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
December 10, 2013
| 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
| Company Secretariat |
| |||||
| BHP Billiton Limited | BHP Billiton Plc | |||||
| 171 Collins Street | Neathouse Place | |||||
| Melbourne Victoria 3000 Australia | London SW1V 1BH UK | |||||
| GPO BOX 86 | Tel +44 20 7802 4000 | |||||
| Melbourne Victoria 3001 Australia | Fax + 44 20 7802 4111 | |||||
| Tel +61 1300 554 757 Fax +61 3 9609 3015 | bhpbilliton.com | |||||
| bhpbilliton.com | ||||||
10 December 2013
| To: | Australian Securities Exchange1 | cc: | New York Stock Exchange | |||
| London Stock Exchange | JSE Limited |
INVESTOR BRIEFING
BHP Billiton President Petroleum and Potash, Tim Cutt, will present at the Company’s Petroleum investor briefing in Houston, USA on Tuesday, 10 December 2013.
When discussing his presentation, Mr Cutt said: “Our high quality resource portfolio is concentrated in our core regions of the United States and Australia, where we have a thorough understanding of the geology and a proven operating track record. Although our resource base could support substantially higher rates of investment, we will focus on value over volume. Our production guidance for the 2014 financial year remains unchanged at 250 million barrels of oil equivalent (BHP Billiton share).
“Our conventional oil and gas portfolio is the foundation of the Petroleum business and we expect to maintain steady production in the medium term by focusing on low risk, high return investments in proximity to existing infrastructure. This will include infill drilling at Shenzi, Pyrenees, Atlantis and Mad Dog where individual wells can deliver investment returns of over 90 per cent.”
When discussing BHP Billiton’s Onshore US business, Mr Cutt said: “On the basis of annual investment of US$4 billion, liquids production in our shale business will grow to 200 thousand barrels per day in the 2017 financial year, with total Onshore US production reaching 500 thousand barrels of oil equivalent per day over the same period. In this scenario, Onshore US is expected to be self-funding in the 2016 financial year before generating almost US$3 billion of free cash flow in the 2020 financial year. As a result, Onshore US is well positioned to become another major cash flow generator for BHP Billiton.
“Consistent with our strategy, we continue to evaluate and strengthen our acreage position as we seek to extend our liquids production profile. Our evaluation program in the Permian has successfully identified a focus area where we are actively pursuing a 100 thousand barrel of oil equivalent per day development. The investment associated with our overall evaluation of the Permian Basin, which has identified this focus area, will lead to a depreciation charge of approximately US$600 million in the Permian in the 2014 financial year, which reflects the early stage of development.
“Our productivity agenda is also a major focus and some of the largest opportunities can be found right here in the shale industry. This is a business that looks a lot like a manufacturing operation where repetition, efficiency and advancements in technology characterise best practice.”
| 1 | This release was made outside the hours of operation of the ASX market announcements office. |
| BHP Billiton Limited ABN 49 004 028 077 | BHP Billiton Plc Registration number 3196209 | |
| Registered in Australia | Registered in England and Wales | |
| Registered Office: 171 Collins Street Melbourne Victoria 3000 Australia | Registered Office: Neathouse Place London SW1V 1BH United Kingdom |
The BHP Billiton Group is headquartered in Australia
Mr Cutt also said that he will continue to simplify the Petroleum portfolio, for value: “Future investment will be increasingly focused on those same core areas of Australia, the United States and potentially, Trinidad and Tobago. Our disciplined divestment process, which led to the US$1.7 billion sale of our interests in Browse, will continue to create substantial value for shareholders.”
A copy of the materials to be presented on Tuesday, 10 December 2013 is attached.
Further information on BHP Billiton can be found at: www.bhpbilliton.com
|
| Nicole Duncan |
| Company Secretary |
| BHP Billiton Limited |
| Media Relations | Investor Relations | |
| Australia | Australia | |
| Emily Perry | James Agar | |
| Tel: +61 3 9609 2800 Mobile: +61 477 325 803 | Tel: +61 3 9609 2222 Mobile: +61 467 807 064 | |
| email: Emily.Perry@bhpbilliton.com | email: James.Agar@bhpbilliton.com | |
| Fiona Hadley | Andrew Gunn | |
| Tel: +61 3 9609 2211 Mobile: +61 427 777 908 | Tel: +61 3 9609 3575 Mobile: +61 402 087 354 | |
| email: Fiona.Hadley@bhpbilliton.com | email: Andrew.Gunn@bhpbilliton.com | |
| Eleanor Nichols | United Kingdom and South Africa | |
| Tel: +61 3 9609 2360 Mobile: +61 407 064 748 email: Eleanor.Nichols@bhpbilliton.com |
Tara Dines | |
| Tel: +44 20 7802 7113 Mobile: +44 7825 342 232 | ||
| email: Tara.Dines@bhpbilliton.com | ||
| United Kingdom | Americas | |
| Ruban Yogarajah | James Agar | |
| Tel: +44 20 7802 4033 Mobile: +44 7827 082 022 | Tel: +61 3 9609 2222 Mobile: +61 467 807 064 | |
| email: Ruban.Yogarajah@bhpbilliton.com | email: James.Agar@bhpbilliton.com | |
| Jennifer White | Matt Chism | |
| Tel: +44 20 7802 7462 Mobile: +44 7827 253 764 | Tel: +1 713 599 6158 Mobile: +1 281 782 2238 | |
| email: Jennifer.White@bhpbilliton.com | email: Matt.E.Chism@bhpbilliton.com | |
| Americas | ||
| Jaryl Strong | ||
| Tel: +1 713 499 5548 Mobile: +1 281 222 6627 email: Jaryl.Strong@bhpbilliton.com |
||
2
Pyrenees – Western Australia
Focusing on
value over volume
Tim Cutt
President, Petroleum and Potash
10 December 2013
bhpbilliton
resourcing the future
Disclaimer
bhpbilliton
resourcing the future
Forward-looking statements
This presentation includes forward-looking statements within the meaning of the U.S. Private Securities Litigation Reform Act of 1995 regarding future events, conditions,
circumstances and the future financial performance of BHP Billiton, including for capital expenditures, production volumes, project capacity, and schedules for expected production. Often, but not always, forward-looking statements can be identified
by the use of the words such as “plans”, “expects”, “expected”, “scheduled”, “estimates”, “intends”, “anticipates”, “believes” or variations of such words and phrases or
state that certain actions, events, conditions, circumstances or results “may”, “could”, “would”, “might” or “will” be taken, occur or be achieved. 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 or implied in the
statements contained in this presentation. For more detail on those risks, you should refer to the sections of our annual report on Form 20-F for the year ended 30 June 2013 entitled “Risk factors”, “Forward looking
statements” and “Operating and financial review and prospects” filed with the U.S. Securities and Exchange Commission. Forward-looking statements should, therefore, be construed in light of such risk factors and undue reliance should
not be placed on forward-looking statements. Forward-looking statements speak only as of the date of this presentation. BHP Billiton will not undertake any obligation to release publicly any revisions or updates to these forward-looking statements
to reflect events, circumstances or unanticipated events occurring after the date of this presentation except as required by law or by any appropriate regulatory authority. All estimates and projections in this presentation are illustrative only.
Our actual results may be materially affected by changes in economic or other circumstances which cannot be foreseen. Nothing in this presentation is, or should be relied on as, a promise or representation either as to future results or events or as
to the reasonableness of any assumption or view expressly or impliedly contained herein. Nothing in this presentation should be interpreted to mean that future earnings per share of BHP Billiton Plc or BHP Billiton Limited will necessarily match or
exceed its historical published earnings per share.
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 presentation also includes certain non-IFRS measures including Attributable profit excluding exceptional items, Underlying EBITDA interest coverage, Underlying effective tax rate, Underlying EBIT margin, Underlying EBITDA margin
and Underlying return on capital. 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 measures have not been
subject to audit or review.
UK GAAP financial information
Certain
historical financial information for periods prior to FY2005 has been presented on the basis of UK GAAP, which is not comparable to IFRS or US GAAP. Readers are cautioned not to place undue reliance on UK GAAP information.
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.
