BHP Billiton Investor Briefing - Day 2

8/13/2019 BHP Billiton Investor Briefing - Day 2

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BHP Billiton Limited BHP Billiton Plc171 Collins Street Neathouse PlaceMelbourne Victoria 3000 Australia London SW1V 1BH UKGPO BOX 86 Tel +44 20 7802 4000Melbourne Victoria 3001 Australia Fax + 44 20 7802 4111Tel +61 1300 554 757 Fax +61 3 9609 3015 bhpbilliton.com

bhpbilliton.com

Company Secretariat

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 Companys 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 inour core regions of the United States and Australia, where we have a thorough understanding of thegeology and a proven operating track record. Although our resource base could support substantiallyhigher rates of investment, we will focus on value over volume. Our production guidance for the 2014financial 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 inproximity to existing infrastructure. This will include infill drilling at Shenzi, Pyrenees, Atlantis and MadDog where individual wells can deliver investment returns of over 90 per cent.

When discussing BHP Billitons Onshore US business, Mr Cutt said: On the basis of annualinvestment of US$4 billion, liquids production in our shale business will grow to 200 thousand barrelsper day in the 2017 financial year, with total Onshore US production reaching 500 thousand barrels ofoil 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 flowgenerator for BHP Billiton.

Consistent with our strategy, we continue to evaluate and strengthen our acreage position as we seekto extend our liquids production profile. Our evaluation program in the Permian has successfullyidentified a focus area where we are actively pursuing a 100 thousand barrel of oil equivalent per daydevelopment. The investment associated with our overall evaluation of the Permian Basin, which has


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p

Mr Cutt also said that he will continue to simplify the Petroleum portfolio, for value: Future investmentwill 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 ourinterests 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 SecretaryBHP Billiton Limited

Media Relations

Austral ia

Emily PerryTel: +61 3 9609 2800 Mobile: +61 477 325 803email:[email protected]

Fiona HadleyTel: +61 3 9609 2211 Mobile: +61 427 777 908email:[email protected]

Eleanor NicholsTel: +61 3 9609 2360 Mobile: +61 407 064 748email:[email protected]

United Kingdom

Ruban YogarajahTel: +44 20 7802 4033 Mobile: +44 7827 082 022email:[email protected]

Jennifer WhiteTel: +44 20 7802 7462 Mobile: +44 7827 253 764

Investor Relations

Austral ia

James AgarTel: +61 3 9609 2222 Mobile: +61 467 807 064email:[email protected]

Andrew GunnTel: +61 3 9609 3575 Mobile: +61 402 087 354email:[email protected]

United Kingdom and South Africa

Tara DinesTel: +44 20 7802 7113 Mobile: +44 7825 342 232email:[email protected]

Amer icas

James AgarTel: +61 3 9609 2222 Mobile: +61 467 807 064email:[email protected]

Matt ChismTel: +1 713 599 6158 Mobile: +1 281 782 2238

il M tt E Chi @bh billit
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Focusing on value over volume

Tim Cutt

President, Petroleum and Potash10 December 2013

Pyrenees Western Australia


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Key themes

Slide 4

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


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Safety is our priority

Slide 5

Total Recordable Injury Frequency(TRIF, 12 month moving average)

0

2

4

6

8

Jul 08 Jan 09 Jul 09 Jan 10 Jul 10 Jan 11 Jul 11 Jan 12 Jul 12 Jan 13 Jul 13

Fatality

Shale TRIF

Petroleum TRIF



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Our HSEC focus areas

Slide 6

Community

Continue to make a meaningful contribution through social investment andpartnerships

Health

Minimise exposure to silica during hydraulic fracturing operations inour Shale business

Environment

Manage water usage and reduce greenhouse gas emissions

Safety

Leverage systems and technology to manage material risks



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An experienced Petroleum management team

Slide 7

President Petroleum and Potash

Tim Cutt

VP Strategy and

Development

Rob Kase

President Exploration

David RaineyAsset President Convent ional

Steve PastorAsset President Shale

Rod Skaufel

VP HSEC

Kristen Ray

VP Human Resource

David Nelson

VP Government and

External AffairsFred Hagemeyer

VP Finance

David PowellVP Drilling

Derek CardnoVP Engineering

Doug Handyside

Senior Manager Planning

and PerformanceMichael Stone

VP Marketing

Brett Langley

VP Group Legal

Justin Stuhldreher



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0

2

4

6

8

10

30 June 2008 30 June 2013 30 June 2013

US

Australia

rest of worldgas

liquids

A large, high quality resource portfolio

Slide 8

We have more than doubled our resourcebase and delivered >100% reservereplacement over the past five years

Our business is underpinned by largefields, concentrated in Australia and the US

multiple high return developmentoptions

Our targeted exploration program is

focused on large, high quality oilopportunities primarily within our existingfootprint

BHP Billi ton petroleum resource(billion boe)

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.



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Australia and the US remain our core regions

Slide 9

Trinidad & Tobago

United Kingdom

PakistanAlgeria

Australia

Onshore US

Gulf of Mexico

Petroleum

other

FY14 BHP Bill iton capital and exploration expenditure

Shale

Australia

Gulf of Mexico

Explorationother

PetroleumBHP Billiton

Bubble size represents resource of one billion barrels of oil equivalent.



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Australian assets deliver strong, stable cash flow

Slide 10

Bass StraitNorth West Shelf Pyrenees /

Stybarrow

Macedon Petroleum Underlying EBITDA(US$ billion)

0

5

10

FY09 FY10 FY11 FY12 FY13

Petroleum

Australia

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.

