownership interest at the Group’s reporting Profit/(loss) from equity accounted investments date(1) and related expenses Half year Half year 31 Dec 31 Dec 30 June ended ended Year ended 2017 2016 2017 31 Dec 2017 31 Dec 2016 30 June 2017 % % % US$M US$M US$M Share of operating profit/(loss) of equity accounted investments: Carbones del CerrejÏŒn LLC 33.33 33.33 33.33 87 64 129 Compañia Minera Antamina SA 33.75 33.75 33.75 282 138 341 Samarco Mineração SA (2)(3) 50.00 50.00 50.00 (50) (61) (134) Other (19) (16) (26) Share of operating profit of equity accounted investments 300 125 310 Samarco dam failure provision (expense)/release(2) (87) 13 (38) Profit from equity accounted investments and related expenses 213 138 272 (1) The ownership interest at the Group’s and the associates and joint venture entities’ reporting dates are the same. (2) Refer to note 10 Significant events – Samarco dam failure for further information. Financial impact of US$(210) million from the Samarco dam failure relates to US$(50) million share of loss from US$(50) million funding provided during the period, US$(29) million direct costs incurred by BHP Billiton Brasil Ltda and other BHP entities, US$(44) million amortisation of discounting impacting net finance costs and US$(87) million other movements in the Samarco dam failure provision including foreign exchange. (3) As the carrying value has been previously written down to US$ nil, any additional share of Samarco’s losses are only recognised to the extent BHP Billiton Brasil Ltda has an obligation to fund the losses or investment funding is provided. BHP Billiton Brasil Ltda has provided US$(50) million funding during the period and recognised additional share of losses of US$(50) million. 4. Net finance costs Half year Half year Year ended ended ended 31 Dec 31 Dec 30 June 2017 2016 2017 US$M US$M US$M Financial expenses Interest on bank loans, overdrafts and all other borrowings 558 558 1,131 Interest capitalised at 3.86% (30 June 2017: 3.25%; 31 December 2016: 3.08%)(1) (59) (53) (113) Discounting on provisions and other liabilities 223 238 462 Fair value change on hedged loans 93 (1,133) (1,185) Fair value change on hedging derivatives (26) 1,020 1,244 Exchange variations on net debt (75) (4) (23) Other financial expenses 35 13 58 749 639 1,574 Financial income Interest income (79) (62) (143) Net finance costs 670 577 1,431 (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.

5. Income tax expense Half year Half year ended ended 31 Dec 31 Dec Year ended 2017 2016 30 June 2017 US$M US$M US$M Total taxation expense comprises: Current tax expense 2,331 1,956 4,288 Deferred tax expense/(benefit) 1,161 72 (188) 3,492 2,028 4,100 Half year Half year ended ended 31 Dec 31 Dec Year ended 2017 2016 30 June 2017 US$M US$M US$M Factors affecting income tax expense for the period Income tax expense differs to the standard rate of corporation tax as follows: Profit before taxation 6,066 5,480 10,322 Tax on profit at Australian prima facie tax rate of 30 per cent 1,820 1,644 3,097 Impact of US tax reform Tax on remitted and unremitted foreign earnings (1) 194 — — Non-tax effected operating losses and capital gains 834 — — Tax rate changes 898 — — Recognition of previously unrecognised tax assets (95) — — Other (3) — — Subtotal 1,828 — — Other items not related to US tax reform Tax on remitted and unremitted foreign earnings 221 9 478 Non-tax effected operating losses and capital gains 81 101 259 Tax rate changes 16 4 25 Amounts (over)/under provided in prior years (26) 130 199 Tax effect of profit from equity accounted investments and related expenses (2) (64) (41) (82) Investment and development allowance (81) (58) (53) Foreign exchange adjustments (98) 82 88 Impact of tax rates applicable outside of Australia (280) (81) (189) Recognition of previously unrecognised tax assets (24) (18) (106) Other 55 130 217 Income tax expense 3,448 1,902 3,933 Royalty-related taxation (net of income tax benefit) 44 126 167 Total taxation expense 3,492 2,028 4,100 (1) Comprising US$797 million repatriation tax and US$603 million of previously unrecognised tax credits. (2) The profit from equity accounted investments and related expenses is net of income tax. This item removes the prima facie tax effect on such profits and related expenses. 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. US tax reform As per note 2 – Exceptional items, the impact of the TCJA has been included in the Financial Statements. The TCJA includes a number of complex provisions, the application of which are potentially subject to further implementation and regulatory guidance, and possible elections. Judgements are required about the application of the TCJA and its interaction with income tax accounting principles.

