Beach Energy : International Roadshow Presentation

Beach Energy Limited (ABN 20 007 617 969) | Level 8, 80 Flinders Street Adelaide, South Australia 5000

GPO Box 175, Adelaide, South Australia 5001 | beachenergy.com.au

ASX Announcement

International roadshow presentation

Reference #031/19	Date02 September 2019

For information, attached is the presentation that Beach Energy will be taking on its UK and Europe roadshow this week. Also available from the Beach Energy website.

For further information contact the following on [phone]

Investor relations	Nik Burns, Investor Relations Manager
Media	Rob Malinauskas, Head of Corporate Affairs and Community Relations

Beach Energy Limited

Page 1 of 1

S E P T E M B E R 2 0 1 9

INTERNATIONAL ROADSHOW PRESENTATION

Compliance statements

Disclaimer

This presentation contains forward looking statements that are subject to risk factors associated with oil, gas 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.

Underlying EBITDAX (earnings before interest, tax, depreciation, amortisation, evaluation, exploration expenses and impairment adjustments), underlying EBITDA (earnings before interest, tax, depreciation, amortisation, evaluation and impairment adjustments), underlying EBIT (earnings before interest, tax, and impairment adjustments) and underlying profit are non-IFRS financial information provided to assist readers to better understand the financial performance of

the underlying operating business. They have not been subject to audit or review by Beach's external auditors. The

information has been extracted from the audited financial statements.

Free cash flow in this presentation is defined as cash flows from operating activities plus cash flows from investing activities less cash flows from acquisitions and divestments.

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 2019 and represent Beach's share.

References to planned activities in FY20 and beyond FY20 may be subject to finalisation of work programs, government approvals, joint venture approvals and board approvals.

Due to rounding, figures and ratios may not reconcile to totals throughout the presentation.

2

Assumptions

The five year outlook set out in this presentation is not guidance. The outlook is uncertain and subject to change. The outlook has been estimated on the basis of the following assumptions: 1. a US$62.50/bbl Brent oil price in FY20 and a US$70/bbl Brent oil price from FY21; 2. 0.70 AUD/USD exchange rate in FY20 and 0.75 AUD/USD exchange rate from FY21;

3. various other economic and corporate assumptions; 4. assumptions regarding drilling results; and 5. expected future development, appraisal and exploration projects being delivered in accordance with their current expected project schedules.

FY20 guidance is uncertain and subject to change. FY20 guidance has been estimated on the basis of the following assumptions: 1. a US$62.50/bbl Brent oil price; 2. 0.70 AUD/USD exchange rate; 3. various other economic and corporate assumptions; 4. assumptions regarding drilling results; and 5. expected future development, appraisal and exploration projects being delivered in accordance with their current expected project schedules.

These future development, appraisal and exploration projects are subject to approvals such as government approvals, joint venture approvals and board approvals. Beach expresses no view as to whether all required approvals will be obtained in accordance with current project schedules.

Reserves disclosure

Beach prepares its petroleum reserves and contingent resources estimates in accordance with the Petroleum Resources Management System (PRMS) published by the Society of Petroleum Engineers. The reserves and contingent resources presented in this report were originally disclosed to the market in the FY19 annual report released 19 August 2019. Beach confirms that it is not aware of any new information or data that materially affects the information included in the aforesaid market announcement and that all the material assumptions and technical parameters underpinning the estimates in the aforesaid market announcement continue to apply and have not materially changed.

The reserves and resources information in this report is based on, and fairly represents, information and supporting documentation prepared by, or under the supervision of, Mr David Capon (Manager Development Offshore Victoria, New Zealand and NT). Mr Capon is a full time employee of Beach Energy Limited and has a BSc (Hons) degree from the University of Adelaide and is a member of the Society of Petroleum Engineers. He has in excess of 25 years of relevant experience. The reserves and resources information in this presentation has been issued with the prior written consent of Mr Capon as to the form and context in which it appears.

Conversion factors used to evaluate oil equivalent quantities are sales gas and ethane: 5.816 TJ per kboe, LPG: 1.398 bbl

per boe, condensate: 1.069 bbl per boe and oil: 1 bbl per boe. The reference point for reserves determination is the custody transfer point for the products. Reserves are stated net of fuel, flare & vent and third party royalties.

