SANTOS LIMITED — Interim / Quarterly Report 2021

Aug 16, 2021

17 August 2021

Santos reports record half-year production and sales volumes, strong free cash flow and underlying earnings, and higher interim dividend

Half-year (US$million)	2021	2020	Change
Production (mmboe)	47.3	38.5	23%
Sales volume (mmboe)	53.8	46.9	15%
Product salesrevenue	2,040	1,668	22%
EBITDAX1	1,231	995	24%
Underlying profit1	317	212	50%
Netprofit/(loss)after tax	354	(289)	222%
Free cash flow1	572	431	33%
Interim dividend (UScps)	5.5	2.1	162%

Santos today announced its half-year results for 2021, reporting record production of 47.3 mmboe and record sales volumes of 53.8 mmboe, free cash flow of US$572 million and underlying profit of US$317 million. The results reflect higher oil prices compared to the corresponding period due to recovery in demand but were offset by lower average LNG prices due to lagged oil-linked pricing in long-term LNG offtake contracts.

The reported net profit after tax of US$354 million includes net gains on asset sales and is significantly higher than the corresponding period mainly due to impairments included in the previous half-year result.

The Board has resolved to pay an interim dividend of US5.5 cents per share fully-franked, 162 per cent higher than the previous interim dividend. The dividend equates to 20 per cent of first half free cash flow, in-line with the company's sustainable dividend policy which targets a range of 10 per cent to 30 per cent payout of free cash flow.

Santos Managing Director and Chief Executive Officer Kevin Gallagher said Santos delivered record production and sales volumes in the first half of 2021, and strong free cash flow of US$572 million despite lower average LNG prices.

"These results again demonstrate the resilience of our cash-generative base business and strong operational performance across our diversified asset portfolio.

Investor enquiries Andrew Nairn +61 8 8116 5314 / +61 (0) 437 166 497 andrew.nairn@santos.com

"Consistent application of our low-cost disciplined operating model continues to deliver cost reductions and efficiencies despite cost challenges across the industry and COVID-related cost impacts in the base business.

"We will remain disciplined and cost focused as we enter our next phase of growth and progress the proposed merger with Oil Search.

"The proposed merger is a compelling combination of two industry leaders to create an unrivalled regional champion of size and scale with a unique diversified portfolio of long-life, lowcost oil and gas assets.

"The merged company would have strong cash generation from a diverse range of assets which provides a strong platform for sustainable growth and continued shareholder returns.

"The merger would also build on our industry-leading approach to ESG through the combination of Santos' net-zero 2040 pathway, including its sector-leading CCS projects, and Oil Search's unique social programs in PNG, underpinned by a strong balance sheet to fund the transition to a lower-carbon future.

"I am pleased with the progress we are making on due diligence and look forward to the signing of a binding Merger Implementation Deed in the coming weeks.

"Since taking FID on Barossa in March, the project is off to a great start including the cutting of first steel for the FPSO turret, commencing manufacturing of subsea and export flowlines, and the assembly of subsea trees. FPSO hull build and topsides fabrication is scheduled to commence in the third quarter. The project is on track for first gas in the first half of 2025.

"While Barossa FID is a visible benefit of the acquisition of the ConocoPhillips assets in Northern Australia and Timor-Leste, I am also pleased with the very strong result from the first infill well drilled at Bayu-Undan, with initial gas rate of 178 million standard cubic feet per day and liquids rate of 11,350 barrels per day. The infill campaign adds immediate value and extends the life of Bayu-Undan.

"We are extremely appreciative of the positive working relationship we have with the Timor-Leste regulator Autoridade Nacional do Petróleo e Minerais (ANPM) and the Timor-Leste Government, whose support enabled this late-life infill campaign.

"Our Moomba carbon capture and storage (CCS) project is FID ready, subject to eligibility for Australian Carbon Credit Units, which is expected in the fourth quarter. We are also assessing the feasibility of creating a CCS hub at Bayu-Undan with the capacity of approximately 10 million tonnes per annum of CO2 and providing a cost-effective solution for Barossa reservoir emissions as part of our roadmap to net-zero by 2040.

"We have also made significant progress on our exciting Dorado project with FEED entry on an integrated oil and gas project taken in June. We are targeting FID in mid-2022 on the first phase of liquids production, with FID on a second phase of gas development to backfill our Western Australia domestic gas infrastructure likely to occur in the second half of the decade.

"Our strongly cash-generative base business, diversified portfolio and disciplined approach to capital allocation means that we are well positioned to drive free cash flow and sustainable shareholder returns," Mr Gallagher said.

Live webcast

A video presentation on the 2021 half-year results is available on Santos' website. A live question and answer webcast for analysts and investors will be held today at 12:30pm AEST.

To access the live webcast, register on Santos' website at www.santos.com.

This ASX announcement was approved and authorised for release by Kevin Gallagher, Managing Director and Chief Executive Officer.

1 EBITDAX (earnings before interest, tax, depreciation, depletion, exploration, evaluation and impairment), underlying profit and free cash flow (operating cash flows less investing cash flows net of acquisitions and disposals) 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, hedging as well as items that are subject to significant variability from one period to the next. The non-IFRS financial information is unaudited however the numbers have been extracted from the financial statements which have been subject to review by the auditor. A reconciliation between net profit after tax and underlying profit is provided in the Appendix of the 2021 half-year results presentation released to ASX on 17 August 2021.

Santos 2021 Half-year results

17 August 2021

Disclaimer and important notice

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. The symbol "~" means approximately.