Reliance on third party information
The views expressed in this presentation contain information that has been derived from publicly available sources or provided by third parties and has 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, December 2013
Slide 2
Disclaimer
bhpbilliton
resourcing the future
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 qualify 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. Aggregates of
Reserves and contingent resources estimates contained in this presentation have been calculated by arithmetic summation of field/project estimates by category. The aggregate 1P reserves may be conservative due to the portfolio effects of arithmetic
summation. Reserves and contingent resources estimates contained in this presentation have been estimated using deterministic methodology with the exception of the North West Shelf gas asset in Australia where probabilistic methodology has been
utilized to estimate and aggregate reserves and contingent resources for the reservoirs dedicated to the gas project only. 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: proved reserves 92 MMboe, probable reserves 27 MMboe, contingent resources 161 MMboe. The custody transfer point(s)/point(s) of sale applicable for each field or project are the reference point for
reserves and contingent resources. The barrel of oil equivalent conversion is based on 6000 scf of natural gas equals 1 boe. The reserves replacement ratio is the reserves change during the year, before production, divided by production during the
year, stated as a percentage. Unless noted otherwise, reserves and contingent resources are as at 30 June 2013. 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 20F report with the SEC. All unproved volumes are estimated
using SPE-PRMS guidelines which 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. We have provided a list of resource terms along with
their definitions in this presentation. Non-proved estimates are inherently more uncertain than proved.
BHP Billiton Investor briefing: Petroleum, December 2013
Slide 3
Key themes
bhpbilliton
resourcing the future
Committed to ongoing improvement in our HSEC performance
A large, high quality resource base concentrated in Australia and the US
Low risk brownfield
investment is maximising the value of our Conventional business
Our Shale business is well positioned to generate substantial growth in free cash flow
Our productivity agenda continues to deliver strong results
Our strategy is focused on value
over volume
BHP Billiton Investor briefing: Petroleum, December 2013
Slide 4
Safety is our priority
bhpbilliton
resourcing the future
Total Recordable Injury Frequency
(TRIF, 12 month moving average)
8 Petroleum TRIF Shale TRIF Fatality
6
4
2
0
Jul 08 Jan 09 Jul 09 Jan 10 Jul 10 Jan 11 Jul 11 Jan 12 Jul 12 Jan 13 Jul
13
BHP Billiton Investor briefing: Petroleum, December 2013
Slide 5
Our HSEC focus areas
bhpbilliton
resourcing the future
Health
Minimise exposure to silica during hydraulic fracturing operations in our Shale business
Safety
Leverage systems and technology to manage material risks
Environment
Manage water usage and reduce greenhouse gas emissions
Community
Continue to make a meaningful contribution through social investment and
partnerships
BHP Billiton Investor briefing: Petroleum, December 2013
Slide 6
An experienced Petroleum management team
bhpbilliton
resourcing the future
President Petroleum and Potash Tim Cutt
President Exploration David Rainey
Asset President Shale Rod Skaufel
Asset President Conventional Steve Pastor
VP Finance David Powell VP Strategy and Development Rob Kase VP Drilling Derek Cardno VP Engineering Doug Handyside
VP Marketing Brett Langley VP HSEC Kristen Ray Senior Manager Planning and Performance Michael Stone
VP Government and External Affairs Fred Hagemeyer VP Human Resource David Nelson VP Group Legal Justin Stuhldreher
BHP Billiton Investor briefing: Petroleum, December 2013 Slide 7
A large, high quality resource portfolio
bhpbilliton
resourcing the future
We have more than doubled our resource base and delivered >100% reserve replacement over the past five years
Our business is underpinned by large fields, concentrated in Australia and the US
–
multiple high return development options
Our targeted exploration program is focused on large, high quality oil opportunities primarily within our existing
footprint
BHP Billiton petroleum resource
(billion boe) 10 US Australia rest
of world 8 gas liquids 6 4 2 0 30 June 2008 30 June 20131
1. Resource classifications – Proved Reserves (1P) 2,563 MMboe, Proved and Probable Reserves
(2P) 6,501 MMboe, Contingent Resources (2C) 3,259 MMboe.
BHP Billiton Investor briefing: Petroleum, December 2013
Slide 8
Australia and the US remain our core regions
bhpbilliton
resourcing the future
FY14 BHP Billiton capital and exploration expenditure
BHP Billiton
Petroleum Shale Petroleum Australia other Gulf of Mexico Exploration other United Kingdom Onshore US
Gulf of Mexico
Trinidad & Tobago
Algeria
Pakistan
Australia
Bubble size represents resource of one billion barrels of oil equivalent.
BHP Billiton Investor briefing: Petroleum, December 2013
Slide 9
Australian assets deliver strong, stable cash flow bhpbilliton resourcing the future
liquids field gas field BHP Billiton acreage North West Shelf Pyrenees / Stybarrow Macedon Bass Strait
Thebe Jupiter Scarborough Tallaganda Stybarrow Pyrenees Macedon Onslow Macedon Gas Plant North West Shelf
LNG Plant Dampier Karratha Australia Petroleum Underlying EBITDA (US$ billion) 10 Petroleum Australia 5 0
FY09 FY10 FY11 FY12 FY13 Australia Bubble size represents resource of one billion barrels of oil equivalent.
Resource classifications – Proved Reserves (1P) 837 MMboe, Proved and Probable Reserves (2P) 1,035 MMboe, Contingent Resources (2C) 1,265 MMboe. BHP Billiton
Investor briefing: Petroleum, December 2013 Slide 10
US assets will underpin substantial growth bhpbilliton resourcing the future
Onshore US Gulf of Mexico Petroleum Underlying EBITDA Shenzi Atlantis Mad Dog Neptune Onshore US
(US$ billion) 10 Petroleum US 5 0 FY09 FY10 FY11 FY12 FY13 N W S E 0 20 40 80 Miles
liquids focused area gas focused area BHP Billiton acreage New Mexico Permian Oklahoma Fayetteville Arkansas Mississippi Haynesville Texas Louisiana Houston Eagle Ford Shenzi
Neptune Atlantis Mad Dog Bubble size represents resource of one billion barrels of oil equivalent. Onshore US resource classifications – Proved Reserves (1P) 1,334 MMboe, Proved and Probable Reserves (2P) 4,894 MMboe, Contingent
Resources (2C) 1,547 MMboe. Gulf of Mexico resource classifications – Proved Reserves (1P) 284 MMboe, Proved and Probable Reserves (2P) 424 MMboe, Contingent Resources (2C) 327 MMboe.
BHP Billiton Investor briefing: Petroleum, December 2013 Slide 11
Conventional investment profile
bhpbilliton
resourcing the future
Exploration Appraisal Engineering Execution Operations
Brownfield projects
Conventional life cycle driven by few but significant front end investment decisions
– development plan is established up front for the full life cycle of the field
–
early technology decisions have significant value implications
The majority of capital invested prior to first production
Large tranche of initial production followed by limited additions
Production and free cash
flow peak in early years post start up
Representative investment profile
(US$
million) EBITDA capital free cash flow 0 2 4 6 8 10 12 14 16 18 20 years Representative production profile
(MMboe) nearfield tie-ins infill drilling initial
project 0 2 4 6 8 10 12 14 16 18 20 years
Representative investment and production profiles are for illustrative purposes only and do not reflect actual BHP
Billiton estimates or operations. BHP Billiton Investor briefing: Petroleum, December 2013 Slide 12
Shale investment profile
bhpbilliton
resourcing the future
Exploration Mapping and Leasing Appraisal Area specific tests Full
development
Shale life cycle driven by continuous investment decisions and optimisation opportunities – thousands of potential well locations, each reflecting
a discrete opportunity
Significant portion of annual capital offset by early revenue generation
Flexibility to adjust development plans in response to market conditions
Multiple
opportunities to add material value over the long term
Progressive development delivers steady growth in production and free cash flow over many years
Representative investment profile
(US$ million) EBITDA capital free cash flow 0 2 4 6 8 10 12
14 16 18 20 years
Representative production profile
(MMboe) 0 2 4 6 8 10 12
14 16 18 20 years
Representative investment and production profiles are for illustrative purposes only and do not reflect actual BHP Billiton estimates or
operations. BHP Billiton Investor briefing: Petroleum, December 2013 Slide 13
A clear focus on value over volume
bhpbilliton
resourcing the future
We will prioritise the highest return investment
opportunity – investment in our shale liquids acreage (tight oil) generates strong returns – deepwater infill drilling and brownfield expansions will maximise the value of our Conventional business – preserving the value of our dry
gas shale acreage
We will continue to simplify the portfolio for value – interest in Browse divested for US$1.7 billion in FY13
– Liverpool Bay divestment announced in October 2013
Greenfield project IRR (%, IRR) 30
BHP Billiton near term focus 25 Deepwater Tight oil 20 Shale gas Conventional BHP Billiton long term value creation 15 Oil sands Greenfield LNG 10
BHP Billiton
development options must compete within the portfolio
5 0 0 100 200 300 400 500
Capital investment in greenfield projects 2006-2020
(US$ billion)
Source: Wood Mackenzie.