5. Income tax expense (continued) Key judgements and estimates The Group has made preliminary determinations, based on currently available implementation guidance. However, judgements made are subject to risk and uncertainty, hence there is a possibility that changes in circumstances or future regulatory guidance may alter the judgements made, which may potentially impact the amount of deferred or current taxes recognised on the balance sheet and the amount of other tax balances not yet recognised. The significant judgements and estimates include: The TCJA requires mandatory deemed repatriation of post-1986 undistributed earnings and profits from specific non-US subsidiaries. In assessing the potential tax charge, the Group has made certain assumptions as to offsets available under the TCJA, including the use of available foreign tax credits to partially offset the deemed repatriation tax liability. The US will continue to tax foreign income from partnerships on a worldwide basis with the ability to offset US tax liabilities on foreign earnings with a credit for taxes paid in foreign jurisdictions. The reduction in the US corporate tax rate and the revised differential in tax rates with other jurisdictions impacts the forecasted utilisation of these foreign tax credits. The Group has made certain assumptions as to the utilisation of available foreign tax credits based on an assessment of probable future US income tax. Where further clarifying regulatory guidance is issued, this may potentially impact the assumptions made and result in a different outcome. 6. Deferred tax balances The movement for the period in the Group’s net deferred tax position is as follows: 31 Dec 2017 31 Dec 2016 30 June 2017 US$M US$M US$M Net deferred tax asset At the beginning of the period 2,023 1,823 1,823 Income tax (charge)/credit recorded in the income statement (1,161) (72) 188 Income tax (charge)/credit recorded directly in equity (13) 22 12 Other movement (20) 48 — At the end of the period 829 1,821 2,023 For recognition and measurement refer to note 5 Income tax expense. The composition of the Group’s net deferred tax assets and liabilities recognised in the balance sheet and the deferred tax expense charged/(credited) to the income statement is as follows: Charged/(credited) to the income Deferred tax assets Deferred tax liabilities statement Half year Half year 31 Dec 30 June 31 Dec 30 June ended ended Year ended 2017 2017 2017 2017 31 Dec 2017 31 Dec 2016 30 June 2017 US$M US$M US$M US$M US$M US$M US$M Type of temporary difference Depreciation (2,555) (3,454) 1,384 1,411 (925) 161 391 Exploration expenditure 515 543 — — 28 (60) (22) Employee benefits 309 379 (2) 3 64 1 (37) Closure and rehabilitation 1,614 1,809 (206) (230) 218 20 (151) Resource rent tax 491 559 1,441 1,614 (104) (99) (189) Other provisions 126 131 (1) (1) 4 1 14 Deferred income (15) (2) (1) (10) 22 5 3 Deferred charges (405) (443) 285 322 (76) (38) (77) Investments, including foreign tax credits 660 1,145 600 648 418 46 (17) Foreign exchange gains and losses (78) (87) 36 69 (43) (30) (77) Tax losses 3,784 5,352 — — 1,569 (256) (381) Other (91) (144) (10) (61) (14) 321 355 Total 4,355 5,788 3,526 3,765 1,161 72 (188) The Group had unrecognised deferred tax assets of US$1,682 million at 31 December 2017 (30 June 2017: US$856 million) and unrecognised deferred tax liabilities of US$2,318 million (30 June 2017: US$2,500 million) associated with investments in subsidiaries. The Group’s unrecognised deferred tax assets increased by US$834 million and unrecognised deferred tax liabilities decreased by US$192 million due to the impact of US tax reform at 31 December 2017.

7. Earnings per share Half year Half year Year ended ended ended 31 Dec 31 Dec 30 June 2017 2016 2017 Earnings attributable to BHP shareholders (US$M) 2,015 3,204 5,890 Weighted average number of shares—Basic (Million)(1) 5,323 5,322 5,323 Weighted average number of shares—Diluted (Million)(2) 5,338 5,336 5,336 Basic earnings per ordinary share (US cents)(3) 37.9 60.2 110.7 Diluted earnings per ordinary share (US cents)(3) 37.7 60.0 110.4 (1) The calculation of the number of ordinary shares used in the computation of basic earnings per share is the aggregate of the weighted average number of ordinary shares of BHP Billiton Limited and BHP Billiton Plc outstanding during the period after deduction of the number of shares held by the Billiton Employee Share Ownership Plan Trust and the BHP Billiton Limited Employee Equity Trust. (2) For the purposes of calculating diluted earnings per share, the effect of 15 million of dilutive shares has been taken into account for the half year ended 31 December 2017 (31 December 2016: 14 million shares; 30 June 2017: 13 million shares). The Group’s only potential dilutive ordinary shares are share awards granted under employee share ownership plans. Diluted earnings per share calculation excludes instruments which are considered antidilutive. At 31 December 2017, there are no instruments which are considered antidilutive (31 December 2016: nil; 30 June 2017: nil). (3) Each American Depositary Share represents twice the earnings for BHP ordinary shares. 8. Dividends Half year ended Half year ended Year ended 31 Dec 2017 31 Dec 2016 30 June 2017 Per share Total Per share Total Per share Total US cents US$M US cents US$M US cents US$M Dividends paid during the period(1) Prior year final dividend 43.0 2,291 14.0 749 14.0 749 Interim dividend N/A — N/A — 40.0 2,130 43.0 2,291 14.0 749 54.0 2,879 (1) 5.5 per cent dividend on 50,000 preference shares of L1 each determined and paid annually (31 December 2016: 5.5 per cent; 30 June 2017: 5.5 per cent). Subsequent to the half year ended 31 December 2017, on 20 February 2018, BHP Billiton Limited and BHP Billiton Plc determined an interim dividend of 55 US cents per share (US$2,928 million), which will be paid on 27 March 2018. At 31 December 2017, BHP Billiton Limited had 3,211 million ordinary shares on issue and held by the public and BHP Billiton Plc had 2,112 million ordinary shares on issue and held by the public. No shares in BHP Billiton Limited were held by BHP Billiton Plc at 31 December 2017 (31 December 2016: nil, 30 June 2017: nil). Dividends paid during the period differs from the amount of dividends paid in the Cash Flow Statement as a result of foreign exchange gains and losses relating to the timing of equity distributions between the record date and the payment date. The Dual Listed Company merger terms require that ordinary shareholders of BHP Billiton Limited and BHP Billiton Plc are paid equal cash dividends on a per share basis. Each American Depositary Share (ADS) represents two ordinary shares of BHP Billiton Limited or BHP Billiton Plc. Dividends determined on each ADS represent twice the dividend determined on BHP ordinary shares. BHP Billiton Limited dividends for all periods presented are, or will be, fully franked based on a tax rate of 30 per cent.