Thebe

Scarborough

Stybarrow

MacedonPyrenees

Macedon

Gas Plant

LNG Plant

Onslow

KarrathaDampier

North West Shelf

Australia

liquids field

Tallaganda

Jupiter

gas field

BHP Billiton acreage



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US assets will underpin substantial growth

Slide 11

Shenzi Atlantis Onshore USMad Dog Neptune

Onshore US

Gulf of Mexico

Bubble size represents resource of one billion barrels of oil equivalent.

Petroleum Underlying EBITDA(US$ billion)

0

5

10


Petroleum

US

Onshore US resource classifications Proved Reserves (1P) 1,334 MMboe, Proved andProbable Reserves (2P) 4,894 MMboe, Contingent Resources (2C) 1,547 MMboe.

Gulf of Mexico resource classifications Proved Reserves (1P) 284 MMboe, Proved andProbable Reserves (2P) 424 MMboe, Contingent Resources (2C) 327 MMboe.

New Mexico

Texas

Oklahoma

Arkansas

Louisiana

Mississippi

Haynesville

Fayetteville

Eagle Ford

Permian

Houston

Shenzi

AtlantisMad Dog

Neptune

liquids focused area

gas focused area




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Conventional investment profile

Slide 12

Conventional life cycle driven by few but

significant front end investment decisions

development plan is established upfront for the full life cycle of the field

early technology decisions have

significant value implications

The majority of capital invested prior tofirst production

Large tranche of initial production

followed by limited additions

Production and free cash flow peak inearly years post start up

(400)

(300)

(200)

(100)

-

100

200

300

400

0 2 4 6 8 10 12 14 16 18 20

EBITDA

capital

free cash flow

Representative investment profile

(US$ million)

0

50

100

150

200

250

300

0 2 4 6 8 10 12 14 16 18 20

nearfield tie-ins

infill drilling

initial project

Representative production profile(MMboe)

OperationsOperationsExecutionExecutionEngineeringEngineeringAppraisalAppraisalExplorationExplorationBrownfield

projects

Brownfield

projects

Representative investment and production profiles are for illustrative purposesonly and do not reflect actual BHP Billiton estimates or operations.

years

years



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-

5.00

10.00

15.00

20.00

25.00

30.00

35.00

40.00

45.00

50.00

0 2 4 6 8 10 12 14 16 18 20

Shale investment profile

Slide 13

Shale life cycle driven by continuous

investment decisions and optimisationopportunities

thousands of potential well locations,each reflecting a discrete opportunity

Significant portion of annual capital offsetby early revenue generation

Flexibility to adjust development plans inresponse to market conditions

Multiple opportunities to add materialvalue over the long term

Progressive development delivers steadygrowth in production and free cash flowover many years

(30)

(20)

(10)

-

10

20

30

40

50

60

0 2 4 6 8 10 12 14 16 18 20

EBITDA

capital

free cash flow

Representative investment profile

(US$ million)

Representative production profile(MMboe)

Area speci fic

tests

Area speci fic

testsAppraisalAppraisal

Mapping and

Leasing

Mapping and

LeasingExplorationExploration Full developmentFull development

years

yearsRepresentative investment and production profiles are for illustrative purposesonly and do not reflect actual BHP Billiton estimates or operations.



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0

5

10

15

20

25

30

0 100 200 300 400 500

BHP Billiton

near term focus

BHP Billiton

long term valuecreation

BHP Billiton

development

options must

compete within

the portfolio

A clear focus on value over volume

Slide 14

We will prioritise the highest returninvestment opportunity

investment in our shale liquidsacreage (tight oil) generates strong

returns

deepwater infill drilling and brownfieldexpansions will maximise the value ofour Conventional business

preserving the value of our dry gasshale acreage

We will continue to simplify the portfoliofor value

interest in Browse divested for

US$1.7 billion in FY13

Liverpool Bay divestment announcedin October 2013

Source: Wood Mackenzie.

Greenfield project IRR(%, IRR)

Oil sands Greenfield

LNG

Shale gas Conventional

Tight oil

Deepwater

Capital investment in greenfield projects 2006-2020

(US$ billion)



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FY14 production guidance maintained

Slide 15

On track to produce 250 MMboe in FY14

75% increase in shale liquids production

stable Conventional volumes as Macedonand Atlantis offset natural field decline andplanned maintenance

Production for the December 2013 quarter isexpected to decline to approximately 58 MMboe

Bass Strait seasonal demand

Pyrenees scheduled maintenance

Eagle Ford planned facility tie-in activities

well remediation and weather relateddowntime at Hawkville

partially offset by strong Atlantis performance

0

100

200

300

FY09 FY10 FY11 FY12 FY13 FY14e

Conventional

Shale gas

Shale liquids

Strong growth in Shale liquids product ion(Petroleum production, MMboe)

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 pendingsuccessful transaction close expected in H2 FY14.



