SANTOS LIMITED — Interim / Quarterly Report 2017

Aug 23, 2017

2017 First-half results

24 August 2017

Santos 2017 HY Results Page 1

This presentation contains forward looking statements that are subject to risk factors associated with the oil and gas industry. It is believed that the expectations reflected in these statements are reasonable, but they may be affected by a range of variables which could cause actual results or trends to differ materially, including but not limited to: price fluctuations, actual demand, currency fluctuations, geotechnical factors, drilling and production results, gas commercialisation, development progress, operating results, engineering estimates, reserve estimates, loss of market, industry competition, environmental risks, physical risks, legislative, fiscal and regulatory developments, economic and financial markets conditions in various countries, approvals and cost estimates.

All references to dollars, cents or $ in this document are to United States currency, unless otherwise stated.

EBITDAX (earnings before interest, tax, depreciation, depletion, exploration, evaluation and impairment), EBIT (earnings before interest and tax) and underlying profit are non-IFRS measures that are presented to provide an understanding of the performance of Santos' operations. Underlying profit excludes the impacts of asset acquisitions, disposals and impairments, as well as items that are subject to significant variability from one period to the next, including the effects of fair value adjustments and fluctuations in exchange rates. The non-IFRS financial information is unaudited however the numbers have been extracted from the audited financial statements.

This presentation refers to estimates of petroleum reserves contained in Santos' Annual Report released to the ASX on 17 February 2017 (Annual Reserves Statement). Santos confirms that it is not aware of any new information or data that materially affects the information included in the Annual Reserves Statement and that all the material assumptions and technical parameters underpinning the estimates in the Annual Reserves Statement continue to apply and have not materially changed.

The estimates of petroleum reserves contained in this presentation are as at 31 December 2016. Santos prepares its petroleum reserves estimates in accordance with the Petroleum Resources Management System (PRMS) sponsored by the Society of Petroleum Engineers (SPE). Unless otherwise stated, all references to petroleum reserves quantities in this presentation are Santos' net share. Reference points for Santos' petroleum reserves and production are defined points within Santos' operations where normal exploration and production business ceases, and quantities of produced product are measured under defined conditions prior to custody transfer. Fuel, flare and vent consumed to the reference points are excluded. Petroleum reserves are aggregated by arithmetic summation by category and as a result, proved reserves may be a very conservative estimate due to the portfolio effects of arithmetic summation. Petroleum reserves are typically prepared by deterministic methods with support from probabilistic methods. Petroleum reserves replacement ratio is the ratio of the change in petroleum reserves (excluding production) divided by production. Conversion factors: 1PJ of sales gas and ethane equals 171,937 boe; 1 tonne of LPG equals 8.458 boe; 1 barrel of condensate equals 0.935 boe; 1 barrel of crude oil equals 1 boe.

2017 First-half highlights

Significant turnaround in underlying performance

Forecast free cash flow breakeven reduced

Forecast free cash flow breakeven1 Net debt

• • US$302 million free cash flow generated in the firsthalf
• • Focus remains on maximising operating cash flow to reduce debt

Balance sheet strengthened

• • Ample liquidity of US$4.2 billion in cash and undrawn bilateral facilities
• • Target US$2 billion in net debt by the end of 2019
• • No interim dividend declared

Underlying profit increased

Underlying NPAT Upstream unit production cost

• US$161 million higher
• • Net loss of US$506 million, incorporates previously announced US$689 million after-tax net impairment

Disciplined cost control

• • Cultural shift to lean, focused operations with rigorous cost control
• • Proven cost performance supports increasing development activity to unlock future gas supply

1 Free cash flow breakeven is the average annual oil price in 2017 at which cash flows from operating activities (including hedging) equals cash flows from investing activities. Forecast methodology uses corporate assumptions. Excludes one-off restructuring and redundancy costs and asset divestitures.

