Edgar Filing: BHP BILLITON LTD

BHP Billiton Limited and BHP Billiton Plc

Date: October 5, 2016

/s/ Rachel Agnew

Rachel Agnew

Company Secretary

Form 6-K

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

October 5, 2016

BHP BILLITON LIMITED

(ABN 49 004 028 077)

(Exact name of Registrant as specified in its charter)

VICTORIA, AUSTRALIA

(Jurisdiction of incorporation or organisation)

171 COLLINS STREET, MELBOURNE,

VICTORIA 3000 AUSTRALIA

(Address of principal executive offices)

BHP BILLITON PLC

(REG. NO. 3196209)

(Exact name of Registrant as specified in its charter)

ENGLAND AND WALES

(Jurisdiction of incorporation or organisation)

NEATHOUSE PLACE, LONDON,

UNITED KINGDOM

(Address of principal executive offices)

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F: x Form 20-F ¨ Form 40-F

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): ¨

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): ¨

Indicate by check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934: ¨ Yes x No

If “Yes” is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b): n/a


NEWS RELEASE


Release Time		IMMEDIATE

Date		5 October 2016

Location		London, United Kingdom

Number		23/16

RICH SET OF OPPORTUNITIES TO DRIVE VALUABLE GROWTH

BHP Billiton today outlined the broad range of opportunities within its Petroleum business to grow value, returns and cash flow as markets improve.

Speaking at an investor briefing in London, BHP Billiton President Operations Petroleum, Steve Pastor said “Having both minerals and petroleum in our portfolio allows us to maximise the value of our petroleum assets at the right point in the cycle.”

“While currently well supplied, underlying fundamentals suggest both oil and gas markets are improving more quickly than our minerals commodities.”

“Over the next decade, demand growth, natural field decline and the effects of industry wide investment deferrals are expected to create a significant opportunity to invest and maximize value in oil. By 2025 the world is expected to consume more than 100,000 barrels of liquids per day – a third of which would come from new sources.

“We are well placed to capitalise on this opportunity. We have a large, high quality resource base. Our focus on productivity has significantly reduced both operating and capital costs, supporting a range of shale and conventional investment opportunities that would generate compelling returns at today’s prices. As a result, Petroleum is well placed to maintain its position as BHP Billiton’s highest margin business and to grow its free cash flow contribution.”

BHP Billiton runs its Onshore US assets to maximise value rather than volumes and will continue to adjust its investment plans to reflect market conditions.

“Our Onshore US business gives us valuable flexibility. Our shale assets generate cash at current prices, with significant upside should oil and gas prices recover as we expect,” Mr Pastor said.

“We operate in the heart of some of the best shale plays and by further reducing costs and improving capital efficiency to levels among the best in the industry, we have increased our investible well inventory. As a result, we now have up to 1,200 undrilled net oil wells, contingent upon trials in the Eagle Ford, and 220 undrilled net gas wells that generate a minimum 15 per cent internal rate of return (IRR) at US$50 per barrel of oil and US$3 per MMbtu.

“In the Permian, we have access to over one billion barrels of oil equivalent (boe) meaning this field has the potential to become the largest production and free cash contributor in our Petroleum portfolio within five years.”

In Conventional, BHP Billiton is expecting unit operating costs to remain at approximately US$10 per boe over the 2017 and 2018 financial years as it pursues a number of options to extend high margin production from its existing facilities.

“We have a rich portfolio of brownfield project options, with total capital expenditure of US$2.5 billion and an average IRR of 45 per cent that will help offset field decline. With significant improvements in capital efficiency, major capital projects like Mad Dog 2 are now economically attractive, even below US$50 per barrel of oil,” Mr Pastor said.

BHP Billiton today also announced positive drilling results at the Caicos exploration well in the Gulf of Mexico. Located in Green Canyon 564, this well is approximately 100 miles south of the Louisiana coast in the deep water Gulf of Mexico. Caicos was drilled to a total depth of 30,803 feet and encountered oil in multiple horizons.

“We are encouraged by the Caicos results and are moving to further appraise the area. The next step will be drilling the Wildling well in November. With success at Caicos and Shenzi North, we continue to be optimistic around the opportunity for a commercial development in the area.”

Further information on BHP Billiton can be found at: bhpbilliton.com


Media Relations		Investor Relations

Australia and Asia		Australia and Asia

Matthew Martyn-Jones		Tara Dines
Tel: +61 7 3227 5816 Mobile +61 419 418 394		Tel: +61 3 9609 2222 Mobile: +61 499 249 005
Email: Matthew.Martyn-Jones@bhpbilliton.com		Email: Tara.Dines@bhpbilliton.com

Paul Hitchins		Andrew Gunn
Tel: +61 3 9609 2592 Mobile +61 419 315 001		Tel: +61 3 9609 3575 Mobile: +61 402 087 354
Email: Paul.Hitchins@bhpbilliton.com		Email: Andrew.Gunn@bhpbilliton.com

Fiona Hadley		United Kingdom and South Africa
Tel: +61 3 9609 2211 Mobile +61 427 777 908
Email: Fiona.Hadley@bhpbilliton.com		Rob Clifford
		Tel: +44 20 7802 4131 Mobile: +44 7788 308 844
Amanda Saunders		Email: Rob.Clifford@bhpbilliton.com
Tel: +61 3 9609 3935 Mobile +61 417 487 973
Email: Amanda.Saunders@bhpbilliton.com		Elisa Morniroli
		Tel: +44 20 7802 7611 Mobile: +44 7825 926 646
United Kingdom and South Africa		Email: Elisa.Morniroli@bhpbilliton.com

Ruban Yogarajah		Americas
Tel: +44 207 802 4033 Mobile +44 7827 082 022
Email: Ruban.Yogarajah@bhpbilliton.com		James Wear
		Tel: +1 713 993 3737 Mobile: +1 347 882 3011
North America		Email: James.Wear@bhpbilliton.com

Bronwyn Wilkinson
Mobile: +1 604 340 8753
Email: Bronwyn.Wilkinson@bhpbilliton.com





BHP Billiton Limited ABN 49 004 028 077		BHP Billiton Plc Registration number 3196209
Registered in Australia		Registered in England and Wales
Registered Office: Level 18, 171 Collins Street		Registered Office: Neathouse Place
Melbourne Victoria 3000 Australia		London SW1V 1LH United Kingdom
Tel +61 1300 55 4757 Fax +61 3 9609 3015		Tel +44 20 7802 4000 Fax +44 20 7802 4111

Members of the BHP Billiton Group which is

headquartered in Australia

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bhpbilliton
BHP Billiton Petroleum
An exciting outlook for our Petroleum business
Steve Pastor President Operations, Petroleum

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Disclaimer
Forward-looking statements
This presentation contains forward-looking statements, including statements regarding: reserves and resources and the production, revenues and costs relating thereto, 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 presentation. Readers are cautioned not to put undue reliance on forward-looking statements.
For example, future revenues from our operations, other results, projects or mines described in this presentation will be based, in part, upon the market price of the minerals, metals or petroleum produced, which may vary significantly from current levels. These variations, if materially adverse, may affect the timing or the feasibility of the development of a particular project, the expansion of certain facilities or mines, the continuation of existing operations.
Other factors that may cause actual results to differ from those expressed in the forward-looking statements include uncertainties in estimating reserves, difficulties in converting resources into reserves and reserves into quantities of oil and gas, operating risks, changes in operating costs, factors that 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 Billiton’s filings with the US Securities and Exchange Commission (the “SEC”) (including in Annual Reports on Form 20-F) which are available on the SEC’s website at www.sec.gov.
Except as required by applicable regulations or by law, the Group does not undertake any obligation to publicly update or review any forward-looking statements, whether as a result of new information or future events.
Past performance cannot be relied on as a guide to future performance.
Non-IFRS financial information
BHP Billiton results are reported under International Financial Reporting Standards (IFRS) including Underlying EBIT and Underlying EBITDA which are used to measure segment performance. This release may also include certain non-IFRS and other financial measures including Adjusted effective tax rate, Free cash flow, Gearing ratio, Net debt, Net operating assets, Underlying attributable profit, Underlying basic (loss)/earnings per share, Underlying EBIT margin and Underlying EBITDA margin. These measures are used internally by management to assess the performance of our business, make decisions on the allocation of our resources and assess operational management. Non-IFRS and other financial 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.
Presentation of data
Unless specified otherwise: all data is presented on a continuing operations basis to exclude the contribution from assets that were demerged with South32; references to Underlying EBITDA margin exclude third party trading activities; data from subsidiaries is shown on a 100 per cent basis and data from equity accounted investments and other operations is shown on a proportionate consolidation basis. Numbers presented may not add up precisely to the totals provided due to rounding. Onshore US scenarios are based on price estimates from Bank of America Merrill Lynch, Citi, Credit Suisse, Deutsche Bank, JP Morgan, Macquarie, Morgan Stanley and UBS as at 8 August 2016 and do not necessarily correspond to BHP Billiton’s view of prices.
No offer of securities
Nothing in this presentation should be construed as either an offer to sell or a solicitation of an offer to buy or sell BHP Billiton securities in any jurisdiction, or be treated or relied upon as a recommendation or advice by BHP Billiton.
Reliance on third party information
The views expressed in this presentation contain information that has been derived from publicly available sources that have not been independently verified. No representation or warranty is made as to the accuracy, completeness or reliability of the information. This presentation should not be relied upon as a recommendation or forecast by BHP Billiton.
BHP Billiton Investor Briefing, Petroleum Overview
5 October 2016 2 bhpbilliton

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Statement of Petroleum Resources
Petroleum Resources
The estimates of Petroleum Reserves and Contingent Resources contained in this presentation are based on, and fairly represent, information and supporting documentation prepared under the supervision of Mr. A. G. Gadgil, who is employed by BHP Billiton. Mr. Gadgil is a member of the Society of Petroleum Engineers and has the required qualifications and experience to act as a qualified Petroleum Reserves and Resources evaluator under the ASX Listing Rules. This presentation is issued with the prior written consent of Mr. Gadgil who agrees with the form and context in which the Petroleum Reserves and Contingent Resources are presented.
Reserves and Contingent Resources are net of royalties owned by others and have been estimated using deterministic methodology. Aggregates of Reserves and Contingent Resources estimates contained in this presentation have been calculated by arithmetic summation of field/project estimates by category with the exception of the North West Shelf (NWS) Gas Project in Australia. Probabilistic methodology has been utilised to aggregate the NWS Reserves and Contingent Resources for the reservoirs dedicated to the gas project only and represents an incremental 39 MMboe of Proved Reserves. The barrel of oil equivalent conversion is based on 6000 scf of natural gas equals 1 boe. The Reserves and Contingent Resources contained in this presentation are inclusive of fuel required for operations. The respective amounts of fuel for each category are provided by footnote for the resource graphics. The custody transfer point(s)/point(s) of sale applicable for each field or project are the reference point for Reserves and Contingent Resources. Reserves and Contingent Resources estimates have not been adjusted for risk. Unless noted otherwise, Reserves and Contingent Resources are as of 30 June 2016. Where used in this presentation, the term Resources represents the sum of 2P reserves and 2C Contingent Resources.
BHP Billiton estimates Proved Reserve volumes according to SEC disclosure regulations and files these in our annual 20-F report with the SEC. All Unproved volumes are estimated using SPE-PRMS guidelines, which among other things, allow escalations to prices and costs, and as such, would be on a different basis than that prescribed by the SEC, and are therefore excluded from our SEC filings. All Resources and other Unproved volumes may differ from and may not be comparable to the same or similarly-named measures used by other companies. Non-proved estimates are inherently more uncertain than proved.
Table 1 Net BHP Billiton Petroleum Reserves and Contingent Resources as of 30 June 2016
Onshore US Offshore US Australia Rest of World
Net MMboe Eagle Ford & Permian Haynesville & Fayetteville Subtotal Gulf of Mexico Offshore Western Australia1, 2 Bass Strait & Offshore Victoria Subtotal Trinidad & Tobago Algeria United Kingdom & Other Subtotal Total BHP Billiton
Proved 124 173 298 210 414 303 717 56 22 - 78 1,303
Probable 1,433 1,273 2,707 127 59 94 153 17 10 - 27 3,013
2P 1,558 1,447 3,004 337 473 397 869 73 32 - 105 4,316
2C 1,547 1,782 3,329 392 1,099 153 1,252 52 18 20 89 5,061
2P+2C 3,105 3,228 6,333 729 1,571 550 2,121 124 50 20 194 9,377
Fuel included above
Proved 2.0 5.0 7.0 5.8 36.5 16.9 53.4 1.4 1.3—2.8 69.0
Probable 33.2 22.2 55.4 3.2 3.6 4.7 8.3 — — 66.8
2P 35.2 27.2 62.4 8.9 40.0 21.7 61.7 1.4 1.3—2.8 135.8
2C 27.3 41.4 68.7 5.8 113.4 6.8 120.2 — — 194.7
2P+2C 62.5 68.6 131.1 14.8 153.4 28.5 181.9 1.4 1.3—2.8 330.6
1) Includes NWS Gas Project probabilistic increment noted in disclaimer above.
2) Australian resources prior to the announced agreement by Woodside to acquire 50% of BHP Billiton Scarborough area assets.
The SEC permits oil and gas companies, in their filings with the SEC, to disclose only Proved, Probable and Possible Reserves, and only when such Reserves have been determined in accordance with SEC guidelines. We use certain terms in this presentation such as “Resources,” “Contingent Resources,” “2C Contingent Resources” and similar terms as well as Probable Reserves not determined in accordance with the SEC’s guidelines, all of which measures we are strictly prohibited from including in filings with the SEC. These measures include Reserves and Resources with substantially less certainty than Proved Reserves. U.S. investors are urged to consider closely the disclosure in our Form 20-F for the fiscal year ended June 30, 2016, File No. 001-09526 and in our other filings with the SEC, available from us at http://www.bhpbilliton.com/. These forms can also be obtained from the SEC as described above.
BHP Billiton Investor Briefing, Petroleum Overview
5 October 2016 3 bhpbilliton