BHP Billiton Investor briefing: Petroleum, December 2013 Slide 14
FY14 production guidance maintained bhpbilliton resourcing the future
On track to produce 250 MMboe in FY14
– 75% increase in shale liquids production –
stable Conventional volumes as Macedon and Atlantis offset natural field decline and planned maintenance
Production for the December 2013 quarter is expected to
decline to approximately 58 MMboe
– Bass Strait seasonal demand – Pyrenees scheduled maintenance
– Eagle Ford planned facility tie-in activities – well remediation and weather related downtime at Hawkville – partially offset by strong Atlantis performance Strong
growth in Shale liquids production
(Petroleum production, MMboe) 300 Conventional
Shale gas Shale liquids
200 100 0
FY09 FY10 FY11 FY12 FY13 FY14e1
1. Includes a full year of production from Liverpool Bay (UK),
which is the subject of an announced, ongoing divestment process. Production guidance will be updated pending successful transaction close expected in H2 FY14.
BHP
Billiton Investor briefing: Petroleum, December 2013 Slide 15
Leveraging the infrastructure of our Conventional business
bhpbilliton resourcing the future
Capital expenditure of ~US$1.5 billion per annum is expected
to maintain Conventional volumes for three to five years – high return infill drilling at Shenzi, Pyrenees, Atlantis and Mad Dog – completion of field extension projects at Bass Strait and North West Shelf
FY14 Conventional production outlook
(MMboe) 100 120 140 FY13 Base decline Macedon Atlantis
infill Pyrenees infill North Rankin 2 other FY14e FY14 Conventional infill drilling returns Capital spend IRR1
(BHP Billiton share)
Shenzi infill well
US$62 million >90%
Atlantis infill well US$91 million
>100% Pyrenees 3 well
US$218 million ~20%
subsea tie-back2
1. After tax, based on September 2013 futures prices.
2. Includes additional subsea manifolds
and flowlines.
BHP Billiton Investor briefing: Petroleum, December 2013 Slide 16
Development options must compete for capital
bhpbilliton resourcing the future
We own significant contingent resources
within our core areas
– Scarborough (ExxonMobil operated, BHP Billiton share 50%) is an ~8 tcf1 (100% basis) gas resource
– Mad Dog (BP operated, BHP Billiton share 23.9%) is among the largest oil fields in the Gulf of Mexico
Both projects are under evaluation with a firm focus on improving capital efficiency
We will
pursue the path that maximises shareholder value
Scarborough / Thebe – Western Australia Thebe Jupiter Scarborough
North West Shelf LNG Plant Dampier Karratha
Tallaganda liquids field Stybarrow gas field
Pyrenees
Macedon Onslow BHP Billiton acreage
Macedon Gas Plant Australia
Mad Dog field – Gulf of Mexico
North West Mad Dog platform
East Phase 2
1. Resources on a 2C basis.
BHP Billiton Investor briefing: Petroleum, December 2013 Slide 17
Shale development plan will be continually optimised for value
bhpbilliton resourcing the future
We are prioritising investment in the liquids rich, high
return shale assets
– pursuing accelerated development in the prolific Black Hawk area of the Eagle Ford – timing Hawkville development for liquids
content and lease retention – large scale development of the Permian will extend our liquids production profile
We are preserving the value of our dry gas
shale assets
– current drilling in the Haynesville delivers 30%1 rates of return – Fayetteville investment limited to strong non-operated opportunities
with 25%1 rates of return
We have flexibility in our Shale portfolio to time investment for maximum value
BHP Billiton Onshore US shale plays
NEW MEXICO OKLAHOMA Fayetteville ARKANSAS Delaware South
Midland Permian TEXAS LOUISIANA Haynesville Black Hawk Hawkville Eagle Ford Houston
liquids focused area
dry gas focused area
1. After tax, based on September 2013 futures prices.
BHP Billiton Investor briefing: Petroleum, December 2013 Slide 18
Positioned to deliver substantial growth in free cash flow bhpbilliton resourcing the future
Our Shale business must compete for capital within the broader BHP Billiton portfolio – annual budgets will be subject to ongoing review A capital expenditure program of US$4
billion per annum will support strong growth in liquids production
– forecast ~200 kb/d of liquids by FY17 from the Eagle Ford and Permian – growth in
gas production reflects associated gas from our liquids rich areas Free cash flow from our Shale business is expected to be positive by FY16 and to approach US$3 billion per annum by the end of the decade Onshore US production scenario (kboe/d) 600
450 300 150 0 FY12 FY13 FY14e FY15e FY16e FY17e FY18e crude & condensate NGL associated gas dry gas Onshore US free cash flow scenario1 (US$ billion, pre-tax cash flow)
10 5 0 (5) FY12 FY13 FY14e FY15e FY16e FY17e FY18e
EBITDA
capital
free cash flow
1. Forward projections are based on current development plans and September 2013 futures prices. Outlook will continue to be adjusted in response to market conditions, new
opportunities and BHP Billiton Group capital prioritisation.
BHP Billiton Investor briefing: Petroleum, December 2013 Slide 19
Extending our high return liquids profile bhpbilliton resourcing the future
Efforts underway to expand our Permian land position in our core focus area
– 100,000 net
acres1 in this focus area – acquiring additional acreage in highly prospective areas with a view to consolidating our position within our focus area – testing multiple productive horizons First shale exploration well drilled in October
2013 in the emerging Pearsall play – successfully accessed 30,000 net acres1 and an option for an additional 70,000 net acres2, all contiguous – evaluation ongoing to determine liquids production potential
NEW MEXICO OKLAHOMA Fayetteville ARKANSAS TEXAS LOUISIANA Delaware South Midland Focus area Pearsall Permian Haynesville Black Hawk Hawkville Eagle Ford Houston liquids focused
area dry gas focused area
Exploration Mapping Leasing Appraisal Area specific tests Full development
Permian focus area
100,000 net acres
Pearsall 100,000 net acres
Black Hawk 58,000 net acres
1. As at 30 June 2013.
2. As at 31 October 2013.
BHP Billiton Investor briefing: Petroleum, December 2013 Slide 20
We have flexibility to adjust our plans
bhpbilliton
resourcing the future
Development of our existing liquids acreage dominates our investment program
–
infrastructure component will decline as build out in the Eagle Ford is largely completed in the near term
Near term dry gas investments yield attractive returns,
however they can be deferred without loss of value
We have significant flexibility to adjust our plans
– extend liquids program with exploration success and/or acreage optimisation
– ramp
up dry gas development as market conditions improve
Onshore US capital expenditure scenario
(US$ billion)
5
4
3
2
1
0
FY11 FY12 FY13 FY14e FY15e FY16e FY17e FY18e
liquids liquids expansion or dry gas ramp up dry
gas
BHP Billiton Investor briefing: Petroleum, December 2013 Slide 21
Our productivity agenda continues to deliver strong results
bhpbilliton
resourcing the future
Repetitive, manufacturing nature of shale is ideally suited to our productivity agenda
–
reduce drilling costs per well through efficiency and supply chain management
– increase ultimate recovery per well through completions optimisation (eg. well
spacing and frac design)
– accelerate spud to sales timing (eg. simultaneous operations and pad drilling optimisation)
These low cost initiatives have the potential to unlock substantial value
BHP Billiton Black
Hawk drilling cost performance1
(index, Q1 FY13 = 100, US$ million)
100
80
60
40
Q1 FY13 Q2 FY13 Q3 FY13 Q4 FY13 Q1 FY14 Oct-13
Improving well EUR2 through completion optimisation
(% improvement in cumulative production)
60
individual well
40
20
0
0 10 20 30 40 50 60
(days)
1. For 3-string well design.
2. Estimated ultimate recovery.
BHP Billiton Investor briefing: Petroleum, December 2013 Slide 22
Strong outlook with growth prioritised for value
bhpbilliton
resourcing the future
Petroleum production scenario1
(MMboe)
400
Conventional
Onshore US
300
200
100
0
FY09 FY10 FY11 FY12 FY13 FY14e2 FY15e FY16e FY17e FY18e
1. Forward projections are based on existing acreage, current development plans and September 2013 futures prices. Outlook will continue to be adjusted in response to market
conditions, new opportunities and BHP Billiton Group capital prioritisation.
2. Includes a full year of production from Liverpool Bay (UK), which is the subject of
an announced, ongoing divestment process. Production guidance will be updated pending successful transaction close expected in H2 FY14.
BHP Billiton Investor
briefing: Petroleum, December 2013 Slide 23
Key themes
bhpbilliton
resourcing the future
Committed to ongoing improvement in our HSEC performance
A large, high quality resource base concentrated in Australia and the US
Low risk brownfield
investment is maximising the value of our Conventional business
Our Shale business is well positioned to generate substantial growth in free cash flow
Our productivity agenda continues to deliver strong results
Our strategy is focused on value
over volume
BHP Billiton Investor briefing: Petroleum, December 2013 Slide 24
bhpbilliton
resourcing the future
A major earnings contributor
bhpbilliton
resourcing the future
David Powell
Vice President, Finance
10 December 2013
Petroleum is a pillar of BHP Billiton
bhpbilliton
resourcing the future
Strong financial performance over the last five years reflects the quality of our Petroleum assets
– 18% of total BHP Billiton production1
– US$27 billion of Underlying EBIT,
representing 23% of total BHP Billiton Underlying EBIT
– average Underlying EBIT margin of 53%2
BHP Billiton Underlying EBIT2
(US$ billion) (margin, %)
40 80
30 60
20 40
10 20
0 0
FY09 FY10 FY11 FY12 FY13
Petroleum BHP Billiton Petroleum EBIT margin
1. Based on copper equivalent production
calculated using FY13 average prices.
