BEACH ENERGY LIMITED — Annual Report 2011

Aug 30, 2011

Beach E Limited nergy FY11 Full Year Results

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FY11 Full Year Results

31 August and 1 September 2011 Slide 1

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FY11 Highlights

Reg Nelson – Managing Director

Slide 2

FY11 Full Year Results

Compliance statements

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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.

Slide 3

FY11 Full Year Results

FY11 Highlights

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Corporate

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• Acquisition of Impress Energy Ltd

• • Negotiations with Santos regarding gas supply to its GLNG project

Operations

• Successful shale exploration program with booking of 2TCF 2C contingent resource

• Western Flank exploration and appraisal success in PEL 91 and PEL 92

• Three new Saxon build rigs for SACB JV and SWQ JV

Finance

• Solid underlying profit of $41 million

• Strong cash position of $173 million

• New $150 million multi option finance facility

Subsequent events

• Holdfast-1 shale well flowed up to 2 MMscfd

• Two rigs secured for 2012 unconventional pilot program

Slide 4

FY11 Full Year Results

Beach Energy Limited - A unique value proposition

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Slide 5

FY11 Full Year Results

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Financial results Kathryn Presser – Chief Financial Officer

Slide 6

FY11 Full Year Results

FY11 Full Year results overview

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	FY11	FY10
Sales volume (MMboe)	8.8	9.3
Sales revenue ($ million)	496.4	487.5
Cash flow from operations ($ million)	184.5	128.5
Net (loss)/profit after tax ($ million)	(97.5)	33.1
Underlying net profit after tax ($ million)	41.4	38.7
Total dividends declared (cents per share)	1.75	1.75

• Solid underlying profit of $41.4 million, up 7%

• Strong cash position of $173.3 million

• A new multi option finance facility of $150 million replaced the $35 million working capital facility

• Dividend declared of 1.0 cent per share fully franked in addition to 0.75 cent per share fully franked dividend at half year

Slide 7

FY11 Full Year Results

Sales revenue up 2%

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600
$65.7 $5.8 $3.4 $31.1
$34.9
500 $487.5 Gas/ethane Prices Third Party Purchases Volume / Mix $496.4
Liquids Prices A$/GJ FX Rates
2010 $5.04
US$/boe AUD/USD
400 2011 $5.35
2010 $77 2010 $0.88
2011 $95 2011 $0.99
$m
300
200 $8.9 million
total increase
100
0
June 10 June 11
Average Price Average Price
A$52.21/boe Oil Price A$56.28/boe
150
•
Sales revenue driven by improving gas
100
and oil prices (oil averaged A$97/bbl);
partially offset by A$/bbl
50
•
Sales volumes decline, mainly due to
-
Tantanna shutdown, flooding and
2006/07 2007/08 2008/09 2009/10 2010/11
Actual Average
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• Sales revenue driven by improving gas and oil prices (oil averaged A$97/bbl); partially offset by

• Sales volumes decline, mainly due to Tantanna shutdown, flooding and cessation of BMG operations.

Slide 8

FY11 Full Year Results

Cash production costs down 3%

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250
$11.6 $8.6
$221.8 $9.3
$215.5
Royalties Tariffs / tolls
Field operating costs
200
150
$m
100
$6.3 million
total decrease
50
0
June 10 June 11
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Lower cash production costs mainly due to:

• Tariffs and toll reduction due to lower production and the shutdown of the Tantanna pipeline;

• Lower field operating costs due to cessation of BMG production partly offset by higher costs on non-operated operations; partially offset by

• Higher royalties paid on USD income

Slide 9

FY11 Full Year Results

Gross profit up 6%

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120
$6.3 $7.1
100 $8.9 $16.1
$12.5
Cash 3rd party
80 $72.8 Sales revenue production purchases $77.3
costs
Inventory
Depreciation
$m 60
40
$4.5 million
20
total increase
0
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June 10

June 11

Gross profit increase mainly due to:

• Increase in oil and gas prices; partially offset by

• Lower field operating costs due to cessation of BMG production partly offset by higher costs on non-operated operations; and

• Higher third party purchases and inventory drawdown due to lower production

Slide 10

FY11 Full Year Results

Cash flow from operations up 44%

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250

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$3.7 $2.1 $9.4
$25.6
$12.8
200
$46.8 Interest Other Operating $184.5
received
costs Legal
Sales settlement
receipts
150
$128.5
$m
Tax
100
50 $56.0 million
total increase
0
June 10 June 11
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Cash flow from operations increase mainly due to:

• The tax payment on the sale of the Tipton West assets in FY10 and not FY11;

• Sales receipt increase due to higher oil and gas prices and the drawdown from inventory; partially offset by

• Higher costs for non-operated operations, third party purchases and the BMG legal settlement