9. Financial risk management – Fair values All financial assets and financial 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, as indicated in the tables below. Derivatives are initially recognised at fair value on the date the contract is entered into and are subsequently remeasured at their fair value. 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 Based on inputs other than Based on inputs not (unadjusted) in active quoted prices included observable in the market markets for identical within Level 1 that are using appropriate valuation financial assets and observable for the financial models, including liabilities. asset or liability, either discounted cash flow directly (i.e. as unquoted modelling. prices) or indirectly (i.e. derived from prices). The financial assets and liabilities are presented by class in the tables below at their carrying values, which generally approximate to fair value. In the case of US$3,019 million (30 June 2017: US$3,019 million) of fixed rate debt not swapped to floating rate, the fair value at 31 December 2017 was US$3,684 million (30 June 2017: US$3,523 million) included within Notes and debentures in the table below. 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 is categorised as Level 2.

9. Financial risk management – Fair values (continued) Financial assets and liabilities Other financial Held at fair assets and 31 December 2017 Loans and Available for value through Cash flow liabilities at US$M receivables sale securities profit or loss hedges amortised cost Total Fair value hierarchy (1) Level 3 Levels 1,2 & 3 Level 2 Current cross currency and interest rate swaps — — 6 — — 6 Current other derivative contracts (2)(6) — — 23 7 — 30 Current available for sale shares and other investments(3) — — 15 — — 15 Non-current cross currency and interest rate swaps — — 869 (47) — 822 Non-current other derivative contracts (2)(6) — — 254 1 — 255 Non-current available for sale shares and other investments(3)(4) — 80 344 — — 424 Total other financial assets — 80 1,511 (39) — 1,552 Cash and cash equivalents 12,322 — — — — 12,322 Trade and other receivables (5) 2,011 — 1,406 — — 3,417 Loans to equity accounted investments 144 — — — — 144 Total financial assets 14,477 80 2,917 (39) — 17,435 Non-financial assets 95,147 Total assets 112,582 Current cross currency and interest rate swaps — — 190 (102) — 88 Current other derivative contracts (2) — — 129 — — 129 Non-current cross currency and interest rate swaps — — 391 238 — 629 Non-current other derivative contracts (2) — — 3 1 — 4 Total other financial liabilities — — 713 137 — 850 Trade and other payables(7) — — 386 — 5,471 5,857 Bank overdrafts and short-term borrowings (8) — — — — 45 45 Bank loans(8) — — — — 2,656 2,656 Notes and debentures (8) — — — — 24,063 24,063 Finance leases — — — — 857 857 Other(8) — — — — 112 112 Total financial liabilities — — 1,099 137 33,204 34,440 Non-financial liabilities 15,981 Total liabilities 50,421

9. Financial risk management – Fair values (continued) Financial assets and liabilities Other financial Held at fair assets and 30 June 2017 Loans and Available for value through Cash flow liabilities at US$M receivables sale securities profit or loss hedges amortised cost Total Fair value hierarchy (1) Level 3 Levels 1,2 & 3 Level 2 Current cross currency and interest rate swaps — — — — — — 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 — — — — 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 (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$268 million (30 June 2017: US$365 million) categorised as Level 3. (3) Includes other investments held at fair value through profit or loss (US Treasury Notes) of US$115 million categorised as Level 1 (30 June 2017: US$97 million). (4) Includes shares and other investments available for sale of US$80 million (30 June 2017: US$70 million) categorised as Level 3. (5) Excludes input taxes of US$300 million (30 June 2017: US$262 million) included in other receivables. (6) Includes net assets of US$7 million (30 June 2017: net liabilities of US$7 million) natural gas futures contracts used by the Group to mitigate price risk designated as cash flow hedges. (7) Excludes input taxes of US$148 million (30 June 2017: US$134 million) included in other payables. (8) All interest bearing liabilities, excluding finance leases, are unsecured.