2. Excludes exceptional items and third party products.
BHP Billiton Investor briefing: Petroleum, December 2013 Slide 27
Product mix a key driver of Onshore US revenue
bhpbilliton
resourcing the future
Decisive response to market conditions underpins significant growth in Onshore US liquids production
– liquids contributed ~20% of Onshore US production and ~45% of revenue in FY13
–
75% increase in liquids production anticipated in FY14
Our Onshore US crude and condensate sales currently achieve ~94% of WTI1
Our current average realised Onshore US NGL price represents ~32% of WTI1
We achieve ~95% of
the Henry Hub gas price due to location differentials
Onshore US liquids contribution
(% of total Onshore US production) (% of total revenue)
60 60
40 40
20 20
0 0
FY12 FY13 FY14e
NGL
crude and condensate
liquids revenue contribution
US NGL prices have diverged from oil
(WTI, US$/bbl) (NGL price as % of WTI)
120 100
90 75
60 50
30 25
0 0
Jan 11 Jul 11 Jan 12 Jul 12 Jan 13 Jul 13
NGL price as a % of WTI WTI
Source: WTI, NYMEX; NGL prices reflect the Mt Belvieu indices for our Onshore US production.
1. Onshore US realised prices based on FY14 YTD as at 31 October 2013.
BHP Billiton
Investor briefing: Petroleum, December 2013 Slide 28
Seeking to improve our low cost position
bhpbilliton
resourcing the future
Low cost conventional operations underpin exceptional margins
Our decision to prioritise shale
liquids development has increased margins albeit with an increase in average production costs
– costs expected to decline in the medium term with the addition
of infrastructure
Our near term liquids focus has resulted in a series of non-recurring charges
– rig termination costs of ~US$100 million in FY14 associated with the optimisation of our dry gas program (majority incurred in H1)
– underutilised legacy gas pipeline commitments will incur charges of ~US$170 million per annum in FY14 and FY15, primarily in the Haynesville
Petroleum costs
(US$/boe)
20
15
10
5
0
FY09 FY10 FY11 FY12 FY13 FY14e FY15e
production cash cost1 all in cash cost2
Shale all in cash costs2
(US$/boe) (%)
20 80
15 70
10 60
5 50
0 40
FY12 FY13 FY14e FY15e FY16e FY17e FY18e
production cash cost1 transportation
production taxes and other non-recurring3
EBITDA margin
1. Production cash cost includes lifting, maintenance and overheads.
2. All in cash cost is Revenue (excluding third party) minus Underlying EBITDA, adjusted for exploration and embedded derivatives.
3. Shale non-recurring costs include charges associated with the termination of rig contracts, underutilised gas pipeline commitments and system conversion costs.
BHP Billiton Investor briefing: Petroleum, December 2013 Slide 29
Timing of reserve additions impacts depreciation
bhpbilliton
resourcing the future
Conventional unit depreciation remains highly competitive
– minor variations reflect
project start-ups and timing of resource additions
Our successful Permian evaluation program has near term depreciation implications
– we will incur ~US$600 million in depreciation charges in FY14 on 4 MMboe of Permian production
– Permian depreciation rate is expected to normalise as production ramps up and reserves are booked
Depreciation
(US$/boe)
25
20
15
10
5
0
FY09 FY10 FY11 FY12 FY13 FY14e FY15e
Petroleum Conventional Shale
Shale depreciation
(US$ billion) (US$/boe)
5 25
4 20
3 15
2 10
1 5
0 0
FY12 FY13 FY14e FY15e FY16e FY17e FY18e
Shale other Permian unit depreciation
BHP Billiton Investor briefing: Petroleum, December 2013
Slide 30
A compelling long term outlook for Onshore US
bhpbilliton
resourcing the future
Onshore US margin scenario1
(%)
80
EBITDA margin
EBIT margin
60
40
20
0
(20)
FY13 FY14e FY15e FY16e FY17e FY18e
1. Forward projections are based on current development plans and September 2013 futures prices. Outlook will continue to be adjusted in response to market conditions, new
opportunities and BHP Billiton Group capital prioritisation.
BHP Billiton Investor briefing: Petroleum, December 2013 Slide 31
Understanding the US fiscal regime
bhpbilliton
resourcing the future
The fiscal regime in the US is aimed at encouraging development of oil and gas resources
US
tax code allows for immediate deduction of intangible drilling and development costs (IDC) deferring cash tax
– contributes to carry forward tax Net Operating
Losses
BHP Billiton Investor briefing: Petroleum, December 2013 Slide 32
A high return investment program
bhpbilliton
resourcing the future
Petroleum offers some of the highest return investment opportunities for the Group
Capital and
exploration expenditure of ~US$6.2 billion is planned for Petroleum in FY14
– >75% of our US$3.9 billion budget for Onshore US will be invested in our
liquids rich acreage
– Conventional spend of ~US$1.7 billion focused on high return infill drilling and field extension projects
– US$600 million exploration budget will target high quality oil opportunities
Capital
and exploration expenditure
(US$ billion)
25
20
15
10
5
0
FY09 FY10 FY11 FY12 FY13 FY14e
Petroleum BHP Billiton
BHP Billiton Investor briefing: Petroleum, December 2013 Slide 33
bhpbilliton
resourcing the future
Trinidad
Maximising the value of our
Conventional business
bhpbilliton
resourcing the future
Steve Pastor
Asset President, Conventional
10 December 2013
Key themes
bhpbilliton
resourcing the future
Operating excellence and highly profitable assets provide a strong
foundation for our Petroleum business
Low-risk, high return infill drilling and brownfield expansions will extend our production profile
Demonstrated technical capability to deliver projects on budget and schedule
We are evaluating
long term investment opportunities and will pursue the path that maximises shareholder value
We will continue to simplify our portfolio
Our conventional assets will continue to deliver strong, stable free cash flow
BHP Billiton
Investor briefing: Petroleum, December 2013 Slide 36
A strong foundation for our Petroleum business
bhpbilliton
resourcing the future
Conventional production outlook
(FY14, BHP Billiton share)
International other
46 kboe/d
Gulf of Mexico
87 kboe/d
Trinidad & Tobago
19 kboe/d
North West Shelf
75 kboe/d
Australia operated
50 kboe/d
Bass Strait
96 kboe/d
Petroleum Underlying EBITDA
(US$ billion)
10
Petroleum
Conventional
5
0
FY09 FY10 FY11 FY12 FY13
crude & condensate NGL gas LNG
Note: Conventional volumes, BHP Billiton share. Based on
FY14 forecast production. Size of bubbles scaled to production rates.
BHP Billiton Investor briefing: Petroleum, December 2013 Slide 37
Highly profitable Conventional business
bhpbilliton
resourcing the future
Australia and the Gulf of Mexico are our core regions with valuable infrastructure positions
Conventional volumes have remained steady
– ~50% crude, condensate and
NGL
– ~50% natural gas
Liquids contributed ~70% of revenue in FY13,
underpinning exceptional EBIT margins
Our Conventional business continues to deliver strong, stable free cash flow
Production volume
(Conventional, MMboe)
(%)
200 80
150 60
100 40
50 20
0 0
FY09 FY10 FY11 FY12 FY13
liquids gas % revenue liquids
Underlying EBIT
(US$ billion)
(%)
8 65
6 60
4 55
2 50
0 45
FY09 FY10 FY11 FY12 FY13
EBIT EBIT margin
BHP Billiton Investor briefing: Petroleum, December 2013 Slide 38
|
|
Maximising value through operational excellence
bhpbilliton
resourcing the future
We are an industry leader in deepwater drilling capability and operational uptime – our drilling times are well below industry average – we were the first operator to
resume production drilling in the Gulf of Mexico post Macondo – average operated facility uptime ~95%
We are applying technology to increase value and
identify additional resources
– 4D seismic technology and reservoir simulation to identify infill opportunities – water injection to maximise recovery
Average drill time per 1,000 ft
(Deepwater Gulf of Mexico, subsalt, days)
8
others BHP Billiton
6
4
2
0
pre-moratorium post-moratorium
FY13 facility uptime
80% 90% 100%
OBO1
Stybarrow
Pyrenees
Shenzi
Neptune
Angostura
Zamzama
Minerva
Source: Average drill time per 1,000 ft, Rushmore Associates’ The Rushmore Reviews, Scout Tickets and BHP Billiton analysis as at 14 November 2013.