Slide 11

FY11 Full Year Results

Comparison of Underlying Profit

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	FY11 $ million	FY10 $ million
Net (loss)/profit after tax	(97)	33
Remove unrealised hedging (gains)/losses	(2)	5
Remove revaluation of assets	(14)	1
Remove asset sales	(11)	(55)
Remove impairment of assets	158	64
Remove legal settlement	13	–
Remove BMG NPP	30	–
Remove gain on acquisition of subsidiary	(1)	(4)
Remove takeover costs	1	–
Tax impact of above changes	(52)	(5)
Remove tax benefit from consolidation of subsidiary	(11)	–
Remove impact of PRRT adjustment	27	–
Underlying Net Profit After Tax	41	39

Slide 12

FY11 Full Year Results

Underlying net profit after tax up 7%

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50
$0.8 $5.3
$2.7
45 $4.5 Other expenses
$41.4
40 $38.7 Net financing and revenue
Tax
costs
Gross profit
35
30
$m 25
20
15
10
$2.7 million
5 total
increase
0
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June 10

June 11

Strong operational performance delivering a profit increase during a very challenging year

Slide 13

FY11 Full Year Results

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Operational overview
Neil Gibbins – Chief Operating Officer
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Slide 14

FY11 Full Year Results

Large Resource base to build Reserves

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2P Reserves

77 MMboe*

2P Reserves and 2C Contingent Resources

660 MMboe*

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2P Reserves
73% gas & gas liquids
are a fraction
27% oil
of the total
resource base
97% gas & gas liquids
3% oil
Other
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Cooper / Eromanga Other
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Cooper / Eromanga 2P Other
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2P Reserves increase of 17% and 2C Resource increase of 96% on FY10

• Volumes quoted are as at 30 June 2011

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FY11 Full Year Results

Production volumes down 10%

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8
7.3 0.03 0.2
0.2
0.3
7
US Production 6.6
BMG
Trucking
Flooding /
6 and field
Access
decline
5 issues
MMboe
4
3
2
0.7 mmboe
1
total
decrease
0
June 10 June 11
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Production volumes decrease mainly due to:

• BMG moving to a non-productive phase;

• Trucking due to Tantanna pipeline closure and natural field decline; and

• Access issues due to flooding

Slide 16

FY11 Full Year Results

FY12 production guidance of 7.5 MMboe

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Beach actual and forecast production (MMboe)

• Production guidance for FY12 of 8 7.5MMboe, expected to be 7

• primarily driven by: – Better land access for activities 6 Oil Oil

• following Cooper Basin floods 5

• – Enhanced exploration and 4

• development drilling planned for FY12 3 Gas*

• – Gas* New pipeline infrastructure 2

• accessing Western Flank oil tenements 1

• – Infill drilling in the SACB JV acreage 0

Near-term production uplift potential

Act FY11 Fcst FY12

• Gas and gas liquids

Slide 17

FY11 Full Year Results

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FY12 Capital requirements, wells and seismic

	FY12 Fcst Capex $ million	FY11 Act Capex $ million	FY12 Fcst Wells to drill	FY12 Fcst Seismic **2D - Km 3D - Km2 **	FY12 Fcst Seismic **2D - Km 3D - Km2 **
Development
Cooper Basin	186.9	92.2	61	–	–
BMG	–	1.2	–	–	–
International	5.3	4.1	1	–	–
Total Development	192.2	97.5	62	–	–
Exploration
Cooper Basin	64.3	12.5	34	1,100	1,865
Other Australasia	26.5	(0.1)	4	200	–
Unconventional	46.0	37.6	4	500	–
International	20.0	11.7	6	1,800	–
New Ventures and other	6.1	1.9	–	–	–
Total Exploration	162.9	63.6	48	3,600	1,865
Total	355.1	161.1	110	3,600	1,865

Higher capex due to enhanced FY12 program with no flooding forecast

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FY11 Full Year Results

Key catalysts for FY12

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Multiple near-term catalysts with material re-rating potential

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FY11 Full Year Results

Shale gas play exceeds expectations

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Two vertical shale evaluation wells drilled

• Encounter-1 and Holdfast-1 drilled late 2010 and early 2011

• Thick shale section, averaging 240m through PEL 218, extensively cored

• Technical evaluation continuing

• Gas desorption from shale suggests almost 100 TCF GIP in PEL 218 shales

• Sands gas bearing – basin centred gas play in addition to shale, potentially adding a further 200TCF GIP

• ~700 metres of gas saturated section

Successful flow test at Holdfast-1

• Holdfast-1 fracture stimulated June 2011 and flow tested July 2011

• Encounter-1 to be stimulated and flow tested late 2011

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Roseneath Shale – Encounter -1
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A potentially massive gas resource located next to key export infrastructure

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FY11 Full Year Results

Gas production from shales and basin centred gas

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• Holdfast-1 fracture stimulation consisted of seven stages:

• Roseneath Shale (2)

• Epsilon Formation (3)

• Murteree Shale (1)

• Patchawarra Formation (1)

