Beach Energy Limited -...

Slide 1 Citi and GS conferences – March 2012

Beach Energy Limited

Citi conference – London, 5-6 March 2012

Goldman Sachs conference – New York, 7-8 March 2012


Compliance statements

Disclaimer

• This presentation contains forward looking statements that are subject to risk factors associated with oil, gas, geothermal and related businesses. It is believed that the expectations reflected in these statements are reasonable but they may be affected by a variety of variables and changes in underlying assumptions which could cause actual results or trends to differ materially, including, but not limited to: price fluctuations, actual demand, currency fluctuations, drilling and production results, reserve estimates, loss of market, industry competition, environmental risks, physical risks, legislative, fiscal and regulatory developments, economic and financial market conditions in various countries and regions, political risks, project delays or advancements, approvals and cost estimates.

• All references to dollars, cents or $ in this presentation are to Australian currency, unless otherwise stated. References to “Beach” may be references to Beach Energy Limited or its applicable subsidiaries.

• Unless otherwise noted, all references to reserves and resources figures are as at 30 June 2011 and represent Beach’s share.

Competent Persons Statement

• This presentation contains information on Beach’s Reserves and Resources which have been compiled by Mr Gordon Moseby, who is a full time employee of Beach, is qualified in accordance with ASX listing rule 5.11 and has consented to the inclusion of this information in the form and context in which it appears.


Strategic and operational overview


A unique value proposition


Safety a priority

Safety takes precedence in all operations

• Low Supervision Classification for Production Operations (SA) by South Australian Government regulator

• HSE Strategic Planning – three year plan

• Continued support for APPEA Stand Together for Safety campaign

• 2010 and 2011 without a recordable injury across all operated sites, with highest work hour exposure to date

• Leadership and Mentoring Program

• Winner of 2011 APPEA Safety Performance Award


Cooper / Eromanga Other

Large Resource base to build Reserves

2P Reserves 77 MMboe*

2P Reserves increase of 17% and contingent Resource increase of 96% on FY10

Cooper / Eromanga 2P Other

2P Reserves are a fraction

of the total resource base

2P Reserves and 2C Contingent Resources

660 MMboe*

97% gas & gas liquids

3% oil

73% gas & gas liquids

27% oil

* Volumes quoted are as at 30 June 2011


Reserves expected to increase for FY12

2P Reserves for FY12 likely to increase by over 20%

* Estimates only

• SACB JV completed a highly successful infill drilling program in 2011

• Resource to reserve conversion exceeded expectations

• Advances through multi-well pad drilling

• Potential for significant unconventional Resource addition from up to eight vertical exploration wells in 2012

2P Reserves

1. Additions to be confirmed as part of Beach’s annual reserves statement, and do not

include international and unconventional

0

10

20

30

40

50

60

70

80

90

100

FY10 FY11 FY12*

66 MMboe 77 MMboe 95 MMboe


FY12 production guidance of 7.5 MMboe

0

1

2

3

4

5

6

7

8

Act FY11 Fcst FY12

Oil 2.7 MMbbl Oil

2.1 MMbbl

Gas* 4.8 MMboe

(28 PJe)

Gas* 4.5 MMboe

(26 PJe)

* Gas and gas liquids

Beach actual and forecast production

Near-term production uplift potential

7.5 MMboe

6.6 MMboe

• Production guidance for FY12 expected to be primarily driven by:

– Better access for activities following Cooper Basin floods

– Enhanced exploration and development drilling campaigns

– Successful infill drilling in the SACB JV acreage

• New pipeline infrastructure, connecting Western Flank oil tenements to Moomba, to drive oil production from FY13


Underlying NPAT increased significantly for 1H12

Beach historical underlying NPAT

Significant uplift in 1H12 underlying NPAT expected to improve further in 2H12

• Six months to December 2011 (1H12) underlying net profit after tax (NPAT) has increased, year on year, by 179%

• Improvement mainly due to:

– Renegotiation of Delhi – Esso confidential royalty

– Improved oil prices

– Increased production activity as a result of abating floodwaters

– Reinstatement of the Tantanna pipeline

• Second half profit expected to improve due to:

– Access to all operating areas for the whole period

– New fields coming online

– Trucking of oil on top of pipeline flow

0

10

20

30

40

50

60

70

FY10 FY11 FY12

1H 2H

A$

mill

ion


Renegotiation of the Delhi – Esso royalty

The renegotiated royalty aligns Beach and EARL and has a positive ongoing impact on Beach’s cash flow and profitability