Underlying profit, EBITDAX (earnings before interest, tax, depreciation, depletion, exploration and evaluation expensed, change in future restoration assumptions and impairment) and free cash flow (operating cash flows, less investing cash flows net of acquisitions and disposals and major growth capex, less lease liability payments) are non-IFRS measures that are presented to provide an understanding of the performance of Santos' operations. The non-IFRS financial information is unaudited however the numbers have been extracted from the financial statements which have been subject to review by the auditor. Free cash flow breakeven is the average annual oil price at which cash flows from operating activities (before hedging) equals cash flows from investing activities. Forecast methodology uses corporate assumptions. Excludes one-off restructuring and redundancy costs, costs associated with asset divestitures and acquisitions, major growth capex and lease liability payments.

The estimates of petroleum reserves and contingent resources contained in this presentation are as at 31 December 2020. Santos is not aware of any new information or data that materially affects the estimates of reserves and contingent resources and the material assumptions and technical parameters underpinning the estimates continue to apply and have not materially changed. Santos prepares its petroleum reserves and contingent resources estimates in accordance with the 2018 Petroleum Resources Management System (PRMS) sponsored by the Society of Petroleum Engineers (SPE). Unless otherwise stated, all references to petroleum reserves and contingent resources 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. Organic reserves replacement ratio excludes net acquisitions and divestments. 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.

The proposed merger of Santos and Oil Search outlined in this presentation (Proposal) is non-binding and indicative only and is subject to due diligence and the agreement of a binding Merger Implementation Agreement. There is no certainty that a binding transaction will result from the Proposal. In addition, any binding Merger Implementation Agreement entered into between the parties would be subject to a number of additional conditions to completion of the merger, such as regulatory approvals.

The information set out in this presentation does not take into account any person's individual financial objectives or circumstances.

Cover image: Valaris MS1 mobile offshore drilling unit, Van Gogh Phase 2 infill program

2021 Strategic priorities

Base business performing strongly and achieved key milestones on major growth projects

1	Maintain strong base business with FCF breakeven <$25/bbl1	POn track
2	FID Barossa	PFID taken in March 2021
3	FID Moomba CCS	On track for 2H21
4	FEED Dorado	PAchieved in June 2021
5	Commence appraisal drilling at Narrabri	Pending appeal in 2H21
	1 Before hedging.

2021 Half-year highlights

Disciplined low cost operating model continues to underpin strong free cash flows from the base business and position the company for growth

Strong and diversified basePbusiness	2021 volume and costPguidance ranges upgraded	Strong free cash flow and lowPfree cash flow breakeven
+Diversified portfolio of 5 core assets+Record sales volumes and revenue+Value accretive, low cost of supplyoffshore infill developments	+Production at 87-91 mmboe+Sales volume at 100-105 mmboe+Lowered upstream production coststo $7.90-8.30/boe	+$572 million FCF in the first half+On track to deliver over $1.1 billionin 2021 assuming current oil prices
PAchieved growth milestones	PEnergy transition to cleaner fuels	PStrengthened balance sheet
+Completed sell-downs in BayuUndanand DLNG to SK E&S+Commenced all major work scopesfor Barossa following FID+Entered FEED for Dorado integratedoil and gas project	+Infrastructure-led, three hub CCSstrategy+Moomba CCS project is FID-ready,subject to confirmation of eligibilityfor Australian Carbon Credit Units	+Issued US$1 billion 10-year seniorunsecured fixed rate bond in the US144A/Reg-S market+Reduced gearing to 31.8%

2021 Half-year results

Our disciplined operating model and improving commodity prices have delivered strong first half results

1 Operating cash flows less investing cash flows (net of acquisitions and disposals and major growth capex) less lease liability payments.

2 A reconciliation between net profit after tax and underlying profit is provided in the Appendix. Underlying profit excludes the impacts of costs associated with asset acquisitions, disposals and impairments, commodity hedging and items that are subject to significant variability from one period to the next.

Cash generative base business through the cycle

At current oil prices, forecast to generate over US$1.1 billion in 2021

1Operating cash flows less investing cash flows (net of acquisitions and disposals and major growth capex) less lease liability payments.

• • Diversified and balanced portfolio providing defense through the cycle
• • Record half year sales volume and revenue of $2,040 million
• • Strong first half free cash flow $572 million
• • 2021 forecast free cash flow sensitivity of ~$330 million per annum for every $10 above the breakeven oil price, before hedging
• • Targeting 2021 free cash flow breakeven oil price of <$25 per barrel before hedging with higher sustaining capex than 2020

Health, safety and environment

Our "Always Safe" value is at the centre of everything we do

Injury frequency rates

Number of injuries per million hours worked

• Disappointing start to the year with injury frequency rates increasing due to three lost time injuries, associated with slips and/or trips

Loss of containment

Number of Tier 1 and Tier 2 incidents

• Continued integrity management focus has delivered a substantial reduction in loss of containment incidents

Barossa investment decision announced in March 2021

Targeting cash cost of production of ~$2.00/mmBtu and first gas in first half 2025

Barossa development

• • Capex estimated at ~$3.6 billion gross FID to first gas, including a FPSO service contract with upfront prepayment and option to buy-out
• • ~80% of project costs are under fixed-price contracts, which were executed under favourable market conditions
• • Initiated major workstreams including cutting first steel for the FPSO turret, commencing manufacturing of subsea and export flowlines, and assembly of subsea trees
• • Hull build and topsides fabrication scheduled to commence in Q3 2021

Equity sell-downs

• • Completed 25% sell-down in DLNG and Bayu-Undan to SK E&S at the end of April for net cash proceeds of $186 million
• • Finalising 12.5% Barossa sell-down to JERA

Darwin LNG life extension project

• • DLNG and Barossa have approved and executed all agreements to transport and process Barossa gas
• • Barossa FID paves the way for the US$600 million DLNG life extension and pipeline tie-in projects, which will extend the plant life for around 20 years
• • Pipeline subsea tie-in EPCI contract awarded
• 2021 Half-year results 8 + Darwin life extension project on track to meet Barossa first gas

Moomba CCS provides step change in emission reduction

Lowest cost (<US$24/t lifecycle) and one of the largest CCS project globally. Project is FIDready, subject to Australian Carbon Credit Units eligibility

1Forecast assumes US$50/tonne carbon price by 2030. All Santos-operated assets subject to Australia's Safeguard Mechanism are currently operating below their designated facility baselines.