Beach Energy portfolio

FY19 production

Taranaki

Basin

Bass

Basin

29.4

MMboe

Otway

Basin

Perth

Basin

FY19 2P reserves

Taranaki

Western

Flank

Cooper

Basin

Bass

Basin

Western

Flank

Basin

Otway	326
MMboe
Basin
Perth
Basin

Cooper

Basin

3

Asset summary

Asset			Beach	Operator?	FY19 production1	FY19 2P reserves2	FY20 capex3	Key FY20 proposed activities
		Interest	(MMboe)	(MMboe)	range ($million)
Western Flank Oil	40 - 100%	Op/Non-op	5.2	42	200	- 225	Drill up to 77 wells
Western Flank Gas	100%	Op	1.9	16	40	- 60	Drill up to 7 wells
Cooper Basin JV	Various	Non-op	8.3	84	200	- 220	Drill ~100 wells
SA Otway	70 - 100%	Op	-	1	30	- 35	Drill 2 wells. Gas facility construction
Vic Otway	60%	Op	8.4	62	205	- 225	Commence 10 well drilling campaign
BassGas		53.75%4	Op	1.7	20	10 - 25	Trefoil concept select
Kupe (New Zealand)	50%	Op	3.2	27	15	- 20	Compression project FID
Perth Basin	50%5	Op/Non-op	0.7	73	30	- 35	Drill 1 well. Waitsia Stage 2 FID
Frontier Exploration	Various	Op/Non-op	-	-	15	- 15	Preparation for FY21 drilling
TOTAL				29.4	326	750	- 850
	1.	Refer to Q4 FY19 quarterly report ref: #020/19 dated 24thJuly 2019 for further details
	2.	Refer to FY19 annual report for further details
	3.	Based on data contained within slide 13
4	4.	Beach interest in producing permits. 50.25% interest in retention licenses.
5.	Note that Perth Basin, Beharra Springs interest of 50% is subject to completion of sale of 17% interest to Mitsui E&P Australia

Strong FY19 sets the platform for FY20

Strong FY19 performance

Financial strength

Financial discipline

Accelerated investment begins in

FY20

Driving improved 5 year outlook

• Production 29.4 MMboe, +55% vs FY18
• 85% drilling success rate inBeach-operated wells
• 204% organic 2P reserves replacement1, 2P reserves life increased to >12 years2
• Underlying EBITDA $1,375 million, +80% vs FY18
• Underlying NPAT $560 million, +86% vs FY18
• ROCE 27%3up from 19% in FY18
• Net cash position at 30 June 2019, achieved 2 years ahead of initial expectations
• $60 million synergy target met, $30 million op. cost reduction target on track
• Final dividend 1.0 cps
• 194 wells targeted with focus on Cooper Basin and Otway Basin (+45% vs FY19)
• 90% of growth projects commencing in FY20 deliver IRRs > 50%
• FY20 investment expenditure guidance $750 - $850 million
• 5 year production target increased to 34 - 40 MMboe (Prior: 30 - 36 MMboe)
• 5 year free cash flow target increased to $2.7 billion, over $1 billion FCF in FY24
• Additional $1.5 billion of value accretive investment opportunities identified

5Refer to disclaimer on slide 2 for information relating to the use of underlying financial measures in this presentation

1. FY19 organic 2P reserves replacement ratio calculated as 2P reserves additions, excluding acquisitions and divestments, of 60 MMboe divided by FY19 reported production of 29.4 MMboe.
2. FY19 2P reserves life calculated as 326 MMboe 2P reserves, divided by FY19 Pro Forma production of 26.2 MMboe, which adjusts reported production to reflect Victorian Otway assets at 60% for the entire FY19.
3. Return on capital employed (ROCE) is defined as underlying net profit after tax (underlying NPAT) divided by the average of opening total equity and closing total equity.

Delivering on our promises

	Beach said….	In FY19 Beach delivered…
FY19 production1	26 - 28 MMboe	✓29.4 MMboe
FY19 capital expenditure1	$460 - 540 million	✓$447 million
FY19 free cash flow2	~$290 million	✓$559 million
FY19 underlying EBITDA2	$1.1 - 1.2 billion	✓$1.375 billion
Return on capital employed (ROCE)	17 - 20%	✓27%
Five year average 2P reserves	>100%	✓204%
replacement ratio
Lattice synergies	Target of $60m p.a. by end of FY19	✓Synergy target met
Direct controllable operating costs	$30m p.a. reduction by end of FY20	✓$21 million p.a. reduction by the end of FY19

61. Beach initial FY19 guidance released in ASX Release #040/18 dated 20 August 2018 and is based on ownership of Victorian Otway assets at 100% for entire FY19. Beach reported 100% of Victorian Otway for 11 months, 60% for one month.

2. Beach initial FY19 EBITDA guidance and free cash flow outlook released in ASX Release #045/18 dated 27 September,"2018 Investor Briefing".

Investing to accelerate production and free cash flow growth

Beach is now targeting

34-40MMboe annual production

in the medium term…

Production outlook1

(MMboe)

40

35

30

25

20

FY19A FY20E FY21E FY22E FY23E FY24E

Outlook presented October 2018		Updated 5 year outlook

…and cumulative free cash flow3of more than $2.7 billion over the next 5 years…

	Free cash flow outlook1
1,200	($ million)
1,000
800
600
400
200
0
FY20E FY21E FY22E FY23E FY24E

…by accelerating investment in our expanded growth portfolio

Capital expenditure outlook1

	($ million)
1,000
750 - 850		650 - 800
800
600
400
200
0		FY21 - 24
FY20 guidance
range	Range	Outlook

1. Outlook is determined using the assumptions set out on the "Compliance Statements" slide.

72. "Fixed" refers to stay-in-business capital expenditure.

3. Free cash flow is defined in disclosures on slide 2 of this presentation. For five year outlook purposes cash flows associated with operating leases are not adjusted for potential changes from AASB 16.