1. Operated by others.
BHP Billiton Investor briefing: Petroleum, December 2013 Slide 39
Strong track record of project delivery
bhpbilliton
resourcing the future
Demonstrated ability to deliver our projects on budget and schedule
Six major operated
projects completed on schedule and budget in the last six years
– two deepwater Tension Leg Platforms (TLP) in the GoM, Shenzi and Neptune
– two Floating Production Storage and Offtake (FPSO) vessels in Western Australia, Stybarrow and Pyrenees
– Angostura Phase 2 gas project in Trinidad
– Macedon gas development in Western
Australia (FY14 start-up)
These projects contributed >35% of Petroleum’s FY13 Underlying EBIT
Shenzi Neptune
Stybarrow Pyrenees
Angostura Macedon
BHP Billiton Investor briefing: Petroleum, December 2013 Slide 40
Shenzi – our premier operated facility
bhpbilliton
resourcing the future
High quality reservoir over 400 feet thick in the Gulf of Mexico
Excellent operating
performance, ~95% uptime since start-up
High return infill drilling campaign continues to extend the production profile
Two new infill wells in FY14 will maintain near term production at nameplate capacity
Valuable
incremental investment opportunities are under evaluation
– additional infill and water injection wells
– exploration to the north of the field
Operator BHP Billiton
Working interest 44%
First production date 2009
FY13 net production 17 MMboe
Resources1
130 MMboe
2C 10% P2 21% P1 69%
Shenzi field map
North
West East
Shenzi platform
Shenzi production
(kboe/d, 100% basis)
150
facility nameplate capacity
100
50
0
Mar 09 Dec 09 Sep 10 Jun 11 Mar 12 Dec 12 Sep 13
first production infill
production
1. 2P+2C remaining resource as at 30 June 2013, BHP Billiton share.
BHP Billiton Investor briefing: Petroleum, December 2013 Slide 41
Atlantis – release of high margin latent capacity
bhpbilliton
resourcing the future
World class Gulf of Mexico oil asset with substantial latent capacity
Excellent results from
wells drilled in North area, initial rate from recent well >30 kboe/d (100% basis)
– field currently ~135 kboe/d (100% basis)
Active two rig development program underway with production expected to double between FY13 and FY15
Operator BP
Working interest 44%
First production date 2007
FY13 net production 9 MMboe
Resources1
278 MMboe
2C 23%
P1 P2 47% 30%
Atlantis field map
South North East
Atlantis platform
Atlantis production
(kboe/d, 100% basis)
200
facility nameplate capacity
150
100
50
0
Oct 07 Dec 08 Feb 10 Apr 11 Jun 12 Aug 13
first production infill production
1. 2P+2C remaining resource as at 30 June 2013, BHP Billiton share.
BHP
Billiton Investor briefing: Petroleum, December 2013 Slide 42
Mad Dog – release of high margin latent capacity
bhpbilliton
resourcing the future
Mad Dog is among the largest oil fields in the Gulf of Mexico
Mad Dog Phase 1 rig lost during
Hurricane Ike in 2008 has been replaced and is now operational
Additional scheduled downtime during FY14 is expected to reduce year on year production
Infill drilling is expected to increase Phase 1 production in FY15, with rates approaching facility capacity by FY18
Substantial resource potential for Phase 2 development of South and West areas
Operator BP
Working interest 23.9%
First production date 2005
FY13 net production 3 MMboe
Resources1
266 MMboe P1 21% P2 6% 2C 73%
1. Includes Mad Dog Phase 2 resource. 2P+2C remaining resource
as at 30 June 2013, BHP Billiton share.
Mad Dog field map
North West Mad
Dog platform East
Phase 2
Mad Dog production
(kboe/d, 100% basis)
80 facility nameplate capacity
60 40 20 0
Jan 05 Mar 07 May 09 Jul 11 Sep 13
first production infill production
BHP Billiton Investor briefing: Petroleum, December 2013
Slide 43
bhpbilliton
resourcing
the future
WA operated – valuable infrastructure position
Significant
resource and valuable infrastructure position underpins our operated assets in this area
Macedon gas project now online, expected to contribute 6 MMboe (BHP
Billiton share) in FY14
Multi well extension program at Pyrenees expected to deliver additional 20 kboe/d (100% basis) in H2 FY14
Significant exploration acreage under permit
Leveraging existing infrastructure unlocks
potential for additional high return opportunities
Operator BHP Billiton Resources1 170 MMboe
First production date
20072 2C 24% P1 50%
FY13 net production 14 MMboe P2 26%
1. 2P+2C remaining resource as at 30 June 2013, BHP
Billiton share.
2. First production from the Stybarrow field.
Western
Australia operated assets
Tallaganda
liquids fieldgas field Stybarrow
BHP Billiton acreage Pyrenees Macedon Onslow Australia Macedon Gas Plant
0 15
20 60 kilometers
Western Australia operated production
(kboe/d, 100% basis)
150 100 50 0
Macedon start-up
Nov 07 Oct 08 Sep 09 Aug 10 Jul 11 Jun 12 May 13
Stybarrow and Pyrenees Macedon
BHP Billiton Investor briefing: Petroleum, December 2013 Slide 44
bhpbilliton
resourcing
the future
Bass Strait – our largest Conventional asset
Delivered first
production more than 40 years ago
Project execution challenges at Turrum and Kipper resulted in revisions to original budget and schedule
Longford gas conditioning plant on budget and schedule with start-up CY16; Kipper mercury removal anticipated start-up CY16
Turrum and Kipper will deliver valuable additional wet gas partially offsetting liquids decline
Eastern Australia gas prices expected to strengthen with new LNG demand and rising costs of supply
Assessing additional opportunities to extend gas plateau production through 2030 and beyond
Operator Esso Resources1 664 MMboe
Working interest 50% 2C 22%
First production date 1969 P2 P1 20% 58%
FY13 net production 36 MMboe
1. 2P+2C remaining resource as at 30 June 2013, BHP Billiton share.
Bass Strait assets
0 20 40 km Eastern Gas Pipeline LAKES ENTRANCE N
SALE LONGFORD PLANT SEAHORSE
Moonfish Turrum TUNA Kipper
To LIP PLANT BARRACOUTA WHITING SNAPPER MARLIN WEST TUNA FLOUNDER
MELBOURNE TARWHINE DOLPHIN FORTESCUE HALIBUT PERCH BREAM A BREAM B WEST KINGFISH KINGFISH A
KINGFISH B COBIA MACKEREL BLACKBACK Tasmania Gas Pipeline
Oil/Gas Concrete
Platform Oil/Gas Platform Oil Platform Oil Monotower Oil Sub-Sea Satellite Field Oil Pipeline Gas Pipeline NGL Pipeline
Bass Strait production
(kboe/d, 100% basis)
400 300 200 100 0
2001 2003 2005 2007 2009 2011 2013
liquids gas
BHP Billiton Investor briefing: Petroleum, December 2013 Slide 45
bhpbilliton
resourcing
the future
North West Shelf – a major Asian LNG supplier
NWS has five
LNG trains with capacity of 16 mtpa
Major projects will extend the production profile
– North Rankin 2 online October 2013 on schedule and budget
– Greater Western Flank
A (GWF-A) on schedule and budget, start-up CY16
Additional projects under evaluation including GWF-B and Persephone
NWS joint venture is assessing opportunities to process third party gas to maximise value from established infrastructure
Operator Woodside Resources1 483 MMboe
Working interest 14.85% 2C 23%
First production date 1984 P2 3% P1 74%
FY13 net production 30 MMboe
1. 2P+2C remaining resource as at 30 June 2013, BHP Billiton share.