• Legacy royalty from the acquisition of Delhi Petroleum Pty Ltd in 2006

• Original royalty agreement required Delhi to pay Esso Resources Australia Pty Ltd (EARL) a percentage of revenue from certain products

• Renegotiated with EARL in January 2012, effective 1 July 2011 and expiring 31 December 2030

• Renegotiated royalty takes the form of an annual payment to EARL of a % of the net cash flow (before corporate tax) of Delhi’s business:

– Subject to a minimum of $40 million in total to be paid in the first five years

– An additional one-off payment of $8 million has also been made

* Includes Delhi, State Government and all other royalties payable by the Beach Group of companies

0

5

10

15

20

25

30

35

1H11 1H12

Beach Group Royalties*

A$

mill

ion


FY12 Capital guidance

Higher capex due to enhanced FY12 program with no flooding forecast


Unlocking the Cooper Basin gas potential


Beach is well placed strategically and geographically, with the necessary infrastructure in place to supply gas to the market for generations to come

Prolific acreage position strategically located


Eastern Australian gas markets are growing

• Strong predicted growth in Eastern Australian gas and Asian LNG demand

• Cooper Basin has excellent channels to markets

• Gladstone based LNG projects add a new dimension to gas market dynamics

• Independent producers with material reserves/resources are well placed to supply LNG and domestic markets

• The ‘clean energy future’ is likely to incorporate a larger role for natural gas

Beach assets are proximal to key markets


Excellent prospects to increase Cooper Basin supply

• Current domestic gas demand ~ 715 petajoules (PJ) per annum:

– ~ 100 PJ from Cooper Basin

• Domestic and LNG project gas demand expected to grow to ~ 3,000 PJ by 2025*

• 2015+ opens up various domestic and export linked opportunities

• Cooper Basin gas does not have the potential challenges that may impact long-term coal seam gas (CSG) development in Queensland and New South Wales

*Source: Core Energy Group 2011

Uncontracted demand

Industry commentators suggesting gas prices trending

toward $6-9/GJ

Uncontracted demand


Cooper Basin a potential supply option for LNG

Benefits of non-CSG supply to LNG proponents include:

• Flexibility, security and base load supply

• Field sequencing optimisation, delivering enhanced project economics

• Different risk profile in terms of environmental and/or land access

• Established infrastructure accessing a large reserves and resource base

Cooper Basin gas supply has multiple potential benefits to LNG projects

Gladstone based LNG projects


• Discussions ongoing between Beach and Santos for the supply of gas to Santos’ GLNG Project:

– 15 year contract proposed to commence around 2014

– Oil-linked gas pricing

• Joint Venture discussions regarding the development size being progressed

• Beach’s entitlement for supply could now be up to ~ 230 PJ

• Beach also in discussions with other large scale customers for this supply

LNG supply opportunity

Highlights strategic importance of the Cooper Basin asset base


Australian East Coast 2P Reserves*

The impact of eastern Australian LNG projects

• Three LNG projects in Gladstone, Queensland, have achieved FID, committing > 20 mtpa capacity

• LNG proponents are seeking more gas for expansion

• LNG markets provide access to oil-linked gas pricing – a paradigm shift from traditional domestic pricing

• Corporate and asset consolidation in train ahead of LNG production (eg. BG/Drillsearch, Santos/Eastern Star Gas, Arrow/Bow Energy)

~ 80% of East Coast 2P reserves are owned by parties developing LNG projects or with LNG aspirations

* Adapted from Energy Quest, November 2011

East Coast 2P Reserves held by LNG proponents

~ 35k PJ

Non-LNG ~ 11k PJ


SACB/SWQ JV – Significant long-term resource potential


SACB/SWQ JV

• Santos operated

• Equity interests of approximately 20% for the SACB JV and 23% for the SWQ JV

• A significant land holding of 26,800 km2 (gross)

• Situated in a proven and prolific basin

• Cooper Basin cumulative gross production to date of approximately 6 Tcf

• Provides access to a large onshore hydrocarbon province with:

– A proven reserve base

– A large booked contingent resource

– Significant upside from technological development and cracking the ‘codes’