Bridging to our updated 5 year outlook

$1.5 billion of new investment opportunities identified since 2018 investor day

5-Year Capital expenditure outlook ($ million)

Outcomes

~850

~500

~2,700

~1,650

~350	~450
2018 Investor day		Updated view
FY19 - 23		FY20 - 24
Exploration/appraisal		Development		Fixed

• More Western Flank and CBJV drilling
• Ironbark and Wherry exploration prospects progressed and included
• More Western Flank and CBJV drilling
• La Bella Development
• Inclusion of Trefoil development
• Ownership of Waitsia stage 2 infrastructure
• Increased Cooper Basin well count

• Production outlook increasedfrom 30 - 36 MMboe to 34 - 40 MMboe by FY24
• Incremental 18 MMbblcumulative oil production from FY20 - 24 vs prior outlook
• Develop undeveloped 2P reserves(169 MMboe)

• 1. Cooper, Otway, Trefoil, Waitsia production lives go beyond five year outlook period
• >100% reserves replacementon more production
• Delineate and develop additional Cooper Basin reserves(3P->2P, 2C->2P)
• Progress on low cost, high impact exploration opportunities(Beharra Springs Deep, Ironbark, Wherry)

8"Fixed" refers to stay-in-business capital expenditure.

Reserves and contingent resources

204% organic 2P reserves replacement, well ahead of 100% five year average target

Summary of reserves at 30 June 2019 (developed plus undeveloped, net to Beach)

(MMboe )	FY18	FY19
1P reserves	190	201	+6%
2P reserves	313	326	+4%
3P reserves	491	514	+5%
2C contingent resources	207	185	(11%)

2P reserves

Highlights

• 2P reserves increased by 4% from 313 MMboe to 326 MMboe
• 204% organic 2P reserves replacement
• 2P reserves life increased from 11.0 years to 12.4 years
• Western Flank oil and gas had 2P Total Revisions of 22 MMboe

Key factors influencing 2P reserves

✓Sale of 40% interest in Victorian Otway assets

9

Taranaki

Basin

Bass Basin

Otway Basin	326
MMboe

Perth Basin

Refer to Compliance Statement slides for reserves disclosures.

Western

Flank

CBJV

✓Victorian Otway Basin: Rigorous reassessment of existing fields

✓Western Flank: Positive reservoir performance and appraisal success

✓Cooper Basin JV: Moomba South appraisal and oil appraisal results

✓New 2P reserves booking at Trefoil, Haselgrove, La Bella

FY20 guidance

	FY19 Reported1	FY19 Pro Forma1	FY20 Guidance
Production	29.4 MMboe	26.2 MMboe	27 - 29 MMboe
Capital Expenditure2	$447 million	$435 million	$750 - 850 million
Underlying EBITDA	$1.375 billion	$1.22 billion	$1.25 - 1.40 billion
DD&A3	$523 million ($17.8/boe)	$443 million ($16.9/boe)	$17-18 / boe

• FY20 Underlying EBITDA guidance includes an estimated $50 million of "other revenue"
• FY20 Underlying EBITDA guidance includes an estimated $30 million positive impact from the application of AASB 16 (lease) accounting standard
• FY20 DD&A guidance includes ~$30 million associated with the impact of AASB16 (lease) accounting standard
• FY20 cash tax expected to be ~$175 million higher than tax expense
• No PRRT expected to be paid in FY20

More than half of FY20 capital expenditure drives FY21+ production

1.

10 2.

3.

FY19 Reported data accounts for Victoria Otway assets at 100% for 11 months to 31 May 2019 and 60% for June 2019. FY19 Pro Forma adjusts to reflect Victorian Otway assets at 60% for the entire FY19. Excludes corporate capital expenditure

Excludes DD&A associated with corporate assets

FY20 production guidance

Higher Western Flank oil output to offset statutory shutdowns in Otway, Kupe

29.4
					26.2		27 - 29
18.5			15.7	14.8	- 15.8
						3.5	- 4.0
4.0			3.6
6.9			6.9	8.7	- 9.2
FY19 reported	FY19 pro forma		FY20 production
	production	production		guidance
		Oil		Gas Liquids (condensate / LPG)		Sales Gas / Ethane

FY20 production movement vs FY19

Oil production

Forecast increase driven by contribution from up to 97 new oil wells planned in FY20, including up to 16 Western Flank horizontal wells

Gas and gas liquids production

Increased Cooper Basin gas production from up to 90 new gas wells in FY20

Customer demand and facility reliability remain important factors in guidance range

Scheduled 30 day statutory shutdowns at Kupe and Otway in November 2019 and March 2020 respectively

11

FY20 capital expenditure guidance splits

Investment focus remains on Cooper Basin and Victoria

Capital expenditure by type

…by asset group

Increase in FY20 vs FY19 driven by

14%

29%

4% 4%

5%

•Participation in up to 194 wells (FY18: 134 wells)

oWestern Flank (~84 wells doubling FY19)

57%

Exploration/Appraisal Development Fixed

…by target

8%

30%

62%

	26%
27%
	33%
Cooper Basin JV	Western Flank
Vic Otway	SA Otway
WA	Other

oCooper Basin JV (~100 wells, 4 rigs for full year)

oVictoria (ERD and offshore drilling programs)

•Re-phasing of Otway drilling expenditure from FY19 to

FY20 (~$50 million)

•Almost two thirds of investment is directed at gas

supplies for the east coast gas market

•59% of investment onshore in the Cooper Basin

•90% of FY20 growth projects deliver IRRs > 50%

•25% of FY20 growth projects deliver IRRs > 100%

East Coast Gas

Oil

Other

12"Fixed" refers to stay-in-business capital expenditure.