NWS assets
Goodwyn A Platform North Rankin A & B Platforms Angel Platform Okha FPSO Greater Western Flank - A Karratha Gas Plant
NWS production
(kboe/d, 100% basis)
600 400 200 0
2001 2003 2005 2007 2009 2011 2013
liquids gas LNG
BHP Billiton Investor briefing: Petroleum, December 2013 Slide 46
bhpbilliton
resourcing
the future
International assets – Trinidad has significant potential
Trinidad has the potential to become a third core region for our Petroleum business
– plans to extend production plateau at Angostura
– exploration focused on highly
prospective deepwater acreage
Non-operated ROD asset in Algeria contributes substantial cash flow
We continue to achieve excellent performance and uptime at our operated Zamzama asset in Pakistan
We have announced the divestment of our UK Liverpool Bay asset
Production from International
operations
(MMboe, BHP Billiton share)
40 30 20 10 0
FY09 FY10 FY11 FY12 FY13
Trinidad Pakistan Algeria UK
Trinidad
BHP Billiton Investor briefing: Petroleum, December 2013 Slide 47
bhpbilliton
resourcing
the future
All investments must compete for capital
Scarborough ~8 tcf1 (100%
basis)
– BHP Billiton 50%, ExxonMobil operator
– good quality
reservoir, lean gas
– delineated field with five appraisal wells – currently in Identification phase
Thebe discovery ~1 tcf1 (100% basis)
– BHP Billiton 100% and operator
– delineated with four well penetrations
Working with ExxonMobil to optimise development
concepts
We will pursue the path that maximises value for shareholders
Scarborough / Thebe – Western Australia
Thebe Jupiter Scarborough North
West Shelf LNG Plant Tallaganda Dampier Karratha Stybarrow Pyrenees Macedon Onslow Macedon Gas Plant Australia
liquids field gas field BHP Billiton acreage
W N E S
0 15 30 60 Kilometers
1. Resources on a 2C basis.
BHP Billiton Investor briefing: Petroleum, December 2013 Slide 48
bhpbilliton
resourcing
the future
Further opportunities in the Gulf of Mexico
Mad Dog Phase 2 has
potential to deliver high rates of return
– we are assessing development concepts with the operator
Stampede (formerly Knotty Head) is 30 miles north west of Mad Dog
– BHP Billiton 20%,
Hess operated
– continuing to assess options for this field
Gulf of
Mexico assets
Stampede
Shenzi
Mad Dog
Atlantis
Neptune
0 5 10 Miles N
BHP Billiton acreage
BHP Billiton Investor briefing: Petroleum, December 2013 Slide 49
bhpbilliton
resourcing
the future
We will simplify the portfolio for value
Six assets contributed
>90% of Petroleum Underlying EBIT in FY13
Recent divestments highlight our ability to create substantial value
– interest in Browse divested for US$1.7 billion in FY13
– Liverpool Bay divestment
announced in FY14
We will continue to simplify the portfolio with a firm focus on value
Contribution from the core regions
(Underlying EBIT,% of Conventional total1)
100 80 60 40 20 0
FY09 FY10 FY11 FY12 FY13
Gulf of Mexico Australia rest of world
1. Excludes exploration and unallocated overheads.
BHP Billiton Investor briefing: Petroleum, December 2013 Slide 50
bhpbilliton
resourcing
the future
Key themes
Operating excellence and highly profitable assets
provide a strong foundation for our Petroleum business
Low-risk, high return infill drilling and brownfield expansions will extend our production profile
Demonstrated technical capability to deliver projects on budget and schedule
We are evaluating long term investment opportunities and will pursue the path that maximises shareholder value
We will continue to simplify our portfolio
Our conventional assets will continue to deliver
strong, stable free cash flow
BHP Billiton Investor briefing: Petroleum, December 2013 Slide 51
bhpbilliton
resourcing the future
A disciplined focus on Tier 1 oil opportunities
David Rainey
President, Exploration
10 December 2013
bhpbilliton
resourcing the future
bhpbilliton
resourcing
the future
Key themes
We are targeting large, high quality oil opportunities,
primarily within our existing operated footprint
Exploration for conventional and shale resources require a deep understanding of regional geology and petroleum
systems
Our conventional program continues to focus on high impact deepwater drilling in the Gulf of Mexico and Western Australia
We have built a material position in deepwater Trinidad and Tobago that could underpin a future core area
Our shale exploration activity is aimed at extending our high return liquids profile in the Gulf Coast and Permian Basins
BHP Billiton Investor briefing: Petroleum, December 2013 Slide 54
bhpbilliton
resourcing
the future
Focused conventional exploration program
Gulf of Mexico
Progress best Miocene opportunities
Evaluate other Gulf of Mexico plays for
Tier 1 potential ahead of lease turnover
Tier 1 exploration criteria
ü World class source rock
ü Big reservoir system
ü Large traps
ü Acceptable fiscal terms
ü Early mover
Trinidad and Tobago
Commence seismic program2
Plan for CY16 drilling
South Africa
Process seismic1 and determine Tier 1 potential
Brazil
Plan for seismic in FY162
Southeast Asia
Evaluate current acreage for Tier 1 potential
Western Australia
Drill Bunyip exploration well
Evaluate and test near field opportunities
Complete regional geology study, targeting large
oil plays
Core area
Evaluating
1. In FY13, BHP Billiton acquired 10,075 sq km 3D seismic in Block 3B/4B.
2. Trinidad and
Tobago and Brazil seismic programs currently in planning phase.
BHP Billiton Investor briefing: Petroleum, December 2013 Slide 55
bhpbilliton
resourcing
the future
We have built a material position in Trinidad and Tobago
We have
an established operational presence in Trinidad and Tobago with our shallow water Angostura asset
The deepwater is largely untested and has Tier 1 oil potential
world class source rock
giant Orinoco River system
large traps
acceptable fiscal terms
Over the past year we have built a material ‘early mover’ position in deepwater Trinidad and Tobago
We are commencing a major 17,000 square kilometre seismic acquisition program in FY14
Leads
BHP Billiton blocks
Tobago
Trinidad
Angostura
50 km
Shenzi
Large footprints
Mad Dog
Atlantis
Pegleg lead
*sizes are to scale
BHP Billiton Investor briefing: Petroleum, December 2013 Slide 56
bhpbilliton
resourcing
the future
Extending our high return shale liquids profile
Our priority is to
delineate the liquid sweet spots in the Gulf Coast and Permian Basins to guide acreage optimisation
Pearsall exploration well drilled in October 2013 targeting
horizon below the Eagle Ford shale
Continuing to assess other North American shale plays for possible liquids potential
We are building our understanding of the global endowment of shale resources
Fayetteville
Permian
Haynesville
Eagle Ford
Total industry wells drilled since
2001
Source: IHS Global Inc.
BHP Billiton Investor briefing: Petroleum, December 2013 Slide 57
bhpbilliton
resourcing
the future
Key themes
We are targeting large, high quality oil opportunities,
primarily within our existing operated footprint
Exploration for conventional and shale resources require a deep understanding of regional geology and petroleum
systems
Our conventional program continues to focus on high impact deepwater drilling in the Gulf of Mexico and Western Australia
We have built a material position in deepwater Trinidad and Tobago that could underpin a future core area
Our shale exploration activity is aimed at extending our high return liquids profile in the Gulf Coast and Permian Basins
BHP Billiton Investor briefing: Petroleum, December 2013 Slide 58
bhpbilliton
resourcing
the future
Eagle Ford – Texas
Extending our high return, shale liquids profile
Rod Skaufel
Asset President, Shale
10 December 2013
bhpbilliton
resourcing the future
bhpbilliton
resourcing
the future
Key themes
Large, high quality resource position across multiple
fields
We have successfully refocused drilling activity on our liquids rich acreage
Progressing development in the liquids rich Permian
We are evaluating options to extend our
liquids profile
Defer dry gas opportunities without loss of value
We will
continue to optimise our investment program for value
Pursuing significant productivity opportunities targeting cost and resource recovery