Safety and environment

2016 injury performance was our best on record but first-half results show we cannot be complacent

Lost Time Injury Frequency Rate three year rolling average 2012 – 1H 2017 Rate per million hours worked

• • Actions underway to address increase in low severity incidents including risk awareness programs
• • Transforming our approach to safety
  • • highly capable leaders and workforce delivering safety outcomes in the line
  • • focus on high exposure events
  • • safety integrated into the way we work
• • Significant reduction in process safety incidents and continued focus on compliance to safety critical maintenance activities
• • Continued improvement in environmental performance

Our strategy

Three phase strategy to deliver a low-cost, reliable and high performance business

Transform

• • New leadership team and simplified operating model to deliver a low-cost, reliable and high performance business
• • Focus on five core long-life natural gas assets

Core portfolio provides stable production and growth

Santos' core assets provide stable base production for the next decade Growth opportunities include Barossa backfill to Darwin LNG and PNG LNG expansion

	Delivering Australia's lowest cost onshoreoperations		High margin conventional production
	Cooper Basin	GLNG	PNG	NorthernAustralia	WA Gas
Operations	Cost base+transformed,furtherreductionsexpectedStable+production forthe next decade	Cost base+transformed,furtherreductionsexpectedRamp-up LNG+sales to~6 mtpa	Production+significantlyabovenameplate, withfurther upsidepotential	Strong operating+performance+FID taken onnext phase ofBayu-Undan infillwelldevelopment	High margin+conventionalproductionRobust domestic+gas demand
Growth	Free up more+gas for thedomestic market	Build equity gas+supply	PNG LNG+expansion+Murukareaexplorationsuccess	Barossa backfill+to Darwin LNG	Capacity and+reserves to meetshort and longterm demand

Delivering more gas to the domestic market

Santos has scale, capacity and optionality to sell into both domestic and export markets

• • Santos committed to delivering increased gas supply to the domestic market
  • • contract signed with Engie to supply 15 PJ of gas to the Pelican Point Power Station in South Australia from GLNG and Santos portfolio gas
  • • further domestic supply contracts expected to be announced
• • Strong infrastructure and resource position provides future optionality
  • • active portfolio management to make gas available to the domestic and export markets

2017 First-half financial results

Anthony Neilson

2017 First-half financial snapshot

Net loss of US$506 million, after US$689 million after tax net impairment. EBITDAX up 46% to US$718 million and underlying NPAT up US$161 million to US$156 million

1 Free cash flow breakeven is the average annual oil price in 2017 at which cash flows from operating activities (including hedging) equals cash flows from investing activities. Forecast methodology uses corporate assumptions. Excludes one-off restructuring and redundancy costs and asset divestitures.

2 For a reconciliation of 2017 first-half net loss to underlying profit, refer to Appendix.

Production and sales volumes

Higher production and sales from the core assets. 2017 sales volume guidance upgraded to 77-82 mmboe

mmboe

Oil Sales gas and ethane LNG LPG Condensate Own product Third party

• • Production from core assets increased by 2% to 25.3 mmboe, primarily due to ramp-up of GLNG and stronger PNG LNG production
• • Production from other assets decreased to 4.2 mmboe primarily due to the sale of the Victorian, Mereenie and Stag assets
• • 2017 full-year guidance maintained at 57-60 mmboe

• • Core asset sales volumes were up 5% to 36.1 mmboe, due to ramp-up of GLNG, and higher WA Gas and PNG LNG sales volumes, partially offset by lower Cooper Basin sales
• • Other assets 2.4 mmboe lower primarily due to asset sales
• • 2017 full-year guidance upgraded to 77-82 mmboe (previously 75-80 mmboe)

Transforming underlying earnings

Cost-out and efficiency gains combined with higher realised prices drive higher earnings. First-half underlying NPAT increased to US$156 million compared to a loss in 1H 2016

Strong free cash flow generation

First-half free cash flow (before asset sales) of US$302 million continues trend of improving free cash flow in a lower oil price environment

1 Excludes acquisitions / divestments

Capital expenditure

First-half capex US$321 million. 2017 capex guidance maintained at US$700-750 million

