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
November 14, 2011
| BHP BILLITON LIMITED | BHP BILLITON PLC | |
| (ABN 49 004 028 077) | (REG. NO. 3196209) | |
| (Exact name of Registrant as specified in its charter) | (Exact name of Registrant as specified in its charter) |
| VICTORIA, AUSTRALIA | ENGLAND AND WALES | |
| (Jurisdiction of incorporation or organisation) | (Jurisdiction of incorporation or organisation) | |
| 180 LONSDALE STREET, MELBOURNE, VICTORIA 3000 AUSTRALIA |
NEATHOUSE PLACE, VICTORIA, LONDON, UNITED KINGDOM | |
| (Address of principal executive offices) | (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
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BHP Billiton Petroleum Onshore US shale briefing J. Michael Yeager Group Executive and Chief Executive, Petroleum 14 November 2011 bhpbilliton resourcing the future
bhpbilliton resourcing the future Disclaimer Bhpbilliton resourcing the future Reliance on Third Party Information The views expressed here 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. Forward Looking Statements This presentation includes forward-looking statements within the meaning of the US Securities Litigation Reform Act of 1995 regarding future events and the future financial performance of BHP Billiton. 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. 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 2011 entitled “Risk factors”, “Forward looking statements” and “Operating and financial review and prospects” filed with the US Securities and Exchange Commission. No Offer of Securities Nothing in this release 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. J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 Slide 2
bhpbilliton resourcing the future
Petroleum briefing agenda
Bhpbilliton resourcing the future
§?Introduction
§?Part 1: Technical overview of the shale industry
§?Part 2: Business update
J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 Slide 3
bhpbilliton resourcing the future
7th largest independent upstream oil and
gas company by total resource
Shenzi Neptune
Atlantis Mad Dog
Pyrenees Stybarrow
Liverpool Bay
Angostura
Minerva
ROD Zamzama
North West Shelf
Bass Strait
Fayetteville, Haynesville,
Eagle Ford
J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 Slide 4
bhpbilliton resourcing the future
Outstanding safety performance
Petroleum conventional business safety performance
(Number of incidents)
0
| 1 |
| 2 |
| 3 |
| 4 |
| 5 |
0
10
20
30
40
50
FY06 FY07 FY08 FY09 FY10 FY11 Q1 FY12
Recordable incidents
Total recordable injury frequency (TRIF)
J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 Slide 5
(TRIF)
bhpbilliton resourcing the future
Strong production growth
1st back to work in the Gulf of Mexico
Production volumes
(Net, Mboe/d)
200
250
300
350
400
450
FY07 FY08 FY09 FY10 FY11
J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 Slide 6
bhpbilliton resourcing the future
Part 1: Technical overview of the shale industry
J. Michael Yeager
Group Executive and Chief Executive, Petroleum
14 November 2011
bhpbilliton resourcing the future
Conventional and gas reservoirs versus unconventional oil
§?Conventional reservoirs have sufficient porosity and permeability to allow oil and gas to flow through the rock matrix
§?The pore spaces in shale reservoirs are significantly smaller and more restrictive
§?Unlike a conventional field, the shale acts as both the source and the reservoir for the hydrocarbons
§?Shale reservoirs are deep, with depths of up to 15,000 feet (unlike much shallower coal bed methane reservoirs)
Schematic geology of natural gas resources
J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 Slide 8
bhpbilliton resourcing the future
Extracting shale resources
J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 Slide 9
§?To produce profitably, most shale reservoirs require both horizontal drilling and hydraulic fracturing
§?Hydraulic fracturing (or ‘fracing’) is a process used to create fractures within the shale rock matrix
to provide a path for the hydrocarbons to move
§?Fracing has been used on over 1 million producing wells and operators now fracture as many as
35,000 wells per year
Impact of hydraulic fracturing
(Cumulative production, MMcf)
0
2,500
5,000
7,500
10,000
0 10 20 30 40 50
No hydraulic
fracturing
4-year old
technology
Current
technology
Source: Company simulation.