BHP Billiton Investor briefing: Petroleum, December 2013 Slide 61
bhpbilliton
resourcing
the future
Significant presence in premier US shale plays
We hold 1.5 million
net acres1 across four highly productive US shale plays and three US states
– Black Hawk (Eagle Ford) – condensate rich
– Hawkville (Eagle Ford) – mix of condensate and gas with NGL
– Permian –
liquids rich but geologically complex
– Haynesville – prolific dry gas wells with premier acreage position
– Fayetteville – long term, low technical risk, dry gas option
BHP Billiton Onshore
US shale plays
OKLAHOMA
Fayetteville
ARKANSAS
LOUISIANA
Haynesville
TEXAS
NEW MEXICO
Delaware
South Midland
Permian
Hawkville
Eagle Ford
Black Hawk
Houston
liquids focused area
dry gas focused area
1. As at 30 June 2013.
BHP Billiton Investor briefing: Petroleum, December 2013 Slide 62
bhpbilliton
resourcing
the future
A high quality shale resource portfolio
Onshore US resources by
product
(as at 30 June 2013, net, billion boe)
liquids gas
3.0 2.5 2.0 1.5 1.0 0.5 0.0
Hawkville Permian Black Hawk Haynesville Fayetteville
Onshore US resources by category
(as at 30 June 2013, net, billion boe)
3.0 Contingent Resources (2C)
2.5 Probable Reserves
Proved Reserves
2.0 1.5 1.0 0.5 0.0
Hawkville Permian Black Hawk Haynesville Fayetteville
BHP Billiton Investor briefing:
Petroleum, December 2013 Slide 63
bhpbilliton
resourcing
the future
Dry gas acreage is largely ‘Held by Production’
In the
Haynesville and Fayetteville, leases comprise regulatory unit size of 640 acres, generally one square mile
Lease terms range from approximately three to seven
years
Acreage is retained provided production is established within the term of the lease and continues in economic quantities i.e. ‘Held by Production’
(HBP)
Limited obligation drilling remaining in our Haynesville and Fayetteville acreage, providing flexibility to time investment for value
Similar lease arrangements exist in the Black Hawk area of the Eagle Ford
Example: multiple
leases within a 640 acre unit held once production established within terms of the leases
Other operator
Lease acreage within the unit is retained once production is established i.e. ‘Held by Production (HBP)’
Other operator
Acreage is lost if unit production is not established within the terms of the
leases
well drilled
held acreage
future well option
released acreage
BHP Billiton Investor briefing: Petroleum, December 2013 Slide 64
bhpbilliton
resourcing
the future
Hawkville has continuous drilling obligations
Hawkville is
characterised by irregular leases with boundaries often defined by the large ranches held by private landowners
Portions of the lease are ‘earned’
through drilling with time dependent requirements i.e. ‘Continuous Drilling Obligations’
If continuous drilling obligations are allowed to lapse, acreage
that has not been earned is lost unless an extension can be secured from the landowner
Ongoing evaluation undertaken to ensure that retained acreage meets economic
criteria
Similar leasing arrangements in Permian
Example1: Large, irregular
leases with continuous, time dependent drilling obligations for retention
First well retains 320 acres around the well, creating the option for future drilling in
the retained area
Second well must be drilled within six months of the first well, retaining another 320 acres
If the six month continuous drilling requirement is not met, all ‘unearned’ acreage at that time is released
well drilled
held acreage
future well option
released acreage
1. Actual acres retained and time available for subsequent drilling can vary by lease; 320 acres and six months is representative but not standard.
BHP Billiton Investor briefing: Petroleum, December 2013 Slide 65
bhpbilliton
resourcing
the future
Rigs re-focused to liquids development
Onshore US operated rigs
(% rig split) (average number of gross operated drill rigs)
0 20 40 60 80 100
Sep 11 Oct 11 Nov 11 Dec 11 Jan 12 Feb 12 Mar 12 Apr 12 May 12 Jun 12 Jul 12 Aug 12 Sep 12 Oct 12 Nov 12
Dec 12 Jan 13 Feb 13 Mar 13 Apr 13 May 13 Jun 13 Jul 13 Aug 13 Sep 13 Oct 13
0 10 20 30 40 50
Black Hawk Hawkville Permian Haynesville Fayetteville rig count
BHP Billiton
Investor briefing: Petroleum, December 2013 Slide 66
bhpbilliton
resourcing
the future
Delivering strong growth in high value liquids production
Onshore
US production by product
(MMboe)
Liquids
gas
0 10 20 30
Q2 FY12
Q3 FY12
Q4 FY12
Q1 FY13
Q2 FY13
Q3 FY13
Q4 FY13
Q1 FY14
Onshore US production by area
0 10 20 30
Q2 FY12 (MMboe)
Q3 FY12 Fayetteville Permian Black
Hawk
Q4 FY12
Q1 FY13
Q2 FY13 Haynesville Hawkville
Q3 FY13
Q4 FY13
Q1 FY14
BHP Billiton Investor briefing: Petroleum, December 2013
Slide 67
bhpbilliton
resourcing
the future
We are among the largest producers in the Eagle Ford
Eagle Ford is
now the largest producing field within our Petroleum portfolio
– currently producing in excess of 100 kboe/d (BHP Billiton share)
– approximately 60% liquids
Potential to build production above 200 kboe/d by FY16 based
on current development plans
Source: Wood Mackenzie Q3 2013; BHP Billiton analysis.
1. Includes legacy Petrohawk.
Eagle Ford production by operator
(net, kboe/d)
125
BHP Billiton1
other operators
100
75
50
25
0
2007
2008
2009
2010
2011
2012
2013e
BHP Billiton Investor briefing: Petroleum, December 2013
Slide 68
bhpbilliton
resourcing
the future
We hold a premier position in the Eagle Ford
Black Hawk (58k net
acres1) in the heart of the condensate window
Hawkville (250k net acres1) a mix of condensate and gas with NGLs
Approximately 75% of our FY14 Onshore US drilling activity is focused on the Eagle Ford
Continuous drilling is required to retain leases in Hawkville with each investment decision subject to strict economic criteria
BHP Billiton Eagle Ford acreage position
condensate window
BHP Billiton acreage
FRIO
ATASCOSA
LA SALLE
MCMULLEN
Hawkville
LIVE OAK
BEE
WILSON
KARNES
Black Hawk
DE WITT
1. As at 30 June 2013.
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Black Hawk – heart of the condensate window
148 net producing
wells as at 30 June 2013
Average production of 60 kboe/d
(BHP Billiton share)
at approximately 80% liquids during the September 2013 quarter
50% average working interest
Well downspacing and optimising stage spacing in high value areas to enhance value
Typical
single well economics (FY14 program, 100% basis)
Initial production1
1.3
kboe/d; 73% condensate; 7% NGL
Resources
0.9 MMboe; 58% condensate; 17% NGL
Well cost2
US$12 million
Rate of return3
70%
1. Initial production averaged over a 30 day period.
2. Well cost includes drilling,
completion and facility single well costs.
3. Rate of return after tax, based on September 2013 futures prices.
Black Hawk acreage position
condensate window
BHP Billiton acreage
40 acre development area
60 acre development area
WILSON
KARNES
DE WITT
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Hawkville – mix of condensate and gas with NGL
235 net
producing wells as at 30 June 2013
Average production of 66 kboe/d
(BHP
Billiton share) at approximately 45% liquids during the September 2013 quarter
Approximately 90% average working interest
Good condensate rates and NGL yields in the north of the field
Southern area primarily gas
with NGL
– preparing to release roughly 50k net acres in FY14 that do not meet economic criteria for retention
Hawkville acreage position
condensate window
BHP Billiton acreage
Typical single well economics1 (FY14 program, 100% basis)
Initial production2
1.0 kboe/d; 44% condensate; 22% NGL
Resources
0.9 MMboe; 52% condensate; 19% NGL
Well cost3
US$11 million
Rate of return4
19%
1. Within liquids rich gas focus area.
2. Initial production averaged over a 30 day period.
3. Well cost includes drilling, completion and facility single well costs.
4.
Rate of return after tax, based on September 2013 futures prices.
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Haynesville – strong returns at current prices
Premier
acreage position in one of the most productive shale gas plays in the US
936 net producing wells as at 30 June 2013
Average dry gas production of 89 kboe/d (BHP Billiton share) during the September 2013 quarter
FY14 drilling activity in sections with working interest ranging from 50-100%
Typical single well economics (FY14 program, 100% basis)
Initial production1
8.5 MMcf/d
Resources
11 bcf gas
Well cost2
US$10 million
Rate of return3
30%
1. Initial production averaged over a 30 day period.
2. Well cost includes drilling, completion and facility single well costs.
3. Rate of return
after tax, based on September 2013 futures prices.
Haynesville acreage by Recoverable Resource
Arkansas
Louisiana
BHP Billiton acreage
Single well recoverable resource (bcf)
>10 8-10 6-8 <6
BOSSIER
WEBSTER
CLAIBORNE
CADDO
BIENVILLE
DE SOTO
RED RIVER
SABINE
NATCHITOCHES
Miles
0 2 4 8 12 16 20
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Fayetteville – preserving value
Extensively drilled with low
geologic risk
959 net producing wells as at 30 June 2013
Average dry gas
production of 68 kboe/d (BHP Billiton share) during the September 2013 quarter of which approximately 45% was non-operated
Operated rig program currently suspended
with value preserved for future investment
Continuing to selectively invest in strong non-operated opportunities within the core of the field
Fayetteville map with FY13 non-operated drilling
FY13 non-operated wells put online
Single well recoverable resource (bcf)
>5
4-5
3-4
2-3
<2
Typical single well economics (FY14 OBO program, 100% basis)
Initial production1
3.8 MMcf/d gas
Resources
4.5 bcf gas
Well cost2
US$3 million
Rate of return3
25%
1. Initial production averaged over a 30 day period.
2. Well cost includes drilling, completion and facility single well costs.
3. Rate of return
after tax, based on September 2013 futures prices.