Growth projects defined as Exploration/appraisal and Development projects Other represents New Zealand, Western Australia and Frontier

FY20 capital increase driving high return growth

Doubling well count in Western Flank and growing the Otway

Capital expenditure bridge ($ million)

800

FY20 expectations at

2018 Investor Day

400

0

FY19A	Mid-point FY20
	guidance of
	$750 - 850 million

Project phasing - deferral of FY19 capital items to FY20

New onshore investment added (Western Flank and CBJV rigs for longer increasing well count by ~40%)

Key contributors include Otway Victoria drilling (begins for long life east coast gas business), Beharra Springs Deep exploration and Kupe compression project

FY19 capital expenditure equivalent

13

East coast gas market

Market dynamics support Beach's investment strategy

Southeastern Australia gas demand vs production1

	600
	500
	400
		Supply gap expected to be met by
			LNG diversions and/or LNG
PJ	300		imports in the absence of material
			new indigenous supply sources
	200

100

0

2019	2020	2021	2022	2023	2024	2025	2026	2027	2028	2029	2030	2031	2032	2033	2034	2035	2036	2037	2038
				Southern production from anticipated projects

• AEMO forecasts project Southeastern Australia gas production to be insufficient to meet demand
• Supply shortfall has been met by gas from Queensland, primarily from LNG projects diverting gas
• In the absence of material new gas supplies, AEMO forecasts the southern demand/supply gap to widen, increasing reliance on LNG
• ACCC reported2that Victorian and South Australian producers have agreed prices ranging from $8.92 - 10.97/GJfor gas supply in 2020

Southern production from existing and committed projects

Southern demand

141. Source: AEMO. Southeastern Australia is defined as New South Wales, Victoria, South Australia and Tasmania

2. Source: ACCC Gas Inquiry Report 2017 - 2020 Interim Report April 2019, page 34. Expected 2020 wholesale producer gas commodity prices in the East Coast Gas Market, from Victoria and South Australian producers, for supply in 2020, agreed under GSAs executed between 1 January 2017 and 23 January 2019.

Attractive medium-long term pricing outlook

Higher gas sales and repricing of legacy volumes to deliver higher gas revenues

East coast gas supply

Beach

average realised price:

FY19

$6.81/GJ

Re-contracted /re-priced volumes

100%

90%

80%

70%

60%

50%

40%

30%

20%

10%

0%

FY20		FY21		FY22	FY23	FY24
		Legacy Pricing		New Market Pricing

Almost 80% of Beach's estimated east coast gas sales in FY24 is sold at prevailing market prices

• Lattice gas contracts have annualstep-ups and CPI adjustments ahead of repricing events
• By FY22 more than 70% of
  Beach's east coast gas sales is expected to be re-priced or re- contracted
• Beach capital investment supported by market dynamics

151. Source: 2019 Gas Statement of Opportunities, AEMO - March 2019..

Key takeaways

Beach is ahead of schedule and delivering on its promises

Ready to accelerate growth

Record activity planned in FY20

Updated 5 year targets, financial

discipline remains

Business has long life ahead

• Expandedvalue-accretive portfolio (90% of growth projects deliver IRRs > 50%)
• Strong balance sheet position ($172 million cash at 30 June 2019)
• Target development of 169 MMboe undeveloped 2P reserves base by FY24
• Up to 194 wells planned in FY20 - a significant increase on FY19 (134 wells)
• Investing $750 - 850 million to drive medium term growth
• Production guidance 27 - 29 MMboe

✓Production:	34 - 40 MMboe in FY24	(prior: 30 - 36 MMboe in FY23)
✓Free cash flow:	$2.7 billion	(prior: $2.3 billion)
✓ROCE:	remains 17-20%

• Western Flank oil 2P reserves life increased from 3.5 years (FY16) to 8.0 years (FY19)
• Group 2P reserves life increased to 12.4 years
• Retain target of > 100% 2P reserves replacement average over next 5 years

16

I N T E R N A T I O N A L R O A D S H O W P R E S E N TA T I O N

Asset updates

HSE Performance

Lattice acquisition safely integrated

Safety performance

TRIFR116

15.6

Environmental performance2

Crude Spill Volumes (kl)

12

8

7.9

51.9

99.9%

9.6

4											3.5	3.4
		3.8
0
		FY15				FY16				FY17				FY18				FY19

Focus on HSE delivering best performance to date

• Safety: Our safest year on record
• Environment: Our best environmental performance on record
• Process Safety: Our best process safety performance on record

181. TRIFR: Total Recordable Injury Frequency Rate, calculated as number of recordable injuries per million hours worked (Beach employees and contractors).