(Years)
bhpbilliton resourcing the future
Advancements in technology
J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011
1821
First commercial
US natural gas
well produces
gas from shale
1860s-1920s
Natural gas is limited to
use in cities close to
producing fields, including
low pressure, fractured
shales in the Appalachian
and Illinois basins
1930s
Technology
developed to lay large
diameter pipelines –
natural gas industry
grows exponentially
1947
Hydraulic fracing
first commercially
employed in Grant
County, Kansas
Source: US Department of Energy, EIA.
Early 1970s
Development of
downhole motors
accelerates – key
to directional
drilling
Slide 10
1980s-1990s
First commercial
horizontal wells
Early 2000s
Initial development of
the Barnett shale play
in Fort Worth, Texas
2002-2008
Multi stage fracing
emerges for both vertical
and horizontal wells
2010+
US shale gas
production rapidly
increases as technology
continues to improve
0
15
30
45
2005 2015 2025
Bcfd
Short development timeline from site
preparation to production
J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 Slide 11
Preparation
of the site Drilling Hydraulic
fracturing Production
2-4 weeks 2-4 weeks 2-4 weeks Decades
bhpbilliton resourcing the future
Preparation of the site
§?Setting up a well site takes 2-4 weeks and includes:
– Construction of roads for the transport of heavy equipment such as the drill rig
– Levelling of the site
– Structures for erosion control
– Construction of lined pits to hold drilling fluids and drill cuttings
– Placement of racks to hold the drill pipe and casing strings
§?Drilling multiple wells from a single location (a pad) creates efficiencies by reducing the number of site preparations required
J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 Slide 12
bhpbilliton resourcing the future
Routine drilling operations
§?The well construction process is started by drilling a 20 inch+ diameter hole to a depth of ~100 feet and installing conductor pipe which is cemented back to surface
§?Drilling is continued vertically to a depth below known groundwater; a casing string is installed and cemented back to the surface providing isolation to the groundwater zones (primary barrier)
§?Directional drilling commences and the well path is steered to penetrate the target zone while simultaneously changing the well inclination from vertical to horizontal
§?Horizontal drilling within the target zone continues until the well reaches the planned total measured depth (lateral length of approximately 5,000 to 6,000 feet)
§?A production casing string is installed and cemented in place (secondary barrier for groundwater zones)
Schematic of horizontal drilling through a shale formation
J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 Slide 13
bhpbilliton resourcing the future
Hydraulic fracturing – the process
1. The horizontal section of the wellbore is perforated with explosive charges, thousands of feet underground within the target zone of the shale formation
2. The perforation tunnels that are created provide communication from the wellbore to the shale formation
3. Fluid and proppant (sand) are pumped into the well at high pressure
J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 Slide 14
bhpbilliton resourcing the future
Hydraulic fracturing – the process
4. Fractures are created and expanded through the pumping process and are kept open by the proppant
5. The fracturing and pumping process is repeated at multiple intervals of the wellbore – after each stage a plug is installed to provide isolation from the previously fractured interval
6. After all frac stages are completed, the plugs are drilled out and hydrocarbons safely flow back to the surface
J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 Slide 15
bhpbilliton resourcing the future
Hydraulic product intensive fracturing – equipment and
§?Surface fracturing equipment consists of multiple pumping units, blending units, control units, and adequate supplies of fracture fluid and proppant material
§?Supplies are transported to location and stored in tanks or containers, and then mixed and pumped into the well
§?A typical well uses 100,000 barrels of fresh water and in excess of 5,000,000 pounds of sand for fracing operations
§?Once the fracture operations are completed, a proportion of the fluids are flowed back to the surface where they are treated for reuse or properly disposed
Example of surface equipment used for hydraulic fracturing operations
J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 Slide 16
bhpbilliton resourcing the future
Minimal environmental impact