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An exciting outlook for our Petroleum business
Petroleum is core to BHP Billiton
strong financial and operating performance
oil and US gas markets expected to rebalance first
Petroleum strategy focused on value over volume
Concentrated resource base and proven operating capability
Onshore US – capturing full resource value while driving returns and free cash flow
Conventional – high margins with inventory of in-fill projects to offset field decline
Rich set of opportunities to drive valuable growth
Mad Dog 2 investment decision expected in next six months
Haynesville acceleration supported by hedging
Permian progressing towards full pad development in FY19
exploration program yielding encouraging results
would consider value accretive acquisitions
Value accretive production potential over the next decade1
(BHP Billiton production, MMboe) 300
Onshore US gas
200
Onshore US liquids
100
0
FY17e FY19e FY21e FY23e FY25e
Base
Mad Dog 2
Potential exploration success
Conventional in-fill
Onshore US
1. Production estimates for FY18 onwards represents a scenario. Scenarios do not constitute guidance; actual production will be determined according to market conditions prevailing at the relevant time.
BHP Billiton Investor Briefing, Petroleum Overview
5 October 2016 4 bhpbilliton

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Experienced leadership driving value and returns
Deep experience across leadership team
average industry and functional experience of over 25 years
operating experience across six continents
Operating model supports improved returns
operations enabled to focus on safety, volume and cost
globally integrated functions co-located with operations
accelerated sharing of best practice between minerals and petroleum
Dynamic approach focused on value
monthly signpost reviews support hedging decisions
quarterly capital allocation reviews
President Operations Petroleum
Steve Pastor
27 years
Asset President Shale
Alex Archila
33 years
Asset President Conventional
Geraldine Slattery
26 years
VP Exploration
Niall McCormack
21 years
VP HSE
David Crawford
17 years
Head of Planning
John Simmons
24 years
VP Engineering
David Purvis
33 years
VP Drilling
Derek Cardno
33 years
VP Geoscience
Paul McIntosh
31 years
VP Marketing
Michiel Hovers
21 years
VP Finance
Michelle Turner
21 years
Global Functions
Supply
Risk and Marketing Legal
HR
Corporate Technology Finance Affairs
Global Centres of Excellence
BHP Billiton Investor Briefing, Petroleum Overview
5 October 2016 5 bhpbilliton

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Petroleum is core to BHP Billiton
Significant contributor over the last five years
over 20% of Group production1
over 30% of Group Underlying EBITDA
average Underlying EBITDA margin of 66%
Differentiated diversification
technical, operational and functional economies of scale
talent, ideas and best practice flow across the Group
diversification of customer markets and political jurisdictions
supports cash flow stability and strong balance sheet
enables greater capital mobility across commodity cycles
encourages increased competition for capital
Oil and US gas markets expected to rebalance first
1. Copper equivalent production based on continuing operations and FY16 realised prices.
2. BHP Billiton data for FY01 to FY13 presented on a total operations basis; FY14 to FY16 excludes Nickel West as reported in Group and unallocated items.
3. Versus 2015.
Strong and stable margins
(Underlying EBITDA margin2, %)
100
75
50
25
0
FY01 FY04 FY07 FY10 FY13 FY16
BHP Billiton Petroleum Minerals
Commodity market outlook to 2025
Supply opportunity by 20253
Petroleum
Copper
Potash
Energy coal
Iron ore
Metallurgical coal
Time until expected market rebalance
BHP Billiton Investor Briefing, Petroleum Overview
5 October 2016 6 bhpbilliton

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Global energy needs are rising
Emerging economies will drive energy demand
– global population to increase by 1.5 billion and GDP to double by 2035
– world must pursue the twin objectives of providing access to affordable and reliable energy while limiting climate change
Fossil fuels will remain an important part of the energy mix
– fossil fuels represent four-fifths of the world’s energy needs through to 2035
– oil demand to grow as rising fleet size and industrial use more than offset efficiency gains and technological disruption
– environmental, operational and economic advantages of natural gas enable it to be the fastest growing fossil fuel
– despite strong growth in solar and wind, overall contribution to energy mix remains relatively small over the next two decades
Source: International Energy Agency (IEA), BHP Billiton analysis.
1. Excludes metallurgical coal and biomass used in power and heating.
2. Oil includes biofuels.
3. Natural gas based on Standard cubic meter.
4. Billion tonnes of oil equivalent.
Primary energy demand by commodity1,2,3
(Btoe4)
16
14
12
10
8
6 ~2% CAGR
4
2 ~1% CAGR
0
1990 1995 2000 2005 2010 2015 2020e 2025e 2030e 2035e
Oil
Uranium
Natural gas
Hydro
Thermal coal
Wind & Solar
BHP Billiton Investor Briefing, Petroleum Overview
5 October 2016 7 bhpbilliton

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Attractive crude oil fundamentals
Oil market is rebalancing
robust demand growth underpinned by developing countries
supply growth slowing as capital investment is deferred
Continue to see positive longer-term fundamentals
demand growing ~1% per annum
natural field decline will continue at 3-4 MMbbl/d per annum
as lower cost supply declines, all major producing regions will need to grow to meet anticipated demand
higher prices required to induce new supply
Source: International Energy Agency (IEA), BHP Billiton analysis.
Oil mass balance: global
(MMbbl/d) (Supply/Demand, MMbbl/d)
2 98
1 96
0 94
(1) 92
(2) 90
2012 2013 2014 2015 2016e 2017e
Implied inventory change (LHS)
Supply (RHS) Demand (RHS)
Supply opportunity
(MMbbl/d)
Supply
opportunity
2015 2020e 2025e 2030e 2035e
Existing supply Demand
OPEC US L48 Other Non-OPEC
BHP Billiton Investor Briefing, Petroleum Overview
5 October 2016 8 bhpbilliton

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Robust gas demand growth
US market expected to rebalance at the end of this year
mild winter, industry-wide productivity gains and resilient supply resulted in record inventory levels earlier this year
strong demand from the power sector and increasing exports
Long run demand growth driven by multiple regions
global natural gas demand forecast to grow at ~2% per annum over the next 20 years
accelerating convergence of the global gas markets over the next decade as export capacity increases
Source: US Energy information Administration (EIA), BHP Billiton analysis.
Gas mass balance: North America
(bcf/d) (Supply/Demand, bcf/d)
2 100
1 95
0 90
(1) 85
(2) 80
2012 2013 2014 2015 2016e 2017e
Storage change (LHS)
Supply (RHS) Demand (RHS)
Global gas and LNG demand
(bcf/d)
500 125
400 100
300 75
200 50
100 25
0 0
2015 2020e 2025e 2030e 2035e
RoW
North America
Europe
Asia
Middle East
LNG (RHS)
BHP Billiton Investor Briefing, Petroleum Overview
5 October 2016 9 bhpbilliton

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Australia and the US are our core regions
Our high-quality resource base…
(BHP Billiton resource, FY16, Bboe)1
4
2
0
Australia Eagle Ford Permian Haynesville Fayetteville Gulf of Mexico RoW
…underpins our major producer position in core regions
(BHP Billiton production, Mboe/d, CY15, net)
300
2nd 6th 9th 4th Rank2
200
100
0
Australia US Tight Oil US Shale Gas Gulf of Mexico
United Kingdom
Onshore US Algeria
Gulf of Mexico
Mexico3
Trinidad & Tobago
Bubble size represents resource of 500 MMboe as of 30 June 2016.
Source: BHP Billiton analysis, Wood Mackenzie.
1. Table 1 provides the Proved and Probable Reserves and 2C Contingent Resources and fuel amounts for the areas noted.
2. Peers: Woodside, Shell, ExxonMobil, Chevron, BP, Santos, ConocoPhillips, Apache, Sinopec, Anadarko, Hess, Freeport-MMR, ENI, Petrobras, Southwestern, Chesapeake,
Devon, Range Resources, EOG, Marathon, Continental.
3. Represents potential exploration region.
Australia
BHP Billiton Investor Briefing, Petroleum Overview
5 October 2016 10 bhpbilliton

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Operating safely and sustainably is our priority
The health and safety of our people is paramount
– record and reputation as one of the safest companies in the petroleum industry
– number of recordable injuries reduced by 60% during period of significant market change
Meaningful contribution to the communities we operate in
– US$3.5 billion in payments to local suppliers and royalties to landowners in FY16
– US$8.1 million in direct investment to support local community needs in FY16
Focused on environmental sustainability
– reduced greenhouse gas emissions by 7% in FY16
– partnering to accelerate development of Carbon Capture and Storage technologies
1. Source: IOGP Safety Performance Indicators – 2015 Data; excludes contractors.
Lost-Time Injury Frequency (LTIF)
(number of recordable injuries per million hours worked1)
1.5
1.0
0.5
0.0
Peers BHP Billiton
Total Recordable Injury Frequency
(per million hours worked)
3.0
down 26%
2.0
1.0
0.0
FY15 FY16
Significant events
(count)
45
30
down 64%
15
0
FY15 FY16
BHP Billiton Investor Briefing, Petroleum Overview
5 October 2016 11 bhpbilliton

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Onshore US well placed as prices recover
Operating in the heart of some of the best shale plays
– large resource base in Eagle Ford
– significant potential in Permian
Continuing to reduce costs with technical excellence
Improving economic inventory
Monetising multi-decade gas resource through forward curve
Focused on value and near-term free cash flow
– continue to exercise development flexibility to maximise value
– potential to remain cash flow positive under the three price scenarios outlined
1. 15% rate of return under constant WTI oil and Henry Hub gas prices; liquids analysis assumes US$3.00/MMbtu Henry Hub gas price and NGL prices as a percentage of WTI. Incremental G&A not included for economic inventory; organisation is scalable for growth.
2. Where applicable, economics do not include Freight, Selling & Distribution (FS&D) costs.
3. Contingent upon ongoing and upcoming trials in Eagle Ford.
Black Hawk drilling cost performance
(US$ million/well, 100% basis)
6
4
2
0
Q1 FY13 Q2 FY13 Q3 FY13 Q4 FY13 Q1 FY14 Q2 FY14 Q3 FY14 Q4 FY14 Q1 FY15 Q2 FY15 Q3 FY15 FY15 Q4 Q1 FY16 Q2 FY16 Q3 FY16 Q4 FY16
BHP Billiton Lowest cost achieved
Onshore US investable inventory1,2,3
(net working interest wells competitive for development)
1,500
1,000
500
0
<US$50/bbl US$50-60/bbl US$60-70/bbl
<US$3/mcf US$3-3.50/mcf US$3.50-4/mcf
Current Estimated May 2016
BHP Billiton Investor Briefing, Petroleum Overview
5 October 2016 12 bhpbilliton

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Stable volumes and high margins in Conventional
Our Conventional business is low cost and high-margin
– unit cash costs expected to be ~US$10/boe over the next two years1,2
Comprehensive portfolio of options to arrest field decline
– >40 brownfield projects with total capex of ~US$2.5 billion and an average IRR of ~45%
– average ~140 MMboe of brownfield production expected in the next five years2
Mad Dog 2 investment decision expected in next six months
1. Unit cash costs exclude freight, distribution and selling, third party costs and exploration expenditure.
2. EBITDA margin estimates for FY17 onwards, and production and unit cash cost estimates for FY18 represent a scenario. Scenarios do not constitute guidance; actual EBITDA margin, production and unit cash costs will be determined according to market conditions prevailing at the relevant time.
High margins in Conventional2
(Conventional production, MMboe) (EBITDA margin, %)
150 90
100 60
50 30
0 0
FY14 FY15 FY16 FY17e FY18e
Production Margin
BHP Billiton Investor Briefing, Petroleum Overview
5 October 2016 13 bhpbilliton

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Targeting Tier 1 liquids growth opportunities
Organic growth is the priority
– targeting frontier basins with Tier 1 potential
– program aimed at conventional deepwater oil plays that complement our operating expertise and core portfolio
– investing through the cycle and extending reach with countercyclical investment
Will selectively pursue inorganic opportunities that are aligned with our strategy
– must be value accretive
– leverage our view of global endowment
– focused primarily on deepwater conventional oil
– rigorous screening applied against Capital Allocation Framework
1. Under our long-term price forecasts; BHP Billiton share.
Significant potential in oil exploration over the next three years
(value1, BHP Billiton share)
FY16 – Phase I FY17 – Phase II
FY17 – Phase I FY18 – Phase II
FY18 – Phase I
Gulf of Mexico Trinidad and Tobago Western Australia
Risked Unrisked
BHP Billiton Investor Briefing, Petroleum Overview
5 October 2016 14 bhpbilliton