+ Low cost CCS project due to

• • Existing separation equipment delivering high purity CO2
• • Existing wells which can be repurposed
• • Depleted reservoirs with proven rock seal and potential to scale-up to ~20 mtpa across the basin
• • Awarded A$15 million grant under the Federal Government CCUS Development Fund
• • US$165m capex phased over three years and cash cost in operation ~US$6-8/tCO2

• Forecast IRR ~20%1

• • Phase 1 project has the capacity to capture and store ~44 million tonnes of CO2 by 2050
• • CCS is a critical enabler for zero-emissions hydrogen
• • Expect ACCU Methodology to be in place Q4 2021
• • Expect to book CO2 storage 2P capacity per PRMS guidelines at year-end

Dorado Development

FEED commenced, with FID targeted for mid 2022

Phase 1 liquids development

• • FEED underway with FID targeted for mid 2022
• • Estimated capital cost of ~$2 billion, delivering competitive cost of supply1
• • Low CO2 (~1.5%) and high-quality fluid expected to earn a premium to regional pricing benchmarks
• • Stage 1 Assessment of Offshore Project Proposal (OPP) approved by NOPSEMA and released for public consultation
• • Production Licence application planned by 4Q21

Phase 2 gas development

• • Integrated development concept established for both liquids and gas
• • Gas export is a source of supply for Santos' existing WA domestic gas infrastructure
• • Flexibility retained for tieback of future exploration success
• • Exploration wells Apus and Pavo scheduled for 1Q22

1Subject to detailed FEED for build and own FPSO.

Sustainability

Sustainability is core to our strategy to drive long-term shareholder value

Environmental Social Governance

• • Reduce Scope 1 and 2 absolute equity emissions by 26-30% by 2030
• • Net-zero Scope 1 and 2 emissions by 2040, supported by a clear roadmap
• • Moomba carbon capture and storage project provides a step-change in emissions reduction
• • West Arnhem Land Fire Abatement project is a world-leading naturebased carbon offset project
• • Targeting zero net-abstraction from the Great Artesian Basin by 2030
• • In 2020, A$17 million invested in community partnerships and local infrastructure projects
• • Community perception surveys are completed to understand and support local priorities
• • Working in partnership with 21 Traditional Owner Groups with over 2,000 active land access agreements
• • Sites of cultural heritage are identified, protected and avoided
• • Executive remuneration linked to ESG and emissions reduction targets
• • Non-binding advisory shareholder Say on Climate vote at the 2022 AGM
• • Industry Associations climate positions review released in 2020
• • EHSS and PRC Board Committees provide oversight on all ESG matters
• • Robust Enterprise Risk Management process

• Reporting + Released fourth-annual Climate Change Report consistent with the TCFD guidelines in February 2021 + Released new format annual Sustainability Report in April 2021 + Released second-annual Modern Slavery Statement in June 2021

Infrastructure-led carbon capture and storage strategy

Our extensive infrastructure position provides a competitive advantage for decarbonisation with more than 30 mtpa of carbon storage capacity across three Santos-operated hubs

1. Cooper Basin CCS

• • Moomba CCS Phase 1 at 1.7 mtpa, FID-ready subject to confirmation of eligibity for Australian Carbon Credit Units
• • Capacity: ~20 mtpa across the basin
• • Work continues on the Moomba Zero Emissions Hydrogen project including pursuing market development opportunities to secure offtake arrangements

2. Northern Australia and Timor-Leste CCS

• • Capacity: ~10 mtpa at Bayu-Undan once the field is depleted
• • Existing wells can be repurposed for CO2 injection. Pipeline is CO2 compatible
• • MOU signed with ENI to investigate repurposing Bayu-Undan to store CO2 for projects in the region
• • Targeting project start up to coincide with Barossa production subject to reaching agreements with Timor-Leste, Federal and Territory governments, and existing partners

3. Western Australia CCS

• Desktop studies commenced to confirm CO2 injection capacity

Oil Search merger strategic rationale

Merger will create a regional champion of scale and provide shareholders with an opportunity to participate in a new company that can optimally fund the development of a diverse portfolio of high-quality O&G assets

A	CREATES A REGIONAL CHAMPION OFSIZE AND SCALE	PP	Positioned within S&P ASX-20 index and top 20 largest global O&G companies1Operated footprint gives ability to control cost and deliver growth
B	DIVERSIFIED PORTFOLIO OF LONG-LIFE,LOW COST ASSETS WITH GROWTH OPTIONS	PP	Balanced portfolio of geographically and product differentiated assetsRobust development pipeline with flexibility
C	STRONG BALANCE SHEET AND INVESTMENTGRADE FUNDING PLATFORM	PP	>US$5.5bn of liquidity2and an investment grade credit ratingSufficient capacity to self-fund development pipeline
D	UNLOCKS SYNERGIESAND LATENTSHAREHOLDER VALUE	P	Substantial potential combination synergies to the benefit of allshareholders
E	PORTFOLIO OPTIMISATION OPPORTUNITIES	PP	Opportunities to align joint venture interest across PNG projectsOptimise portfolio to further strengthen balance sheet and high grade portfolio
	1 Based on market data as at 30 July 2021.