Results

• Gas flow from shales and gas sands

• Maximum flow rate 2 MMscfd

• Gas resource of 2TCF booked for 100km[2 ] around each well

• Basin centred gas potential confirmed by gas flow from tight sand intervals

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The Nappamerri Trough is a large basin centred gas resource play

Slide 21

FY11 Full Year Results

Basin centred gas – upside confirmed

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• Encounter-1 and Holdfast-1 drilled off-structure to test basin centred gas potential

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• Mud gas logs and electric logs suggest gas in sands outside of structural trap

• Considerable upside gas potential in sands which are:

• Over-pressured

• Thick

• Gas saturated

• Regionally extensive

• Potential GIP exceeds 200 TCF in sands across PEL 218

Source: Schenk and Pollastro, 2002

A continuous basin centred gas play has emerged

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FY11 Full Year Results

The next steps

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

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

• Expand production pilot with up to 6 extra horizontal wells around Holdfast-1 and Encounter-1; production test shale and basin centred gas targets

• Seek to monetise early production via existing facilities

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Fracture 3 horizontal Extended flow
Expansion of
stimulate pilot test – pilot Development and
production
Encounter-1 production production production program
pilot wells –
wells and 5 wells
~ 7 zones shale and
vertical
sand targets
exploration
wells
Q4 2011 Encounter-1 well site 2012 Q1/Q2 2013 2013 2013/2014
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FY11 Full Year Results

Rigs secured for pilot and resource upgrade program

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Ensign#65

• New build ADR 1500 horsepower rig, expected in April 2012

• Able to drill 1,500+ metre laterals

• First horizontal well in ATP 855P, followed by wells next to Holdfast-1 and Encounter-1

Ensign#16

• 1,200 horsepower rig used to drill Holdfast-1 and Encounter-1

• Will drill a series of vertical wells in PEL 218 to evaluate the basin centred gas play

• Able to drill to 4,270 metres

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An ADR1500 rig drilling shale gas in the US

Multiple wells in 2012 to evaluate the basin centred gas play

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FY11 Full Year Results

Western Flank oil - Beach Operated

PEL 92

• Beach 75%

• JV approval for 8 exploration and 8 development wells for FY12

• Exploration target of 1.3 million barrels of oil (MMbbl) (net)

• FY12 success at two of three exploration wells, Rincon-1 and Elliston-1, for 0.5 MMbbl (net)

PEL 91

• Beach 40%

• JV approval for 4 exploration and 1 development well for FY12

• Exploration target of 0.5 MMbbl (net) already exceeded due to success at Bauer-1

• Recent success likely to expand program in FY12

Potential risked reserves addition for FY12 of ~2 million barrels of oil

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FY11 Full Year Results

Western Flank oil - Non-Operated

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• Beach 40%

• JV approval for 6 exploration and 5 development wells for FY12

• Drilling access restricted until October 2011, floodwaters receding

• Exploration success rate to date of approx. 80% when drilled on 3D seismic

• Senex, the Operator, has identified 25 highly prospective Birkhead exploration targets from 3D

• 2P reserves in the Growler and Snatcher oil fields estimated by Operator at 7.9 MMbbl (gross)

• Production of ~500 barrels of oil per day expected to increase to 1,500 bopd (net) by end of FY12

Potential risked reserves addition for FY12 of ~1 million barrels of oil

Slide 26

FY11 Full Year Results

Western Flank oil – New pipelines proposed

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• First section from Growler to Lycium (Beach 40%):

• Capacity of 8,000 bopd

• 6 inch pipeline

• Second section from Lycium to Moomba (Beach 60%):

• Capacity of 15,000 bopd

• 8 inch pipeline

• SACB JV approval still required to tie-in second section at Moomba

• Beach to construct and operate both pipelines

• Net cost of $21 million

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New pipeline infrastructure to deliver increased Western Flank oil roduction and rotection a ainst loodin p p g f g

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FY11 Full Year Results

Rift systems - Lake Tanganyika South Block, Tanzania

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• Beach 100%

• Approx. 7,000 km[2 ]

• Underexplored area with high potential

• Potential for large (> 200 MMbbl) discoveries

• Natural oil seeps on Lake

• Tanganyika indicate a working petroleum system

• Airborne gravity and high resolution aeromag data acquired in 2010

• Acquisition of 1,800 kilometres of new 2D seismic data to be undertaken in Q4 2011

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

Initial prospect and leads

generation

Slide 28

FY11 Full Year Results

Egypt overview

• Beach interests range 15 – 22%

• An established and growing portfolio

• Exposure to prolific and emerging hydrocarbon basins:

• Portfolio of near-term development & exploration opportunities

• North Shadwan expected to produce first oil during FY12

• Abu Sennan six well appraisal/ exploration program – two wells drilled, both discoveries

• Mesaha* has the potential to contain 100 MMbbl+ targets

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• Subject to Ministerial approval

Slide 29

FY11 Full Year Results

Contact information

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Email: chris.jamieson@beachenergy.com.au FY11 Full Year Results

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