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An exciting outlook for our Petroleum business
Petroleum is core to BHP Billiton
– strong financial and operating performance
– oil and US gas markets expected to rebalance first
Petroleum strategy focused on value over volume
Concentrated resource base and proven operating capability
– Onshore US – capturing full resource value while driving returns and free cash flow
– Conventional – high margins with inventory of in-fill projects to offset field decline
Rich set of opportunities to drive valuable growth
– Mad Dog 2 investment decision expected in next six months
– Haynesville acceleration supported by hedging
– Permian progressing towards full pad development in FY19
– exploration program yielding encouraging results
– would consider value accretive acquisitions
1. Production estimates for FY18 onwards represents a scenario. Scenarios do not constitute guidance; actual production will be determined according to market conditions prevailing at the relevant time.
Value accretive production potential over the next decade1
(BHP Billiton production, MMboe)
300
Onshore US gas
200
Onshore US liquids
100
0
FY17e FY19e FY21e FY23e FY25e
Base
Mad Dog 2
Potential exploration success
Conventional in-fill
Onshore US
BHP Billiton Investor Briefing, Petroleum Overview
5 October 2016 15 bhpbilliton

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Petroleum Marketing
Rebalancing markets, positive long-term fundamentals
Michiel Hovers Vice President Marketing, Petroleum

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Rebalancing markets, positive long-term fundamentals
Oil market is rebalancing
- near-term demand growth of more than 1 MMbbl/d per annum
- inventory drawdown as supply growth slows considerably
Long-term positive outlook for oil underpinned by strong fundamentals
- rising energy demand driven by non-OECD countries
- natural field decline supports significant supply opportunity
North American gas long-term outlook - diversified demand growth
- multiple sectors contribute to total demand growth of 3% per annum
- abundant supply options
Unique shale gas market characteristics support hedging
- hedging of gas price and input costs secures attractive returns at low risk
- accelerates development of the Haynesville core
BHP Billiton Investor Briefing, Marketing
October 2016 3 bhpbilliton

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Global oil market is rebalancing
Global demand expected to surpass global supply in 2017, inventories to decline
- demand growth in 2017 expected to be 1.2 MMbbl/d
- non-US production to remain relatively flat
- estimated 2-3 days of demand cover in excess commercial inventory
New US supply needed to balance market
- US faces steep decline rates; output is down 1 MMbbl/d versus April 2015 peak
- production needs to return to around 9 MMbbl/d by end of 2017 to balance market
- actual ramp-up profile dependent on price, infrastructure and capital constraints
Source: US Energy Information Administration (EIA), BHP Billiton analysis.
Total US crude oil production and rig profile
(MMbbl/d) (Oil rigs)
11 1,750
10 1,500
9 1,250
8 1,000
7 750
6 500
5 250
Q1 2012 Q1 2013 Q1 2014 Q1 2015 Q1 2016 Q1 2017e
Base production New supply Total oil rig count
BHP Billiton Investor Briefing, Marketing
October 2016 4 bhpbilliton

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Positive long-term oil demand fundamentals
Robust demand growth underpinned by developing countries
- China and India expected to account for half of global demand growth over the next decade
- OECD demand has peaked and is expected to decline
Demand will rise, despite gains in energy efficiency and electric vehicles (EV)
- rising fuel efficiency of conventional and hybrid vehicles will be the major source of oil displacement over the next two decades
- EV sales are expected to grow by ~25% per annum for 20 years, leading to a ~140 million EV fleet by 2035
- EVs expected to displace more than 2 MMbbl/d of oil consumption in 2035, versus around 12.5 MMbbl/d from fuel efficiency improvements
Source: International Energy Agency (IEA), BHP Billiton analysis.
Long-term liquids demand forecast
(MMbbl/d)
80
60
40
20
0
2000 2005 2010 2015 2020e 2025e 2030e 2035e
Other non-OECD China India OECD
Prospects: a view from ground up http://www.bhpbilliton.com/investors/prospects/electric-vehicles-why-all-the-noise
BHP Billiton Investor Briefing, Marketing
October 2016 5 bhpbilliton

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~30 MMbbl/d of new supply required by 2025
Compelling supply opportunity
- natural field decline and demand growth drive need for new supply
- new supply required equates to approximately one third of current demand by 2025
- upstream spending is down significantly over the last two years
Higher prices required to induce investment
- many supply sources have a core that is profitable below US$60/bbl
- development of non-core supply needs higher inducement prices; shale is no exception
- productivity improvements likely to continue, but at a more moderate pace
Source: BHP Billiton analysis.
1. Box width represents 2025 production by category; ordered by weighted average cost of production (lowest to highest). Excludes on-line supply and supply under development. Top/Bottom on box represents cost of production for 10/90 percentile for the respective category.
Potential new oil supply1 by 2025
(US$/bbl, real Jan 2016)
100
75
50 US Shale Core Other Conventional Deepwater Heavy Oil US Shale Non-core
25 Middle East
0
0 10 20 30 40
Cumulative total (MMbbl/d)
BHP Billiton Investor Briefing, Marketing
October 2016 6 bhpbilliton

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North American gas: strong demand, abundant supply
Strong demand growth underpinned by multiple sectors
- total North American demand CAGR of ~3% to 2025
- gas is a reliable, economic and a low emission fuel for power generation
- gas displaces coal and provides flexible generation to support the rising penetration of intermittent wind and solar in the power sector
- US is becoming one of the top three LNG exporters globally
Availability of lower cost supply will limit price appreciation
- abundant supply options
- as core areas are depleted, new production additions are incrementally higher cost
Source: BHP Billiton analysis.
1. Includes pipeline losses and other.
North America gas demand
(bcf/d)
120
80
40
0
2010 2015 2020e 2025e
US Power US Industrial US Res/Comm1
Canada Mexico LNG Export
North America gas supply
(bcf/d)
120
Demand
80
40
Existing supply
0
2015 2020e
New supply at
> US$3/MMbtu
New supply at
< US$3/MMbtu
2025e
BHP Billiton Investor Briefing, Marketing
October 2016 7 bhpbilliton

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Hedging price and input costs accelerates Haynesville gas volumes
Gas and iron ore production profiles1 comparison
(Production as % of peak rate)
100
80
60
40
20
0
0 2 4 6 8 10 12 14 16 18 20
Years from first production
Gas (1 rig for 12 months) Iron ore
Source: BHP Billiton analysis.
1. Indicative production profiles.
Henry Hub monthly futures and spot pricing
(US$/MMbtu, nominal)
8
6
4
2
0
2010 2011 2012 2013 2014 2015 2016 2017e 2018e
Spot Futures strips
BHP Billiton Investor Briefing, Marketing
October 2016 8 bhpbilliton

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Petroleum Financial Performance
Driving productivity and capital discipline
Michelle Turner Vice President Finance, Petroleum

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Driving productivity and capital discipline
Petroleum supports cash flow stability
average Underlying EBITDA margin of 66% over the last five years
Conventional provides stable volumes and cash flow
Onshore US provides flexibility to capture price cycles
Focus on productivity in all price environments
targeting Petroleum unit cash costs of ~US$11/boe over the next two years1
increased capital efficiency across Conventional and Onshore US
Capital Allocation Framework provides discipline and transparency
Petroleum projects compete well for capital
our global finance function plays a critical role in determining how our Company creates value
1. Unit cash cost estimates for FY18 represents a scenario. Scenarios do not constitute guidance; actual unit cash costs will be determined according to market conditions prevailing at the relevant time. Unit cash costs exclude freight, distribution and selling, third party costs and exploration expenditure.
BHP Billiton Investor Briefing, Finance
5 October 2016
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Leading EBITDA margins
Consistently strong margins over the last five years
- contributed ~US$40 billion Underlying EBITDA
- peer leading Underlying EBITDA margin of 66%
Productivity supported FY16 financial performance
- ~US$3/boe reduction in cash costs
- US$3.6 billion Underlying EBITDA in lower price environment
Productivity protecting margins
- ~US$11/boe Petroleum unit cash costs expected in FY172
- medium-term unit cash costs expected to remain below FY14 baseline
1. Source: FactSet. Peers include: Anadarko, ConocoPhillips, Freeport-McMoRan, Hess, Marathon Oil, Noble Energy, Occidental Petroleum, Devon Energy.
2. Unit cash costs exclude freight, distribution and selling, third party costs and exploration expenditure.
Peer leading EBITDA margins1
(Underlying EBITDA margin, %)
80
60
40
20
0
FY12 FY13 FY14 FY15 FY16
Peer group range BHP Billiton Petroleum
Unit cash costs to remain below FY14 baseline2
(US$/boe) 15
10
5
FY14 FY15 FY16 FY17e Petroleum Conventional Onshore US
BHP Billiton Investor Briefing, Finance
5 October 2016
4
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Depreciation ~US$18/boe in FY17
Conventional unit depreciation increases ~US$1/boe in FY17 reflecting project completions and timing of resource additions
Onshore US depreciation increases ~US$1/boe in FY17
- the unit rate decline following the FY16 impairment is expected to be partially offset by price impacts
- significant reductions in drilling times and well costs achieved in Onshore US reduces the depreciation rate
1. Excludes exploration.
Petroleum depreciation rates1
(US$/boe)
30
25
20
15
10
5
0
FY14 FY15 FY16 FY17e
Petroleum Conventional Onshore US
BHP Billiton Investor Briefing, Finance
5 October 2016
5
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Driving capital and operating productivity
Productivity underpinned efficiency in FY16
- controllable cash costs fell US$677 million
- working capital management decreased inventory by 25%
Right sizing our organisation
- overhead costs decreased by 22% during FY16
- offshoring work to Trinidad and Malaysia
Capital efficiency supporting project returns
- ~40% reduction in Onshore US well costs1,2
- US$586 million of supply savings2
Culture of continuous improvement
- employees engaged through “transformation” campaign
- functional business partnering accelerates value creation
1. Drilling and completion costs are not normalised for lateral length. Black Hawk drilling cost calculated for 2-string wells only. Permian drilling and completion costs calculated using North Reeves activities. Completion costs exclude trials.
2. Savings in FY15 and FY16.
Annual supply savings
(US$ million)
400
300
200
100
0
FY15 FY16 FY17e
Petroleum headcount
(count) down 28%
4,000
3,000
2,000
1,000
0
FY15 FY16
Total unit cash cost
(US$/boe, average)
15
10
5
US$12.20
0
FY15
down US$2.80/boe
Productivity:
Operating efficiency
Organisational effectiveness
Reduction in overheads
Culture
US$9.40
FY16
BHP Billiton Investor Briefing, Finance
5 October 2016
6
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Capital allocation provides discipline and transparency
Globalised finance function oversees capital allocation
- co-located finance teams support operations
- competition for capital focused on value over volume
Flexibility to adjust Onshore US development
- cost efficiencies continue to increase investable well inventory
- dynamic capital allocation for Onshore US
Petroleum’s high-return projects competitive for capital
- high-return conventional brownfield projects
- high-return incremental wells in Onshore US
- Tier 1 exploration opportunities
1. Capital and exploration expenditure estimates for FY18 represents a scenario. Scenarios do not constitute guidance; actual capital and exploration expenditure will be determined according to market conditions prevailing at the relevant time.
Capital and exploration expenditure1
(US$ billion)
5
4
3
2
1
0
Conventional Onshore US Exploration
FY14 FY15 FY16 FY17e FY18e
BHP Billiton Investor Briefing, Finance
5 October 2016
7
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Driving productivity and capital discipline
Petroleum supports cash flow stability
- average Underlying EBITDA margin of 66% over the last five years
- Conventional provides stable volumes and cash flow
- Onshore US provides flexibility to capture price cycles
Focus on productivity in all price environments
- targeting Petroleum unit cash costs of ~US$11/boe over the next two years1
- increased capital efficiency across Conventional and Onshore US
Capital Allocation Framework provides discipline and transparency
- Petroleum projects compete well for capital
- our global finance function plays a critical role in determining how our Company creates value
1. Unit cash cost estimates for FY18 represents a scenario. Scenarios do not constitute guidance; actual unit cash costs will be determined according to market conditions prevailing at the relevant time. Unit cash costs exclude freight, distribution and selling, third party costs and exploration expenditure.
BHP Billiton Investor Briefing, Finance
5 October 2016
8
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Onshore US
Capturing full resource value
Alex Archila Asset President, Shale