9. Financial risk management – Fair values (continued) Sensitivity of level 3 financial assets and liabilities Financial instruments categorised as level 3 are shares and other investments available for sale and other derivative contracts with a carrying net amount of US$348 million (30 June 2017: US$435 million). Significant items are derivatives embedded in physical commodity purchase and sales contracts of gas in Trinidad and Tobago with a net assets fair value of US$272 million (30 June 2017: US$370 million). The potential effect of using reasonably possible alternative assumptions in these models, based on a change in the most significant input, commodity prices, by an increase/(decrease) of 10 per cent while holding all other variables constant will increase/(decrease) profit after taxation by US$50 million (30 June 2017: US$62 million). 10. Significant events – Samarco dam failure On 5 November 2015, the Samarco Mineração S.A. (Samarco) iron ore operation in Minas Gerais, Brazil, experienced a tailings dam failure that resulted in a release of mine tailings, flooding the communities of Bento Rodrigues, Gesteira and Paracatu and impacting other communities downstream (the Samarco dam failure). Samarco is jointly owned by BHP Billiton Brasil Ltda (BHP Billiton Brasil) and Vale S.A. (Vale). BHP Billiton Brasil’s 50 per cent interest is accounted for as an equity accounted joint venture investment. BHP Billiton Brasil does not separately recognise its share of the underlying assets and liabilities of Samarco, but instead records the investment as one line on the balance sheet. Each period, BHP Billiton Brasil recognises its 50 per cent share of Samarco’s profit or loss and adjusts the carrying value of the investment in Samarco accordingly. Such adjustment continues until the investment carrying value is reduced to US$ 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 half year ended 31 December 2017 are shown in the table below and have been treated as an exceptional item. Half year Half year Year ended ended ended 31 Dec 31 Dec 30 June 2017 2016 2017 Financial impacts of Samarco dam failure US$M US$M US$M Income statement Expenses excluding net finance costs: Costs incurred directly by BHP Billiton Brasil and other BHP entities in relation to the Samarco dam failure(1)(2) (29) (41) (82) Loss from equity accounted investments and related expenses: Share of loss relating to the Samarco dam failure(2) (50) (61) (134) Samarco dam failure provision(2) (87) 13 (38) Loss from operations (166) (89) (254) Net finance costs (44) (66) (127) Loss before taxation (210) (155) (381) Income tax benefit — — — Loss after taxation (210) (155) (381) Balance sheet movement Trade and other payables (2) (2) (3) Provisions 25 97 143 Net assets 23 95 140

10. Significant events – Samarco dam failure (continued) Half year ended Half year ended Year ended 31 Dec 2017 31 Dec 2016 30 June 2017 US$M US$M US$M Cash flow statement Loss before taxation (210) (155) (381) Comprising: Costs incurred directly by BHP Billiton Brasil and other BHP entities in relation to the Samarco dam failure(1)(2) (29) (41) (82) Share of loss relating to the Samarco dam failure(2) (50) (61) (134) Samarco dam failure provision(2) (87) 13 (38) Net finance costs (44) (66) (127) Non-cash or non-operating exceptional items 183 116 302 Net operating cash flows (27) (39) (79) Net investment and funding of equity accounted investments(3) (206) (211) (442) Net investing cash flows (206) (211) (442) Net decrease in cash and cash equivalents (233) (250) (521) (1) Includes legal and advisor costs incurred. (2) Financial impacts of US$(210) million from the Samarco dam failure relates to US$(50) million share of loss from US$(50) million funding provided during the period, US$(29) million direct costs incurred by BHP Billiton Brasil Ltda and other BHP entities, US$(44) million amortisation of discounting impacting net finance costs and US$(87) million other movements in the Samarco dam failure provision including foreign exchange. (3) Includes US$(50) million funding provided during the period and US$(156) million utilisation of the Samarco dam failure provision, of which US$(154) million allowed for the continuation of reparatory and compensatory programs in relation to the Framework Agreement and a further US$(2) million for dam stabilisation. Equity accounted investment in Samarco BHP Billiton Brasil’s investment in Samarco remains at US$ nil. BHP Billiton Brasil provided US$50 million funding under a working capital facility during the period and recognised additional share of losses of US$50 million. No dividends have been received by BHP Billiton Brasil from Samarco during the period. Samarco currently does not have profits available for distribution and is legally prevented from paying previously declared and unpaid dividends. Provision for Samarco dam failure 31 Dec 2017 30 June 2017 US$M US$M At the beginning of the reporting period 1,057 1,200 Movement in provision (25) (143) Comprising: Utilised (156) (308) Adjustments charged to the income statement: Amortisation of discounting impacting net finance costs 44 127 Other(1) 87 38 At the end of the reporting period 1,032 1,057 Comprising: Current 331 310 Non-current 701 747 At the end of the reporting period 1,032 1,057 (1) US$87 million relates to other movements in the Samarco dam failure provision including foreign exchange.