The initial footprint is minimised by drilling as many wells together from one location as possible, referred to as ‘pad drilling’
When drilling is completed, the land is restored to its original condition
The production phase creates far less disturbance and can last up to 50 years
Well sites include the well(s) and sometimes limited production and storage equipment
The wells are monitored remotely and accessed only for routine maintenance
Landowners are normally royalty owners
Producing shale gas well
J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 Slide 17
bhpbilliton resourcing the future
Sustainable resources development of shale
Positive impacts
§?Energy security for the US
§?Employment opportunities
§?Lower carbon emissions though coal substitution
§?Attractive landowner mineral rights
Areas of concern
§?Quantity of water used for hydraulic fracturing
§?Chemicals used in hydraulic fracturing
§?Aquifer and groundwater protection
§?Seismic activity
§?Air and noise pollution
J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 Slide 18
bhpbilliton resourcing the future
Efficient alternate water forms usage of energy compared to many
Water is critical to shale gas development, specifically for hydraulic fracing
Confined to the drilling phase, this does not represent a long term requirement
Withdrawals from lakes and streams are subject to regulatory review and approval
On a per unit of energy basis, water used for shale gas operations is significantly less than is used in extracting coal or producing corn ethanol
BHP Billiton continues to evaluate technologies for increasing the recycling of produced water as well as the feasibility of using salty water for fracturing
Shale gas plays and population density in the US
Source: IHS CERA and US Census Bureau.
J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 Slide 19
Chemicals represent a minor component
of the hydraulic fracturing mixture
J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 Slide 20
Typical composition of a
shale fracturing mixture
§?Hydraulic fracing mixtures are typically
99.5% water and sand
– Chemical additives are required to
enable proppant transport and to
prevent damage to the producing zone
§?BHP Billiton has joined more than 20 other
companies to voluntarily disclose the
chemical additives used in the process
Source: US Department of Energy, Groundwater Protection Council.
bhpbilliton resourcing the future
Multiple barriers protect aquifers
J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 Slide 21
§?The horizontal section where the
fractures are created is generally over
a mile deeper than any aquifer
§?As with all oil and gas operations, the
well bore is isolated from the
surrounding rock and aquifers using
concentric steel pipes and cement
§?Fracture height is both measureable
and traceable
§?The small percentage of chemicals
used are relatively benign in the
concentration of the deployed fluids
and industry continues to work towards
making them completely benign
Greater
than 1 mile
Schematic of hydraulic fracturing operations
relative to aquifers and groundwater
Aquifer
Shale
bhpbilliton resourcing the future
Shale versus Coal Bed Methane (CBM)
CBM developments are typically much shallower than shale, creating a greater potential for interaction with groundwater resources
Significant amounts of water are produced when coal seam is depressurised to release the gas
Landowners in US shale developments may receive direct royalties and share in the economic benefits of the development
J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 Slide 22
bhpbilliton resourcing the future
Safe groundwater operations ensure protection of
All oil and gas operations involve the disposal of liquids that must be properly managed
Shale gas production involves the disposal of moderate volumes of water brought up with natural gas during the production process
Water disposal options include underground injection, treatment and discharge or reuse
Although other options are viable, underground injection is BHP Billiton’s preferred water disposal option after the maximum amount is utilised through recycling
Combined with sound operating practices, the underground injection of water substantially reduces any possibility of groundwater contamination
J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 Slide 23
bhpbilliton resourcing the future
Taking concerns a prudent relating approach to seismic to activity address
Water disposal via deep underground injection has been cited as a potential cause of seismic activity, particularly when injection occurs near to faults