2 Based on Oil Search and Santos balance sheet data as at 30 June 2021.

Merger process update

Exclusive mutual due diligence underway. Targeting to execute binding Merger Implementation Deed in September and Scheme vote by late November

Proven track record of delivering integration synergies

Delivered more than $160 million in synergies from the Quadrant and ConocoPhillips transactions. Substantial potential combination synergies expected from Oil Search merger

Quadrant integration pre-tax synergies

US$50-60m synergies delivered through:

• • Gas marketing and operational efficiencies
• • Removal of non-operated duplication for WA gas assets
• • Reduced corporate costs by consolidating Perth offices, support functions, IT costs and insurance

ConocoPhillips AW integration pre-tax synergies

More than US$100m synergies delivered through:

• • Significant reductions in corporate and IT costs from global parent and local office
• • Optimisation of operational activities across the asset portfolio
• • Restructured to an integrated organisation

Delivering incremental value through acquisitions

Short-cycle, low-risk, high-value developments delivering production in 2021 and extending life

	Bayu-Undan Phase 3C	Van Gogh Infill Phase2
Description	2 platform and 1subsea wells developing gas andliquids	3 dual lateral wells, infilling existing Van Goghdevelopment
Startup	3Q 2021	4Q 2021
STO working interest	43.4%	52.5%
2P reserves (YE20)	23 mmboegrossnet110 mmboe	10 mmbblgross5 mmbblnet
Total capex (gross)	US$235m	US$225m
Breakeven cost of supply	US$2.80/mmBtu	US$25/bbl
Initial well production rates	178 mmscf/d and 11,350 bbl/d liquids	23,200 bbl/d

1 Net working interest at 43.4% following completion of the 25% sell-down to SK E&S on 30 April 2021.

Finance and Capital Management

Anthony Neilson Chief Financial Officer

Financial discipline

Strong base business and balance sheet supportive of disciplined and phased growth

Strong, cash-generative basebusiness with steady production	+Generated $572 million free cash flow in the first half of 2021+Targeting 2021 free cash flow breakeven oil price of less than $25 per barrel beforehedging+2021 free cash flow sensitivity of ~$330 million per annum for every $10 above thebreakeven oil price. At current oil prices, 2021 forecast FCF is greater than $1.1 billionincluding hedging1
Disciplined capital allocation	+Consistent with the disciplined low cost operating model, growth projects are phasedand equity levels reviewed+Completed 25 per cent sell-down in Bayu-Undanand DLNG to SK E&S+12.5 per cent Barossa sell-down to JERA progressing well and expected 2H21
Strengthened balance sheet andprepared to fund growth	+Issued $1 billion 10-year senior unsecured fixed-rate bond in the US 144A/Reg-Smarket with liquidity ~$4.5 billion+Strong cash flows reduced net debt (including leases) to $3.4 billion and gearing to31.8% at end June 2021. At current oil prices, gearing would be ~30% by year end+Secured second investment grade credit rating: Fitch BBB/Stable+No significant debt maturities until 2024

1 Assumes an average 2021 oil price of US$60 per barrel and 7.7 million barrels of oil hedged in the second half of 2021 at an average ceiling price of US$55 per barrel.

Strong base business generated $572 million of free cash flow

$ million	1H21	1H20	Change
Productsales revenue	2,040	1,668	22%
EBITDAX	1,231	995	24%
profit1Underlying	317	212	50%
Net profit/(loss) aftertax	354	(289)	222%
Operating cash flow	942	838	12%
Free cash flow2	572	431	33%
Interim dividend(UScps)	5.5	2.1	162%

1 For a reconciliation of 2021 half-year net profit after tax to underlying profit, refer to Appendix.

2 Operating cash flow less investing cash flows (net of acquisitions and disposals and major growth capex) less lease liability payments.

Strong free cash flow generation

At current oil prices, forecast to generate over US$1.1 billion in 2021

1Excludes acquisitions / divestments, major growth capex and includes lease liability payments. 2021 Half-year results 20

Underlying earnings

Generated >$1.2 billion in EBITDAX predominantly reflecting improved commodity prices and lower unit costs. Higher depreciation, primarily in Western Australia, impacted underling profit

1 Underlying profit excludes the impacts of asset acquisitions, disposals and impairments, and the impact of commodity hedging.

2021 Half-year results 21

Record production and sales volumes

Strong first half performance. Volumes expected to be lower in the second half due to the 25 per cent sell-down in Bayu-Undan and DLNG which completed on 30 April

Major shutdown + PNG earthquake impact

• • Record 1H21 production volumes were driven by average higher equity in Bayu-Undan, strong upstream performance at GLNG and Western Australia oil and gas
• • 2021 full-year production guidance maintained at 87-91 mmboe

• • Record 1H21 production volumes resulted in a corresponding increase in sales volumes for the first half
• • 2021 full-year sales volume guidance maintained at 100-105 mmboe

Production costs

Unit production costs lower despite COVID-19 and unfavourable foreign exchange impacts

$/boe

• • Greater than $100 million of pre-tax synergies have been delivered in Northern Australia which is reflected in the ~30% reduction in unit costs to US$13.95/boe in 1H21
• • Partially offset by increased COVID-related costs to maintain safe and continual operations combined with increased AUD/USD exchange rate resulted in the following group-level impacts for the first half
  • • $0.35/boe COVID-related costs, particularly for Bayu-Undan where increased quarantine periods were required, both prior to departure and upon return from offshore operations
  • • $0.55/boe foreign exchange impact for our Australian dollar denominated cost base, mainly for our onshore business
• • 2021 upstream production cost guidance maintained at $7.90-$8.30/boe