10. Significant events – Samarco dam failure (continued) Dam failure provisions and contingencies As at 31 December 2017, provisions and contingent liabilities for BHP Billiton Brasil are not materially different from those disclosed in note 3 ‘Significant events – Samarco dam failure’ in the 30 June 2017 Annual Report, subject to the updates set out below: 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 Espĺrito 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. 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 31 December 2017, BHP Billiton Brasil has recognised a provision of US$1.0 billion before tax and after discounting (30 June 2017: US$1.1 billion), in respect of its potential 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, the outcome of the ongoing negotiations with the Federal and State 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. For the half year ended 31 December 2017, BHP Billiton Brasil has paid US$154 million to allow for the continuation of reparatory and compensatory programs in relation to the Framework Agreement and a further US$2 million for dam stabilisation, with the total US$156 million offset against the provision for the Samarco dam failure. On 22 December 2017, BHP Billiton Brasil announced a further US$133 million to support Fundação Renova, in the event Samarco does not meet its funding obligations under the Framework Agreement. Any support to the 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 negotiations towards a settlement regarding the R$20 billion (approximately US$6 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 will be considered in the negotiation of a final settlement arrangement with the Federal Prosecutors. Under the Preliminary Agreement, BHP Billiton Brasil, Samarco and Vale 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$240 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 Interim Security was provided to the 12th Civil/Agricultural Federal Court of Minas Gerais on 24 January 2017 and will remain in place until the earlier of 20 April 2018 and the date that a settlement arrangement is agreed between the Federal Prosecutors, BHP Billiton Brasil, Samarco and Vale.

10. Significant events – Samarco dam failure (continued) On 16 November 2017, BHP Billiton Brasil, together with Samarco and Vale, entered into an Amendment Agreement with the Federal Prosecutors’ Office in Brazil (Federal Prosecutors) and the Minas Gerais State Prosecutors Office (State Prosecutors). The Amendment Agreement amends the Preliminary Agreement by providing for the State Prosecutors to become party to the Preliminary Agreement, in addition to including provisions for additional community consultation and replacing one of the socioeconomic experts appointed in the Preliminary Agreement to advise the Federal Prosecutors. In light of the ongoing negotiations, BHP Billiton Brasil, Samarco and Vale, together with the Federal and State Prosecutors, requested, and the 12th Civil/Agricultural Federal Court of Minas Gerais approved, an extension to the date for negotiations towards a settlement agreement in relation to the R$20 billion (approximately US$6 billion) public civil claim and R$155 billion (approximately US$47 billion) Federal Public Prosecution Office claim to 20 April 2018. During the extension period, the Interim Security and the current suspension of legal proceedings and injunctions under the Preliminary Agreement (see below) will remain in place. The parties will use best efforts to achieve a partial settlement agreement, focused mainly on including prosecutor and community participation into the governance structure of the Framework Agreement, by 20 April 2018. 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 the Foundation. 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, governmental inquiries and investigations relating to the Samarco dam failure have been commenced by numerous agencies of the Brazilian government and are ongoing. Ultimately, all 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. As at 31 December 2017, contingent liabilities for BHP Billiton Brasil are not materially different from those disclosed in note 3 ‘Significant events – Samarco dam failure’ in the 30 June 2017 Annual Report, subject to the updates set out below: R$20 billion 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 Espĺrito 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 billion) in aggregate for clean-up costs and damages. While a final decision by the 12th Civil/Agricultural Federal Court of Minas Gerais on the issue of ratification of the Framework Agreement is pending, the Preliminary Agreement suspends a R$1.2 billion (approximately US$360 million) injunction order under the R$20 billion Public Civil Claim. The Preliminary Agreement also requests suspension of the R$20 billion (approximately US$6 billion) Public Civil Claim with a decision from the Court pending. The R$1.2 billion (approximately US$360 million) injunction order may be reinstated if a settlement arrangement is not agreed by 20 April 2018. 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.

10. Significant events – Samarco dam failure (continued) 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 Civil/Agricultural Federal Court of Minas Gerais 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 settlement arrangement is not agreed by 20 April 2018. 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 Depository Receipts of BHP Billiton Ltd and BHP Billiton Plc between 25 September 2014 and 30 November 2015 against BHP Billiton Ltd 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 plaintiffs will seek certification to proceed as a class action. The amount of damages sought by the plaintiffs 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 Ltd 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. On 6 March 2017, the Complaint was amended to include BHP Billiton Ltd, 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 Complaint on 26 June 2017. That motion is pending before the Court. 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 Ltd, 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), Vale and Samarco 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 of the individuals, a R$20 billion (approximately US$6 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.