Reviews by scientists at regulatory agencies have been inconclusive as earthquake swarms were recorded decades prior to shale industry activity
Nonetheless, two BHP Billiton water injection wells in Arkansas were voluntarily plugged and abandoned as a precautionary measure
BHP Billiton will continue to dispose of water only in approved wells and facilities and this is not expected to impact our business plans or production growth
J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 Slide 24
bhpbilliton resourcing the future
Other impacts on local populations
Local impacts (such as land disruption, air quality changes, wildlife issues and noise disturbance) occur during the drilling phase, which lasts only a few weeks
BHP Billiton complies with all environmental regulations, maintains rigid internal processes and actively consults with local communities
The trade off between local impacts and the economic benefits of shale development are ultimately judged at the state and local levels
BHP Billiton’s operating areas are primarily low population density and overwhelmingly favour shale development
J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 Slide 25
bhpbilliton resourcing the future
Natural source gas is a clean and efficient energy
When reasonable assumptions about industry practices are made, studies agree that in the long term there is a net benefit in moving from coal to gas
As a corporation, our goal is to reduce our greenhouse gas emissions by using clean fuels and by increasing the energy efficiencies in our operations
BHP Billiton sets corporate emissions reduction targets and engages in programs to manage greenhouse gas emissions
J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 Slide 26
bhpbilliton resourcing the future
Key messages
Hydraulic fracing is essential for shale development and is a routine process that has been used for more than 60 years
We will develop our shale assets in line with our values that we will protect people, the environment and the communities in which we operate
We engage regularly, openly and honestly with our host governments and the people affected by our operations, taking their concerns into account in our decision making
Rigorous assessments of all our operations are undertaken as a matter of routine, and we will not undertake any activity that is not in line with our Charter guidelines
We do not expect any material change to our investment plans from sensible regulatory change
J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 Slide 27
bhpbilliton resourcing the future
Part 2: Business update
J. Michael Yeager
Group Executive and Chief Executive, Petroleum
14 November 2011
Agenda
US shale overview
BHP Billiton’s shale assets
Business outlook
J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 Slide 29
What makes US shale work?
J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011
Rig and
services
availability
Large US gas
market
Landowners as
royalty owners
Supportive
regulators
Attractive
fiscal terms
Low population
density in
development
areas
Extensive
pipeline
network
Attractive
geology
Slide 30
Not all shales have this combination of favourable characteristics working together
leading Increasing to greater transparency acceptance and knowledge of shale is
Continued positive movement of support for development
Strong state support due to jobs, taxes and carbon reduction
Supply dependability key to new long term demand
Increases US energy self sufficiency for the long term
Industry’s transparency and technology improvements can have further positive impacts on public sentiment
Possible boost to the US economy for decades
J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 Slide 31
bhpbilliton resourcing the future
Significant ramp up in onshore US shale
J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011
Source: Wood Mackenzie.
0
| 1 |
| 2 |
| 3 |
| 4 |
| 5 |
| 6 |
| 7 |
Jan 08 Jul 08 Jan 09 Jul 09 Jan 10 Jul 10 Jan 11 Jul 11
Barnett
Fayetteville
Marcellus
Eagle Ford
Haynesville
Production
(Bcfd)
Slide 32
bhpbilliton resourcing the future
Shale gas forecast to contribute half of US
supply by 2020
§Shale gas has fundamentally
altered the supply mix
§Increased dependability attracts
customers and regulatory support
§Natural gas is a preferred fuel in a
low carbon world
§Shale forecast to be almost 50% of
total US gas production by 2020
§As long term shale gas supply is
substantiated, current oversupply
will be absorbed
§?LNG export potential and
purchases announced
Slide J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 de 33
Source: Wood Mackenzie.