Upstream unit production costs1

1Includes all planned shutdown activity and PNG earthquake recovery costs. Increased equity in Bayu-Undan & DLNG

Upstream unit production costs

Synergy cost reductions realised in Northern Australia. Partially offset by COVID-19 related costs and foreign exchange increases in the first half

Disciplined Operating Model

• Core portfolio free cash flow breakeven at ≤$35/bbl oil price through the oil price cycle

• Each core asset free cash flow positive at ≤$35/bbl, premajor growth spend

Cash generative Operating Model continues to drive value

EBITAX margin improved to 58% due to higher commodity prices and lower unit costs

2021 Half-year results summary1

	CooperBasin	Qld& NSW	PNG	Nth Aust& T-L2	WA	Santos
Totalrevenue$million	507	383	264	383	504	2,112
Productioncost$/boe	8.84	5.55	4.04	13.95	5.94	7.97
Capex$million	141	79	4	148	134	535
EBITDAX$million	211	183	213	286	388	1,231
EBITDAXmargin	42%	48%	81%	75%	77%	58%

1Corporate segment not shown.

2Reduced equity in Bayu-Undan & DLNG from 68.4% to 43.4% from 30 April 2021.

Impact reflects the average FY20 AUD/USD FX rate, to allow comparison with 1H21 on a $/boe basis.

• • Cost reductions are occurring across our operated assets. Acquisition synergies are reflected in the Offshore Division in our Northern and Western Australian assets
• • This is partially offset by cost impacts related to managing the response to COVID-19 and foreign exchange impacts
• • Cooper Basin unit production cost increase compared to FY20 is due to foreign exchange impacts ($0.90/boe) 3and COVID-19 related costs of ~$1 million
• • Group EBITDAX margin remains strong at 58%

Capital expenditure

2021 guidance maintained at ~$900m for sustaining capex and ~$700m for major growth with spend expected to be weighted to the second half

1H21 capital expenditure $535 million1

• • Comprising $340m sustaining and $195m major growth, predominantly related to the Barossa project
• • 28 wells drilled in the Cooper Basin with a fourth rig added for the second half
• • 110 wells drilled across the GLNG acreage

1Capital expenditure incurred includes abandonment expenditure but excludes capitalised interest.

Capex by type

$million

Creating value from midstream infrastructure portfolio

Unique portfolio of strategic midstream infrastructure assets generating stable and material EBITDA of ~$400 million per annum, excluding GLNG which could add an extra ~$95 million

	MIDSTREAM INFRASTRUCTURE ASSETS					ADDITIONAL
	Moomba	Port Bonython	DLNG	Varanus Island	Devil Creek	OPPORTUNITIES
						GLNG synthetic toll based onthe recent TotalEnergiestransaction values Santos30% share at ~US$820mwith EBITDA of~US$95m2p.a
Annual capacity	Gas: 400 TJ/dStorage: 70 PJ	Liquids:20 mmboe	LNG: 3.7 mtpawith approvalsup to 10 mtpa	Gas: 390 TJ/d	Gas: 220 TJ/d	Futureopportunitiesinclude:Macedon (synthetic)
1H21 throughput(gross)	348 TJ/d	7.2 mmboe	1.6 mt	293 TJ/d	146 TJ/d	NarrabriMcArthur
Utilisation (%)	87	69	88	75	67	DLNG expansionCCS + hydrogen
Existing tollingstructure	Internal andexternal tolls	Internal andexternal tolls	Internal tolls	Internal tolls	Internal tolls	Cost savings of US$60mper annum by 2025 also
1H21 EBITDA	~$217 million1					identified to furtherimprove margins

1 This amount is already included in Santos financials as existing earnings and costs at asset level.

2 ~$95 million reflects Santos' 30% interest in GLNG on a 2021 annualised basis and assumes a processing toll that is like-for-like with the TotalEnergies and GIP transaction, effective as of 1 January 2021.

Debt and liquidity

Gearing reduced to 31.8% and balance sheet ready for growth with net debt $3.4 billion and liquidity of ~$4.5 billion

• Net debt $3,398 million (includes $417 million AASB 16 lease liabilities) as at 30 June 2021

• • Gearing 31.8% (including AASB 16)
• • Liquidity in place of:
  • • $2,417 million in cash
  • • $2,065 million in committed undrawn debt facilities
• • Investment grade credit rating
  • • S&P BBB- (stable)
  • • Fitch BBB (stable)
• • Flexibility to optimise the broader Santos asset portfolio through strategically aligned farm-outs and disposals

excludes derivatives $178 million.

Summary

Disciplined low-cost operating model ensures we can sustain our base business and remain resilient through the cycle

Disciplined approach

+Disciplined, low-cost operating model sets the framework to deliver value+Targeting 2021 free cash flow breakeven of less than $25 per barrel before hedging+2021 free cash flow sensitivity of ~$330 million per annum for every $10 above thebreakeven oil price. At current oil prices, 2021 forecast FCF is greater than $1.1 billionincluding hedging1+Sustainable dividend in accordance with our 10-30% FCF payout ratio

Strong free cash flow andliquidity

+Strong operational and cost focus delivered $572 million of free cash flow in first half+Strong balance sheet. Liquidity of over ~$4.5 billion, comprising $2.4 billion in cash and$2.1 billion in committed undrawn debt facilities+Strong cash flows reduced net debt, including leases, to $3.4 billion and gearing to31.8% at end June 2021. At current oil prices, gearing would be ~30% by year end+Investment grade credit rating

1 Assumes an average 2021 oil price of US$60 per barrel and 7.7 million barrels of oil hedged in the second half of 2021 at an average ceiling price of US$55 per barrel.