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Statement of Petroleum Resources
Petroleum Resources
The estimates of Petroleum Reserves and Contingent Resources contained in this presentation are based on, and fairly represent, information and supporting documentation prepared under the supervision of Mr. A. G. Gadgil, who is employed by BHP Billiton. Mr. Gadgil is a member of the Society of Petroleum Engineers and has the required qualifications and experience to act as a qualified Petroleum Reserves and Resources evaluator under the ASX Listing Rules. This presentation is issued with the prior written consent of Mr. Gadgil who agrees with the form and context in which the Petroleum Reserves and Contingent Resources are presented.
Reserves and Contingent Resources are net of royalties owned by others and have been estimated using deterministic methodology. Aggregates of Reserves and Contingent Resources estimates contained in this presentation have been calculated by arithmetic summation of field/project estimates by category with the exception of the North West Shelf (NWS) Gas Project in Australia. Probabilistic methodology has been utilised to aggregate the NWS Reserves and Contingent Resources for the reservoirs dedicated to the gas project only and represents an incremental 39 MMboe of Proved Reserves. The barrel of oil equivalent conversion is based on 6000 scf of natural gas equals 1 boe. The Reserves and Contingent Resources contained in this presentation are inclusive of fuel required for operations. The respective amounts of fuel for each category are provided by footnote for the resource graphics. The custody transfer point(s)/point(s) of sale applicable for each field or project are the reference point for Reserves and Contingent Resources. Reserves and Contingent Resources estimates have not been adjusted for risk. Unless noted otherwise, Reserves and Contingent Resources are as of 30 June 2016. Where used in this presentation, the term Resources represents the sum of 2P reserves and 2C Contingent Resources.
BHP Billiton estimates Proved Reserve volumes according to SEC disclosure regulations and files these in our annual 20-F report with the SEC. All Unproved volumes are estimated using SPE-PRMS guidelines, which among other things, allow escalations to prices and costs, and as such, would be on a different basis than that prescribed by the SEC, and are therefore excluded from our SEC filings. All Resources and other Unproved volumes may differ from and may not be comparable to the same or similarly-named measures used by other companies. Non-proved estimates are inherently more uncertain than proved.
Table 1 Net BHP Billiton Petroleum Reserves and Contingent Resources as of 30 June 2016
Onshore US Offshore US Australia Rest of World
Net MMboe Eagle Ford & Permian Haynesville & Fayetteville Subtotal Gulf of Mexico Offshore Western Australia1, 2 Bass Strait & Offshore Victoria Subtotal Trinidad & Tobago Algeria United Kingdom & Other Subtotal Total BHP Billiton
Proved 124 173 298 210 414 303 717 56 22 - 78 1,303
Probable 1,433 1,273 2,707 127 59 94 153 17 10 - 27 3,013
2P 1,558 1,447 3,004 337 473 397 869 73 32 - 105 4,316
2C 1,547 1,782 3,329 392 1,099 153 1,252 52 18 20 89 5,061
2P+2C 3,105 3,228 6,333 729 1,571 550 2,121 124 50 20 194 9,377
Fuel included above
Proved 2.0 5.0 7.0 5.8 36.5 16.9 53.4 1.4 1.3 - 2.8 69.0
Probable 33.2 22.2 55.4 3.2 3.6 4.7 8.3 - - - - 66.8
2P 35.2 27.2 62.4 8.9 40.0 21.7 61.7 1.4 1.3 - 2.8 135.8
2C 27.3 41.4 68.7 5.8 113.4 6.8 120.2 - - - - 194.7
2P+2C 62.5 68.6 131.1 14.8 153.4 28.5 181.9 1.4 1.3 - 2.8 330.6
1) Includes NWS Gas Project probabilistic increment noted in disclaimer above.
2) Australian resources prior to the announced agreement by Woodside to acquire 50% of BHP Billiton Scarborough area assets.
The SEC permits oil and gas companies, in their filings with the SEC, to disclose only Proved, Probable and Possible Reserves, and only when such Reserves have been determined in accordance with SEC guidelines. We use certain terms in this presentation such as “Resources,” “Contingent Resources,” “2C Contingent Resources” and similar terms as well as Probable Reserves not determined in accordance with the SEC’s guidelines, all of which measures we are strictly prohibited from including in filings with the SEC. These measures include Reserves and Resources with substantially less certainty than Proved Reserves. U.S. investors are urged to consider closely the disclosure in our Form 20-F for the fiscal year ended June 30, 2016, File No. 001-09526 and in our other filings with the SEC, available from us at http://www.bhpbilliton.com/. These forms can also be obtained from the SEC as described above.
BHP Billiton Investor Briefing, Onshore US
5 October 2016 3 bhpbilliton

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Capturing full resource value
Large, quality resource supports returns and optionality
- 3 Bboe 2P1 reserves including ~500 MMbbls of oil
- up to 1,200 net liquids-rich wells deliver at least 15% IRR at US$50/bbl, contingent upon trials in Eagle Ford
- up to 220 net dry gas wells deliver at least 15% IRR at US$3/MMbtu
- pursuing additional resource potential across all fields
Productivity is increasing recoveries and lowering breakevens
- well costs and field operating costs down ~30% in FY16
- superior well performance in Black Hawk and Permian
- return to drilling in Haynesville supported by hedging program
Capturing full resource value while driving returns and free cash flow
- potential to remain cash flow positive at a range of consensus prices through investment flexibility
- significant net cash flow could be generated at average analyst prices, with low cost of carry at low prices and upside at higher prices
- will consider monetisation of long-dated dry gas options for value
1. Total Proved reserves: 0.3 Bboe, Probable reserves: 2.7 Bboe, includes fuel consumed in operations: Proved: 7 MMboe, Probable: 55 MMboe.
BHP Billiton Investor Briefing, Onshore US
5 October 2016 4 bhpbilliton

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Approximately 850k net acres across four large fields
Eagle Ford
largest component of current production
liquids-rich acreage in Black Hawk
mix of condensate and dry gas acreage in Hawkville
Permian
liquids-rich with multiple productive horizons
clear line of sight to full pad development within 2-3 years
Haynesville
high-pressure / high-recovery dry gas wells
accelerating high-return development through productivity
Fayetteville
low technical risk, long-term dry gas option
Outline of BHP Billiton Onshore US acreage by play
Fayetteville
Oklahoma
New Mexico
Arkansas
Haynesville
Mississippi
Permian
Texas
Eagle Ford
Louisiana
Black Hawk
Hawkville
Liquids-rich
Dry gas
BHP Billiton Investor Briefing, Onshore US
5 October 2016 5 bhpbilliton

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Responding to market while improving capital efficiency
Production growth over FY12 to FY15 (14% CAGR) demonstrates rapid growth potential with new investment
Reduction in capital investment since FY15 highlights flexibility to dynamically respond to changing market conditions
Productivity has further improved capital efficiency and partially offset production impact of lower investment
- ~85% capital reduction in FY15-17e
- ~35% production decline in FY15-17e
1. Source: BHP Billiton analysis.
2. Source: Energy Information Administration (EIA).
Onshore US production1 Onshore US capital1
(MMboe, BHP Billiton share) (US$ billion, BHP Billiton share)
150 6
125 5
100 4
75 3
50 2
25 1
0 0
FY12 FY13 FY14 FY15 FY16 FY17e
Oil NGLs Gas Capital investment
Average WTI oil prices2
(US$ per barrel)
FY12 FY13 FY14 FY15 FY16
95 92 101 69 42
BHP Billiton Investor Briefing, Onshore US
5 October 2016 6 bhpbilliton

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3 Bboe 2P reserves including ~500 MMbbls of oil
Onshore US reserves and resources1, 2, 3
(as at 30 June 2016, Bboe, BHP Billiton share)
2.5
2.0
1.5
1.0
0.5
0.0
Haynesville Permian Hawkville Fayetteville Black Hawk
Reserves Contingent resources
1. Total Proved reserves: 0.3 Bboe, Probable reserves: 2.7 Bboe, Contingent resources: 3.3 Bboe.
2. 2016 year-end 2P+2C resources totaled 6.3 Bboe or a net reduction of 1.2 Bboe from FY15. The overall resource reduction was a result of production of 0.1 Bboe, new additions of 2C resources of 0.3 Bboe, divestments and lease expiries of 1.3 Bboe and other revisions of -0.1 Bboe.
3. Includes fuel consumed in operations: Proved: 7 MMboe, Probable: 55 MMboe, Contingent: 69 MMboe.
Onshore US resources by product1, 2, 3
(as at 30 June 2016, Bboe, BHP Billiton share)
2.5
2.0
1.5
1.0
0.5
0.0
Haynesville Permian Hawkville Fayetteville Black Hawk
Oil NGLs Gas
BHP Billiton Investor Briefing, Onshore US
5 October 2016 7 bhpbilliton

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Continuing to deliver material well cost savings
Well costs down ~40% over the past two years with further reductions in FY17
Large portion of drilling cost reductions will be maintained independent of price environment
- drilling rate increased up to 50%
- rig move time reduced by ~50%
Similar cost reductions achieved in well-site facilities
1. Drilling and completion costs are not normalised for lateral length. Black Hawk drilling cost calculated for 2-string wells only. Permian drilling and completion costs calculated using North Reeves activities. Completion costs exclude trials.
Reduction in Black Hawk well costs1
(US$ million, 100% basis)
10
8
6
4
2
0
FY14 FY15 FY16 FY17e
Drilling cost Completion cost
Reduction in Permian well costs1
(US$ million, 100% basis)
15
10
5
0
FY14 FY15 FY16 FY17e
Drilling cost Completion cost
BHP Billiton Investor Briefing, Onshore US
5 October 2016 8 bhpbilliton

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Operating productivity delivering significant savings
~30% reduction in field operating costs relative to FY15
- embedded tools and practices originally developed by Minerals business
- rapid progress enabled by reduction in activity levels
Absolute cost reductions continue in FY17
~20% reduction in G&A1 costs relative to FY15
1. General & Administrative costs.
2. Upstream field operating costs include lifting, workovers and other field costs; does not include midstream, secondary taxes or Freight, Selling & Distribution (FS&D) costs.
Reduction in upstream field operating costs
(US$ million, BHP Billiton share)
60
40 FY15 average
20
FY16 actual
0
Jul 15 Aug 15 Sep 15 Oct 15 Nov 15 Dec 15 Jan 16 Feb 16 Mar 16 Apr 16 May 16 Jun 16
Upstream field operating costs improvement by field2
(US$/boe)
15 10 5 0
Black Hawk Hawkville Permian Haynesville Fayetteville
FY15 FY16
BHP Billiton Investor Briefing, Onshore US
5 October 2016 9 bhpbilliton

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Superior well performance in core liquids-rich fields
Condensate production in the first 12 months outperforms peers in both Black Hawk and Permian
First-mover position and reservoir/fluid quality in both basins provide an advantage over the competition
Continuous incremental completion optimisations further reduce costs and improve recoveries
Source: IHS, BHP Billiton analysis.
1. Cumulative production on single well basis calculated from total monthly production divided by well count for each operator. Peer selection based on well count, rig activity and offset acreage. Analysis excludes peers with less than five comparable wells.
2. Data normalised for 5,000 ft lateral length.
3. Peers are Conoco, EOG, Marathon and Pioneer.
4. Peers are Anadarko, Cimarex, EOG and RKI/WPX.
Black Hawk well performance relative to peers1, 2, 3
(cumulative production, gross condensate Mbbls)
200
150
100
50
0
0 1 2 3 4 5 6 7 8 9 10 11 12
Months from first production
BHP Billiton Peers
Permian Upper Wolfcamp well performance relative to peers1, 2, 4
(cumulative production, gross condensate Mbbls)
200
150
100
50
0
0 1 2 3 4 5 6 7 8 9 10 11 12
Months from first production
BHP Billiton Peers
BHP Billiton Investor Briefing, Onshore US
5 October 2016 10 bhpbilliton

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Black Hawk: expanding inventory
Current production of ~55 Mboe/d (net)
De-risking future development areas through ongoing trials
- ongoing Lower Eagle Ford (LEF) trials in Southwest and upcoming trials in Northeast
- ongoing Upper Eagle Ford (UEF) trial with encouraging results from nearby operators
Majority of DUCs1 inventory (~45 of ~55 net wells)2 expected to come online in FY17
Existing and potential Black Hawk well inventory2
(net wells)
600
400
200
0
Producing wells Future potential
Upper Eagle Ford
Main & Karnes
Southwest
Northeast
DUCs
1. Drilled but Uncompleted wells.
2. As at 30 June 2016.
Black Hawk field acreage
UEF potential
Main
Northeast
Karnes
UEF/LEF trial area
Southwest
Additional UEF potential
Core area - developed Lower Eagle Ford acreage
BHP Billiton Investor Briefing, Onshore US
5 October 2016 11 bhpbilliton

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Hawkville: encouraging results from recent trials
Current production of ~30 Mboe/d (net)
Evaluating encouraging results from new completions designs trialled by both BHP Billiton and other operators
~230 net wells delivering at least 15% IRR at $50/bbl
Majority of drilling obligations successfully deferred to FY18
Evaluating divestment of less competitive dry-gas areas for value
Hawkville acreage
Oil
Condensate / Wet gas
Dry gas
BHP Billiton operates
BHP Billiton is a minority partner
BHP Billiton recent trials
Recent wells by third party
Hawkville trial results
(cumulative production, gross condensate Mbbls)
150
100
50
0
0 1 2 3 4 5 6 7 8 9 10 11 12
Months from first production
Old design parent well Old design in-fill well New design in-fill well
BHP Billiton Investor Briefing, Onshore US
5 October 2016 12 bhpbilliton