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Permian – we have defined a highly prospective focus area
BHP
Billiton acreage in the Permian basin
NORTHWESTERN SHELF
NEW MEXICO
DELAWARE BASIN
Yeso Abo Trend
Lincoln Chaves Otero Eddy Lea Focus area Hudspeth Divestment area Jeff Davis Culberson DIABLO PLATFORM Reeves
Loving Winkler Ward Pecos Crane CENTRAL BASIN PLATFORM SHEFFIELD CHANNEL Crockett Terrell OZON ARCH
MAPPED AREA Upton Under evaluation Tom Green Runnels Coke Sterling Glasscock Midland Ector Andrews Martin
MIDLAND BASIN Howard Mitchell Nolan TEXAS Taylor Jones Fisher EASTERN SHELF Scurry Borden Dawson Gaines
Divestment area Stoneewall Crosby Dickens King Cochran Yoakum Hockley Terry Lynn Lubbock
10 5
0 10 Miles
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Permian – unique multiple horizon potential
Large liquid
bearing column creates the potential for multiple economically productive horizons
A vertical well program followed by targeted horizontal wells has been used to
appraise the play
Extensive appraisal program given the large areal and vertical footprint
Lease ownership interest can vary by depth and horizon
Avalon
Bone Spring
1st
2nd
3rd
Approximately 4,000 feet thick
Upper
Wolfcamp
Middle
Lower
Schematic for representative purposes
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Permian – targeting a 100 kboe/d development
Well results
support planned 100 kboe/d development within the focus area with approximately 60% liquids
Process of acquiring and consolidating our acreage position
Testing multiple productive horizons
Significant productivity upside with lower well cost and
higher recovery as we have demonstrated in Black Hawk
Production rate – recent wells in focus area
(boe/d, 100% basis)
1,800
1,600
1,400
1,200
1,000
800
600
400
200
0
0
50
100
150
200
(days)
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Shale capital allocation optimised for value
1. For every operated
well, we calculate the optimum timing to deliver maximum value, utilising forward price projections and cost learning curves
2. We test the sensitivity of value to
timing, assessing the impact of acceleration or deferral
3. We allocate capital based on this analysis while taking into account:
– acreage retention requirements
– operational capability
– competing non-operated opportunities
– appraisal and land capture objectives
– capital availability
Eagle Ford
Permian
Haynesville
Fayetteville
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Timing investment for maximum value
Capital allocation methodology
informs rig program decisions to capture maximum value
Well inventory can be categorised into three groups, reflecting the sensitivity of value to timing of
investment
- group 1: maximum value delivered through acceleration, deferral erodes value – liquids rich wells
– group 2: value largely insensitive to timing – wet gas and prolific dry gas wells
– group 3: value enhanced through deferral – less prolific dry gas wells
Illustration of value sensitivity to spud date
(% of maximum NPV delivered relative to spud
date)
100
insensitive to timing
accelerate
75
defer for value
50
25
group 1 wells
group 2 wells
group 3 wells
0
1 year
2 year
3 year
4 year
5 year
6 year
7 year
8 year
9 year
10 year
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Video – the drilling and completions process
BHP Billiton
Investor briefing: Petroleum, December 2013
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Committed to sustainable development
ü Be the safest company in industry
ü Protect the land where we operate
ü Safeguard and manage water resources
ü Minimise air emissions
ü Be a good neighbour to our communities
bhpbilliton
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North America Shale
Operating Principles
These five basic operating principles shape everything BHP Billiton
Petroleum does as a company and serve as its pledge to local communities.
1. To be the safest company in the industry
We carefully develop and rigorously implement safety and operating systems, properly train our people, and will not compromise our behav-ioral standards.
We only work with contractors who share our commitment to safety.
We partner with local
communities to prepare them to respond to unplanned events.
2. We will protect the land where we operate
We install and operate our wells and facilities in the most environmentally sensitive manner.
We look for opportunities to drill multiple wells from a single pad to reduce the size of our surface footprint.
We conduct environmental assessments prior to the execution of work to properly plan for and minimize the impacts of our operations.
We are committed to restoring the environment when we complete our operations to ensure it is as healthy and robust as before we arrived.
3. We will safeguard and manage water resources
We minimize our impact on fresh water by
utilizing alternate sources whenever possible.
We do not dispose wastewater into any surface source (streams, lakes, rivers).
We do not drill or conduct hydraulic fracturing operations unless we are confi-dent that groundwater will be protected.
4. We will minimize air emissions from our operations
We conduct our operations in a manner
that minimizes flaring and venting.
We use alternative or cleaner-fuel source technologies.
We have one of the most modern and operationally efficient drilling fleets in the onshore industry.
5. We will be a good neighbor to our communities
We look for ways to make our operations less
intrusive to the community.
We publicly disclose the chemicals that are used in our hydraulic fracturing operations.
We work with state and local officials to find workable solutions to common industry problems.
We give back to the community in a meaningful way through social investment and partnerships.
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Manufacturing process, ideally suited for productivity improvement
Stake
Build
Drill
Complete
Connect
Development
Clearing and
Well design
Inventory
Equipment
plans and site
construction
Support services
management
procurement
selection
Well pads and
Location moves
Water availability
Coordination
Negotiations
support systems
SIMOPS1
Permitting
Infrastructure and Pipelines
Right of Way negotiations
Construction
1. Simultaneous operations.
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Productivity opportunities have been identified and actioned
Repetitive, manufacturing nature of shale is ideally suited to our productivity agenda
We are targeting multiple opportunities to deliver material value
– reduce drilling costs
per well through efficiency and supply chain management
– increase ultimate recovery through completions optimisation and well down spacing
– reduce spud to sales cycle time to accelerate cash flow through SIMOPS and pad drilling optimisation
Our productivity initiatives have the potential to increase NPV by 20% in the Black Hawk field
Multiple opportunities to deliver material value
(Black Hawk, % NPV
improvement)
20
15
10
5
0drilling costs
improved recovery
spud to sales cycle time
20% NPV improvement opportunity
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Utilising benchmarking and repetition of best practice to drive performance
Total well costs include site preparation and well site facilities
– ~25% of our well
costs are time sensitive
We have utilised a pacesetter concept to improve time performance and repetition of best practice
– pacesetter concept utilises a composite benchmark of fastest drilling times for individual well segments across all wells
Components of Black Hawk well cost
(US$ million)
12
time sensitivenon-time sensitive
8
4
0site preparation
drilling
completions
well site facilities
total well cost
Pacesetter well drilling times
(measured depth, thousand feet)
(casing design)
0
13-3/8”
5
10
9-5/8”
15
pacesetter
average well
5-1/2”
20
0
5
10
15
20
25
(days)
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Targeting a significant reduction in drilling costs
Significant
cost improvement has been realised
We have recontracted key services including fracturing, cementing and casing over the past six months
Well specification reviews are in progress to optimise well design and cost
Drilling cost
performance continues to improve, despite an increase in 3-string wells
Targeting drilling costs below US$4 million per well
BHP Billiton Black Hawk drilling cost performance1
(US$ million)
8
6
4
2
0
Q1 FY13 Q2 FY13 Q3 FY13 Q4 FY13 Q1 FY14 Oct 13
BHP Billiton Black Hawk drilling time
performance2
(days)
40
30
20
10
0
Q1 FY13 Q2 FY13 Q3 FY13 Q4 FY13 Q1 FY14 Oct 13
1. 3-string well design.
2. Drilling time from spud to rig release.
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Increased recoveries provide the greatest upside
We are targeting
an improvement in ultimate recovery from completion optimisation and well downspacing
Multiple field trials are underway to evaluate various components of
completion design
– high temperature gels for better proppant transport
– stage spacing to maximise stimulated rock volume
– reservoir
modelling to simulate stress capture and optimise well sequencing
Early results have significantly exceeded expectations
Significant opportunity to replicate this success across our Onshore US business
Successfully
trialling high temperature frac fluids
(% improvement in cumulative production)
40
individual well
20
0
0
10
20
30
(days)
Improving well EUR through optimal stage spacing
(% improvement in cumulative
production)
60
individual well
40
20
0
0
10
20
30
40
50
60
(days)
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Targeting a reduction in spud to sales time
We are targeting a
reduction in the number of days from spud to sales in the Black Hawk while continuing to focus on safety
– aggressively working down completion inventory with
improved utilisation of frac spreads
– minimising wait time through efficient planning and execution of the process
– focusing on faster execution in all phases
Average spud to sales (on a four well pad)
(days)
200
150
100
50
0
actual
target
drill
wait
complete
connect
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Key themes
Large, high quality resource position across multiple
fields
We have successfully refocused drilling activity on our liquids rich acreage
Progressing development in the liquids rich Permian
We are evaluating options to extend our
liquids profile
Defer dry gas opportunities without loss of value
We will
continue to optimise our investment program for value
Pursuing significant productivity opportunities targeting cost and resource recovery
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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.
| BHP Billiton Limited and BHP Billiton Plc | ||||||
| Date: December 10, 2013 | By: | /s/Jane McAloon | ||||
| Name: | Jane McAloon | |||||
| Title: | Group Company Secretary | |||||