Asset Performance

Offshore conventional business

Santos supplies ~45% of Western Australia's domestic gas requirements and Northern Australia synergies are reducing upstream production costs

Strongcashmargin, lowcost operatingbusiness	+Western Australia EBITDAX marginimproved to 77%+WA unit production cost $5.94 per boe,down 42% since 2017
	+Northern Australia EBITDAX marginstrengthened to 75%
	+NA unit cost lowered ~30% to$13.95/boesince assuming operatorship
Near term,near-fieldgrowthopportunitiesutilisingexistinginfrastructure	+Bayu-Undaninfill drilling underway withsuccessful startupachieved from first well
	+Van Gogh infill drilling underway withsuccessful startupachieved from first well
	+FID taken on Spartan gas backfill to VI
	+FID taken on Pyrenees Ph IV Infill
	+Varanus Island compression to recoverlow pressure reserves startup4Q 21

Growing production and improving efficiency

Quadrant and ConocoPhillips acquisitions have transformed the scale of the Offshore business

Strong gas production

• • Domestic gas production and sales have been strong averaging 475 TJ/d in 1H21
• • Three well Van Gogh Phase 2 oil infill program underway and will deliver incremental production in 2021

1 Includes Quadrant Energy acquisition from 27 Nov 2018.

Lowered production costs Western Australia production1

• Production volumes increased and unit production costs reduced by 42% since 2017

Western Australia upstream production cost

Delivering acquisition synergies

• Since commencing operatorship, production costs have reduced by ~30% in the

application of Santos' disciplined operating model and acquisition synergies

first half of 2021 through the

Northern Australia upstream production cost

Bayu-Undan exceeding expectations

• • Continued strong reservoir and facility performance
• • Three well Bayu-Undan Phase 3C infill program underway and will deliver incremental production in 2021

1 Includes Bayu-Undan at 68.4% from 28 May 2020 to 30 April 2021 and 43.4% thereafter.

Northern Australia production1 mmboe

2021 Half-year results 32

High value infrastructure led development

Operated portfolio of infrastructure led gas supply and oil infill development at a low cost of supply, generating high value and delivering incremental production

	Bayu-Undan Phase3C	Van Gogh InfillPyrenees InfillVaranus IslandPhase2Phase 4Compression		SpartanDevelopment
Description	2 platform and 1subsea wellsdeveloping gas andliquids	3 dual lateral wells,infilling existing VanGogh development	1 dual lateral, andwater shut-offintervention	Low pressurereserves recoverymaintaining facilityplateau	New supply subseatieback to JohnBrookes
Startup	3Q 2021	4Q 2021	1Q 2023	4Q 2021	1Q 2023
STO working interest	43.4%	52.5%	29%	100%	100%
2P reserves (YE20)	23 mmboegrossnet110 mmboe	10 mmbblgross5 mmbblnet	10 mmbblgross2.9 mmbblnet	44 mmboegross andnet	15 mmboegross andnet
Total capex (gross)	US$235m	US$225m	US$110m	US$250m2	US$120m
Breakeven cost ofsupply	US$2.80/mmBtu	US$25/bbl	US$18/bbl	A$2.40/GJ	A$3.20/GJ

2021 Half-year results

1 Net working interest at 43.4% following completion of the 25% sell-down to SK E&S on 30 April 2021. 2Only US$36m remaining to be spent in 2021/22. 33

Integrated onshore business with market optionality

Onshore assets connected to domestic markets and long-term Asian demand for LNG with strong growth options

	+Growth self-funded within the low costdisciplined Operating Model
Australia's lowest costonshore operator	+Driving capital efficiency to unlock additionalresources	McArthur
	+COVID-19 and joint venture budget constraintsin 1H 2021 impacted activity levels
Cooper Basin highvalue swing producer	+Increased focus on oil development tocomplement stable gas production program+Using underbalanced drilling and enhancedstimulation technology to improvedeliverability	South NicholsonSurat & Bowen
GLNG	+Upstream production supports GLNG salesabove 6.2 mtpain 2021+Arcadia production exceeding expectation andnow lowest upstream unit cost field	CooperAmadeus
Narrabri Gas Project	+Appraisal on hold, pending an appeal againstthe NSW Independent Planning Commissionapproval. A hearing is scheduled for August2021	Narrabri
Northern Territory	+First of two horizontal wells commenced drillingin 2Q 2021

2021 Half-year results 34

Cooper Basin operating model

Increased activity levels in second half including an additional rig to drill oil wells

Wells drilled Targeting ~73 wells in 2021

Number per year % three-year rolling average mmboe

• • Well count is subject to well type and joint venture participation levels
• • Focus on increased activity levels including the recent addition of fourth rig in second half to drill oil wells

2P reserves replacement ratio Targeting >100% RRR

-118 -73 37 98 102 2016 2017 2018 2019 2020 2021F Reserves replacement target

• • Focus on area and play based development expected to result in larger, discrete reserves bookings
• • 2C resource to 2P appraisal well success rate on a three-year rolling average is ~69%

First half production volume

• Lower 1H 21 production primarily due to higher unplanned surface downtime and lower drilling activity due to impact of COVID on joint venture budgets

Strong GLNG upstream production and cost out

Record upstream GLNG production driven by strong ramp-up at Roma and Arcadia supporting higher than 6.2 mtpa LNG run-rate in 2021

Strong GLNG gas production

• • Record upstream production at 700TJ/d
• • Roma Field continuing to increase production, approaching 200TJ/d
• • Arcadia ramp-up, field and facilities debottlenecking delivering >90TJ/d combined with low well failure rate