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Permian: clear line of sight to development
Current production of ~30 Mboe/d (net)
- one rig focused on ~100 remaining obligation wells (gross)
- recent acreage swaps to enable longer laterals
Progressing toward full pad development in FY19 with six rigs
- potential ~150 Mboe/d (net) within four years of development start
- targeting multi-horizon Wolfcamp development
Possible Permian path to full development
FY16 FY17 FY18 FY19
Hold-by-production (HBP) drilling
Midstream strategy Midstream execution
Completion trials
UWC-MWC stagger trial
Optimal spacing trials
Pad development
Permian core acreage and producing wells
New Mexico
Texas
Acreage held
Acreage requiring HBP drilling
Producing wells
BHP Billiton Investor Briefing, Onshore US
5 October 2016 13 bhpbilliton

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Haynesville: recommenced high-return drilling program
Current production of ~50 Mboe/d (net)
Commenced drilling 16 well (gross) program in October with >30% returns1
- production hedged at ~US$3/MMbtu
- supply contracts locked for key services
- executing long laterals and optimised completion design
Working towards drilling ~100 additional wells (gross) beginning as early as FY18
Evaluating divestment of less competitive acreage for value
1. Incremental economics exclude otherwise unutilised transportation cost.
Haynesville acreage and core development area
Texas
Louisiana
BHP Billiton operates
HP Billiton is a minority partner
core development area
BHP Billiton Investor Briefing, Onshore US
5 October 2016 14 bhpbilliton

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Fayetteville: low technical risk, long-term option
Current production of ~45 Mboe/d (net)
Extensively drilled with low geological risk
Investment limited to minimal OBO1 elections
Working with partners to assess new potential Moorefield horizon
1. Operated by others.
Fayetteville acreage
BHP Billiton operates
BHP Billiton is a minority partner
BHP Billiton-owned midstream
BHP Billiton Investor Briefing, Onshore US
5 October 2016 15 bhpbilliton

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Large and improving investable inventory
Attractive investment options at relatively low prices
- ~1,200 net liquids-rich wells deliver at least 15% IRR at US$50/bbl
- ~220 net dry gas wells deliver at least 15% IRR at US$3/MMbtu
Ongoing trials to confirm improved productivity at Lower Eagle Ford (LEF) and the extent of Upper Eagle Ford (UEF) potential
Capital allocation will time investment to maximise value and optimise free cash flow
1. 15% rate of return under constant WTI oil and Henry Hub gas prices; liquids analysis assumes US$3.00/MMbtu Henry Hub gas price and NGL prices as a percentage of WTI. Incremental G&A not included for economic inventory; organisation is scalable for growth.
2. Where applicable, economics do not include Freight, Selling & Distribution (FS&D) costs.
3. Inventory includes only BHP Billiton-operated investments; information relating to non-operated inventory is included in the Appendix.
Liquids-rich portfolio delivering 15% returns at flat price bands1, 2, 3
(net working interest wells, US$/bbl)
1,250
1,000 Permian Hawkville Black Hawk LEF Black Hawk UEF
750
500
250
0
<50 50-60 60-70 70-80
Expected performance
<50 50-60 60-70 70-80
Excluding trial success
Dry gas portfolio delivering 15% returns at flat price bands1, 2, 3
(net working interest wells, US$/MMbtu)
750
500
250
0
<3.00 3.00-3.50 3.50-4.00
Haynesville Fayetteville
BHP Billiton Investor Briefing, Onshore US
5 October 2016 16 bhpbilliton

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Price scenarios
A range of possible price scenarios derived from analysts’ forecasts.
West Texas Intermediate crude oil consensus prices
(US$/bbl, nominal)
100
90 Scenario 2
(High consensus)
80 Scenario 1
(Average consensus)
70
Scenario 3
60 (Low consensus)
50
40
30
FY17e FY18e FY19e FY20e FY21e FY22e
Henry Hub natural gas consensus prices
(US$/MMbtu, nominal)
4.50
4.25
Scenario 2
(High consensus)
4.00
3.75
Scenario 1
(Average consensus)
3.50
3.25 Scenario 3
(Low consensus)
3.00
2.75
2.50
FY17e FY18e FY19e FY20e FY21e FY22e
Note: Range of possible price scenarios is presented for illustrative purposes; this range does not necessarily correspond to BHP Billiton’s view of prices going forward.
BHP Billiton Investor Briefing, Onshore US
5 October 2016 17 bhpbilliton

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Operational capability to respond to market conditions
Scenario 11, 2, 3
Mid activity based on consensus average prices
Gross operated rigs Capital investment
(annual average) (US$ billion, net, nominal)
21 3.5
18 3.0
15 2.5
12 2.0
9 1.5
6 1.0
3 0.5
0 0.0
FY17e FY18e FY19e FY20e FY21e FY22e
Black Hawk
Scenario 21, 2, 3
High activity based on consensus high prices
Gross operated rigs Capital investment
(annual average) (US$ billion, net, nominal)
21 3.5
18 3.0
15 2.5
12 2.0
9 1.5
6 1.0
3 0.5
0 0.0
FY17e FY18e FY19e FY20e FY21e FY22e
Hawkville Permian Haynesville
Scenario 31, 2, 3
Low activity based on consensus low prices
Gross operated rigs Capital investment
(annual average) (US$ billion, net, nominal)
21 3.5
18 3.0
15 2.5
12 2.0
9 1.5
6 1.0
3 0.5
0 0.0
FY17e FY18e FY19e FY20e FY21e FY22e
Capital investment
Note: Gross operated rig count and capital investment estimates for FY18 onwards represent possible responses to price scenarios. Scenarios do not constitute guidance; actual response will be determined according to market conditions prevailing at the relevant time.
1. Source: BHP Billiton analysis.
2. FY17 includes non-rig driven capital associated with Black Hawk DUC inventory.
3. Includes non-operated capital associated with investments in new wells operated by others (see Appendix for OBO information), and non-well specific capital investments (e.g. Permian water infrastructure, artificial lift, etc.).
BHP Billiton Investor Briefing, Onshore US
5 October 2016 18 bhpbilliton

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Ability to quickly adjust production response
Potential response in a range of price scenarios
- annual average base decline of ~15% in FY18-22
- volumes broadly flat in low price scenario from FY18 with key acreage retained
- volumes could more than double within five years in high price scenario with rig count capped at 20 to preserve productivity
Increased investment flexibility
- majority of long-term rig contracts expired or terminated
- organisation right-sized but scalable for growth
Onshore US potential production response1, 2
(MMboe, BHP Billiton share)
250
Scenario 2
200
Scenario 1
150
100
Scenario 3
50
Base decline (range)3
0
FY16 FY17e FY18e FY19e FY20e FY21e FY22e
Note: Production estimates for FY18 onwards represent potential outcomes from possible responses to price scenarios.
Scenarios do not constitute guidance; actual production will be determined according to market conditions prevailing at the relevant time.
1. Source: BHP Billiton analysis.
2. Base production and scenarios include BHP Billiton’s share of production from wells operated by others.
3. Over the period FY17-22, portion of crude/condensate comprising base production is expected to decline from 25% to 20%, portion of NGLs is expected to decline from 14% to 13%, and portion of dry gas is expected to increase from 61% to 67%.
BHP Billiton Investor Briefing, Onshore US
5 October 2016 19 bhpbilliton

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Maximising value and cash flow
Potential to remain cash flow positive under the three price scenarios outlined
Flexibility remains to pivot toward higher or lower activity levels in any given year in response to market conditions
Progressing development with a commercial mindset
- disciplined capital allocation
- executed gas hedge with more under evaluation
- pursuing monetisation of long-dated options (~US$100 million proceeds for non-core acreage closed or nearing close in FY17)
Onshore US potential pre-tax free cash flow1, 2
(US$ billion, BHP Billiton share, nominal)
4
Scenario 2
2
Scenario 1
Scenario 3
0
(2)
History
(4)
FY12 FY13 FY14 FY15 FY16 FY17e FY18e FY19e FY20e FY21e FY22e
Note: Free cash flow estimates for FY17 onwards represent potential outcomes from possible responses to price scenarios.
Scenarios do not constitute guidance; actual response will be determined according to market conditions prevailing at the relevant time.
1. Pre-tax free cash flow: EBITDA less capital expenditure. Excludes working capital in FY17e-22e.
2. Source: BHP Billiton analysis.
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5 October 2016 20 bhpbilliton

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Appendices

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Key well parameters: Black Hawk
<$50/bbl1 $50-60/bbl wells1 $60-70/bbl wells1
Total acreage (thousand acres) 97
Rig line efficiency 30 wells / year2
Future well locations (gross) 4893 70 67
Average WI/NRI 54% / 41% 50% / 37% 57% / 43%
Gross well capex (real US$ million) 5.22 5.62 5.32
Total production over life (million boe) 0.6 0.7 0.8
30-day IP (boe/day) 1,400 1,300 900
3-year cumulative production (million boe) 0.4 0.4 0.5
Gross cash costs (real US$)4 3,000/well/month + 6.00/boe 3,000/well/month + 6.00/boe 3,000/well/month + 6.25/boe
Product mix, crude / residue gas / NGLs 60% / 23% / 17% 36% / 35% / 29% 23% / 44% / 33%
1. Required flat WTI price to deliver 15% rate of return. Analysis assumes US$3.00/MMbtu Henry Hub gas price and NGL prices as a percentage of WTI.
2. Cost and rig efficiency as of FY17 start. Figures do not include further productivity improvements and capex savings that are included in the scenarios provided.
3. Excludes 97 gross (~55 net working interest) DUCs.
4. Excludes G&A and severance tax; these costs are included in the scenarios provided.
BHP Billiton Investor Briefing, Onshore US
5 October 2016 23 bhpbilliton

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Key well parameters: Hawkville
<$50/bbl wells1 $50-60/bbl wells1 $60-70/bbl wells1
Total acreage (thousand acres) 248
Rig line efficiency 30 wells / year2
Future well locations (gross)3 233 376 0
Average WI/NRI 98% / 73% 97% / 73% n/a
Gross well capex (real US$ million) 5.42 5.52 n/a
Total production over life (million boe) 0.9 1.1 n/a
30-day IP (boe/day) 1,000 1,200 n/a
3-year cumulative production (million boe) 0.4 0.5 n/a
Gross cash costs (real US$)4 6,000/well/month + 6.50/boe 6,000/well/month + 6.50/boe n/a
Product mix, crude / residue gas / NGLs 36% / 35% / 29% 15% / 52% / 33% n/a
1. Required flat WTI price to deliver 15% rate of return. Analysis assumes US$3.00/MMbtu Henry Hub gas price and NGL prices as a percentage of WTI.
2. Cost and rig efficiency as of FY17 start. Figures do not include further productivity improvements and capex savings that are included in the scenarios provided.
3. Well count excludes ~60 OBO wells (BHP Billiton working interest).
4. Excludes G&A and severance tax; these costs are included in the scenarios provided.
BHP Billiton Investor Briefing, Onshore US
5 October 2016 24 bhpbilliton

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Key well parameters: Permian
<$50/bbl wells1 $50-60/bbl wells1 $60-70/bbl wells1
Total acreage (thousand acres) 123
Rig line efficiency 15 wells / year2
Future well locations (gross) 790 1523 3713
Average WI/NRI 84% / 63% 90% / 68% 83% / 63%
Gross well capex (real US$ million) 6.52 7.12, 3 6.12, 4
Total production over life (million boe) 0.8 0.8 0.5
30-day IP (boe/day) 1,400 1,300 900
3-year cumulative production (million boe) 0.5 0.5 0.3
Gross cash costs (real US$)4 12,500/well/month + 8.50/boe 12,500/well/month + 9.00/boe 12,500/well/month + 9.50/boe
Product mix, crude / residue gas / NGLs 46% / 27% / 27% 41% / 31% / 28% 43% / 30% / 27%
1. Required flat WTI price to deliver 15% rate of return. Analysis assumes US$3.00/MMbtu Henry Hub gas price and NGL prices as a percentage of WTI.
2. Cost and rig efficiency as of FY17 start. Figures do not include further productivity improvements and capex savings that are included in the scenarios provided.
3. Scenarios provided assume sequential development of Middle Wolfcamp (488 gross wells) leading to wellsite facilities capex savings of US$0.75 million per well (not reflected in capex above).
4. Excludes G&A and severance tax; these costs are included in the scenarios provided.
BHP Billiton Investor Briefing, Onshore US
5 October 2016 25 bhpbilliton