1. Includes Lattice assets from 1 January 2018.
2. Based on API 754 Loss of Primary Containment process safety events.

				0.2	0.1	0.07
	FY15		FY16		FY17		FY18	FY19

Process Safety - Loss of containment3

10

8

6

4

2

0

Dec Feb Apr	Jun Aug Oct Dec Feb Apr	Jun Aug Oct Dec Feb Apr June
2017	2018	2019

Delivering as a low cost operator

Beach operating costs/boe1

$/boe
10			9.9
	9.7
		9.3		9.4
				9.2
9.1
9
8
FY17	FY18	FY19	H2 FY18	H1 FY19	H2 FY19
(pre-Lattice)	(blend of pre-
	and post-
	Lattice)

Full year data

Half year data

• Operational Excellenceprogram launched to generate value through safe, reliableand efficientoperations
  oReliability focus has seen average facility reliability improve to >97% across our six operated facilities
  oSustainable cost out has achieved a $21 million reduction in direct controllable operating costs
• $30 million reduction2in direct controllable operating costs by the end of FY20 remains on track
• 98% facility reliability target by the end of FY20 remains on track

	1.	Operating costs exclude royalties, tolls, tariffs and 3rd party purchases. Operating costs per boe is for the entire group and includes both operated and non-operated assets
19	2.	Relative to FY18 baseline direct controllable operating costs of $160 million

A successful year on the Western Flank

Production and reserves

Horizontal drilling

Appraisal strategy

Record production, drilling

activity planned in FY20

• Record Western Flank oil and gas production of 7.1 MMboe, +16% vs FY18
• Western Flank oil and gas had total 2P reserves revision of 22 MMboe (309% reserves replacement ratio)
• Western Flank 2P reserves life increased from 7.0 years to 8.2 years
• Six operated horizontal wells drilled in FY19
• Drilling results (time, cost, net pay, initial production rates) improvement vs FY18
• Productivity of horizontal wells has averaged 8x higher than similar vertical wells
• Discovered eastern extension to the Bauer oil field, further appraisal planned
• Appraisal at Hanson oil field and Lowry gas field also delineated field extensions
• Targeting > 20,000 bopd production rate from operated permits (ex PEL 91,92)
• Targeting 84 wells in Western Flank in FY20, up from 42 in FY19 and 26 in FY18
• Investment in surface infrastructure to handle higher fluid volumes, more wells

202P reserves replacement ratio calculated as Western Flank 2P reserves additions divided by FY19 reported Western Flank production. 2P reserves life calculated Western Flanks 2P reserves, divided by FY19 Western Flank production.

Western Flank Oil

Successful year of appraisal and development

FY19 Highlights:

• 10% increase in production on FY18, 2P reserves now 42MMbbl, +7 MMbbl over FY18
• Increased drilling activities. 34 Western Flank oil wells drilled, +127% over FY18, at a higher success rate
• Included eight horizontal wells; six operated
• Successful oil appraisal programs in Bauer and Hanson fields, field limits increased vs prior 2P reserves mapping

FY19 production

Western

Flank Oil

5.2 MMboe

29.4

MMboe

Rest of

Beach

FY19 2P reserves

Western

Flank Oil

42 MMbbl,

326

MMboe

Rest of

Beach

21

Western Flank Oil

Bauer (Beach 100% interest) - keeps on getting bigger

Top reservoir map - 2018	Top reservoir map - 2019

Success of the Bauer appraisal strategy

• Flat structural relief means seismic is of limited value in defining field extent
• In FY19 Beach appraised "through the drill bit"
• Fourstep-out appraisal wells in Bauer discovered an easterly extension to the field
• Further appraisal is required at Bauer to define the field structure, remaining oil potential and full field development
• In FY20 Beach plans on drilling 8 appraisal wells at Bauer and 15 development wells, including 7 horizontal wells

22

Western Flank Oil

Accelerated investment strategy in place to unlock remaining potential

FY20 activity - record investment year for Western Flank oil

• ~$200 million to be invested in Western Flank oil, a record for Beach
• Up to 77 oil wells to be drilled in FY20, including:
• • 36 exploration and appraisal wells
  • 41 development wells (including up to 17 horizontal wells)
• ~15% of FY20 growth investment for infrastructure expansion and debottlenecking to unlock Western Flank potential
• Continued roll out of the Bauer appraisal strategy across fields including Parsons and Callawonga, as well asfollow-up appraisal drilling at Bauer, Hanson and Kalladeina-Congony complex

23Projects shown in ex PEL 92 subject to joint venture approval.

Western Flank Gas

ex PEL 106, ex PEL 107 and ex PEL 91, Beach 100% and operator

24

FY19 Highlights:

✓35% increase in production on FY18, 2P reserves now 16MMboe, +8 MMboe over FY18

✓Successful gas exploration/appraisal programs in Lowry and Udacha South fields extended field limits vs prior 2P reserves mapping

✓Lowry field is a high liquids content gas field (50 bbl/mmscf)

FY20 Focus:

•Potential further appraisal drilling at Lowry and Middleton

•Drill 3-5 prospects delineated by Spondylus 3D seismic survey to extend proven stratigraphic play and test new exploration plays

•Aim is to increase reserves to extend plateau at Middleton and/or expand capacity

FY19 production

Western

Flank Gas

1.9 MMboe

29.4

MMboe

Rest of

Beach

FY19 2P reserves

Western

Flank Gas

16 MMboe

326

MMboe

Rest of

Beach

Cooper Basin JV

Beach various interests (20.76 - 52.2% range), Santos operator

Cooper Basin JV wells drilled in FY19

•Santos and Beach aligned and targeting production growth

•FY19 CBJV drilling success rate of 87%

25	Beach's Cooper Basin interests span 33,000 km2with surface infrastructure

Cooper Basin JV

Beach various interests (20.76 - 52.2% range), Santos operator

FY19 Highlights:

• 37% increase in production
• 2P reserves 84 MMboe
• 92 Cooper Basin JV wells drilled, +44% over FY18, at 87% success rate
• 50 exploration and appraisal wells at 80% success rate
• Oil appraisal programs in Watkins and Jarrar fields in Southwest Queensland (SWQ) increased 2P reserves in both fields

FY20 Focus:

• ~100 wells currently planned for FY20
• Follow up development proposed at Moomba South coming out of the successful FY19 appraisal campaign
• Further SWQ oil appraisal and development
• Horizontal pilot program across Cooper Basin Permian reservoirs withfollow-up potential in success case

FY19 production

Cooper

Basin JV

8.1 MMboe

29.4

MMboe

Rest of

Beach

FY19 2P reserves

Cooper

Basin JV

• Successful Moomba South gas appraisal program with seven out of eight wells successful

98% 2P reserves replacement in FY19

26

84 MMboe

326

MMboe

Rest of

Beach

Victorian Otway Basin

Beach 60% and operator

27

FY19 Highlights

✓Excellent production outcome at 8.4 MMboe, driven by 97% facility reliability and strong customer nominations

✓Completed the 40% sell-down of Victorian Otway Assets to O.G. Energy in May 2019

✓All offshore 3D seismic data was integrated, reprocessed and analysed delivering:

oBetter understanding of the discovered gas resources

oIdentification of new prospects and leads

✓Acquired undeveloped La Bella gas field

✓62 MMboe 2P reserves at year end. 183% organic reserve replacement ratio1

1. Organic 2P reserves replacement ratio calculated as Victorian Otway 2P reserves additions, excluding acquisitions and divestments, divided by FY19 Victorian Otway reported production.

FY19 production

Vic Otway

Basin

8.4 MMboe

29.4

MMboe

Rest of

Beach

FY19 2P reserves

Vic Otway

Basin

62 MMboe

326

MMboe

Rest of

Beach

Victorian Otway Basin

FY20 activities

• Ten drilling opportunities (eight development) planned in the next 3 years to keep the Otway Gas Plant (OGP) full.
• Development wells plus one exploration success at either Enterprise or Artisan should provide sufficient deliverability to keep plant full until FY26
• Black Watch and Enterprise Extended Reach Directional (ERD) wells to be drilled frommid-FY20
• Black Watch connection will add deliverability from H2 FY20
• Offshore program starts withArtisan-1 exploration well around mid-FY20
• La Bella provides optionality. Development timing can be optimised depending on exploration drilling results
• 30 day statutory shutdown scheduled for March 2020

OGP gas production outlook (100% interest)1

60

50

40

PJ

30

20

10

0

FY20

FY21

FY22

FY23

FY24

FY25

FY26

FY27

FY28

2 exploration successes + La Bella

1 exploration success + La Bella

1. Production outlook is determined using the assumptions set out on the "Compliance Statements" slide and assumes risked exploration success and La Bella development. Any changes to the underlying assumptions could cause actual reported results to differ materially to the outlook presented. Outlook is presented28on 100% basis.
2. Internal rate of return (IRR) calculated based on internal assumptions. Refer to the "Compliance Statements" slide for further detail regarding assumptions.

Bass Basin

Beach 53.75% producing assets, 50.25% non-producing, Beach operated

FY19 Highlights:

• Progressed the evaluation of a potential tieback of the Trefoil Field moving to "Concept select" phase
• Facility reliability 93.3% in FY19
• 2P reserves now 20MMboe, +11 MMboe over FY18
• Beach in discussions with gas buyers to contract remaining Bass Basin 2P reserves beyond expiration of Lattice GSA

FY20 Focus:

• Continue development studies on Trefoil gas field
• Planning for 3D seismic over White Ibis/Bass
• Maintain high facility reliability

FY19 production

Bass Basin

1.7 MMboe

29.4

MMboe

Rest of

Beach

FY19 2P reserves

Bass Basin

20 MMboe

326

MMboe

Rest of

Beach

29

New Zealand - Kupe Gas Project

Beach 50% and operator

FY19 Highlights:

✓High facility reliability and customer nominations supported 115% increase in reported production

✓Reliability of >99% achieved at Kupe production station

✓FEED completed for Kupe compression project

FY20 Focus:

•Kupe compression FID targeted for Q1 FY20, first gas by late FY21. Supports production plateau extension to FY24

•30 day statutory shutdown planned for November 2019

•JV to continue evaluation of additional drilling potential (Kupe and NFE)

30

FY19 production

New Zealand

3.2 MMboe

29.4

MMboe

Rest of

Beach

FY19 2P reserves

New Zealand

27 MMboe

326

MMboe

Rest of

Beach

Perth Basin

Waitsia (Beach 50%), Beharra Springs (Beach 50%1and operator)

FY19 Highlights:	FY19 production

• GSA executed with Alinta Energy for delivery of 20

TJ/d from July 2020 for 4.5 years. FID reached on Waitsia Stage 1 expansion to 20 TJ/day

• Stage 1 includes large diameter connection to DBNGP
• FEED completed and EPC tenders in progress on Waitsia Gas Project Stage 2
• Beach and Mitsui E&P Australia (MEPAU) align interests 50:50 across Perth Basin

FY20 Focus:

29.4

MMboe

Rest of

Beach

FY19 2P reserves

Perth Basin

0.7 MMboe

Perth Basin

73 MMboe

•Drill Beharra Springs Deep-1 exploration well	326
•Commence construction of Waitsia Stage 1 expansion	MMboe
Rest of
•FID on Waitsia Gas Project Stage 2	Beach
•Trieste 3D seismic survey