SACB/SWQ JV

• A diversified product stream delivering gas, gas liquids and oil to multiple markets

• Synergies with other Beach operational areas

• Significant infrastructure made up of:

– Wells accessing Permian strata

– Gathering systems across the tenement area

– Gas and oil processing plants – Moomba, Ballera, Jackson

– Gas storage – Moomba & Ballera

– Gas market access

Gross unrisked resource potential of over 4 billion boe is estimated within

the acreage* * Source: Santos


Resources conversion drivers

Resources to reserves conversion driven by:

• Infill drilling with denser well spacing moving towards 40 acres

• More focused fracture stimulation of individual zones

• Pad drilling at the Tindilpie field delivering lower unit costs

• More efficient wellbore hydraulics, resulting in lower abandonment pressures and improved recovery

• Shale and deep coals accessible via existing wellbores

• Expectation of approx. 10 MMboe resource to reserve conversion per annum for coming years

Resources to reserves conversion of 20 MMboe (net to Beach) recently

announced by Santos* * Additions to be confirmed as part of Beach’s annual reserves statement

Infill drilling – 40 vs 200 acre spacing


Unconventional Cooper Basin gas potential


PEL 218 ~1,600 km2

• Beach 100% (Permian)

• 2 Tcf of contingent resource booked in the Permian

ATP 855P ~1,670 km2

• Beach 60% (operator), Icon Energy 40%

• First dedicated shale well in 2012

SACB JV ~7,100 km2

• Beach 20.21%, Santos 66.6% (operator), Origin Energy 13.19%

• 0.7 Tcf (net) of unconventional contingent resource booked to date

• Dedicated shale well recently fracture stimulated

Commanding acreage position

Multiple targets to be addressed by operated and non-operated

drilling programs


Program highlights to date

• Results from Encounter-1 and Holdfast-1 exceeded expectations due to:

– Shale thickness

– Gas saturated sands outside structural closure

– 700 metres of gas saturated section encountered

– ~2 MMscfd maximum flow rate from Holdfast-1 post fracture stimulation

• 480 metres of core recovered assisting technical analysis

• Encounter-1 to be fracture stimulated in Q1 2012

• Accelerated appraisal of shale and basin centred gas play in 2012 300+ Tcf of gas in place estimated for PEL 218


Shale and basin centred gas play

Gas saturation across a continuous shale and basin centred gas play

Source: Amended from Schenk and Pollastro, 2002


• REM thickness exceeded expectations at 350-400 metres

• Core and log analysis indicates REM, Toolachee, Daralingie and Patchawarra Formations all gas saturated

• Fracture stimulation confirmed gas flows from Roseneath shale to top of the Patchawarra Formation

• Potential for a further 600 metres of gas saturation in the Patchawarra Formation

• Moonta-1 well to drill to the base of the Patchawarra Formation

• Fracture stimulation of Moonta-1 expected in Q2 2012 to target the Patchawarra

PEL 218 drilling - massive gas saturated zone

Gas saturated section has the potential to be in excess of 1,000 metres


• Good working relationship with pastoral owners and other stakeholders

• Co-operative not competitive land use

• Semi-desert country

• Relatively flat topography

• Well established oil and gas infrastructure

• Raw and sales gas pipelines cross PEL 218 and ATP 855P

• Multiple commercialisation options

Advantages of Beach’s Cooper Basin acreage

Good relationships and well established infrastructure


• Three cemented casing strings in the first 1,000 metres isolate surface aquifer

• Two cemented casing strings between 1,000 and 2,000 metres isolate the Eromanga aquifers

• Eromanga aquifers well above the target zone

• The Triassic zone provides a thick protective seal from target intervals

• Over 700 wells fracture stimulated in the Cooper Basin to date

Shale and sands isolated from aquifers

Significant distance and mechanical isolation ensures

aquifer protection


The next steps

Encounter-1 well site

• Fracture stimulate Encounter-1 with sequential stimulation and testing

• Independent certification of all reserves and resources

• Drill vertical delineation wells to appraise significant basin centred gas accumulation

• Design and drill three horizontal wells targeting highest gas yield zones

• Expand drilling program with up to six horizontal wells around Holdfast-1 and Encounter-1 to further characterise production potential of shale and basin centred gas targets