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Key well parameters: Haynesville
<$3/MMbtu wells1 $3-3.50/MMbtu wells1 $3.50-4/MMbtu wells1
Total acreage (thousand acres) 275
Rig line efficiency 12 wells / year2
Future well locations (gross)3 305 615 25
Average WI/NRI 72% / 55% 76% / 59% 86% / 71%
Gross well capex (real US$ million) 7.52 7.12 7.32
Total production over life (million boe) 2 1.2 1.2
30-day IP (boe/day) 2,100 1,500 1,200
3-year cumulative production (million boe) 1.3 0.8 0.6
Gross cash costs (real US$)4 5,000/well/month + 3.75/boe 5,000/well/month + 4.50/boe 5,000/well/month + 4.75/boe
Product mix, crude / residue gas / NGLs 0% / 100% / 0% 0% / 100% / 0% 0% / 100% / 0%
1. Required flat Henry Hub price to deliver 15% rate of return.
2. Cost and rig efficiency as of FY17 start. Figures do not include further productivity improvements and capex savings that are included in the scenarios provided.
3. Well count excludes ~110 OBO wells (BHP Billiton working interest).
4. Excludes G&A and severance tax; these costs are included in the scenarios provided.
BHP Billiton Investor Briefing, Onshore US
5 October 2016 26 bhpbilliton

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Key well parameters: Fayetteville
<$3/MMbtu wells1 $3-3.50/MMbtu wells1 $3.50-4/MMbtu wells1
Total acreage (thousand acres) 625
Rig line efficiency 31 well / year2
Future well locations (gross)3 0 21 275
Average WI/NRI n/a 52% / 43% 55% / 46%
Gross well capex (real US$ million) n/a 2.92 2.82
Total production over life (million boe) n/a 0.7 0.5
30-day IP (boe/day) n/a 500 400
3-year cumulative production (million boe) n/a 0.3 0.2
Gross cash costs (real US$)4 n/a 3,500/well/month + 2.25/boe 3,500/well/month + 3.50/boe
Product mix, crude / residue gas / NGLs n/a 0% / 100% / 0% 0% / 100% / 0%
1. Required flat Henry Hub price to deliver 15% rate of return.
2. Cost and rig efficiency as of FY17 start. Figures do not include further productivity improvements and capex savings that are included in the scenarios provided.
3. Well count excludes ~200 OBO wells (BHP Billiton working interest).
4. Excludes G&A and severance tax; these costs are included in the scenarios provided.
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Conventional Petroleum
Extending the production runway
Geraldine Slattery Asset President, Conventional

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Statement of Petroleum Resources
Petroleum Resources
The estimates of Petroleum Reserves and Contingent Resources contained in this presentation are based on, and fairly represent, information and supporting documentation prepared under the supervision of Mr. A. G. Gadgil, who is employed by BHP Billiton. Mr. Gadgil is a member of the Society of Petroleum Engineers and has the required qualifications and experience to act as a qualified Petroleum Reserves and Resources evaluator under the ASX Listing Rules. This presentation is issued with the prior written consent of Mr. Gadgil who agrees with the form and context in which the Petroleum Reserves and Contingent Resources are presented.
Reserves and Contingent Resources are net of royalties owned by others and have been estimated using deterministic methodology. Aggregates of Reserves and Contingent Resources estimates contained in this presentation have been calculated by arithmetic summation of field/project estimates by category with the exception of the North West Shelf (NWS) Gas Project in Australia. Probabilistic methodology has been utilised to aggregate the NWS Reserves and Contingent Resources for the reservoirs dedicated to the gas project only and represents an incremental 39 MMboe of Proved Reserves. The barrel of oil equivalent conversion is based on 6000 scf of natural gas equals 1 boe. The Reserves and Contingent Resources contained in this presentation are inclusive of fuel required for operations. The respective amounts of fuel for each category are provided by footnote for the resource graphics. The custody transfer point(s)/point(s) of sale applicable for each field or project are the reference point for Reserves and Contingent Resources. Reserves and Contingent Resources estimates have not been adjusted for risk. Unless noted otherwise, Reserves and Contingent Resources are as of 30 June 2016. Where used in this presentation, the term Resources represents the sum of 2P reserves and 2C Contingent Resources.
BHP Billiton estimates Proved Reserve volumes according to SEC disclosure regulations and files these in our annual 20-F report with the SEC. All Unproved volumes are estimated using SPE-PRMS guidelines, which among other things, allow escalations to prices and costs, and as such, would be on a different basis than that prescribed by the SEC, and are therefore excluded from our SEC filings. All Resources and other Unproved volumes may differ from and may not be comparable to the same or similarly-named measures used by other companies. Non-proved estimates are inherently more uncertain than proved.
Table 1 Net BHP Billiton Petroleum Reserves and Contingent Resources as of 30 June 2016
Onshore US Offshore US Australia Rest of World
Net MMboe Eagle Ford & Permian Haynesville & Fayetteville Subtotal Gulf of Mexico Offshore Western Australia1, 2 Bass Strait & Offshore Victoria Subtotal Trinidad & Tobago Algeria United Kingdom & Other Subtotal Total BHP Billiton
Proved 124 173 298 210 414 303 717 56 22 - 78 1,303
Probable 1,433 1,273 2,707 127 59 94 153 17 10 - 27 3,013
2P 1,558 1,447 3,004 337 473 397 869 73 32 - 105 4,316
2C 1,547 1,782 3,329 392 1,099 153 1,252 52 18 20 89 5,061
2P+2C 3,105 3,228 6,333 729 1,571 550 2,121 124 50 20 194 9,377
Fuel included above
Proved 2.0 5.0 7.0 5.8 36.5 16.9 53.4 1.4 1.3 - 2.8 69.0
Probable 33.2 22.2 55.4 3.2 3.6 4.7 8.3 - - 66.8
2P 35.2 27.2 62.4 8.9 40.0 21.7 61.7 1.4 1.3 - 2.8 135.8
2C 27.3 41.4 68.7 5.8 113.4 6.8 120.2 - - 194.7
2P+2C 62.5 68.6 131.1 14.8 153.4 28.5 181.9 1.4 1.3 - 2.8 330.6
1) Includes NWS Gas Project probabilistic increment noted in disclaimer above.
2) Australian resources prior to the announced agreement by Woodside to acquire 50% of BHP Billiton Scarborough area assets.
The SEC permits oil and gas companies, in their filings with the SEC, to disclose only Proved, Probable and Possible Reserves, and only when such Reserves have been determined in accordance with SEC guidelines. We use certain terms in this presentation such as “Resources,”“Contingent Resources,”“2C Contingent Resources” and similar terms as well as Probable Reserves not determined in accordance with the SEC’s guidelines, all of which measures we are strictly prohibited from including in filings with the SEC. These measures include Reserves and Resources with substantially less certainty than Proved Reserves. U.S. investors are urged to consider closely the disclosure in our Form 20-F for the fiscal year ended June 30, 2016, File No. 001-09526 and in our other filings with the SEC, available from us at http://www.bhpbilliton.com/. These forms can also be obtained from the SEC as described above.
BHP Billiton Investor Briefing, Conventional
5 October 2016 3 bhpbilliton

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Extending the production runway
Quality assets provide strong foundations
- low cost assets in stable political environments
- material player in chosen production heartlands
- strong free cash flow and returns through the price cycle
Operating and development excellence provides competitive advantage
- focus on safety and productivity continues to improve performance and protect margins
- low unit costs and deepwater drilling performance reflect leading operating and development capability
- operating and development competencies support acceleration of schedule from discovery to first oil
Multiple options to replenish oil reserves and extend production
- suite of high-return brownfield projects to offset near-term decline
- Mad Dog 2 investment decision expected in next six months with production from CY22 if approved
- currently exploring in deepwater basins of choice
BHP Billiton Investor Briefing, Conventional
5 October 2016 4 bhpbilliton

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Quality assets concentrated in Australia and GoM
Conventional production outlook
(FY17e, BHP Billiton share)
4th largest producer in GoM
Gulf of Mexico
33-35 MMboe
Trinidad & Tobago
5-6 MMboe
International other
3-4 MMboe
Crude & Condensate
NGL
Gas
LNG
Note: Based on FY17 forecast production. Size of bubbles scaled to overall production.
North West Shelf
28-30 MMboe
Australia operated
16-17 MMboe
2nd largest producer in Australia
Bass Strait
35-37 MMboe
BHP Billiton Investor Briefing, Conventional
5 October 2016 5 bhpbilliton

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1.3 Bboe 2P reserves including ~500 MMbbls of oil
Conventional reserves and resources1
(as at 30 June 2016, Bboe, BHP Billiton share)
2.5
2.0
1.5
1.0
0.5
0.0
Australia Gulf of Mexico Rest of World
Proved Probable Contingent Resources
1. Total Proved reserves: 1,005 MMboe, Probable reserves: 307 MMboe, 2C Contingent resources: 1,732 MMboe. Includes fuel consumed in operations: Proved: 62 MMboe, Probable: 11 MMboe, 2C Contingent Resources: 126 MMboe.
Conventional reserves and resources by product1
(as at 30 June 2016, Bboe, BHP Billiton share)
2.5
2.0
1.5
1.0
0.5
0.0
Australia Gulf of Mexico Rest of World
Oil NGLs Gas
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5 October 2016 6 bhpbilliton

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Strong cash flow through the price cycle
Attractive business at consensus prices over the next two years1:
- EBITDA margin of >70%
- EBITDA of ~US$3.5 billion per annum
- pre-tax free cash flow of ~US$2.7 billion per annum
- Return on Capital Employed of ~15%
Low unit cost legacy assets
High-margin low-risk life extension projects continue to yield strong cash flow and earnings
Future investment underpinned by operating cash flows
EBITDA1 EBITDA margin1
(US$ billion) (%)
4 80
2 70
0 60
FY16 FY17e FY18e
EBITDA EBITDA margin
Pre-tax free cash flow (FCF)1 Return on Capital Employed1
(US$ billion) (%)
4 20
2 10
0 0
FY16 FY17e FY18e
FCF ROCE
1. Pre-tax free cash flow, EBITDA, EBITDA margin and Return on Capital Employed estimates for FY17 onwards represents a scenario. Scenarios do not constitute guidance; actual response will be determined according to market conditions prevailing at the relevant time. Pre-tax free cash flow: EBITDA less capital and exploration expenditure. Excludes working capital.
BHP Billiton Investor Briefing, Conventional
5 October 2016 7
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Industry leading operating and development capabilities
Competitive with majors in deepwater drilling performance
Industry leading operating uptime and unit costs
Relentless focus on safety and productivity improvements
continuous improvement culture
latent capacity utilisation
supply chain, technology, work processes
GOM average drill time1,2
(days per 1,000 ft)
Majors Mid-tier
8
4
0
BHP Billiton Statoil Exxon Shell Chevron BP Anadarko Conoco Phillips Noble Apache Hess
Operating uptime3
(%)
100
75
50
25
0
FY14 FY15 FY16 FY17e
BHP Billiton Operated By Others
Deepwater GOM total operating costs (2016)4
(US$/boe)
15
10
5
0
Shenzi Atlantis Thunder Na Kika Blind Faith Mars Tahiti
(BHP (BP) Horse (BP) (BP) (Chevron) (Shell) (Chevron)
Billiton)
1. Deepwater Gulf of Mexico, sub-salt, 2013-2016.
Sources: 2. Rushmore, Offshore Oil Scouts Association (OOSA), BHP Billiton analysis. 3. BHP Billiton analysis. 4. Wood Mackenzie Oil Supply analysis.
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Brownfield and greenfield options to mitigate base decline
Protecting margins from existing assets
maintain industry leading operating and development performance
productivity and capital efficiency protect margins and cash flow
base and brownfield production robust across range of consensus prices
Suite of existing opportunities slow base decline
brownfield opportunities leverage existing infrastructure
Mad Dog 2 Final Investment Decision expected in FY17
Scarborough offers significant gas position
Significant deepwater exploration potential
targeting competitive economic developments in deepwater basins


Conventional brownfield extension and greenfield growth1
(MMboe, net)
150
125
100
75
50
25
0
FY17e	FY19e	FY21e	FY23e	FY25e	FY27e

Base
Brownfield
Mad Dog 2
Scarborough
Risked exploration success
1. Production estimates for FY18 onwards represents a scenario. Scenarios do not constitute guidance; actual production will be determined according to market conditions prevailing at the relevant time. Assumes sell down of 50% of BHP Billiton’s interest in Scarborough.
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5 October 2016
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Rich portfolio of brownfield opportunities High-return brownfield projects in execution North West Shelf (NWS) GWF-A first production achieved Q4 CY15 with all wells producing within FY17 Angostura Phase 3 first production achieved in September 2016 Bass Strait Longford Gas Conditioning Plant 99% complete with first production anticipated in Q4 CY16 Persephone tieback to NWS North Rankin platform with first production anticipated in CY17 NWS GWF-B anticipated to achieve first production in CY19 and all wells producing by CY20 Further near-term development projects Atlantis, Mad Dog Spar A Development and infill wells offer robust returns multiple investment opportunities remain in Bass Strait: West Barracouta, Kipper, Snapper and Tuna areas Exmouth sub-basin potential being evaluated to leverage existing Pyrenees and Macedon infrastructure
Brownfield growth capital1
(US$ million nominal, net, FY17-21 forecast)
1,600
US$0.25 billion NPV.
Bubble size
1,400
represents NPV.
Gulf of Mexico
1,200
(Atlantis, Mad Dog Spar A, Shenzi)
1,000
800
Australia - other
600
NWS GWF-B 400
Angostura Ph. 3
Persephone
200 Rest of World BS LGCP
0
NWS GWF-A
0
20
40
60
80
IRR (%, nominal)
Australia
Gulf of Mexico
Rest of World
1. Gulf of Mexico spend excludes Mad Dog 2. BHP Billiton Investor Briefing, Conventional 5 October 2016 10 bhpbilliton