10. Significant events – Samarco dam failure (continued) Other claims 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 and BHP Billiton Brasil’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 31 December 2017, an insurance receivable has not been recognised for any potential recoveries under insurance arrangements. Commitments Under the terms of the Samarco joint venture agreement, BHP Billiton Brasil does not have an existing obligation to fund Samarco. For the half year ended 31 December 2017, BHP Billiton Brasil has provided US$50 million funding to support Samarco’s operations and a further US$2 million for dam stabilisation, with undrawn amounts of US$24 million expiring as at 31 December 2017. On 22 December 2017, BHP Billiton Brasil announced a new short-term facility of up to US$48 million to carry out ongoing repair works, maintain Samarco’s facilities and support restart planning. Funds will be released to Samarco only as required and subject to the achievement of key milestones with amounts undrawn expiring at 30 June 2018. Any additional requests for funding or future investment provided would be subject to a future decision, accounted for at that time. 11. Impairment of non-current assets – Onshore US The Group is currently progressing a number of alternatives to exit our Onshore US assets for value. In light of this process, and the significant management judgement required when assessing the recoverable amount of assets, this note provides an update on the Group’s assessment of the recoverability of the Onshore US assets. Carrying amount For impairment testing purposes, the goodwill arising from the Petrohawk acquisition in August 2011 is allocated to the Onshore US group of cash generating units (CGUs) which includes the Permian, Haynesville, Fayetteville, Black Hawk and Hawkville CGUs. The carrying amount of the Onshore US group of CGUs for impairment purposes is determined on a basis consistent with the way the recoverable amount is determined and comprises: 31 Dec 2017 30 June 2017 US$M US$M Property, plant and equipment 11,473 11,795 Working capital deficiency (573) (357) Provisions (543) (520) Other 40 38 Net operating assets for Onshore US (included in financial information for Petroleum on page 15) 10,397 10,956 Goodwill 3,009 3,022 Working capital deficiency 583 357 Other 8 34 Onshore US carrying amount for impairment purposes 13,997 14,369 Impairment testing requirements Impairment tests are carried out annually for goodwill. In addition, impairment tests for all assets and CGUs are performed when there is an indication of impairment. If the carrying amount of the asset or CGU exceeds its recoverable amount, the asset or CGU is impaired and an impairment loss is charged to the income statement so as to reduce the carrying amount to its recoverable amount.

11. Impairment of non-current assets – Onshore US (continued) Previously impaired assets and CGUs (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 CGU. At the half year, impairment tests, including for goodwill, are only performed if there is an indication of an impairment, or impairment reversal, since the end of the last financial year. FY2017 Assessment The annual impairment test of the Onshore US goodwill was performed in June after an assessment of the individual CGUs that it comprises. The recoverable amount of Onshore US at 30 June 2017 was calculated using fair value less cost of disposal (FVLCD) methodology. The impairment testing at 30 June 2017 resulted in no impairment or reversals of impairment for Onshore US. HY2018 Assessment For HY2018, an assessment was performed to determine whether there were any indicators of an impairment or impairment reversal since 30 June 2017. This included consideration of changes to market participant assumptions for the most significant estimates impacting asset recoverable amount valuations, including: Production – the review of additional production data from BHP’s wells and third party data did not indicate a significant change to the assumptions regarding production volumes; Price – the Group has forecast some decreases in the long run crude oil and natural gas prices from the forecasts used at 30 June 2017. However, sensitivities performed on internal valuations for these changes did not give rise to an indicator of impairment; and Discount rate – no indicators have arisen since 30 June 2017 that would indicate a significant change to the real post-tax rate of 7.0 per cent. The enactment of the TCJA in the US on 22 December 2017 is expected to have a positive impact on the fair values of the Onshore US assets, largely due to the reduction in the rate of US corporate income tax. Ongoing analysis is being performed to assess the longer term potential impact of the TCJA on price forecasts, supply costs and the cost of capital. Overall, the Group has assessed that there have been no changes that would indicate an impairment or impairment reversal since 30 June 2017. Accordingly, a recoverable amount determination at 31 December 2017 was not required to be performed. Key judgements and estimates In determining the recoverable amount of assets, in the absence of quoted market prices, estimates are made regarding the present value of future post-tax cash flows. These estimates require significant management judgement and are subject to risk and uncertainty that may be beyond the control of the Group. The estimates are made from the perspective of a market participant and include prices, future production volumes, operating costs, tax attributes and discount rates. 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. In our FY2017 financial statements we identified reasonably possible changes that would result in the estimated recoverable amount being equal to the carrying amount of Onshore US, including goodwill. Therefore there is a possibility that changes in circumstances will materially alter projections, which may impact the recoverable amount of assets at future reporting dates. The Group’s current divestment timeline includes the opening of data rooms and the receipt of bids prior to 30 June 2018, with evaluation and negotiation in the September quarter. Other divestment options continue to be considered. As the Group progresses alternative exit strategies, this may give rise to new information relevant to the assumptions used by management in the estimation of recoverable amount. 12. Subsequent events 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.

Directors’ Report The Directors present their report together with the half year financial statements for the half year ended 31 December 2017 and the auditor’s review report thereon. Review of Operations A detailed review of the Group’s operated and non-operated assets, the results of those operations during the half year ended 31 December 2017 and likely future developments are given on pages 1 to 26. The Review of Operations has been incorporated into, and forms part of, this Directors’ Report. Principal Risks and Uncertainties Due to the international scope of the Group’s operated and non-operated assets and the industries in which it is engaged, there are a number of risk factors and uncertainties which could have an effect on the Group’s results and operations over the next six months. The principal risks affecting the Group are described on pages 34 to 43 of the Group’s Annual Report for the year ended 30 June 2017 (a copy of which is available on the Group’s website at www.bhp.com ) and are summarised below. There are no material changes in those risk factors for the remaining six months of the financial year except to the extent described in note 10 ‘Significant events – Samarco dam failure’ of the half year financial statements and the ‘Outlook’ section. - 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 - Our financial results may be negatively affected by exchange rate fluctuations - Reduction in Chinese demand may negatively impact our results - 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 - Failure to discover or acquire new resources, maintain reserves or develop new assets could negatively affect our future results and financial condition - Potential changes to our portfolio of assets through acquisitions and divestments may have a material adverse effect on our future results and financial condition - Increased costs and schedule delays may adversely affect our development projects - If our liquidity and cash flow deteriorate significantly it could adversely affect our ability to fund our major capital programs - We may not fully recover our investments in mining, oil and gas assets, which may require financial write-downs - The commercial counterparties we transact with may not meet their obligations, which may negatively impact our results - Unexpected natural and operational catastrophes may adversely impact our assets - Breaches in, or failures of, our information technology may adversely impact our business activities - 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 they could have a material adverse impact on our business - Cost pressures and reduced productivity 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 - Safety, health, environmental and community impacts, incidents or accidents may adversely affect our people, assets and reputation or licence to operate Dividend Full details of dividends are given on page 10.