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Leveraging the infrastructure of our

Conventional business

Slide 16

Capital expenditure of ~US$1.5 billion perannum is expected to maintain Conventionalvolumes for three to five years

high return infill drilling at Shenzi,

Pyrenees, Atlantis and Mad Dog

completion of field extension projects atBass Strait and North West Shelf

FY14 Conventional production outlook(MMboe)

100

120

140

FY13

Base

dec

line

Mac

edon

Atlanti

sinfill

Pyrenee

sinfill

Nort

hRan

kin2

other

F

Y14e

Capital spend

(BHP Billiton share)

IRR1

Shenzi infill well US$62 million >90%

Atlantis infill well US$91 million >100%

Pyrenees 3 well

subsea tie-back2

US$218 million ~20%

FY14 Conventional infill drilling returns

1. After tax, based on September 2013 futures prices.2. Includes additional subsea manifolds and flowlines.



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Development options must compete for capital

Slide 17

We own significant contingent resourceswithin our core areas

Scarborough (ExxonMobil operated,BHP Billiton share 50%) is an ~8 tcf1

(100% basis) gas resource

Mad Dog (BP operated, BHP Billitonshare 23.9%) is among the largest oilfields in the Gulf of Mexico

Both projects are under evaluation with a firmfocus on improving capital efficiency

We will pursue the path that maximisesshareholder value

Mad Dog field Gulf of Mexico

Scarborough / Thebe Western Australia

North

East

West

Phase 2

Mad Dog p latform

1. Resources on a 2C basis.

Thebe

Scarborough

Stybarrow

MacedonPyrenees

Macedon

Gas Plant

LNG Plant

Onslow

KarrathaDampier

North West Shelf

Australia

liquids field

Tallaganda

Jupiter

gas field




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Shale development plan will be continually

optimised for value

Slide 18

We are prioritising investment in the liquidsrich, high return shale assets

pursuing accelerated development in theprolific Black Hawk area of the Eagle Ford

timing Hawkville development for liquidscontent and lease retention

large scale development of the Permianwill extend our liquids production profile

We are preserving the value of our dry gasshale assets

current drilling in the Haynesville delivers30%1 rates of return

Fayetteville investment limited to strongnon-operated opportunities with 25%1

rates of return

We have flexibility in our Shale portfolio to timeinvestment for maximum value

BHP Bil liton Onshore US shale plays

1. After tax, based on September 2013 futures prices.

Houston


dry gas focused area



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Positioned to deliver substantial growth in free

cash flow

Slide 19

Our Shale business must compete forcapital within the broader BHP Billitonportfolio

annual budgets will be subject to

ongoing review

A capital expenditure program ofUS$4 billion per annum will support stronggrowth in liquids production

forecast ~200 kb/d of liquids by FY17from the Eagle Ford and Permian

growth in gas production reflectsassociated gas from our liquids richareas

Free cash flow from our Shale business isexpected to be positive by FY16 and toapproach US$3 billion per annum by theend of the decade

0

150

300

450

600

FY12 FY13 FY14e FY15e FY16e FY17e FY18e

crude & condensate NGL associated gas dry gas

Onshore US production scenario(kboe/d)

(5)

0

5

10


EBITDA capital free cash flow

Onshore US free cash f low scenario1

(US$ billion, pre-tax 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, newopportunities and BHP Billiton Group capital prioritisation.



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Extending our high return l iquids profi le

Slide 20

Efforts underway to expand our Permianland position in our core focus area

100,000 net acres1 in this focus area

acquiring additional acreage in highlyprospective areas with a view toconsolidating our position within ourfocus area

testing multiple productive horizons

First shale exploration well drilled inOctober 2013 in the emerging Pearsall play

successfully accessed 30,000 netacres1 and an option for an additional70,000 net acres2, all contiguous

evaluation ongoing to determineliquids production potential

Pearsall 100,000 net acres

Permian focus area 100,000 net acres

Black Hawk 58,000 net acres

PearsallFocus

area

Houston



1. As at 30 June 2013.2. As at 31 October 2013.



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We have flexibility to adjust our plans

Slide 21

Development of our existing liquids acreagedominates our investment program

infrastructure component will declineas build out in the Eagle Ford is largely

completed in the near term

Near term dry gas investments yieldattractive returns, however they can bedeferred without loss of value

We have significant flexibility to adjustour plans

extend liquids program with explorationsuccess and/or acreage optimisation

ramp up dry gas development asmarket conditions improve

0

1

2

3

4

5

FY11 FY12 FY13 FY14e FY15e FY16e FY17e FY18e

liquids liquids expansion or dry gas ramp up dry gas

Onshore US capital expenditure scenario(US$ billion)



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Our productivity agenda continues to deliver

strong results

Slide 22

Repetitive, manufacturing nature of shale isideally suited to our productivity agenda

reduce drilling costs per well throughefficiency 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 paddrilling optimisation)

These low cost initiatives have the potentialto unlock substantial value

Improving well EUR2 through completion optimisation(% improvement in cumulative production)

1. For 3-string well design.2. Estimated ultimate recovery.

BHP Billi ton Black Hawk drilling cost performance1

(index, Q1 FY13 = 100, US$ million)

40

60

80

100

Q1 FY13 Q2 FY13 Q3 FY13 Q4 FY13 Q1 FY14 Oct-13

0

20

40

60

0 10 20 30 40 50 60

individual well

(days)



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Strong outlook with growth prioritised for value

Slide 23

0

100

200

300

400

FY09 FY10 FY11 FY12 FY13 FY14e FY15e FY16e FY17e FY18e

Conventional

Onshore US

Petroleum production scenario1

(MMboe)

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 marketconditions, 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 pendingsuccessful transaction close expected in H2 FY14.



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Key themes

Slide 24

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



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A major earnings

contributorDavid Powell

Vice President, Finance10 December 2013


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Product mix a key driver of Onshore US revenue

Slide 28

Decisive response to market conditionsunderpins significant growth in Onshore USliquids 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 USNGL price represents ~32% of WTI1

We achieve ~95% of the Henry Hub gas price

due to location differentials

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.