• • First-half capital expenditure of US$321 million
  • • includes Muruk acquisition and exploration drilling costs (Exploration)
  • • Barossa appraisal drilling (Northern Australia)
• • 2017 capex guidance maintained at US$700-750 million
  • • improved efficiencies and productivity gains have led to increased drilling activity in both the Cooper Basin and GLNG within existing guidance
• • 2018 drilling activity expected to increase2
  • • expect to drill 70-80 wells in the Cooper Basin
  • • expect to drill ~250 wells in GLNG

2Preliminary and subject to joint-venture approval

Impairment

Previously announced non-cash net impairment of US$689 million, primarily due to lower oil prices

• • In determining the carrying value of its assets, Santos considers a range of asset and macro assumptions, including oil price, exchange rates, discount rates, production and costs
• • Since the last carrying value assessment at 31 December 2016, there has been a change in a number of relevant assumptions, including lower forecast US$ oil prices

Brent US$ oil priceassumptions	June2017	Dec2016
2017	50	60
2018	55	70
2019	60	812
2020	65	832
2021	70	852
2022+	791	872

1US$70/bbl long-term (2017 real) from 2022

2US$75/bbl long-term (2016 real) from 2019

GLNG: net impairment of US$867 million

• as a result of the changes in assumptions, predominantly lower US$ oil prices

Cooper Basin: positive net write-back of US$336 million

• lower assumed costs and higher assumed development activity and production, supported by significant improvements in drill, stimulate and connect unit cost performance, partially offset by lower US$ oil prices

AAL: net impairment of US$149 million

• lower US$ oil prices

Reserves

• • Santos will complete its normal annual reserves estimation process as part of its full-year accounts to be released in February 2018
• • no material adverse impact on reserves expected from lower oil price assumptions

Net debt reduced to US$2.9 billion

Target US$2 billion in net debt by the end of 2019

• • Net debt reduced to US$2.9 billion through a combination of free cash flow, previously announced asset sales and proceeds from the Share Purchase Plan
• • Focus remains on debt reduction. Target US$2 billion in net debt by the end of 2019 through free cash flow and sale of non-core assets
• • S&P reaffirmed BBB- (stable) credit rating

2017 first-half movement in net debt US$million

Re-financing Euro hybrid to reduce interest costs

Euro hybrid to be redeemed and Santos expects to issue new lower-cost debt in the nearterm. Targeting significant annual interest cost savings

Drawn debt maturity profile as at 30 June 20171 0 200 400 600 800 1,000 1,200 1,400 1,600 1,800 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 Long-term notes Term bank loans ECA supported loan facilities PNG LNG project finance €1,000 million subordinated notes 15 1,460 219 1,322 209 244 490 317 289 253 124 US$million Euro hybrid subordinated notes (US$1.15 billion) to be redeemed at first call date on 22 September 2017

• Euro hybrid to be redeemed at the first call date in September 2017

• • Ample liquidity of US$4.2 billion to fund redemption
• • Santos has a number of debt funding options available to further support liquidity and extend the debt maturity profile
• • Debt markets remain buoyant and the company expects to undertake suitable additional debt funding at significantly lower-cost in the near term
• • Expect to generate significant annual interest cost savings

¹ Excludes finance leases and derivatives (including cross-currency swap of US$261 million related to Euro hybrid note maturing in September 2017). Refer to appendix.

Hedging reduces impact of commodity price volatility

Prudent oil price hedging retains exposure to oil price upside at zero cost

Zero-cost three-way collar hedge

Open oil price positions	2017	2018
Zero-cost three-way collars (barrels)	4,590,000	9,672,500
Brent short call price ($/bbl)	US$62.85	US$59.68
Brent long put price ($/bbl)	US$50.00	US$47.51
Brent short put price ($/bbl)	US$40.00	US$40.00

As at 1 August 2017

• • 4.6 million barrels hedged for the remainder of 2017 using zero-cost three-way collars
  • • no plans to add more hedging for 2017
• • 9.7 million barrels hedged for 2018 using zerocost three-way collars
• • Continuing to review opportunities for further hedging in 2018 onwards