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Greenfield developments provide longer term optionality
Mad Dog Phase 2
Capital estimate halved since 2013 – field development plan optimisation – standardisation – design simplification – capture market deflation
Wet tree subsea development supported by a floating semi-submersible production and water injection facility
Final Investment Decision expected in next six months with first production in CY22 if approved
Scarborough
Large gas resource with development concept optionality
Potential aggregator within geographic area
Mad Dog 2 concept
BHP Billiton Investor Briefing, Conventional
5 October 2016
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Accelerating development schedule post discovery
Leveraging deepwater development capabilities
positioned to capitalise on industry leading geological, development and operating capabilities
Accelerating discovery to production cycle
targeting ~20% reduction in development time
evaluating development concepts in parallel with appraisal
pre-screening vendors
applying standard industry solutions vs bespoke design
Project development timeline
Industry average
First Oil 12.5 years
75 months
Explore
Appraise
Identification Select Define Execute
Produce
Technology
Contactors
Concept
BHP Billiton
First Oil 11 years
59 months
Appraise /
Select Define
Explore
Produce Identification
Execute
Source: Wood Mackenzie and Performance Forum JIP Benchmark Data for comparable generic project description.
BHP Billiton Investor Briefing, Conventional
5 October 2016
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Extending the production runway
Quality assets provide strong foundations
low cost assets in stable political environments
material player in chosen production heartlands
strong free cash flow and returns through the price cycle
Operating and development excellence provides competitive advantage
focus on safety and productivity continues to improve performance and protect margins
low unit costs and deepwater drilling performance reflect leading operating and development capability
operating and development competencies support acceleration of schedule from discovery to first oil
Multiple options to replenish oil reserves and extend production
suite of high-return brownfield projects to offset near-term decline
Mad Dog 2 investment decision expected in next six months with production from CY22 if approved
currently exploring in deepwater basins of choice
BHP Billiton Investor Briefing, Conventional
5 October 2016
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Appendices

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Australia non-operated focus areas

Bass Strait
Delivery of Longford Gas Conditioning Plant project in Q4 CY16
Progressing multiple investment opportunities
– West Barracouta
– Kipper
– Snapper
– Tuna
Targeted divestment of mature Bass Strait oil assets
North West Shelf
Executing brownfield projects
– GWF A and B
– Persephone
Assessing ullage opportunities
Bass Strait
Operator
Esso
BHP Billiton
GBJV 50.0%
Ownership
KUJV 32.5%
First
1969
Resources2,3
production
FY16
35.3MMboe
2C
28%
production1
P1
55%
P2
Resources2
548MMboe
17%
NWS
Operator Woodside
BHP Billiton ~13% NRI over 9 separate JV
Ownership agreements
First
1984
Resources2,3
production
2C FY16
17%
27.5MMboe
P2 production1
7%
P1 Resources2
401MMboe
76%
1. MMboe, BHP Billiton share.
2. 2P+2C remaining resources as at 30 June 2016, BHP Billiton share.
3. Fuel included in P1, P2 and 2C respectively: Bass Strait: 16.9, 4.7, 6.8 MMboe; NWS: 33.5, 1.4, 7.5 MMboe.
BHP Billiton Investor Briefing, Conventional
5 October 2016
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Australia operated focus areas
Pyrenees
• Phase 3 infill program executed in FY16
• Phase 4 infill opportunities being assessed
• Supporting Exmouth basin seismic appraisal of the region
Macedon
• Optimising value through utilisation of plant capacity by capturing spot gas sales
• Assessing timing of wet gas compression development
Pyrenees
Operator • BHP Billiton
BHP Billiton Ownership • 71.43%
First production • 2010 Resources2,3 2C 15% P1 55% P2 30%
FY16 production1 • 8.6MMboe
Resources2 • 52MMboe
Macedon
Operator • BHP Billiton
BHP Billiton Ownership • 71.43%
First production • 2013 Resources2,3
FY16 production1 • 8.5MMboe 2C 4%P2 16% P1 79%
Resources2 • 99MMboe
1. MMboe, BHP Billiton share.
2. 2P+2C remaining resources as at 30 June 2016, BHP Billiton share.
3. Fuel included in P1, P2 and 2C respectively: Pyrenees: 0.8, 1.5, 0 MMboe; Macedon: 2.2, 0.6, 0.1 MMboe.
BHP Billiton Investor Briefing, Conventional
5 October 2016
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Gulf of Mexico focus areas
Atlantis
• Executing high-return multi-year infill program
Mad Dog
• Executing high-value multi-year Spar A infill program
• Progressing Mad Dog 2 for FID
Shenzi
• Maintaining industry leading production and water injection uptime
Atlantis
Operator • BP
BHP Billiton
Ownership • 44.0%
First production • 2007 Resources2,3
FY16 production1 2C P1 • 18.3MMboe 28% 36% P2
Resources2 • 225Mmboe 36%
Mad Dog
Operator • BP
BHP Billiton
Ownership • 23.9%
First production • 2005
Resources2,3 P1
FY16 17% production1 • 3.5MMboe
P2 2C 8%
Resources2 • 329MMboe 75%
Shenzi
Operator
• BHP Billiton
BHP Billiton
Ownership • 44.0% First • 2009
Resources2,3 production P1 41%
FY16 • 13.7MMboe 2C production1 48% P2
Resources2 • 168MMboe 11%
1. MMboe, BHP Billiton share.
2. 2P+2C remaining resources as at 30 June 2016, BHP Billiton share.
3. Fuel included in P1, P2 and 2C respectively: Atlantis: 2.6, 2.6, 0 MMboe; Mad Dog: 1.0, 0.2, 5.7 MMboe; Shenzi: 1.9, 0.3, 0 MMboe.
BHP Billiton Investor Briefing, Conventional
5 October 2016
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Rest of World assets
Angostura
Angostura Phase 3 completed
Supporting exploration in the region
Algeria
Production Sharing Contract 10 year extension signed
Progressing government approval of extension
Executing infill program
North Sea
End of field life planning
Angostura
Operator
BHP Billiton
BHP Billiton
45.0% Block 2(c)
Ownership
25.5% Block 3(a)
First
2005
Resources2,3
production
FY16
2C
5.9MMboe
41%
production1
P1
45%
P2
Resources2
124MMboe
13%
Algeria (ROD)
Operator
Groupement Sonatrach Agip
BHP Billiton
Ownership
45.0%
First
2004
Resources2,3
production
FY16
2C
P1
production1
3.7MMboe
35%
45%
P2
Resources2
50MMboe
20%
North Sea
Operator
BP
BHP Billiton
16.0% Bruce
Ownership
31.83% Keith
First
1993 Bruce
Resources2,3
production
2000 Keith
P2
FY16
4%
production1
1.0MMboe
2C
Resources2
7MMboe
96%
1. MMboe, BHP Billiton share.
2. 2P+2C remaining resources as at 30 June 2016, BHP Billiton share.
3. Fuel included in P1, P2 and 2C respectively: Angostura: 1.5, 0, 0 MMboe; Algeria: 1.3, 0, 0 MMboe; North Sea: nil.
BHP Billiton Investor Briefing, Conventional
5 October 2016
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bhpbilliton
Petroleum Exploration
Finding the next wave of conventional growth
Niall McCormack Vice President Exploration, Petroleum
Deepwater Invictus

LOGO

Disclaimer
Forward-looking statements
This presentation contains forward-looking statements, including statements regarding: reserves and resources and the production, revenues and costs relating thereto, 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 presentation. Readers are cautioned not to put undue reliance on forward-looking statements.
For example, future revenues from our operations, other results, projects or mines described in this presentation will be based, in part, upon the market price of the minerals, metals or petroleum produced, which may vary significantly from current levels. These variations, if materially adverse, may affect the timing or the feasibility of the development of a particular project, the expansion of certain facilities or mines, the continuation of existing operations.
Other factors that may cause actual results to differ from those expressed in the forward-looking statements include uncertainties in estimating reserves, difficulties in converting resources into reserves and reserves into quantities of oil and gas, operating risks, changes in operating costs, factors that 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 Billiton’s filings with the US Securities and Exchange Commission (the “SEC”) (including in Annual Reports on Form 20-F) which are available on the SEC’s website at www.sec.gov.
Except as required by applicable regulations or by law, the Group does not undertake any obligation to publicly update or review any forward-looking statements, whether as a result of new information or future events. Past performance cannot be relied on as a guide to future performance.
Non-IFRS financial information
BHP Billiton results are reported under International Financial Reporting Standards (IFRS) including Underlying EBIT and Underlying EBITDA which are used to measure segment performance. This release may also include certain non-IFRS and other financial measures including Adjusted effective tax rate, Free cash flow, Gearing ratio, Net debt, Net operating assets, Underlying attributable profit, Underlying basic (loss)/earnings per share, Underlying EBIT margin and Underlying EBITDA margin. These measures are used internally by management to assess the performance of our business, make decisions on the allocation of our resources and assess operational management. Non-IFRS and other financial 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.
Presentation of data
Unless specified otherwise: all data is presented on a continuing operations basis to exclude the contribution from assets that were demerged with South32; references to Underlying EBITDA margin exclude third party trading activities; data from subsidiaries is shown on a 100 per cent basis and data from equity accounted investments and other operations is shown on a proportionate consolidation basis. Numbers presented may not add up precisely to the totals provided due to rounding. Onshore US scenarios are based on price estimates from Bank of America Merrill Lynch, Citi, Credit Suisse, Deutsche Bank, JP Morgan, Macquarie, Morgan Stanley and UBS as at 8 August 2016 and do not necessarily correspond to BHP Billiton’s view of prices.
No offer of securities
Nothing in this presentation should be construed as either an offer to sell or a solicitation of an offer to buy or sell BHP Billiton securities in any jurisdiction, or be treated or relied upon as a recommendation or advice by BHP Billiton.
Reliance on third party information
The views expressed in this presentation contain information that has been derived from publicly available sources that have not been independently verified. No representation or warranty is made as to the accuracy, completeness or reliability of the information. This presentation should not be relied upon as a recommendation or forecast by BHP Billiton.
BHP Billiton Investor Briefing, Exploration
5 October 2016
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2012: 12 countries, 5 continents, over 100 prospects
Canada
Onshore US
Gulf of Mexico (US)
India Vietnam
Trinidad & Tobago Philippines
Colombia Malaysia Brunei
Australia
South Africa
Falkland Islands
BHP Billiton Investor Briefing, Exploration
5 October 2016
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2016: just 3 focus areas
Gulf of Mexico (US)
Mexico
Trinidad & Tobago
Barbados
Australia
Current exploration acreage position
Potential exploration position
BHP Billiton Investor Briefing, Exploration
5 October 2016
5
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Focused footprint offers large prospective upside
Upside is being de-risked by recent drilling successes
Gulf of Mexico (US)
Mexico
Trinidad & Tobago
Barbados
Significant potential in oil exploration over the next three years
(value1, BHP Billiton share)
Gulf of Mexico
Trinidad and Tobago
Western Australia
Risked
Unrisked
Australia
Current exploration acreage position
Potential exploration position
1. Under our long-term price forecasts; BHP Billiton share.
BHP Billiton Investor Briefing, Exploration
5 October 2016
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Testing three basins, six plays in three years
Exploration program timed to minimise cost while maximising value


FY16		FY17		FY18+

Reduced cycle time from access to drill through technology, right data, workflows

Explore

Shenzi North

LeClerc

Burrokeet

Scimitar

T&T


	Increased investment to appraise success
Appraise	Caicos	Wildling	Further Appraisal


GoM Miocene		Trinidad & Tobago Southern Neogene		Trinidad & Tobago Northern Paleogene		Future wells