Board of Directors The Directors of BHP at any time during or since the end of the half year are: Ken MacKenzie – Chairman since September 2017 (a Director since September 2016) Jac Nasser – Chairman from March 2010 to August 2017 (a Director from June 2006 to August 2017) Andrew Mackenzie – an Executive Director since May 2013 Terry Bowen – a Director since October 2017 Malcolm Brinded – a Director from April 2014 to October 2017 Malcolm Broomhead – a Director since March 2010 Anita Frew – a Director since September 2015 Carolyn Hewson – a Director since March 2010 Grant King – a Director from March 2017 to August 2017 Lindsay Maxsted – a Director since March 2011 John Mogford – a Director since October 2017 Wayne Murdy – a Director since June 2009 Shriti Vadera – a Director since January 2011 Auditor’s independence declaration KPMG in Australia are the auditors of BHP Billiton Limited. Their auditor’s independence declaration under Section 307C of the Australian Corporations Act 2001 is set out on page 52 and forms part of this Directors’ Report. Rounding of amounts 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 the Directors’ Report and half year financial statements have been rounded to the nearest million dollars in accordance with ASIC Instrument 2016/191. Signed in accordance with a resolution of the Board of Directors. Ken MacKenzie – Chairman Andrew Mackenzie – Chief Executive Officer Dated this 20th day of February 2018

Directors’ Declaration of Responsibility The half year financial report is the responsibility of, and has been approved by, the Directors. 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 half year financial statements and notes, set out on pages 27 to 48, have been prepared in accordance with IAS 34 ‘Interim Financial Reporting’ as issued by the IASB, IAS 34 ‘Interim Financial Reporting’ as adopted by the EU, AASB 134 ‘Interim Financial Reporting’ as issued by the AASB, the Disclosure Guidance and Transparency Rules of the Financial Conduct Authority in the United Kingdom and the Australian Corporations Act 2001, including: (i) complying with applicable accounting standards and the Australian Corporations Regulations 2001; and (ii) giving a true and fair view of the financial position of the Group as at 31 December 2017 and of its performance for the half year ended on that date; (b) to the best of the Directors’ knowledge, the Directors’ Report, which incorporates the Review of Operations on pages 1 to 26, includes a fair review of the information required by: (i) DTR4.2.7R of the Disclosure Guidance and Transparency Rules in the United Kingdom, being an indication of important events during the first six months of the current financial year and their impact on the half year financial statements, and a description of the principal risks and uncertainties for the remaining six months of the year; and (ii) DTR4.2.8R of the Disclosure Guidance and Transparency Rules in the United Kingdom, being related party transactions that have taken place in the first six months of the current financial year and that have materially affected the financial position or performance of the Group during that period, and any changes in the related party transactions described in the last annual report that could have such a material effect; and (c) 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. Signed on behalf of the Directors in accordance with a resolution of the Board of Directors. Ken MacKenzie – Chairman Andrew Mackenzie – Chief Executive Officer Dated this 20th day of February 2018

Lead Auditor’s Independence Declaration under Section 307C of the Australian Corporations Act 2001 To: the Directors of BHP Billiton Limited I declare that, to the best of my knowledge and belief, in relation to the review of BHP Billiton Limited for the half year ended 31 December 2017 there have been: i. no contraventions of the auditor independence requirements as set out in the Australian Corporations Act 2001 in relation to the review; and ii. no contraventions of any applicable code of professional conduct in relation to the review. This declaration is in respect of BHP Billiton Limited and the entities it controlled during the financial period. KPMG Anthony Young Partner Melbourne 20 February 2018 KPMG, an Australian partnership and a member firm of the KPMG network of independent member firms affiliated with KPMG International Cooperative (‘KPMG International’), a Swiss entity. KPMG Australia’s liability limited by a scheme approved under Professional Standards Legislation.