2017 Zero-cost three-way collar hedge

2018 Zero-cost three-way collar hedge

Operations review

Kevin Gallagher Managing Director and CEO

Record PNG LNG performance drives higher EBITDAX. Expansion of PNG LNG likely and details evolving

• • EBITDAX higher due to strong operating performance, lower unit costs and higher LNG prices
• • PNG LNG operated at ~8.2 mtpa annualised production rate in the first-half, and at ~8.6 mtpa in June, the highest monthly rate since start-up
• • 54 cargoes shipped in the first-half
• + Muruk exploration success EBITDAX

Asset KPIs	1H17	1H16
Production (mmboe)	6.2	5.9
Salesvolume (mmboe)	5.8	5.7
Sales revenue (US$m)	248	207
Productioncost (US$/boe)	4.3	4.5
EBITDAX(US$m)	203	165
Capex (US$m)	8	1

PNG - Muruk gas discovery

Material gas field 21 kilometres northwest of Hides. Follow-up potential, Karoma prospect

Drilling and testing results

• • Muruk-1 and sidetracks encountered two separate pools, Muruk A and Muruk B
• • Multi TCF potential
• • Excellent reservoir quality and potential flow rates

Muruk gas discovery Muruk cross section

Approvals and forward plan

• • Muruk-2 appraisal well located ~10 kilometres from Muruk-1
  • • expect to spud 1Q 2018
• • High-grades Karoma prospect (TCF scale)
  • • potential to spud 4Q 2018

Northern Australia

Strong Darwin LNG performance and successful Barossa two-well appraisal campaign

• • EBITDAX 22% higher mainly due to higher LNG prices
• • DLNG operated at ~3.4 mtpa annualised rate in the first-half
  • • 26 cargoes shipped in the first-half
  • • FID taken on next phase of Bayu-Undan infill well development. On track for first gas Q4 2018

Asset KPIs	1H17	1H16
Production (mmboe)	2.1	2.2
Salesvolume (mmboe)	2.2	2.2
Salesrevenue (US$m)	78	71
Productioncost (US$/boe)	17.4	17.0
EBITDAX(US$m)	45	37
Capex (US$m)	40	1

EBITDAX

Northern Australia exploration and appraisal

Barossa two-well appraisal campaign strengthens position as lead candidate for DLNG backfill

• • Two-well Barossa appraisal drilling campaign successfully completed (Santos 25%)
  • • successful production test of Barossa-6 strengthened the field's position as lead candidate to supply backfill gas to Darwin LNG
  • • pre-FEED Studies for DLNG backfill ongoing with FEED-entry planned for early-2018
  • • Barossa Area Development Offshore Project Proposal (Barossa OPP) published by NOPSEMA
• • Bonaparte Basin
  • • seismic survey completed in WA-459P, nearby Petrel, Tern and Frigate fields
• • McArthur Basin
  • • successful resolution of Tamboran dispute
  • • Santos interest to increase from 50% to 75%

Northern Australia

Cooper Basin

Lower forecast costs allowing increased drilling activity and acceleration of planned program

• • EBITDAX 51% higher due to lower cost operations, improved productivity and higher oil prices
• • Unit production cost down 12% to US$9.7/boe
• • Achieving lower well, production and processing costs
  • • further sustainable cost reductions are expected
• • Commitment to exploration and appraisal renewed
  • • Namur 4 successfully appraised a new play in the Patchawarra and Coorikianna formations. Wells online at 10 mmscf/d, significant followup potential
  • • high rate oil wells at Cocinero and McKinlay oil fields have successfully appraised the application of targeted vertical and horizontal drilling for oil
  • • Okotoko North Exploration well successfully tested Permian section, significant follow-up drilling opportunities

Asset KPIs	1H17	1H16
Production (mmboe)	7.1	7.7
Salesvolume (mmboe)	10.4	11.4
Sales revenue (US$m)	379	345
Productioncost (US$/boe)	9.7	11.0
EBITDAX(US$m)	157	104
Capex (US$m)	84	90