0

25

50

75

100

0

30

60

90

120

Jan 11 Jul 11 Jan 12 Jul 12 Jan 13 Jul 13

NGL price as a % of WTI WTI

US NGL prices have diverged from oil(WTI, US$/bbl) (NGL price as % of WTI)

0

20

40

60

0

20

40

60

FY12 FY13 FY14e

NGL

crude and condensateliquids revenue contribution

Onshore US liquids contribut ion(% of total Onshore US production) (% of total revenue)



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40

50

60

70

80

0

5

10

15

20


production cash cost transportationproduction taxes and other non-recurringEBITDA margin

Seeking to improve our low cost position

Slide 29

Petroleum costs(US$/boe)

Shale all in cash costs2

(US$/boe) (%)

Low cost conventional operations underpinexceptional margins

Our decision to prioritise shale liquidsdevelopment has increased margins albeit

with an increase in average production costs

costs expected to decline in the mediumterm 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 millionin FY14 associated with the optimisationof our dry gas program (majorityincurred in H1)

underutilised legacy gas pipelinecommitments will incur charges of~US$170 million per annum in FY14and FY15, primarily in the Haynesville

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.

0

5

10

15

20

FY09 FY10 FY11 FY12 FY13 FY14e FY15e

production cash cost all in cash cost



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Timing of reserve additions impacts depreciation

Slide 30

Conventional unit depreciation remainshighly competitive

minor variations reflect project start-upsand timing of resource additions

Our successful Permian evaluation programhas near term depreciation implications

we will incur ~US$600 million indepreciation charges in FY14 on

4 MMboe of Permian production Permian depreciation rate is expected to

normalise as production ramps up andreserves are booked

Shale depreciation(US$ billion)

Depreciation(US$/boe)

0

5

10

15

20

25

FY09 FY10 FY11 FY12 FY13 FY14e FY15e

Petroleum Conventional Shale

0

5

10

15

20

25

0

1

2

3

4

5


Shale other Permian unit depreciation

(US$/boe)



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A compelling long term outlook for Onshore US

Slide 31

Onshore US margin scenario1

(%)

(20)

0

20

40

60

80

FY13 FY14e FY15e FY16e FY17e FY18e

EBITDA margin

EBIT margin

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, newopportunities and BHP Billiton Group capital prioritisation.



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Understanding the US fiscal regime

Slide 32

The fiscal regime in the US is aimed atencouraging development of oil and gasresources

US tax code allows for immediate deduction

of intangible drilling and development costs(IDC) deferring cash tax

contributes to carry forward tax NetOperating Losses



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A high return investment program

Slide 33

Petroleum offers some of the highest returninvestment 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 forOnshore US will be invested in our liquidsrich acreage

Conventional spend of ~US$1.7 billion

focused on high return infill drilling and fieldextension projects

US$600 million exploration budget will targethigh quality oil opportunities

Capital and exploration expenditure(US$ billion)

0

5

10

15

20

25

FY09 FY10 FY11 FY12 FY13 FY14e

Petroleum BHP Billiton



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Maximising the value of our

Conventional businessSteve Pastor

Asset President, Conventional10 December 2013

Trinidad


38/90

Key themes

Slide 36

Operating excellence and highly profitable assets provide a strong foundation for ourPetroleum 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 thatmaximises shareholder value

We will continue to simplify our portfolio

Our conventional assets will continue to deliver strong, stable free cash flow



39/90

A strong foundation for our Petroleum business

Slide 37

Note: Conventional volumes, BHP Billiton share. Based on FY14 forecast production. Size of bubbles scaled to production rates.

Austral ia operated50 kboe/d

Trinidad & Tobago19 kboe/d

gas

crude & condensate

LNG

NGL

Gulf of Mexico87 kboe/d

North West Shelf75 kboe/d

Bass Strait96 kboe/d

International other46 kboe/d

0

5

10


Petroleum

Conventional

Petroleum Underlying EBITDA(US$ billion)

Conventional production outlook(FY14, BHP Billiton share)



40/90

Highly profitable Conventional business

Slide 38

Australia and the Gulf of Mexico are our coreregions with valuable infrastructure positions

Conventional volumes have remained steady

~50% crude, condensate and NGL ~50% natural gas

Liquids contributed ~70% of revenue inFY13, underpinning exceptional EBIT

margins

Our Conventional business continues todeliver strong, stable free cash flow

Production volume(Conventional, MMboe) (%)

Underlying EBIT(US$ billion) (%)

45

50

55

60

65

0

2

4

6

8


EBIT EBIT margin

0

20

40

60

80

0

50

100

150

200


liquids gas % revenue liquids



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Maximising value through operational excellence

Slide 39

We are an industry leader in deepwaterdrilling capability and operational uptime

our drilling times are well below industryaverage

we were the first operator to resumeproduction drilling in the Gulf of Mexicopost Macondo

average operated facility uptime ~95%

We are applying technology to increase valueand identify additional resources

4D seismic technology and reservoirsimulation to identify infill opportunities

water injection to maximise recovery

Average dr ill time per 1,000 ft(Deepwater Gulf of Mexico, subsalt, days)

Macedon

FY13 facility upt ime

0

2

4

6

8

pre-moratorium post-moratorium

others BHP Billiton

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.