31

1. Subject to completion of sale of 17% interest to Mitsui E&P Australia

South Australian Otway Basin

Beach interests 70 - 100% and operator

FY19 Highlights:

• Initial 2P reserves booking: 1 MMBoe
• Haselgrove-4encountered thicker sands than Haselgrove-3 in both primary and secondary targets. Well completed for production testing in H1 FY20
• Construction of a 10 TJ/d gas facility commenced at the site of the previous Katnook facility, which was successfully remediated. First gas is scheduledmid-FY20

FY20 Focus:

• Ensign 931 rig being mobilized toDombey-1 exploration well drill site
• Follow up appraisal drilling under consideration
• Expansion potential at Katnook gas facility, subject to drilling results

Ensign 931 rig at Haselgrove-4 drill site in the SA Otway Basin

32

Frontier Exploration

High Impact Exploration Targets in Portfolio

Ironbark - Carnarvon Basin (Beach 21% interest)

Ironbark top reservoir structure

• Large gas prospect withintie-back distance to NWS project
• Targeting deeper Mungaroo reservoirs; the primary reservoirs at Gorgon
• Drilling planned for FY21

33•Beach share of drilling cost ~$35 million

Wherry - Canterbury Basin (Beach 37.5% interest)

• Largeliquids-rich gas prospect with follow-up potential
• Drilling planned FY21, subject to rig availability
• Beach share of drilling cost ~$30 million

Wherry top reservoir structure

Beach illustrative rig schedule1

Beach to employ 10 rigs in FY20, up from 5 in at the start FY19

Cooper Basin JV

Western Flank

Otway Basin

Perth Basin

H1 FY20		H2 FY20		H1 FY21

Non-operated rig (Santos operator)

Non-operated rig (Santos operator)

Non-operated rig (Santos operator)

Non-operated rig (Santos operator)

Operated rig (oil development)

Operated rig (oil exploration / appraisal)

Operated rig (oil exploration & appraisal + gas)

Ocean Onyx (Offshore Vic)	Artisan-1 to be followed by development drilling program
				Ensign 931 (onshore SA and Vic extended reach drilling)
Haselgrove-4Dombey-1	Black Watch-1	Enterprise-1

Haselgrove appraisal

Beharra Springs	Easternwell 106
Deep-1

Beach has significantly expanded its drilling capabilities over the past 18 months to operate 6 rigs in FY20

34

1. Illustrative rig schedule subject to change

Indicative FY20 drilling program

Record drilling activity in the Western Flank, offshore Otway drilling to commence

FY20 expected number of wells			Highlights
	Gas	Oil	Total	•Record drilling activity for Beach in FY20 - up to 194 wells (FY19: 134)
					•Record Western Flank drilling, with 84 wells targeted (FY19: 42)
Western Flank	7		77	84
					•More than half of the wells drilled in the Cooper Basin will target oil vs gas
Cooper Basin JV	83		20	103
					•Offshore Otway drilling to commence, with up to 2 wells expected in FY20
Total Cooper Basin	90		97	187
					•Increased application of horizontal drilling technology (up to 13 wells
SA Otway Basin	2		0	2
					planned) set to materially increase oil production
Victorian Otway Basin	4		0	4
					•Cooper Basin JV expected to maintain 4 rigs and drill ~100 wells
Perth Basin	1		0	1
Total Beach	97		97	194

35Subject to change.

I N T E R N A T I O N A L R O A D S H O W P R E S E N TA T I O N

Appendices

Financial highlights

$ million (unless otherwise indicated)	FY18	FY19	Change
Production (MMboe)	19.0	29.4	55%
Sales volumes (MMboe)	20.1	31.2	55%
Avg. realised oil price1($/bbl)	93.4	101.8	9%

Underlying NPAT recognises

• 55% increase in sales volumes
• 9% increase in realised oil price
• 54% increase in sales revenue

Avg. realised gas /ethane price ($/GJ)	6.57	6.81	4%	Operating cash flow
Sales revenue	1,251	1,925	54%
•57% increase in operating cash flow
Net profit after tax	199	577	190%
				Net cash position
Underlying NPAT2	302	560	86%
				•$172 million net cash at 30 June 2019
Operating cash flow	663	1,038	57%
				•1.0 cent per share fully franked final
Net assets	1,838	2,374	29%
				dividend announced
Net (debt) / cash	(639)	172

1. Excludes the impact of hedging
2. Underlying results in this presentation are categorised asnon-IFRS financial information provided to assist readers to better understand the financial performance of the underlying operating business. They have not been subject to audit or review by Beach's external auditors. The information has been extracted

37	from the audited financial statements. For a reconciliation of FY19 net profit after tax to underlying net profit after tax, refer to Appendix.