Cooper Basin cost base materially lower

58% reduction in drilling costs and 93% improvement in drilling efficiency since 2014

Upstream production cost US$million (gross)

Wells drilled with 2 rigs

• • Transformation has driven significant cost reductions for gas wells and oil wells
• • Drilling performance improvement facilitates more than 3 rigs of activity per year using only 2 rigs
• • Reduced rig cycle time a material contributor to lower drilling capex
• • 29 new wells connected in the first-half
• • Expect to drill 70-80 wells in 2018

GLNG

GLNG LNG sales expected to ramp-up to ~6mtpa by end of 2019 and remain at that level

• • EBITDAX 140% higher reflecting the ramp-up of Train 2 and higher LNG prices
• • Upstream unit production cost down 19% to US$6.0/boe
• • 42 cargoes shipped in the first-half
• • Lower costs and improved well performance supports development program
  • • Fairview production increasing
  • • Roma gross daily production now >50 TJ/d
  • • initial Roma Phase 3A wells producing immediate gas
  • • Scotia CF1 project on track and positive results in Arcadia

Asset KPIs	1H17	1H16
Production (mmboe)	5.6	4.3
Salesvolume (mmboe)	10.6	9.1
Sales revenue (US$m)	354	218
Productioncost (US$/boe)	6.0	7.3
EBITDAX(US$m)	156	65
Capex (US$m)	75	97

GLNG asset results include GLNG Joint Venture plus Combabula, Ramyard, Spring Gully, Denison and Tardrum 140%

GLNG cost base materially lower

Proven cost performance now allows GLNG to increase drill, complete and connect activities. Acceleration of development activity will unlock more near term gas supply

Roma drill, complete, connect US$million per well

1 Santos operated assets only. Excludes Combabula and Spring Gully

Roma development drilling Average days (rig release to rig release)

• • Lower unit costs support additional development and production opportunities
• • Roma drill, complete, connect costs reduced by 83% since Roma Phase 1 (pre 2015)
• • Drilling cycle times reduced by 68% since Roma Phase 1 (pre 2015)
• • 50 new wells connected in the first-half
• • Expect to drill ~250 wells in 2018

Low cost operations with capacity and reserves to meet short and long-term demand

• • EBITDAX lower due to settlement of a revised gas sales agreement in 1H 2016
• • Production lower due to lower Varanus Island nominations offset by higher customer nominations at Reindeer

Asset KPIs	1H17	1H16
Production (mmboe)	4.3	4.7
Salesvolume (mmboe)	4.5	3.9
Sales revenue (US$m)	116	74
Productioncost (US$/boe)	5.3	4.8
EBITDAX(US$m)	116	126
Capex (US$m)	5	10

Other assets

Packaged and run separately for value as a standalone business. Portfolio to be continually optimised to maximise value

• • EBITDAX 13% higher due to due to higher prices
• • Sale of Victoria and Mereenie completed in 1H17
• • Narrabri Gas Project
  • • Santos submitted the Development Application for the State Significant Development and associated Environmental Impact Statement (EIS) to the NSW Department of Planning and Environment on 1 February 2017
  • • EIS consultation period complete EBITDAX

Asset KPIs	1H17	1H16
Production (mmboe)	4.2	6.2
Salesvolume (mmboe)	4.0	6.4
Sales revenue (US$m)	167	217
Productioncost (US$/boe)	14.7	14.7
EBITDAX(US$m)	116	103
Capex (US$m)	39	43

Summary

Create shareholder value by becoming a low-cost, reliable and high performance business

• • A disciplined strategy focussed on five core long-life natural gas assets, each with significant upside potential
  • • strong operating performance. 2017 production and sales volume guidance upgraded
• • Turnaround strategy on track
  • • 2017 forecast free cash flow breakeven reduced to US$33/bbl1 , down 30% on YE15
• • Cultural shift to lean, focused operations with rigorous cost control
  • • unit upstream production costs reduced to US$8.08 per boe, down 22% on YE15
• • Capital allocation focused on debt repayment with flexibility to invest in growth options aligned to the core assets
  • • Net debt reduced to US$2.9 billion, down 38% on YE15
  • • Muruk-1 well exploration success in PNG
  • • Barossa field appraisal positions field as lead candidate to supply backfill to Darwin LNG

1 Free cash flow breakeven is the average annual oil price in 2017 at which cash flows from operating activities (including hedging) equals cash flows from investing activities. Forecast methodology uses corporate assumptions. Excludes one-off restructuring and redundancy costs and asset divestitures.