80%

90%

100%

OBO

Stybarrow

Pyrenees

Shenz

i

Nep

tune

Angos

tura

Zamzama

Minerva



42/90

Strong track record of project delivery

Slide 40

Demonstrated ability to deliver our projectson budget and schedule

Six major operated projects completed onschedule and budget in the last six years

two deepwater Tension Leg Platforms(TLP) in the GoM, Shenzi and Neptune

two Floating Production Storage andOfftake (FPSO) vessels in Western

Australia, Stybarrow and Pyrenees Angostura Phase 2 gas project in

Trinidad

Macedon gas development in WesternAustralia (FY14 start-up)

These projects contributed >35% ofPetroleums FY13 Underlying EBIT

NeptuneShenzi

Macedon

PyreneesStybarrow

Angostura



43/90

Operator BHP BillitonResources1

130 MMboeWorking interest 44%

First production date 2009

FY13 net production 17 MMboe

0

50

100

150

Mar 09 Dec 09 Sep 10 Jun 11 Mar 12 Dec 12 Sep 13

first production infill production

Shenzi our premier operated facility

Slide 41

High quality reservoir over 400 feet thick in theGulf of Mexico

Excellent operating performance, ~95% uptimesince start-up

High return infill drilling campaign continues toextend the production profile

Two new infill wells in FY14 will maintain nearterm production at nameplate capacity

Valuable incremental investment opportunitiesare under evaluation

additional infill and water injection wells

exploration to the north of the field

1. 2P+2C remaining resource as at 30 June 2013, BHP Billiton share.

Shenzi production(kboe/d, 100% basis)

Shenzi field map

facility nameplate capacity

P169%

P221%

2C10%

East

North

West

Shenzi platform



44/90


45/90

North

EastWest

Phase 2

Mad Dog release of high margin latent capacity

Slide 43

Mad Dog is among the largest oil fields in theGulf of Mexico

Mad Dog Phase 1 rig lost during Hurricane Ike in2008 has been replaced and is now operational

Additional scheduled downtime during FY14 isexpected to reduce year on year production

Infill drilling is expected to increase Phase 1production in FY15, with rates approachingfacility capacity by FY18

Substantial resource potential for Phase 2development of South and West areas Mad Dog production

(kboe/d, 100% basis)

1. Includes Mad Dog Phase 2 resource. 2P+2C remaining resource as at 30 June 2013, BHP Billiton share.

Mad Dog field map

Mad Dog p latform

0

20

40

60

80

Jan 05 Mar 07 May 09 Jul 11 Sep 13

first production infill production

facility nameplate capacity

Operator BPResources1

266 MMboeWorking interest 23.9%



P121%

P26%

2C73%



46/90

0

50

100

150

Nov 07 Oct 08 Sep 09 Aug 10 Jul 11 Jun 12 May 13

Stybarrow and Pyrenees Macedon

WA operated valuable infrastructure position

Slide 44

Significant resource and valuable infrastructureposition underpins our operated assets in this area

Macedon gas project now online, expected tocontribute 6 MMboe (BHP Billiton share) in FY14

Multi well extension program at Pyreneesexpected to deliver additional 20 kboe/d (100%basis) in H2 FY14

Significant exploration acreage under permit

Leveraging existing infrastructure unlocks potentialfor additional high return opportunities

1. 2P+2C remaining resource as at 30 June 2013, BHP Billiton share.2. First production from the Stybarrow field.

Western Australia operated production(kboe/d, 100% basis)

Macedonstart-up

Western Australia operated assets

Operator BHP BillitonResources1

170 MMboe



P150%

P226%

2C24%

Stybarrow

Macedon

Pyrenees

Macedon

Gas Plant

Onslow

Tallaganda

Australia

liquids field

gas field



B S i l C i l


47/90

Bass Strait our largest Conventional asset

Slide 45

Delivered first production more than 40 years ago

Project execution challenges at Turrum and Kipperresulted in revisions to original budget and schedule

Longford gas conditioning plant on budget and

schedule with start-up CY16; Kipper mercuryremoval anticipated start-up CY16

Turrum and Kipper will deliver valuable additionalwet gas partially offsetting liquids decline

Eastern Australia gas prices expected to strengthenwith new LNG demand and rising costs of supply

Assessing additional opportunities to extend gasplateau production through 2030 and beyond


0

100

200

300

400

2001 2003 2005 2007 2009 2011 2013

liquids gas

Bass Strait product ion(kboe/d, 100% basis)

Bass Strait assets

Operator EssoResources1

664 MMboeWorking interest 50%



P158%

P220%

2C22%


N th W t Sh lf j A i LNG li


48/90

North West Shelf a major Asian LNG supplier

Slide 46

NWS has five LNG trains with capacity of 16 mtpa

Major projects will extend the production profile

North Rankin 2 online October 2013 onschedule and budget

Greater Western Flank A (GWF-A) onschedule and budget, start-up CY16

Additional projects under evaluation includingGWF-B and Persephone

NWS joint venture is assessing opportunities toprocess third party gas to maximise value fromestablished infrastructure


0

200

400

600

2001 2003 2005 2007 2009 2011 2013

liquids gas LNG

NWS production(kboe/d, 100% basis)

NWS assets

Operator WoodsideResources1

483 MMboeWorking interest 14.85%



P174%

P23%

2C23%


International assets Trinidad has significant


49/90

0

10

20

30

40


Trinidad Pakistan Algeria UK

Production from International operations(MMboe, BHP Billiton share)

International assets Trinidad has significant

potential

Slide 47

Trinidad has the potential to become a third coreregion for our Petroleum business

plans to extend production plateau atAngostura

exploration focused on highly prospectivedeepwater acreage

Non-operated ROD asset in Algeria contributessubstantial cash flow

We continue to achieve excellent performanceand uptime at our operated Zamzama asset inPakistan

We have announced the divestment of our UK

Liverpool Bay asset

Trinidad


All i t t t t f it l


50/90

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 optimisedevelopment concepts