-71%

Average days rig release to rig release

11.3

Roma Phase 1 (pre 2015)

6.3

Roma-2A (2015) 5.3

Roma-2B (2016) Roma-3A (2017)

3.6 3.3 3.3

Roma East (2018 -20)

Roma SD20 (1H21)

Driving down operating cost and increasing production

• • Implementation of new well design
• • Innovative operational tools to mitigate solids-related failures
• • Continuous improvement of technologies and processes

Maintaining well cost discipline

• • Relentless focus on lowering well cost
• • Expect to drill ~180 wells in 2021 (3 rigs) and ~350 wells in 2022 (4 rigs)

1 Drill, complete, connect.

Roma well cost - GLNG1 $million per well

Fit for purpose rigs, experienced crews

• • Fit for purpose rigs, experienced crews
• • High volume, sequential and repeatable scope
• • Technical limit focus

McArthur-Beetaloo and South Nicholson opportunities

Multi-Tcf shale gas potential in two basins with proven flow at Tanumbirini-1

Strategic Opportunities

• Options to satisfy north and east coast gas markets

McArthur-Beetaloo Project

• • Strong performance from Tanumbirini-1 flow test:
  • • 10 mmscf/d peak gas flow rate
  • • 1.5 mmscf/d average rate from first 9 days of testing
• • First of two horizontal wells, Tanumbirini 2H ST1, commenced drilling in 2Q21:
  • • Reached a TD at 4,598mMDRT with >1,000m of horizontal section drilled

South Nicholson Project

• • Analogous play to McArthur-Beetaloo Project
• • Multi-TCF gas potential
• • Play fairways and permits straddle QLD and NT border

Tanumbirini 2H ST1 update

Excellent gas shows while drilling. Well cased and suspended for testing in October

First of two horizontal wells, Tanumbirini 2H ST1, commenced drilling in 2Q21:

• • Reached a TD at 4,598mMDRT with >1,000m of lateral section in well developed Velkerri Formation "B Shale" reservoir
• • Excellent drill gas shows
• • Well cased and suspended for testing
• 2021 Half-year results 38 + Rig currently moving to rig up on Tanumbirini 3H location

Papua New Guinea

PNG LNG is a world-class, low-cost asset consistently delivering above nameplate production with future backfill options

Strongcashmargin, lowcost operatingasset withconsistentproductionperformance	+PNG EBITDAX margin improved from 78%for FY20 to 81% in 1H21+1H 2021 production cost $4.04/boe+Increased cash flow ~2026 once projectfinance repaid+1H21 annualised production of~8.2mtpa.Peak rates restoredfollowingplannedmaintenanceactivities	SE GOBE
ProgressingDevelopmentopportunities	+FID on AngoreDevelopment+Recommenced discussions with Papua LNGJV in July 2021
Future backfilloptions toextend PNGLNG plateau	+Hides F2P'nyang1++Muruk+Working with JV partners and PNGGovernment	1 Santos P'nyang (PRL 3) farm-in subject to the execution of a sale and purchase agreement and government approval.

2021 Half-year results

Strong free cash flow and low free cash flow breakeven oil price

Disciplined, low-cost operating model is delivering consistent results

Barossa FID and Dorado FEED entry achieved in first half

Infrastructure-led carbon capture and storage strategy

Proposed Oil Search merger to create a regional champion of size and scale

Appendix

Financial performance

EBITDAX up 24% to $1,231 million and underlying profit up 50% to $317 million

$million	1H21	1H20	Variance
Totalrevenue	2,112	1,728	22%
Productioncosts	(377)	(284)	33%
Other operating costs	(165)	(132)	25%
Third-party product purchases	(324)	(309)	5%
Other1	(15)	(8)	88%
EBITDAX	1,231	995	24%
Explorationand evaluation expense	(41)	(25)	64%
Depreciation and depletion	(614)	(486)	26%
Impairment losses	(8)	(756)	nm
Change in future restoration	20	5	300%
EBIT	588	(267)	320%
Net finance costs	(109)	(124)	(12%)
Profit/(loss)before tax	479	(391)	223%
Tax expense	(125)	102	223%
Profit/(loss) after tax	354	(289)	222%
Underlyingprofit	317	212	50%

1Other includes product stock movement, corporate expenses, other expenses, other income and share of profit of associates. 2021 Half-year results 42

• • Total revenue up 22% due to higher realised oil prices and higher sales volumes, offset by lower average lagged oillinked LNG prices
• • Average realised oil price up 45% to $69.57/bbl and average realised LNG price down 21% to $6.74/mmBtu
• • Lower unit production costs/boe. Absolute production costs higher due to ConocoPhillips acquisition
• • Higher depreciation, primarily due to a reserves revision in Western Australia gas at year end 2020
• • The $643 million increase in net profit is predominantly due to $526 million after tax impairments in 1H20 combined with higher oil prices and sales volumes in 1H21
• • Normalised effective tax rate 43% including royalty related taxes (excluding impacts of gain on disposal of 25% interests in Bayu-Undan and Darwin LNG and other one-off items)

Sales revenue

Record sales revenue reflecting improved oil prices and higher sales volumes, offset by lower average lagged oil-linked LNG prices

$million	1H21	1H20	Variance
Sales Revenue (incl. third-party)
Gas, ethane and liquefied gas	1,452	1,253	16%
Crude oil	312	274	14%
Condensate and naphtha	203	102	99%
Liquefied petroleum gas	73	39	87%
Total1	2,040	1,668	22%

1 Total product sales include third-party product sales of $429 million (1H20: $408 million)

• • Sales revenue up 22% to $2.0 billion
• • Average realised oil price up 45% to $69.6/bbl
• • Average realised LNG price down 21% to $6.7/mmBtu
• • Average realised east coast domestic gas price up 16% to $5.33/GJ
• • Average realised west coast domestic gas price up 40% to $4.31/GJ

Free cash flow

Calculation of 2021 half-year free cash flow

$million	1H21
Operatingcash flows	942
Deduct Investing cash flows	(334)
Add Net acquisitions and disposals	(169)
Add Major growthcapex	195
Deduct Lease liability payments	(62)
Free cash flow	572

Lease liability payments are now treated as financing cash flows under AASB 16. To ensure like-for-like comparisons with prior periods, the definition of free cash flow reflects operating cash flows less investing cash flows (net of acquisition and disposal payments and major growth capex) less lease liability payments.