Underlying NPAT drivers

Movement in Underlying NPAT1

$ millions

						12	25
							Gas and	19
				91		Other2	23
							ethane
				FX			A$/GJ	Oil and	Net
	136			A$/US$		FY18 $6.57	liquids financing	115
				FY19 $6.81	US$/boe	costs
			FY18 0.775
								Tax
	Other	FY19 0.715				FY18 US$70
							FY19 US$69
revenue3										168

$560 million Underlying NPAT is 86% higher than FY18 driven by factors including:

• A 55% increase in sales volumes
• Higher realised Australian dollar oil and gas prices

Partly offset by higher:

Cash

production

costs

•Gross cash production costs (higher production

volumes)

529

210

Depreciation

			560
		Volume	•Tax expense (profit driven)
		/mix
	302		86%
		$258 million total increase in underlying NPAT
	FY18	FY19
Underlying NPAT	Underlying NPAT

1. Underlying results in this presentation are categorised as non-IFRS financial information provided to assist readers to better understand the financial performance of the underlying operating business. They have not been subject to audit or review by Beach's external auditors. The information has been extracted from the audited financial statements. For a reconciliation of FY19 net profit after tax to underlying net profit after tax, refer to Appendix.

382. Other includes $49 million third party sales, $17 million other income, $2 million other expenses and $8 million inventory change less $64 million third party purchases.

3. Other revenue includes the unwinding of liabilities associated with gas sales agreements

Outstanding debt fully repaid during FY19

Beach in a net cash position two years ahead of initial expectations

Movement in Net Debt

• $950 million in debt repaid from:oOperating cash flow
  oProceeds from Otway Sale oCash on hand
• Closing cash balance of $172 million
• Revolver undrawn, $450 million availability
• Total liquidity of $622 million at 30 June 2019

$ millions

262

1,038

36

479

46

172

639
FY18	Operating	Proceeds from	Other2	Cash capital	Dividends	FY19
Net debt	cash flow	Otway Sale		expenditure		Net cash

391. Net debt defined as drawn debt less cash and cash equivalents

2. Other includes net proceeds from acquisitions and divestments excl Otway Sale, proceeds from repayment of employee share loans and effect of exchange rate on foreign cash balances.

Reconciliation of NPAT to Underlying NPAT1

$ millions

	FY18	FY19	Change
Net profit after tax	199	577	379	+190%
Acquisition costs and writeoff of debt establishment fees	51	-	(51)
Gain on asset disposals	(20)	(20)	(0)
Unrealised hedging movements	13	-	(13)
Impairment of assets	88	-	(88)
Tax impact of the above	(30)	3	33
Underlying net profit after tax	302	560	259	+86%

Note: Due to rounding, figures and ratios may not reconcile to totals.

1. Underlying results in this report are categorised as non-IFRS financial information provided to assist readers to better understand the financial performance of the underlying operating business. They have not been subject to audit or review by Beach's external auditors, however have been extracted from the audited financial statements.

40

Underlying EBITDAX, EBITDA, EBIT, NPBT and NPAT1

$ millions

	FY18	FY19	Change
Underlying EBITDAX	766	1,375	609	80%
Exploration expense	0	0
Underlying EBITDA	766	1,375	609	80%
Depreciation and amortisation	(315)	(527)
Underlying EBIT	451	848	397	88%
Finance expenses	(42)	(62)
Interest income	7	4
Underlying net profit before tax (NPBT)	416	790	374	90%
Tax	(114)	(230)
Underlying net profit after tax (NPAT)	302	560	258	86%

Note: Due to rounding, figures and ratios may not reconcile to totals.

1. Underlying results in this report are categorised as non-IFRS financial information provided to assist readers to better understand the financial performance of the underlying operating business. They have not been subject to audit or review by Beach's external auditors, however have been extracted from the audited financial statements.

41

Summary of east coast gas contracts at 30 June 2019

Beach gas sales to progressively be re-priced at prevailing market pricing

FY19

Market pricing

Asset

Volume (PJ)

Counterparty

Basis

End date

Repricing

FY20

FY21

FY22

FY23

FY24

Cooper Basin JV

Origin Energy1

Oil-linked

Jun '23 - Jun '25

Cooper Basin JV

32.3

Origin (Lattice GSA)2

Fixed step-ups +

Jun '30

1 July 2021

CPI until repricing

Cooper Basin JV

Various3

Dec '19

Ethane

Western Flank Gas

7.9

Various4

Dec '19

Victorian Otway

Origin (Lattice GSA)2

Fixed step-ups +

Jun '33

1 July 2020

CPI until repricing

Victorian Otway

43.0

Origin (Toyota GSA)5

Victorian Otway

AGL6

2021

BassGas

7.5

Origin (Lattice GSA) 2

Fixed + CPI

Latest Jun '20

Total (Beach share)

90.7

1.

BPT ASX releases 10 April 2013 and 1 July 2015, two year range depends on whether extension is exercised by Origin

2.

BPT ASX release 28 September 2017

3.

BPT supplies ethane both direct to Qenos and also indirectly under arrangements with Santos. STO ASX announcement 8 September 2017 stated that ethane supply arrangements are in place until end of 2019

42

4.

All Western Flank gas is currently supplied at market prices

5.

BPT Quarterly Report 29 Oct 2018, BPT and Origin agreed a price increase in accordance with the price reviews provisions of the gas sales agreement.

6.

Source: AGL FY15 Interim Results presentation, 11 February 2015.

Beach Energy Limited

Level 8, 80 Flinders Street

Adelaide SA 5000 Australia

1. [phone]

1. [phone] beachenergy.com.au

Investor Relations

Nik Burns, Investor Relations Manager

Mark Hollis, Investor Relations Advisor

T: [phone]