We will pursue the path that maximisesvalue for shareholders

All investments must compete for capital

Slide 48

Scarborough / Thebe Western Australia

1. Resources on a 2C basis.

Thebe

Scarborough

Stybarrow

MacedonPyrenees

MacedonGas Plant

LNG Plant

Onslow

KarrathaDampier

North West Shelf

Australia

liquids field

Tallaganda

Jupiter

gas field



F th t iti i th G lf f M i


51/90

Further opportunities in the Gulf of Mexico

Slide 49

Mad Dog Phase 2 has potential to deliverhigh rates of return

we are assessing development conceptswith the operator

Stampede (formerly Knotty Head) is 30 milesnorth west of Mad Dog

BHP Billiton 20%, Hess operated

continuing to assess options for this field

Gulf of Mexico assets



W ill i li f th tf li f l


52/90

We will simplify the portfolio for value

Slide 50

Six assets contributed >90% of PetroleumUnderlying EBIT in FY13

Recent divestments highlight our ability tocreate substantial value

interest in Browse divested forUS$1.7 billion in FY13

Liverpool Bay divestment announced inFY14

We will continue to simplify the portfolio witha firm focus on value

1. Excludes exploration and unallocated overheads.

Contribution from the core regions(Underlying EBIT,% of Conventional total1)

0

20

40

60

80

100


Gulf of Mexico Australia rest of world


K th


53/90

Key themes

Slide 51

Operating excellence and highly profitable assets provide a strong foundation for ourPetroleum 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 thatmaximises shareholder value

We will continue to simplify our portfolio

Our conventional assets will continue to deliver strong, stable free cash flow



54/90


55/90

A disciplined focus on Tier 1

oil opportunitiesDavid Rainey

President, Exploration10 December 2013

Asset name here

Key themes


56/90

Key themes

Slide 54

We are targeting large, high quality oil opportunities, primarily within our existingoperated 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 theGulf of Mexico and Western Australia

We have built a material position in deepwater Trinidad and Tobago that could underpina future core area

Our shale exploration activity is aimed at extending our high return liquids profile in the

Gulf Coast and Permian Basins


Focused conventional exploration program


57/90

Focused conventional exploration program

Slide 55

Gulf of Mexico

Progress best Miocene opportunities

Evaluate other Gulf of Mexico plays forTier 1 potential ahead of lease turnover

Gulf of Mexico

Progress best Miocene opportunities

Evaluate other Gulf of Mexico plays forTier 1 potential ahead of lease turnover

Western Australia

Drill Bunyip exploration well

Evaluate and test near field opportunities

Complete regional geology study,

targeting large oil plays

Western Australia

Drill Bunyip exploration well

Evaluate and test near field opportunities

Complete regional geology study,

targeting large oil plays

Trinidad and Tobago

Commence seismic program2

Plan for CY16 drilling

Trinidad and Tobago

Commence seismic program2

Plan for CY16 drilling

South Africa

Process seismic1 anddetermine Tier 1 potential

South Africa

Process seismic1 anddetermine Tier 1 potential

Tier 1 exploration cr iteria

World class source rock

Big reservoir system

Large traps

Acceptable fiscal terms

Early mover

Core area

Evaluating

Southeast Asia

Evaluate current acreagefor Tier 1 potential

Southeast Asia

Evaluate current acreagefor Tier 1 potential

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.

Brazil Plan for seismic in FY162Brazil Plan for seismic in FY162


We have built a material position in


58/90

Shenzi

Mad Dog

At lantis

*sizes are to scale

50 km

Trinidad

Tobago

Angostura

Leads

BHP Billiton blocks

p

Trinidad and Tobago

Slide 56

We have an established operational presencein 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 materialearly mover position in deepwater Trinidadand Tobago

We are commencing a major 17,000 squarekilometre seismic acquisition program in FY14

Large footprints

Pegleg lead


Extending our high return shale liquids profile


59/90

Extending our high return shale liquids profile

Slide 57

Our priority is to delineate the liquidsweet spots in the Gulf Coast andPermian Basins to guide acreageoptimisation

Pearsall exploration well drilled inOctober 2013 targeting horizonbelow the Eagle Ford shale

Continuing to assess other NorthAmerican shale plays for possibleliquids potential

We are building our understandingof the global endowment of shaleresources

Total industry wells drilled since 2001

Permian

Eagle Ford

Fayetteville

Haynesville

Source: IHS Global Inc.


Key themes


60/90

Key themes

Slide 58

We are targeting large, high quality oil opportunities, primarily within our existingoperated 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 theGulf of Mexico and Western Australia

We have built a material position in deepwater Trinidad and Tobago that could underpina future core area

Our shale exploration activity is aimed at extending our high return liquids profile in the

Gulf Coast and Permian Basins



61/90


62/90

Extending our high return,

shale liquids profileRod Skaufel

Asset President, Shale10 December 2013

Eagle Ford Texas

Key themes


63/90

Key themes

Slide 61

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


Significant presence in premier US shale plays


64/90

Significant presence in premier US shale plays

Slide 62

We hold 1.5 million net acres1 across fourhighly productive US shale plays and threeUS states

Black Hawk (Eagle Ford) condensate

rich Hawkville (Eagle Ford) mix of

condensate and gas with NGL

Permian liquids rich but geologicallycomplex

Haynesville prolific dry gas wells withpremier acreage position

Fayetteville long term, low technicalrisk, dry gas option

BHP Bil liton Onshore US shale plays

Houston



1. As at 30 June 2013.


A high quality shale resource portfolio


65/90

A high quality shale resource portfolio

Slide 63

0.0

0.5

1.0

1.5

2.0

2.5

3.0

Haw

kv

ille

Perm

ian

Blac

kHaw

k

Haynesv

ille

Faye

ttev

ille

Contingent Resources (2C)