US natural gas supply
(Bcfd)
US natural gas demand
(Bcfd)
0
20
40
60
80
100
2005 2010 2015 2020 2025 2030
Conventional Net imports Tight gas, CBM Shale
0
20
40
60
80
100
2005 2010 2015 2020 2025 2030
Power Non power
Shale Gas
What BHP Billiton brings to the table
Functional excellence approach:
Systematic improvement to drilling/hydraulic fracturing
Long term technology gains
Scale and leverage to service delivery
Financial ability to do more now and to take a long term approach
Managerial approach to run four simultaneous shale businesses at over US$1 billion annual investment each
. all to create long term shareholder value
J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 Slide 34
Agenda
US shale overview
BHP Billiton’s shale assets
Business outlook
J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 Slide 35
Capturing a significant resource position
§Four extremely large and
concentrated acreage positions
§Core positions in each field
§Long-life, expandable production
base
§Attractive position on the
cost/returns curve, offering strong
economic returns and payback
§Proximity to the Gulf of Mexico
allows price arbitrage
opportunities
§?Each field offers key advantages
for long term economic growth
J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 Slide 36
Liquids area
Dry gas area
Fayetteville – progressing ramp up
§Second largest producer in the play with 487,000 net acres at 58% average operated working interest
§Shallow reservoir depths of 2,000-8,500 feet yield low average drilling and completion costs
§Excellent geology for dependable results and largely derisked through development
§?Current net production 435 MMcfd with pipeline infrastructure in place
§?Total risked net resource potential of 10 Tcf at 70 acre well spacing
§?Total of 6 rigs in the field ramping up to 20 – all rigs to be new build and all now on order
§?Initial service contracts capture significant improvements going forward
§?BHP Billiton team in place – to assume all tasks by April 2012
Slide J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 de 37
Field outline
BHP Billiton interests
Operated acreage
Van Buren Cleburne
White
Faulker
Conway
Pope
Individual well economics
Initial production 3.1 MMcfd
EUR 3.2 Bcf
D&C cost US$3.5 million
Rate of return 16%
Based on November 2011 NYMEX prices.
Eagle Ford offers the highest economic
returns of all US shales
§?Petrohawk drilled the first commercial well in the
Eagle Ford play in 2008 – captured key acreage
§?Rated as the lowest cost play among
North American shales in the liquids rich regions1
§?Attractive product mix of natural gas, condensate
and NGL
§?Highest rig count of US unconventional plays2
§?Average reservoir depths 10,500-14,000 feet at an
approximate D&C cost of US$9-10 million per well
§?Total net acreage holding ~332,000 acres3
§?Current net production 310 MMcfed or
52 Mboe/d (53% liquids)
§?Total risked net resource potential 13.5 Tcfe
(42% liquids) at 90-100 acre well spacing
§?Ramping up from 14 to 26 rigs by 2013
§?Potential for reduced well spacing and higher
recovery factors
Slide J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 de 38
1. Wood Mackenzie.
2. Pritchard Capital Partners “Industry Update” 4 November 2011.
3. Net acreage value includes Hawkville, Black Hawk and Red Hawk fields.
Isopach map net porosity >9%
Hawkville
Field
Black Hawk
Hawkville has the thickest pay in the
Eagle Ford
§?224,000 net acres with average operated working interest of 85%
§?Contributes >50% of BHP Billiton’s net Eagle Ford production at
180 MMcfed or 30 Mboe/d (36% liquids)
§?Total risked net resource potential 10.7 Tcfe (34% liquids)
§?Liquids pipeline available end FY12 (via third party)
§?Ramping up from 5 to 13 rigs by 2013
J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011
24,500 ft
10 Bcf0 Bcfe e
Equivalent EUR
(Bcfe)
Slide 39
Individual well economics (rich gas)
Initial
production
| 5 |
MMcfd gas |
613 bbl/d condensate
EUR 2.5 Bcf gas
250 Mbbl NGL
195 Mbbl condensate
D&C cost US$8.8 million
Rate of return 43%
Individual well economics (lean gas)
Initial
production
8.5 MMcfd gas
EUR 5.0 Bcf gas
207 Mbbl NGL
D&C cost US$9.6 million
Rate of return 15%
Based on November 2011 NYMEX prices.
Based on November 2011 NYMEX prices.