• Seek to monetise early production via existing facilities


Things you can find in your own backyard…

A relatively under-explored part of the Cooper Basin with enormous potential


Other unconventional opportunities


• Established significant acreage positions in other prospective basins

• Focusing on under-explored basins with infrastructure access close to markets:

– High grading acreage in parallel

• Further potential for gas and liquids

• Complimentary to conventional potential:

– Eastern Otway gas – Eastwing area

– Penola Trough Sawpit sandstone play

Other unconventional opportunities

Identified new opportunities to unlock the potential of lightly explored basins


Otway and Gippsland basins

Otway gas and liquids

• Beach 35-67%

• Conventional plays proven – gas, condensate and oil discoveries

• Casterton main source rock and most attractive unconventional target

– Moderate to high TOC’s

– Gas and liquids prone

– Thick and areally extensive

– Mature and overpressured

Gippsland gas

• Beach earning up to 33.3%

• Wombat gas project

• Two wells to be fracture stimulated in the first half of 2012

Map with troughs shown and

permits outlines

Significant onshore acreage positions well located to access growing markets

Note: PEP 150 and PEP 171 are subject to Native Title Agreement


Bonaparte basin

• Beach earning up to 90%* of onshore and up to 55%* of offshore areas

• Underexplored to date due to lack of quality modern seismic

• Conventional and deep unconventional targets

• Highly prospective as a result of:

– Working petroleum systems identified in the few wells to date

– Oil seeps identified at surface

– Oil staining in mineral cores

– Weaber gas field adjacent to acreage

• Beach commitment of $5 - $36 million dependent on various options

A potential supplier to Northern Australian markets * Equity interest dependant on Somerton Energy farm in option: 18% of onshore and 8.25% of offshore tenements


Dominant Western Flank acreage position


Cooper Basin – Western Flank oil

Strong cash generating area with significant exploration upside

Western Flank oil is a core contributor to Beach due to:

• Sales in Brent, considerably stronger than WTI

• High net back per barrel of approx. A$75* (incl. Opex, royalties and transportation costs)

• Strong equity positions

• Quick drill and tie-in periods

• High flow rates from wells

• Excellent understanding of the geology resulting in high success rates

• Multiple play types

• Established and proposed pipeline infrastructure to increase production rates

*Assumes Brent oil price of A$105 per barrel


3D and 2D seismic recently acquired

Newly acquired seismic data to deliver new Western Flank targets

PEL 91

• Beach 40% (operator), Drillsearch 60%

• 336 km2 Aquillus 3D and 151 km2 Limbatus 3D seismic surveys completed and currently being processed

• Targeting Birkhead channel plays in line with PEL 104 in addition to Namur plays

• Interpretation expected in Q2 2012

• 249 km Undatus 2D seismic being processed

PEL 92

• Beach 75% (operator), Cooper Energy 25%

• 197 km2 Rincon 3D seismic has commenced, targeting delineation of the Rincon discovery

• 55 km Fusinus 2D seismic being processed


Western Flank oil production

Production target of 10,000 bopd (net) from Western Flank by 2013

PEL 91

• Bauer oil field expected to produce at up to 1,000 bopd (net) in April 2012

• JV pipeline construction discussion ongoing

PEL 92

• Current net production 4,500 bopd

• Lycium to Moomba trunkline to increase production capacity to 6,000 bopd (net)

PEL 104 and PEL 111

• Beach 40%, Senex 60% (operator)

• Current net production 560 bopd, expected to increase to around 1,500 bopd (net) by June 2012

• Snatcher expected back on-line this financial year at around 300 bopd (net)


FY12 Western Flank drilling program

PEL 91 • FY12 drilling program complete

• FY12 success of 1.4 MMbbl (net) to date, which has exceeded expectations

PEL 92 • JV in discussions for up to three exploration

wells and three development wells

• FY12 success of 0.5 MMbbl (net) to date

PEL 104 and PEL 111 • JV approval for a 6 well exploration drilling

campaign. Two wells completed to date

• JV considering program expansion

• Targeting further reserve additions of 1.0 MMbbl (net) for FY12

Total Beach estimated risked reserves addition for FY12 of ~3 MMbbl (net)


New pipelines proposed

New pipeline infrastructure to deliver increased Western Flank oil production and protection against flooding

• Lycium to Moomba trunkline (Beach 60%):

– Capacity of 15,000 bopd

– 8 inch pipeline

– Expected completion first half 2012

• Growler to Lycium flowline (Beach 40%):