BHP Billiton Investor Briefing, Exploration
5 October 2016
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Gulf of Mexico: Miocene success and Paleogene potential
Oil discoveries in central GoM Miocene
leverages our understanding from Shenzi, Mad Dog and Atlantis
oil discovered in multiple horizons at Shenzi North and Caicos
accelerating investment to follow-up on success – drilling Wildling in Q4 CY16
Established position in highly prospective US GoM subsalt Perdido Trend
Western GoM Paleogene play
multi-billion barrel potential in large reservoir system
dominant acreage holder
152 blocks containing 12 leads
large, high-equity, operated position
plan to drill first play test in CY18
Green Canyon and Perdido
A
Central Gulf of Mexico
(Caicos, Shenzi N, Wildling)
Scimitar
Mini-basin
Wildling
Mini-basin
Wildling
20 Km
Caicos
Atlantis
N
BHP Billiton Fields
Shenzi N
Shenzi
BHP Billiton Blocks
Neptune
Mad Dog
B
Western Gulf of Mexico
20 Km
(Paleogene)
N
BHP Billiton Prospects
Perdido Trend
Aug 2016 Lease Sale Blocks
BHP Billiton Blocks
US Gulf of Mexico
Houston
USA
A
B
200 Km
Perdido Trend
Mexico
N
Aug 2016 Lease Sale Blocks
BHP Billiton Blocks
N
200km
BHP Billiton Investor Briefing, Exploration
5 October 2016
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Mexico: a natural extension of our Perdido position
Early entrant opportunity for potential Tier 1
positioned to bid if prospects and fiscal terms are attractive
significant potential (>10 Bbbl unrisked)
pre-qualified as deepwater exploration operator
Perdido Trend
an extension of the US sub-salt Perdido play
high early success rates through limited drilling activity
Salinas Trend
very limited activity in deepwater to date
world-class source rock and large traps
Discovered resource opportunity
first Discovered Resource Round (Trion) planned for December 2016
one of six companies submitted as an operator
Mexican deep water bid round blocks
Houston
USA
Perdido Trend
Mexico
Salinas
200 Km
(Campeche)
N
Aug 2016 Lease Sale Blocks
BHP Billiton Blocks
Round 0 Pemex
Round 1
Round 2
Round 3
Round 4
BHP Billiton Investor Briefing, Exploration
5 October 2016
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Encouraging early results in the Caribbean
Tier 1 potential in Trinidad
large structures, world-class source rock
at least 12 significant leads and prospects
Accelerated program
from acreage access to first well in 3 years
8 well campaign at industry leading pace
Miocene1
LeClerc (65% operator, Shell 35%)
first Ultra-Deepwater Discovery in Caribbean at LeClerc
gas in multiple zones, oil shows at depth
encouraging results for play
Paleogene2
Burrokeet (70% operator, BP 30%)
first play test in northern Paleogene
1. BHP Billiton 65% operator, Shell 35% across all blocks.
2. Equity position and partners vary by block.
Geoseismic images of LeClerc and Burrokeet
Material operated Caribbean position
A Southern Trinidad &Tobago
(LeClerc) R R
R
1 km
Barbados B
A Trinidad &
Tobago
S B
Northern Trinidad & Tobago
(Burrokeet)
R S
1 km
Legend
BHP Billiton Blocks
LeClerc 1 and Burrokeet 1
BHP Billiton Investor Briefing, Exploration
5 October 2016
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Maximising value through operational excellence

Industry average
~60 months1

36 months

Industry average 75 months2

First Oil 14 years

Explore

Appraise

Select Define Execute

Produce

Technology

Right Data

Work flows

BHP Billiton 40 months

36 months

Industry average 75 months2

First Oil 12.5 years

Explore

Appraise

Select Define Execute

Produce

Technology

Shenzi North

Caicos

Wildling

LeClerc

Contactors

Burrokeet

Concept

BHP Billiton 40 months

36 months

BHP Billiton 59 months

First Oil 11 years

Benefits of reduced cycle time:
improved integration of technical work
enhanced strategic planning
value creation of US$100 million per
annum3

Explore

Appraise

Select Define Execute

Produce

Source: Wood Mackenzie, Performance Forum JIP Benchmark data, BHP Billiton analysis.
1. BHP Billiton analysis of Wood Mackenzie’s deepwater well dataset.
2. Performance Forum JIP Benchmark Data for comparable generic project description.
3. Assumes a success case for a 300 MMbbl oil field using BHP Billiton long-term price assumptions.
BHP Billiton Investor Briefing, Exploration
5 October 2016
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Multi-billion barrel risked potential in current program
Refocused portfolio on Tier 1 opportunities
from 12 countries to three focus areas
dominant acreage position in each basin and operatorship
prospective multi-billion barrel risked potential
100% success rate from three wells in 12 months
multiple oil shows at Shenzi North and Caicos in the GoM
large potential gas resource at LeClerc with encouraging oil shows at depth
Testing six plays and three basins in three years
accelerated drilling to take advantage of low-cost environment
potential discoveries commercial at less than US$50/bbl
Significant risked future production potential to be tested by
current drilling program1
(risked potential future production, MMboe, BHP Billiton share)
100
50
0
FY20e
FY25e
FY30e
FY35e
FY40e
FY45e
FY50e
Gulf of Mexico Trinidad & Tobago (Oil) Trinidad & Tobago (Gas)
Australia
1. Possible production profiles based on a simulation of risked success cases from the current exploration portfolio.
BHP Billiton Investor Briefing, Exploration
5 October 2016
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bhpbilliton
BHP Billiton Petroleum
Closing remarks
Steve Pastor President Operations, Petroleum

LOGO

Disclaimer
Forward-looking statements
This presentation contains forward-looking statements, including statements regarding: reserves and resources and the production, revenues and costs relating thereto, 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 presentation. Readers are cautioned not to put undue reliance on forward-looking statements.
For example, future revenues from our operations, other results, projects or mines described in this presentation will be based, in part, upon the market price of the minerals, metals or petroleum produced, which may vary significantly from current levels. These variations, if materially adverse, may affect the timing or the feasibility of the development of a particular project, the expansion of certain facilities or mines, the continuation of existing operations.
Other factors that may cause actual results to differ from those expressed in the forward-looking statements include uncertainties in estimating reserves, difficulties in converting resources into reserves and reserves into quantities of oil and gas, operating risks, changes in operating costs, factors that 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 Billiton’s filings with the US Securities and Exchange Commission (the “SEC”) (including in Annual Reports on Form 20-F) which are available on the SEC’s website at www.sec.gov.
Except as required by applicable regulations or by law, the Group does not undertake any obligation to publicly update or review any forward-looking statements, whether as a result of new information or future events. Past performance cannot be relied on as a guide to future performance.
Non-IFRS financial information
BHP Billiton results are reported under International Financial Reporting Standards (IFRS) including Underlying EBIT and Underlying EBITDA which are used to measure segment performance. This release may also include certain non-IFRS and other financial measures including Adjusted effective tax rate, Free cash flow, Gearing ratio, Net debt, Net operating assets, Underlying attributable profit, Underlying basic (loss)/earnings per share, Underlying EBIT margin and Underlying EBITDA margin. These measures are used internally by management to assess the performance of our business, make decisions on the allocation of our resources and assess operational management. Non-IFRS and other financial 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.
Presentation of data
Unless specified otherwise: all data is presented on a continuing operations basis to exclude the contribution from assets that were demerged with South32; references to Underlying EBITDA margin exclude third party trading activities; data from subsidiaries is shown on a 100 per cent basis and data from equity accounted investments and other operations is shown on a proportionate consolidation basis. Numbers presented may not add up precisely to the totals provided due to rounding. Onshore US scenarios are based on price estimates from Bank of America Merrill Lynch, Citi, Credit Suisse, Deutsche Bank, JP Morgan, Macquarie, Morgan Stanley and UBS as at 8 August 2016 and do not necessarily correspond to BHP Billiton’s view of prices.
No offer of securities
Nothing in this presentation should be construed as either an offer to sell or a solicitation of an offer to buy or sell BHP Billiton securities in any jurisdiction, or be treated or relied upon as a recommendation or advice by BHP Billiton.
Reliance on third party information
The views expressed in this presentation contain information that has been derived from publicly available sources that have not been independently verified. No representation or warranty is made as to the accuracy, completeness or reliability of the information. This presentation should not be relied upon as a recommendation or forecast by BHP Billiton.
BHP Billiton Investor Briefing, Petroleum Overview
5 October 2016
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Statement of Petroleum Resources
Petroleum Resources
The estimates of Petroleum Reserves and Contingent Resources contained in this presentation are based on, and fairly represent, information and supporting documentation prepared under the supervision of Mr. A. G. Gadgil, who is employed by BHP Billiton. Mr. Gadgil is a member of the Society of Petroleum Engineers and has the required qualifications and experience to act as a qualified Petroleum Reserves and Resources evaluator under the ASX Listing Rules. This presentation is issued with the prior written consent of Mr. Gadgil who agrees with the form and context in which the Petroleum Reserves and Contingent Resources are presented.
Reserves and Contingent Resources are net of royalties owned by others and have been estimated using deterministic methodology. Aggregates of Reserves and Contingent Resources estimates contained in this presentation have been calculated by arithmetic summation of field/project estimates by category with the exception of the North West Shelf (NWS) Gas Project in Australia. Probabilistic methodology has been utilised to aggregate the NWS Reserves and Contingent Resources for the reservoirs dedicated to the gas project only and represents an incremental 39 MMboe of Proved Reserves. The barrel of oil equivalent conversion is based on 6000 scf of natural gas equals 1 boe. The Reserves and Contingent Resources contained in this presentation are inclusive of fuel required for operations. The respective amounts of fuel for each category are provided by footnote for the resource graphics. The custody transfer point(s)/point(s) of sale applicable for each field or project are the reference point for Reserves and Contingent Resources. Reserves and Contingent Resources estimates have not been adjusted for risk. Unless noted otherwise, Reserves and Contingent Resources are as of 30 June 2016. Where used in this presentation, the term Resources represents the sum of 2P reserves and 2C Contingent Resources.
BHP Billiton estimates Proved Reserve volumes according to SEC disclosure regulations and files these in our annual 20-F report with the SEC. All Unproved volumes are estimated using SPE-PRMS guidelines, which among other things, allow escalations to prices and costs, and as such, would be on a different basis than that prescribed by the SEC, and are therefore excluded from our SEC filings. All Resources and other Unproved volumes may differ from and may not be comparable to the same or similarly-named measures used by other companies. Non-proved estimates are inherently more uncertain than proved.
Table 1 Net BHP Billiton Petroleum Reserves and Contingent Resources as of 30 June 2016
Onshore US
Offshore US
Australia
Rest of World
Net MMboe
Eagle Ford & Permian
Haynesville & Fayetteville
Subtotal
Gulf of Mexico
Offshore Western Australia1, 2
Bass Strait & Offshore Victoria
Subtotal
Trinidad & Tobago
Algeria
United Kingdom & Other
Subtotal
Total BHP Billiton
Proved
124
173
298
210
414
303
717
56
22
-
78
1,303
Probable
1,433
1,273
2,707
127
59
94
153
17
10
-
27
3,013
2P
1,558
1,447
3,004
337
473
397
869
73
32
-
105
4,316
2C
1,547
1,782
3,329
392
1,099
153
1,252
52
18
20
89
5,061
2P+2C
3,105
3,228
6,333
729
1,571
550
2,121
124
50
20
194
9,377
Fuel included above
Proved
2.0
5.0
7.0
5.8
36.5
16.9
53.4
1.4
1.3
-
2.8
69.0
Probable
33.2
22.2
55.4
3.2
3.6
4.7
8.3
-
-
-
-
66.8
2P
35.2
27.2
62.4
8.9
40.0
21.7
61.7
1.4
1.3
-
2.8
135.8
2C
27.3
41.4
68.7
5.8
113.4
6.8
120.2
-
-
-
-
194.7
2P+2C
62.5
68.6
131.1
14.8
153.4
28.5
181.9
1.4
1.3
-
2.8
330.6
1) Includes NWS Gas Project probabilistic increment noted in disclaimer above.
2) Australian resources prior to the announced agreement by Woodside to acquire 50% of BHP Billiton Scarborough area assets.
The SEC permits oil and gas companies, in their filings with the SEC, to disclose only Proved, Probable and Possible Reserves, and only when such Reserves have been determined in accordance with SEC guidelines. We use certain terms in this presentation such as “Resources,” “Contingent Resources,” “2C Contingent Resources” and similar terms as well as Probable Reserves not determined in accordance with the SEC’s guidelines, all of which measures we are strictly prohibited from including in filings with the SEC. These measures include Reserves and Resources with substantially less certainty than Proved Reserves. U.S. investors are urged to consider closely the disclosure in our Form 20-F for the fiscal year ended June 30, 2016, File No. 001-09526 and in our other filings with the SEC, available from us at http://www.bhpbilliton.com/. These forms can also be obtained from the SEC as described above.
BHP Billiton Investor Briefing, Petroleum Overview
5 October 2016
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An exciting outlook for our Petroleum business
Petroleum is core to BHP Billiton
strong financial and operating performance
oil and US gas markets expected to rebalance first
Petroleum strategy focused on value over volume
Concentrated resource base and proven operating capability
Onshore US – capturing full resource value while driving returns and free cash flow
Conventional – high margins with inventory of in-fill projects to offset field decline
Rich set of opportunities to drive valuable growth
Mad Dog 2 investment decision expected in next six months
Haynesville acceleration supported by hedging
Permian progressing towards full pad development in FY19
exploration program yielding encouraging results
would consider value accretive acquisitions
1. Production estimates for FY18 onwards represents a scenario. Scenarios do not constitute guidance; actual production will be determined according to market conditions prevailing at the relevant time.


Value accretive production potential over the next decade1
(BHP Billiton production, MMboe)
300
			Onshore US gas
200
			Onshore US liquids
100
0
FY17e	FY19e	FY21e	FY23e	FY25e


Base		Conventional in-fill
Mad Dog 2		Onshore US
Potential exploration success

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5 October 2016
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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.