Black Hawk in economic sweet spot of
the play
§?Black Hawk produces the highest value product mix in our
shale portfolio
§?High liquid content substantially improves individual well
economics
§?Liquids pipeline available end FY12 (via third party)
§?58,300 net acres at 48% average operated working interest
§?Current net production of 22 Mboe/d (77% liquids)
§?Total risked net resource potential 2.8 Tcfe (72% liquids)
§?Ramping up from 9 to 13 rigs by 2013
J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011
Equivalent EUR
(Bcfe)
Slide 40
25,500 ft
10 Bc0 Bcf f
Individual well economics
Initial production 3.8 MMcfd gas; 1,615 bbl/d condensate
EUR 1.8 Bcf gas; 220 Mbbl NGL; 550 Mbbl condensate
D&C cost US$9.9 million
Rate of return >100%
Based on November 2011 NYMEX prices.
Haynesville is now the highest producing
shale play in the US
J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011
Source: Wood Mackenzie.
0
| 1 |
| 2 |
| 3 |
| 4 |
| 5 |
| 6 |
| 7 |
Jan 08 Jul 08 Jan 09 Jul 09 Jan 10 Jul 10 Jan 11 Jul 11
Barnett
Fayetteville
Marcellus
Eagle Ford
Haynesville
Production
(Bcfd)
Slide 41
Haynesville is the highest producing gas
field in the US
§?BHP Billiton has the largest amount of the best acreage
in the highest producing gas field in the US
– Strong acreage position with 345,000 net acres in the
Haynesville and Lower Bossier
– Core of the field yields EURs well above field average
– Natural fractures, high TOC1 and over pressured
– Average operated working interest 75% in
Haynesville, and 70% in Lower Bossier
§?Petrohawk has been an industry leader in technical
achievements in this field
§?Direct access to an extensive gas pipeline network with
ample capacity to support production growth
§?Average reservoir depth of 11,800 feet with an average
D&C cost of US$10 million per well (down from
US$15 million per well with technology improvements)
§?Current net production 780 MMcfd
§?Total risked net resource potential of 22 Tcf at
90 acre well spacing
Slide J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 de 42
Haynesville shale EUR contour map
Individual well economics
Initial production 8.5 MMcfd gas
EUR 8 Bcf gas
D&C cost US$10 million
Rate of return 17%
| 8 |
Bcf |
| 4 |
Bcf |
0 Bcf
BHP Billiton acreage
Based on November 2011 NYMEX prices.
1. TOC = Total Organic Content.
0
| 5 |
10
15
0 100 200 300 400 500
Days on production
bhpbilliton resourcing the future
Higher EUR with rate management
§?Petrohawk pioneered the use of rate
management in the Haynesville
§?Choking back wells during initial
production increases ultimate well
recovery
§?Holding more back pressure keeps
fractures open longer
– Average non-restricted EUR: 4-6 Bcf
– Average restricted EUR: 7-9 Bcf
Slide J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 de 43
0
| 2 |
| 4 |
| 6 |
| 8 |
10
Q4 FY08
Q1 FY09
Q2 FY09
Q3 FY09
Q4 FY09
Q1 FY10
Q2 FY10
Q3 FY10
Q4 FY10
Q1 FY11
Q2 FY11
Average individual well EUR
(Bcf)
Restricted well
Non-restricted well
Gas production
(MMcfd)