2017 First-half results

Appendix

EBITDAX up 46% to US$718 million. Underlying NPAT up US$161 million to US$156 million

US$ million	First-half2017	First-half2016	Var
Product sales revenue	1,453	1,191	22%
Other revenue/income	117	88	33%
Productioncosts	(239)	(273)	(12)%
Other operating costs	(189)	(170)	11%
Third party product purchases	(278)	(250)	11%
Product stock movement	(35)	7	(600)%
Other1	(111)	(102)	(8)%
EBITDAX	718	491	46%
Explorationand evaluation expense	(53)	(47)	13%
Depreciation and depletion	(348)	(399)	(13)%
Impairment losses	(920)	(1,516)	(39)%
EBIT	(603)	(1,471)	59%
Net finance costs	(139)	(131)	(6)%
Lossbefore tax	(742)	(1,602)	54%
Tax benefit/(expense)	236	498	(53)%
Loss after tax	(506)	(1,104)	54%
Underlyingprofit/(loss)	156	(5)	3,220%

Includes foreign exchange gains and losses, corporate expenses, other expenses and share of profit of joint ventures

• • Product sales revenue up 22% driven by favourable product pricing and higher LNG volumes, offset by lower crude volumes
• • Production costs 12% lower due to cost saving initiatives and the sale of non-core assets
• • Other operating costs 11% higher due to full six months of GLNG Train 2, higher pipeline charges and increased royalty charges
• • Pre-tax net impairment charge of US$920 million, primarily due to lower oil prices

Sales revenue

Sales revenue up due to higher LNG sales volumes and higher prices

US$ million	Firsthalf2017	Firsthalf2016	Var
Sales Revenue (incl. third party)
Gas, ethane and liquefied gas	1,053	806	31%
Crude oil	262	285	(8)%
Condensate and naphtha	106	76	39%
Liquefied petroleum gas	32	24	33%
Total1	1,453	1,191	22%

• Sales revenue increased by 22% due to higher LNG sales volumes reflecting the ramp-up of GLNG and strong performance from PNG LNG, combined with higher prices for all products

Average realised crude
oil price up 28%
US$ per bbl	US$ per mmbtu

1 includes third party product sales of US$392 million (2016: US$278 million)

Production costs

Upstream unit production costs improved 8% to US$8.08/boe

US$ million	First-half2017	First-half2016	Var
Production costs	239	273	(12)%
Production cost(US$/boe)	8.08	8.80	(8)%
Other operating costs
LNG plant costs	32	26	23%
Pipelinetariffs,processing tolls & other	88	85	4%
Onerous contract	31	26	19%
Royaltyand excise	30	19	58%
Shipping costs	8	14	(43)%
Total other operatingcosts	189	170	11%
Total cash cost ofproduction	428	443	(3)%

• • Upstream unit production costs down 8% to US$8.08/boe
  • • GLNG down 19% to US$6.0/boe
  • • Cooper Basin down 12% to US$9.7/boe
• • LNG plant costs higher due to a full 6 months of operation from GLNG Train 2
• • Recognition of an onerous contract for gas pipeline capacity
• • Higher royalty and excise due to higher revenue
• • Lower shipping costs due to no GLNG DES cargoes

Operating cash flow up 127% to US$662 million. Free cash flow breakeven reduced to US$33/bbl1

US$million	First-half2017	First-half2016	Var
Operatingcash flow	662	291	127%
Net cash fromdisposals/acquisitions	116	411	(72)%
Investingcash flow	(360)	(391)	(8)%
Free cash flow	418	311	34%
Cash atperiod end	2,226	1,034	115%

• • Operating cash flow up 127% to US$662 million
• • Net proceeds from asset sales in 2017 include Victoria and Mereenie
• • Free cash flow up 34% to US$418 million before funding

1 Free cash flow breakeven is the average annual oil price in 2017 at which cash flows from operating activities (including hedging) equals cash flows from investing activities. Forecast methodology uses corporate assumptions. Excludes one-off restructuring and redundancy costs and asset divestitures.