Probable Reserves

Proved Reserves

Onshore US resources by category(as at 30 June 2013, net, billion boe)

0.0

0.5

1.0

1.5

2.0

2.5

3.0

Haw

kv

ille

Perm

ian

Blac

kHaw

k

Haynesv

ille

Faye

ttev

ille

liquids

gas

Onshore US resources by product(as at 30 June 2013, net, billion boe)


Dry gas acreage is largely Held by Production


66/90

Dry gas acreage is largely Held by Production

Slide 64

In the Haynesville and Fayetteville, leasescomprise regulatory unit size of 640 acres,generally one square mile

Lease terms range from approximately three

to seven years

Acreage is retained provided production isestablished within the term of the lease andcontinues in economic quantities i.e. Held byProduction (HBP)

Limited obligation drilling remaining in ourHaynesville and Fayetteville acreage,providing flexibility to time investment for value

Similar lease arrangements exist in the BlackHawk area of the Eagle Ford

well drilled

future well option released acreage

held acreage

Lease acreagewithin the unit is

retained onceproduction isestablished i.e.

Held byProduction (HBP)

Example: multiple leases within a 640 acre unit heldonce production established within terms of the leases

Otheroperator

Acreage is lost ifunit production isnot established

within the terms ofthe leasesOther

operator


Hawkville has continuous drill ing obligations


67/90

Hawkville has continuous drill ing obligations

Slide 65

Hawkville is characterised by irregular leaseswith boundaries often defined by the largeranches held by private landowners

Portions of the lease are earned through

drilling with time dependent requirementsi.e. Continuous Drilling Obligations

If continuous drilling obligations are allowedto lapse, acreage that has not been earned islost unless an extension can be secured fromthe landowner

Ongoing evaluation undertaken to ensure thatretained acreage meets economic criteria

Similar leasing arrangements in Permian

First well retains320 acres aroundthe well, creating

the option forfuture drilling in the

retained area

Second well mustbe drilled within six

months of the firstwell, retaining

another 320 acres

If the six monthcontinuous drilling

requirement is notmet, all unearned

acreage at thattime is released

Example1: Large, irregular leases with continuous,time dependent drilling obligations for retention

well drilled

future well option released acreage

held 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.


Rigs re-focused to liquids development


68/90

Rigs re focused to liquids development

Slide 66

0

10

20

30

40

50

0

20

40

60

80

100

Sep

11

Oc

t11

Nov

11

Dec

11

Jan

12

Fe

b12

Mar

12

Apr

12

May

12

Jun

12

Ju

l12

Aug

12

Sep

12

Oc

t12

Nov

12

Dec

12

Jan

13

Fe

b13

Mar

13

Apr

13

May

13

Jun

13

Ju

l13

Aug

13

Sep

13

Oc

t13

Black Hawk Hawkville Permian Haynesville Fayetteville rig count

Onshore US operated rigs(% rig split) (average number of gross operated drill rigs)


Delivering strong growth in high value liquids

d i


69/90

production

Slide 67

0

10

20

30

Q2FY12

Q3FY12

Q4FY12

Q1FY13

Q2FY13

Q3FY13

Q4FY13

Q1FY14

Black Hawk Hawkville

Permian Haynesville

Fayetteville

Onshore US production by area(MMboe)

0

10

20

30

Q2FY12

Q3FY12

Q4FY12

Q1FY13

Q2FY13

Q3FY13

Q4FY13

Q1FY14

liquids

gas

Onshore US production by product(MMboe)


We are among the largest producers in the

E l F d


70/90

Eagle Ford

Slide 68

Eagle Ford is now the largest producingfield within our Petroleum portfolio

currently producing in excess of100 kboe/d (BHP Billiton share)

approximately 60% liquids

Potential to build production above200 kboe/d by FY16 based on currentdevelopment plans

0

25

50

75

100

125

2007 2008 2009 2010 2011 2012 2013e

Eagle Ford product ion by operator(net, kboe/d)

BHP Billiton1

Source: Wood Mackenzie Q3 2013; BHP Billiton analysis.1. Includes legacy Petrohawk.

other operators


We hold a premier position in the Eagle Ford


71/90

We hold a premier position in the Eagle Ford

Slide 69

Black Hawk (58k net acres1) in theheart of the condensate window

Hawkville (250k net acres1) a mixof condensate and gas with NGLs

Approximately 75% of our FY14Onshore US drilling activity isfocused on the Eagle Ford

Continuous drilling is required toretain leases in Hawkville witheach investment decision subjectto strict economic criteria

condensate window


Black Hawk

Hawkville

BHP Bil liton Eagle Ford acreage posi tion

1. As at 30 June 2013.



72/90

Hawkville mix of condensate and gas with NGL


73/90

Hawkville mix of condensate and gas with NGL

Slide 71

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 inthe north of the field

Southern area primarily gas with NGL

preparing to release roughly 50k netacres in FY14 that do not meeteconomic criteria for retention

Hawkville acreage position

condensate window


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.


Haynesville strong returns at current prices


74/90

Haynesvil le acreage by Recoverable Resource

y g p

Slide 72

Premier acreage position in one of the mostproductive shale gas plays in the US


Average dry gas production of 89 kboe/d(BHP Billiton share) during the September2013 quarter

FY14 drilling activity in sections with workinginterest ranging from 50-100%

Typical single well economics (FY14 program, 100% basis)

Initial production1 8.5 MMcf/d

Resources 11 bcf gas


Rate of return3 30%

>10 8-10 6-8


75/90

y p g

Slide 73

Extensively drilled with low geologic risk


Average dry gas production of 68 kboe/d

(BHP Billiton share) during the September2013 quarter of which approximately 45%was non-operated

Operated rig program currently suspendedwith value preserved for future investment

Continuing to selectively invest in strongnon-operated opportunities within the coreof the field Typical single well economics (FY14 OBO program, 100% basis)

Initial production1 3.8 MMcf/d gas

Resources 4.5 bcf gas


Rate of return3 25%

Fayetteville map with FY13 non-operated dril ling

FY13 non-operated wells put online

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.