Permian Basin provides prospective oil
opportunities
§?481 rigs currently drilling industry wide in
the Permian Basin
§?Recent entry into a new liquid rich core
shale area with the acquisition of
325,000 net acres at 86% average
operated working interest1
§?Primarily targeting oil from multiple pay
horizons
§?A highly prospective area with seven
appraisal wells drilled to date and four rigs
currently drilling
§?Very positive early results
§?No volumes projected as plans are not firm
Slide J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 de 44
Delaware
Basin
North
Midland
Basin
South
Midland
Basin
1. Net acreage and average working interest values change with expanding position in the Permian.
High quality shale portfolio
Slide J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 de 45
Field Advantages Opportunities
Fayetteville §?Low cost development
§?Shallow/brittle
§?Rig ramp up
§?Scale/leverage
Eagle Ford §?Liquids rich
§?Industry best field acreage
§?Rig ramp up
§?Reduced well spacing
Haynesville §?Largest core acreage holder
§?Highest EUR per well
§?Controlled rig ramp up
§?Shallower Bossier shale
Permian §?Predominantly liquids
§?Multiple pay horizons
§?Un-appraised acreage
§?Additional land capture
Overall §?Four world class fields, each
with distinct advantages
§?Immediate volume gain
§?Multiple, 30-year
opportunities for optimisation
Agenda
§US shale overview
§?BHP Billiton’s shale assets
§Business outlook
Slide J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 de 46
Shale offers the ability to rapidly increase
volumes and earnings over the long term
§?Conventional oil and gas offers strong returns on a full development basis but expansion
capability is limited post investment
§?Shale developments offer strong returns on an individual well basis and are highly
expandable in both the short and long term
§?Shale complements our existing conventional portfolio
§?Shale is ripe for a long term technology approach which few companies can do –
cost per well, EUR per well, frac design, lateral length, drilling design, etc
Slide J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 de 47
Conventional Feature Shale
Yes Geologic risk No
5+ years 1st production Months
Years Payback Months
Limited Flexibility Significant
Shenzi Limited Expandability Substantial Eagle Ford well
Shale value chain
§?Production is gathered in flow lines and mineral owners take a percentage of production
as a royalty
§?Crude and condensate are separated from wet gas – gas is then processed to separate
Natural Gas Liquids (NGL)
§?Gas price NYMEX benchmarks are translated to regional sales hubs by market
differentials
§?Reporting of the ‘upstream’ and the ‘midstream’ is not uniform across the industry
Slide J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 de 48
Stock tanks
Wet gas
(midstream)
Crude and
condensate
Wells Separation
Dry gas
Natural gas
liquids (NGL)
GParso cperossciensgs ing
Components of Onshore US shale
profitability
J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011
Revenue
§?Gas revenue
§?Liquids revenue
§?Third party gathering
Cash costs
§?Transportation
§?Gathering and processing
§?Midstream operating costs
§?Upstream operating costs
§?Secondary taxes
Non-cash costs
§?Acquisition amortisation
§?Capital depreciation
Slide 49
Onshore US shale cash and performance
analysis
Slide J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 de 50
§?FY12 production target of 545 Bcfe
(or 90 MMboe) including partial year Petrohawk
§?Liquids component approximately 10% and
rising with rig ramp up in the Eagle Ford
§?Liquids and midstream uplift growing from
US$1.20-1.70/Mcfe over the next two years,
driven by growth in liquids
§?Cash costs averaging US$1.90/Mcfe over the
next two years, fully burdened with
non-recurring retention and transition costs
§?Non-cash costs averaging US$2.60/Mcfe over
the next two years, including amortisation of
acquisition costs
Note: FY12 guidance reflects ownership of Petrohawk assets from 20 August 2011.