Independent Review Report Independent Auditors’ review report of KPMG LLP (‘KPMG UK’) to the members of BHP Billiton Plc and of KPMG (‘KPMG Australia’) to the members of BHP Billiton Limited Conclusions For the purposes of these reports, the terms ‘we’ and ‘our’ denote KPMG UK in relation to UK responsibilities and reporting obligations to the members of BHP Billiton Plc, and KPMG Australia in relation to Australian responsibilities and reporting obligations to the members of BHP Billiton Limited. BHP (‘the Group’) consists of BHP Billiton Plc, BHP Billiton Limited and the entities they controlled during the half year ended 31 December 2017. We have reviewed the accompanying condensed financial statements of the Group for the half year ended 31 December 2017 (‘half year financial statements’), which comprise the Consolidated Income Statement, Consolidated Statement of Comprehensive Income, Consolidated Balance Sheet, Consolidated Cash Flow Statement, Consolidated Statement of Changes in Equity, Notes 1 to 12 comprising a summary of significant accounting policies and other explanatory information. KPMG Australia considers the Directors’ Declaration to be part of the half year financial statements when forming its conclusion. Review conclusion by KPMG UK Based on our review, nothing has come to our attention that causes us to believe that the half year financial statements for the six months ended 31 December 2017 are not prepared, in all material respects, in accordance with IAS 34 ‘Interim Financial Reporting’, as adopted by the European Union (‘EU’), and the Disclosure Guidance and Transparency Rules (‘the DTR’) of the United Kingdom’s Financial Conduct Authority (‘the UK FCA’). Review conclusion by KPMG Australia Based on our review, which is not an audit, we have not become aware of any matter that makes us believe that the half year financial statements, including the Directors’ Declaration, of the Group are not in accordance with the Australian Corporations Act 2001, including: a) Giving a true and fair view of the Group’s financial position as at 31 December 2017 and of its performance for the half year ended on that date; and b) Complying with Australian Accounting Standard AASB 134 ‘Interim Financial Reporting’ and the Australian Corporations Regulations 2001. Scope of review KPMG UK conducted its review in accordance with International Standard on Review Engagements (UK and Ireland) 2410 ‘Review of Interim Financial Information Performed by the Independent Auditor of the Entity’ (‘ISRE 2410’) issued by the Auditing Practices Board for use in the UK. We read the other information contained in the half year financial report and consider whether it contains any apparent misstatements or material inconsistencies with the information in the half year financial statements. KPMG Australia conducted its review in accordance with Auditing Standard on Review Engagements ASRE 2410 ‘Review of a Financial Report Performed by the Independent Auditor of the Entity’ (‘ASRE 2410’), as issued by the Australian Auditing and Assurance Standards Board. As the auditor of BHP Billiton Limited, ASRE 2410 requires that KPMG Australia complies with the ethical requirements relevant to the audit of the annual consolidated financial statements. A review of half year financial statements consists of making enquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures. A review is substantially less in scope than an audit conducted in accordance with auditing standards and consequently does not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion.

Directors’ responsibilities The Directors are responsible for preparing the half year financial report which gives a true and fair view in accordance with: The DTR of the UK FCA, and under those rules, in accordance with IAS 34 ‘Interim Financial Reporting’ as adopted by the EU; and Australian Accounting Standards and the Australian Corporations Act 2001 and for such internal control as the Directors determine is necessary to enable the preparation of the half year financial statements that are free from material misstatement, whether due to fraud or error; selecting and applying appropriate accounting policies; and making accounting estimates that are reasonable in the circumstances. Respective responsibilities of KPMG UK and KPMG Australia KPMG UK’s responsibility is to express a conclusion on the half year financial statements in the half year financial report based on our review. KPMG Australia’s responsibility is to express a conclusion on the half year financial statements, including the Directors’ Declaration based on our review. The purpose of our review work and to whom we owe our responsibilities KPMG UK’s report is made solely to BHP Billiton Plc’s members, as a body, in accordance with the terms of KPMG UK’s engagement to assist BHP Billiton Plc in meeting the requirements of the DTR of the UK FCA. KPMG Australia’s report is made solely to BHP Billiton Limited’s members, as a body, in accordance with the Australian Corporations Act 2001. KPMG Australia has performed an independent review of the half year financial statements, including the Directors’ Declaration, in order to state whether, on the basis of the procedures described, it has become aware of any matter that makes KPMG Australia believe that the half year financial statements, including the Directors’ Declaration, are not in accordance with the Australian Corporations Act 2001 including: giving a true and fair view of the Group’s financial position as at 31 December 2017 and its performance for the half year ended on that date; and complying with Australian Accounting Standard AASB 134 ‘Interim Financial Reporting’ and the Australian Corporations Regulations 2001. Our review work has been undertaken so that we might state to the members of each BHP Billiton Plc and BHP Billiton Limited those matters we are required to state to them in this report, and the further matters we are required to state to them in accordance with the terms agreed with each company, and for no other purpose. Accordingly, each of KPMG UK and KPMG Australia makes the following statement: to the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the company and the company’s members as a body, for our review work, for our report, or for the conclusions we have reached.

Independence In conducting its review, KPMG Australia has complied with the independence requirements of the Australian Corporations Act 2001. Michiel Soeting For and behalf of KPMG LLP Chartered Accountants London 20 February 2018 KPMG Anthony Young Partner Melbourne 20 February 2018 KPMG, an Australian partnership and KPMG LLP, a UK limited liability partnership, are member firms of the KPMG network of independent member firms affiliated with KPMG International Cooperative (‘KPMG International’), a Swiss entity. KPMG Australia’s liability limited by a scheme approved under Professional Standards Legislation.

SIGNATURES

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