Free cash flow is a non-IFRS measure that is presented to provide an understanding of the performance of Santos' operations. The non-IFRS information is unaudited however the numbers have been extracted from the financial statements which have been subject to review by the auditor.

Reconciliation of half-year net profit/(loss) to underlying profit

$million	1H21	1H20
Net profit/(loss)after tax	354	(289)
Add/(deduct)significant items after tax
Net gain on disposal of a group of assets	(51)	-
Impairmentlosses	6	526
Fair value losses/(gains) on commodity hedges	39	(27)
One-off acquisition and disposal costs	1	2
One-off PRRT credit	(32)	-
Underlying profit	317	212

Drawn debt maturity profile

No significant near-term debt maturities until 2024 and $452 million of debt repaid since 30 June 2021. $1 billion raised from recent US144A/Reg-S bond

Breakdown of drawn

Drawn debt maturity profile1

• Weighted average term to maturity ~5.3 years

Drawn debt maturity profile excluding PNG LNG project finance1

¹ As at 30 June 2021. Excludes leases and derivatives.

Liquidity and net debt as at 30 June 2021

Net debt $3.4 billion and liquidity of $4.5 billion

Liquidity($million)		30Jun 2021	31Dec 2020
Cash		2,417	1,319
Undrawn bilateral bank debt facilities		2,065	1,870
Total liquidity		4,482	3,189
Debt ($million)
Export credit agency supported loan facilities	Senior, unsecured	252	283
Bank term loan facilities	Senior, unsecured	1,242	1,441
US Private Placement	Senior, unsecured	246	252
144A and Reg-S bonds	Senior, unsecured	2,378	1,382
PNG LNG project finance	Non-recourse, secured	1,102	1,184
Leases	Leases	417	457
Other	Derivatives	178	(16)
Total debt		5,815	4,983
Total net debt		3,398	3,664

2021 guidance

2021 guidance maintained

2021 guidance item	Guidance
Production	87-91 mmboe
Sales volumes	100-105 mmboe
Capital expenditure –base	~$900 million
Capital expenditure –major growth	~$700 million
Upstream production costs	$7.90-8.30/boe
Depreciation, depletion and amortisation	$1.15-1.25 billion

2021 Half-year segment results summary

US$million	CooperBasin	Queensland& NSW	PNG	NorthernAustralia1	WesternAustralia	Corporateexplor'n &elimins	Total
Revenue	507	383	264	383	504	71	2,112
Production costs	(70)	(37)	(25)	(139)	(99)	(7)	(377)
Otheroperating costs	(48)	(57)	(21)	-	(2)	(37)	(165)
Third-party product purchases	(184)	(81)	(1)	-	-	(58)	(324)
Inter-segmentpurchases	-	(28)	-	-	-	28	-
Product stock movement	3	(9)	1	-	2	-	(3)
Other income	10	14	-	27	1	-	52
Other expenses	(7)	(2)	(5)	1	(18)	(20)	(51)
FX gains and losses	-	-	-	-	-	28	28
Fair value gains on hedges	-	-	-	-	-	(55)	(55)
Share of profit of associates1	-	-	-	14	-	-	14
EBITDAX	211	183	213	286	388	(50)	1,231

2021 Half-year results 1Decreased equity in Bayu-Undan and Darwin LNG at 43.4% from 30 April 2021. 49

2020 Half-year segment results summary

US$million	CooperBasin	Queensland& NSW	PNG	NorthernAustralia1	WesternAustralia	Corporateexplor'n &elimins	Total
Revenue	471	506	273	146	285	47	1,728
Production costs	(66)	(36)	(32)	(71)	(88)	9	(284)
Otheroperating costs	(27)	(39)	(19)	-	(2)	(45)	(132)
Third-party product purchases	(142)	(119)	-	-	-	(48)	(309)
Inter-segmentpurchases	-	(29)	-	-	-	29	-
Product stock movement	(40)	(8)	1	(1)	15	-	(33)
Other income	4	16	7	-	3	-	30
Other expenses	(6)	(1)	(6)	(16)	(12)	(6)	(47)
FX gains and losses	3	4	-	-	4	(26)	(15)
Fair value gains on hedges	-	-	-	-	-	39	39
Share of profit of associates1	-	-	-	18	-	-	18
EBITDAX	197	294	224	76	205	(1)	995

12021 Half-year results Increased equity in Bayu-Undan and Darwin LNG at 68.4% from 28 May 2020. 50

Open oil price positions as at 30 June 2021	2021	2022
Zero cost collars (barrels)	7,748,792	4,000,000
Average floor price ($/bbl)	42	50
Average ceiling price ($/bbl)	55	66
Re-participating 3-ways (barrels)		2,000,000
Average floor price ($/bbl)		50
Average ceiling price ($/bbl)		60
Average re-participation price ($/bbl)		65