>5 4-5 3-4 2-3


76/90

focus area

Slide 74

BHP Bil liton acreage in the Permian basin

Focus area

Divestment area

Divestment area

Under evaluation


Permian unique multiple horizon potential


77/90

q p p

Slide 75

Large liquid bearing column creates thepotential for multiple economicallyproductive horizons

A vertical well program followed by

targeted horizontal wells has been usedto appraise the play

Extensive appraisal program given thelarge areal and vertical footprint

Lease ownership interest can vary bydepth and horizon

Lower

Middle

Upper

3rd

2nd

1st

Avalon

BoneS

pring

Wolfcamp

Schematic for

representative purposes

Approximately4,0

00feetth

ick


Permian targeting a 100 kboe/d development


78/90

g g p

Slide 76

Production rate recent wells in focus area(boe/d, 100% basis)

Well results support planned 100 kboe/ddevelopment within the focus area withapproximately 60% liquids

Process of acquiring and consolidating our

acreage position

Testing multiple productive horizons

Significant productivity upside with lowerwell cost and higher recovery as we havedemonstrated in Black Hawk

(days)

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

0 50 100 150 200


Shale capital allocation optimised for value


79/90

p p

Slide 77

1. For every operated well, we calculate the optimumtiming to deliver maximum value, utilising forwardprice 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 whiletaking into account:

acreage retention requirements

operational capability

competing non-operated opportunities

appraisal and land capture objectives

capital availability

Eagle Ford

Haynesville

Permian

Fayetteville


Timing investment for maximum value


80/90

g

Slide 78

Capital allocation methodology informs rigprogram decisions to capture maximumvalue

Well inventory can be categorised into three

groups, reflecting the sensitivity of value totiming of investment

group 1: maximum value deliveredthrough acceleration, deferral erodesvalue liquids rich wells

group 2: value largely insensitive totiming wet gas and prolific dry gaswells

group 3: value enhanced throughdeferral less prolific dry gas wells

0

25

50

75

100

year

1

year

2

year

3

year

4

year

5

year

6

year

7

year

8

year

9

year

10

group 1 wells

group 2 wellsgroup 3 wells

Illustration of value sensitivi ty to spud date(% of maximum NPV delivered relative to spud date)

defer for value

accelerate

insensitive to timing


Video the drilling and completions process


81/90

Slide 79BHP Billiton Investor briefing: Petroleum, December 2013

Committed to sustainable development


82/90

Slide 80

Be the safest company in industry

Protect the land where we operate

Safeguard and manage water resources

Minimise air emissions

Be a good neighbour to our communities


Manufacturing process, ideally suited for

productivity improvement


83/90

productivity improvement

Slide 81

Developmentplans and siteselection

Negotiations

Permitting

Clearing andconstruction

Well pads andsupport systems

Well design

Support services

Location moves

Inventorymanagement

Water availability

SIMOPS1

Equipmentprocurement

Coordination

Infrastructure and PipelinesInfrastructure and Pipelines

Right of Way negotiations

Construction

StakeStake BuildBuild DrillDrill CompleteComplete ConnectConnect

1. Simultaneous operations.


Productivity opportunities have been identified

and actioned


84/90

and actioned

Slide 82

Repetitive, manufacturing nature of shale isideally suited to our productivity agenda

We are targeting multiple opportunities todeliver material value

reduce drilling costs per well throughefficiency and supply chain management

increase ultimate recovery throughcompletions optimisation and well downspacing

reduce spud to sales cycle time toaccelerate cash flow through SIMOPSand 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)

drilling costs improvedrecovery

spud to salescycle time

20% NPVimprovementopportunity

0

5

10

15

20


Util ising benchmarking and repetit ion of best

practice to drive performance


85/90

0

4

8

12

sitepreparation

drilling completions well sitefacilities

total wellcost

time sensitive

non-time sensitive

0

5

10

15

200 5 10 15 20 25

pacesetteraverage well

practice to drive performance

Slide 83

Total well costs include site preparation andwell site facilities

~25% of our well costs are time sensitive

We have utilised a pacesetter concept toimprove time performance and repetition ofbest practice

pacesetter concept utilises a compositebenchmark of fastest drilling times forindividual well segments across all wells

13-3/8

9-5/8

5-1/2

Pacesetter well dril ling times(measured depth, thousand feet)

(days)

Components of Black Hawk well cost(US$ million)

(casing design)



86/90

Increased recoveries provide the greatest upside


87/90

Slide 85

We are targeting an improvement in ultimaterecovery from completion optimisation andwell downspacing

Multiple field trials are underway to evaluate

various components of completion design

high temperature gels for betterproppant transport

stage spacing to maximise stimulatedrock volume

reservoir modelling to simulate stresscapture and optimise well sequencing

Early results have significantly exceededexpectations

Significant opportunity to replicate thissuccess across our Onshore US business

Improving well EUR through opt imal stage spacing(% improvement in cumulative production)

Successfully trialling high temperature frac fluids(% improvement in cumulative production)

0

20

40

60

0 10 20 30 40 50 60

individual well

0

20

40

0 10 20 30

individual well

(days)

(days)



88/90


89/90


90/90