– Capacity of 8,000 bopd

– 6 inch pipeline

– Expected completion second half 2012

• Beach to construct and operate both pipelines

• Net cost of $23 million


Western Flank gas and gas liquids production

The first operated gas and gas liquids production for Beach

• Beach 50% (operator), Drillsearch 50%

• First production from the Middleton Brownlow production licence

• Gas sale agreement with the SACB JV for the sale of a minimum of 3 Bcf of raw gas

• Fiberspar flexible pipeline reduced capital cost and accelerated pipe laying time

• Initial flow rates of 25 MMsfd, made up of 15 TJ/d sales gas and 1,250 bbls per day of LPG and condensate

• Five well exploration program – four wells in PEL 106B (Beach 50%, Drillsearch 50%) and one in adjacent PEL 107 (Beach 40%, Drillsearch 60%)

• Two wells completed to date, one C&S for further evaluation, one P&A


‘Big oil’ potential, Tanzania


• Beach 100%

• Permit 7,200 km2 (Lake Albert 5,300 km2)

• Underexplored area with high potential

• Natural oil seeps on Lake Tanganyika, as with Lake Albert, indicate a working petroleum system

• Total S.A. and CNOOC invested US$2.9 billion for 67% of Lake Albert acreage

• Lake Tanganyika has the potential for large (> 200 MMbbl) discoveries

• Airborne gravity and hi-resolution aeromag data acquired in 2010

• 1,800 kilometres of new 2D seismic data to be acquired in Q1 2012

• Total S.A. recently awarded the Lake Tanganyika North Block

Rift systems - Lake Tanganyika South Block, Tanzania

Prospect and leads generation in 2012


Egypt – Established and growing portfolio


Egypt overview

• Beach interests range 15 – 22%

• An established and growing portfolio of production, development & exploration opportunities

• Abu Sennan - six well appraisal/ exploration program – three consecutive discoveries

• North Shadwan - first oil imminent from near shore fields, development of Burtocal expected 2012/13

• Mesaha - recent acquisition of 2D seismic, potential oil targets of 100 MMbbl+


Gulf of Suez – North Shadwan

• Beach 20%, BP 50% (operator), Tri Ocean 30%

NS 377 and NS 385

• Near shore field NS 377 initially to produce approx. 1,000 bopd (gross) via pipeline to Ras Ghara facility

• NS 385 development well expected to spud in May/June 2012

• Total oil flow expected to build to around 5,000 bopd (gross) by Q1 2013

NS 394 (Burtocal)

• Monopod development expected to commence in 2013

• NS 394-1A C&S in 2008, 200ft net pay

• Production anticipated in 2014, flow rate potential of 7,000 bopd (gross)

Oil production to commence soon with short term development

opportunities


Abu Sennan concession – exploration success

• Beach 22%, Kuwait Energy 50% (operator), Dover Investments 28%

• Oil, gas and condensate discoveries from the first three wells drilled

ZZ-4

• Gas and condensate, total flow rate of approx. 2,400 boepd (gross)

Al Ahmadi-1 • Gas and condensate, total flow rate of

approx. 3,100 boepd (gross)

Al Jahraa-1 • Oil, total flow rate of approx. 800 bopd

(gross)

El Salmiya-1 • Testing program currently underway

• Encouraging initial results

100% success to date in the highly prospective Western Desert


• Beach 15%, Melrose 40% (operator), Hellenic 30%, Kuwait Energy 15%

• The largest concession area in Egypt at 42,700 km2

• Possible rift basin similar to Gulf of Suez

• Potential for very large oil fields (>100 MMbbl+)

• ~2,500 km of regional and infill 2D seismic acquired and interpreted

• First exploration well planned for 2H 2012

Mesaha concession

Wildcat acreage with rift graben potential


Summary – multiple near term catalysts


Multiple near term catalysts for FY12

Additional re-rating potential through portfolio optimisation and other opportunities


Beach Energy Limited – Head office 25 Conyngham Street Glenside SA 5065 Tel: +61 8 8338 2833 Fax: +61 8 8338 2336 Website: www.beachenergy.com.au

Chris Jamieson Investor Relations Manager Tel: +61 8 8338 2833 Mob: +61 8 (0)487 173 244 Email: [email protected]

Contact information

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