Long term plans yield significant
improvements
FY12 impacted by short term items
§?Early stage of liquids development
§?Retention programs for Petrohawk staff
§?Major systems costs for land, revenue accounting, etc
§?Excess transport capacity fees to secure future production
Sources of improvement
§?Liquids percentage to double by FY15, without Permian
§?Scale of service contracts continue to be captured in operating and capital costs
§?Optimisation of well spacing, especially in liquids
§?Advances in fracing and other long term technologies are being pursued now
J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 Slide 51
Market indicates that prices will rise
§?Gas demand growth with
dependability of supply
§?Higher cost of new developments,
even in the same field
§?Lower gas drilling activity
– Held by production (HBP)
declining, lowering the US rig
count
– Drilling focus shift to shale with
liquids
– Financial circumstances of
smaller players slows
investments
§?Potential for LNG export
Slide J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 de 52
NYMEX natural gas futures
(1 November 2011, US$/MMbtu nominal)
| 3 |
| 4 |
| 5 |
| 6 |
| 7 |
2012 2013 2014 2015 2016 2017 2018 2019 2020
Onshore US shale outlook
Slide J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 de 53
Forecast production rates (excluding Permian)
(Net, Bcfe/d)
0
| 1 |
| 2 |
| 3 |
| 4 |
| 5 |
| 6 |
| 7 |
| 8 |
FY12F FY15F FY20F
Forecast capital spend
(Net, real, US$ billion)
0
| 1 |
| 2 |
| 3 |
| 4 |
| 5 |
| 6 |
| 7 |
FY12F FY15F FY20F
Note: FY12 guidance reflects ownership of Petrohawk assets from 20 August 2011.
250
Mboe/d
600 +
Mboe/d
1,000 +
Mboe/d
Onshore US shale is an excellent strategic
fit for BHP Billiton
J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 Slide 54
§?World class accessible resource, material to BHP Billiton
– Large, long-life, low cost, with significant future development
§?Access to the world’s largest gas market
§?Low risk due to adequate production history and extensive delineation drilling
§?Long term investment matches our financial strength
§?Large operated positions, leveraging our organisation and expertise
§?Stable operating environment and attractive US fiscal terms
A significant resource position
J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 Slide 55
§?In a single year BHP Billiton
Petroleum’s resource base has
grown by more than 300% to
11 billion barrels of oil equivalent
§?BHP Billiton Petroleum is now one of
the 10 largest independent upstream
oil and gas companies in the world
based on total resources
§?Onshore US provides years of high
return investments at current prices
and exposure to numerous
technology driven upsides
1. Source: Wood Mackenzie.
0
10
20
0
6,000
12,000
Petroleum
30 June 2010
Fayetteville
acquisition
Petrohawk Combined
Resources
Combined net risked resources
(MMboe)
Proved Reserves
Non-proved Resource
Potential
3.7 billion
BOE
1.7 billion
BOE
5.9 billion
BOE
11.3 billion
BOE
Independent upstream oil and gas companies by resources1
(Billions of barrels oil equivalent)
Chesapeake, BG,
Devon, Anadarko
Marathon, Hess,
Woodside
Pre-acquisitioPost-acquisition n
BHP Billiton Petroleum
Full Petroleum outlook
J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 Slide 56
§?FY12 volume target of 225 MMboe
§?Onshore US shale combines with
major growth projects in Western
Australia and the Gulf of Mexico
§?Potential to become a 1 MMboe/d
business in less than 5 years
§?Sustained growth through the rest of
the decade with 10%+ CAGR
0
500
1,000
1,500
2,000
FY11 FY12F FY15F FY20F
Production rates
(Net, Mboe/d)
Notes:
FY11 actual reflects ownership of Fayetteville asset from 31 March 2011.
FY12 guidance reflects ownership of Petrohawk assets from 20 August 2011.
Key messages
§?BHP Billiton has captured key positions in four of
the largest, highest value US shale gas/oil fields,
each with unique advantages
§?Shale economics strengthened by premium
geology and liquids content
§?Rig ramp up in quality reservoirs underpins large
anticipated volume growth – can adjust with
market conditions
§?Developments are in industry-friendly locations
and will be managed as per all BHP Billiton
developments
§?Significant shareholder value with huge
resources and long term approach
J. Michael Yeager, Group Executive and Chief Executive, Petroleum, 14 November 2011 Slide 57
bhpbilliton resourcing the future
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: November 14, 2011 | By: | Jane McAloon | ||
| Name: | Jane McAloon | |||
| Title: | Group Company Secretary | |||