Reconciliation of half-year net loss to underlying profit

US$million	First-half2017	First-half2016
Net profit/(loss)after tax	(506)	(1,104)
Add/(deduct)significant items after tax
Impairmentlosses	689	1,061
Net gains on asset sales	(51)	4
Other	24	34
Underlying profit	156	(5)

Liquidity and net debt as at 30 June 2017

US$4.2 billion in cash and committed undrawn debt facilities

Liquidity(US$million)	30Jun 2017	31Dec 2016
Cash		2,226	2,026
Undrawn bilateral bank debt facilities		2,020	2,313
Total liquidity		4,246	4,339
Debt (US$million)
Export credit agency supported loan facilities	Senior, unsecured	1,445	1,734
US Private Placement	Senior, unsecured	630	619
PNG LNG project finance	Non-recourse	1,684	1,749
Euro-denominated hybrid notes	Subordinated	1,156	1,049
Other	Finance leases and derivatives	239	367
Total debt	5,154	5,518
Total net debt	2,928	3,492

2017 First-half segment results summary

First-half 2017US$million	CooperBasin	GLNG	PNG	NorthernAustralia	WA Gas	OtherAssets	Corporateexplor'n&elimins	Total
Revenue	395	358	250	78	135	170	110	1,496
Production costs	(69)	(34)	(27)	(35)	(25)	(61)	12	(239)
Otheroperatingcosts	(37)	(33)	(22)	(3)	(8)	(8)	(78)	(189)
Thirdpartyproductpurchases	(73)	(84)	(1)	-	-	-	(120)	(278)
Inter-segmentpurchases	(1)	(57)					58	-
Product stockmovement	(46)	9	2	1	(4)	5	(2)	(35)
Other income	1	3	1	-	31	25	13	74
Other expenses	(11)	(1)	-	(1)	(13)	(15)	18	(23)
FX gains andlosses	(2)	(5)	-	-	-	-	(86)	(93)
Share of profit ofjoint ventures	-	-	-	5	-	-	-	5
EBITDAX	157	156	203	45	116	116	(75)	718

2016 First-half segment results summary

First-half 2016US$million	CooperBasin	GLNG	PNG	NorthernAustralia	WA Gas	OtherAssets	Corporateexplor'n&elimins	Total
Revenue	353	224	210	71	74	217	56	1,205
Production costs	(85)	(31)	(26)	(37)	(23)	(91)	20	(273)
Otheroperatingcosts	(40)	(35)	(19)	-	(2)	(8)	(66)	(170)
Thirdpartyproductpurchases	(108)	(62)	(1)	-	-	-	(79)	(250)
Inter-segmentpurchases	(2)	(30)	-	-	-	-	32	-
Product stockmovement	10	(2)	(1)	-	15	(12)	(3)	7
Other income	-	(1)	1	-	65	9	-	74
Other expenses	(23)	(3)	1	(2)	(3)	(12)	(36)	(78)
FX gains andlosses	(1)	5	-	-	-	-	(33)	(29)
Share of profit ofjoint ventures	-	-	-	5	-	-	-	5
EBITDAX	104	65	165	37	126	103	(109)	491

2017 Guidance

2017 sales volumes expected to be between 77 and 82 mmboe and production to be between 57 and 60 mmboe

2017Guidance
Salesvolumes	77-82 mmboe
Production	57-60 mmboe
Upstreamproduction costs	US$8-8.25/boe
DD&A	US$700-750 million
Capital expenditure	US$700-750 million

Capital expenditure guidance includes abandonment expenditure but excludes capitalised interest.