SANTOS LIMITED — Earnings Release 2021

Feb 15, 2022

ASX / Media Release

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16 February 2022

Santos reports record free cash flow and underlying earnings, and higher final dividend

and higher final dividend
Full-year (US$million)	2021	2020	Change
Production (mmboe)	92.1	89.0	3%
Sales volume (mmboe)	104.2	107.1	-3%
Product sales revenue	4,713	3,387	39%
EBITDAX1	2,805	1,898	48%
Underlying profit1	946	287	230%
Net profit/(loss) after tax	658	(357)	284%
Free cash flow1	1,504	740	103%
Final dividend (UScps)	8.5	5.0	70%

Santos today announced its full-year results for 2021, reporting record free cash flow of US$1.5 billion and underlying profit of US$946 million. The results reflect significantly higher oil and LNG prices compared to the corresponding period due to the recovery in global energy demand combined with supply constraints across the industry due to lower capital investment through the pandemic, and three weeks contribution from the Oil Search assets.

The results also reflect Santos’ disciplined, low-cost operating model which delivered a free cash flow breakeven of US$21 per barrel in 2021.[2]

The reported net profit after tax of US$658 million includes losses on commodity hedging and costs associated with acquisitions and one-off tax adjustments, and is significantly higher than the corresponding period mainly due to impairments included in the previous year.

The Board has resolved to pay a final dividend of US8.5 cents per share, 70 per cent higher than the previous final dividend. The dividend equates to 20 per cent of full-year proforma free cash flow for the merged entity less dividends paid in the first half by both companies, in-line with Santos’ sustainable dividend policy which targets a range of 10 per cent to 30 per cent payout of free cash flow.

The final dividend is franked to 70 per cent and substantially distributes the company’s remaining franking credits to shareholders. Based on the company’s carry-forward tax losses, Santos does not expect to generate franking credits for the next several years.

Media enquiries Claire Hammond +61 (0) 401 591 488 claire.hammond@santos.com

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

Santos Limited ABN 80 007 550 923 GPO Box 2455, Adelaide SA 5001 T +61 8 8116 5000 F +61 8 8116 5131 www.santos.com

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Santos Managing Director and Chief Executive Officer Kevin Gallagher said Santos delivered record production, free cash flow and underlying earnings in 2021, as strong base business performance positioned the company to benefit from higher commodity prices.

“The highlight of the year was the completion of our merger with Oil Search. The merger delivers increased scale and capacity to drive our disciplined, low-cost operating model and unrivalled growth opportunities over the next decade – all with a vision of becoming a global leader in the energy transition,” Mr Gallagher said.

“The financial results we are announcing today include only three weeks of the merged company. Had the merger been in place for all of 2021, the combined asset portfolio would have generated more than US$2.3 billion in free cash flow for the year.

“We will now seek to further optimise the portfolio, reduce gearing and conduct a review of our capital management framework including returns to shareholders.

“2021 brought global energy security into the spotlight with higher prices and a supply crunch in the wake of rapidly recovering demand and a lack of investment in new supply.

“It is vitally important that investment in new supply occurs and in a sustainable way. At Santos, we are focussed on supplying critical fuels more sustainably to meet society’s demand.”

2022 Guidance

2022 production is expected to increase to a range of 100 to 110 million barrels of oil equivalent (mmboe) primarily due to higher production from PNG following the Oil Search merger. This is expected to be offset by a lower share of Bayu-Undan production, which is expected to be approximately 10 mmboe less than 2021, due to a lower average working interest following the 25 per cent sell-down to SK E&S in 2021, lower gross production as the field approaches end of field life and lower net entitlement under the Production Sharing Contract due to higher forecast LNG prices. Sales volumes in 2022 are expected to be in the range of 110 to 120 mmboe.

Sustaining capital expenditure is expected to be approximately US$900 million and restoration expenditure is expected to be approximately US$200 million. Sustaining and restoration expenditure is self-funded within the disciplined operating model and is included in the 2022 forecast free cash flow breakeven oil price of less than US$25 per barrel.

Major growth projects capital expenditure is expected to be in the range of US$1.15 billion to US$1.3 billion. A contingent amount of up to approximately US$400 million could be added should the Dorado and Pikka projects take final investment decisions. Guidance assumes current Santos interest in all projects.

At an average oil price of approximately US$65 per barrel in 2022, it is expected sufficient free cash flow would be generated to fund forecast major growth projects capital expenditure, including the contingent amount.[3]

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2022 Annual General Meeting

The 2022 Annual General Meeting will be held on Tuesday 3 May 2022. The closing date for receipt of nominations from persons wishing to be considered for election as director is Thursday 24 February 2022.

Live webcast

A video presentation on the 2021 full-year results is available on Santos’ website. A live question and answer webcast for analysts and investors will be held today at 11:30 AEDT.

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 and major growth capital expenditure, less lease liability payments) are non-IFRS measures that are presented to provide an understanding of the performance of Santos’ operations. Underlying profit excludes the impacts of costs associated with 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 audited financial statements. A reconciliation between net profit after tax and underlying profit is provided in the Appendix of the 2021 full-year results presentation released to ASX on 16 February 2022.

• 2 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. Excludes one-off restructuring and redundancy costs, cost associated with asset divestitures and acquisitions, major growth capital expenditure and lease liability payments.

• 3 Forecast free cash flow of approximately US$1.8 billion at an average oil price of US$65 per barrel based on sensitivity of approximately $450 million in free cash flow for each $10/bbl above forecast free cash flow breakeven of <$25/bbl in 2022. Excludes hedging. 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 capital expenditure and lease liability payments.

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~~2021 Full-year results~~

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16 February 2022

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Disclaimer and im ortant notice p

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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, carbon emissions reduction and associated technology risks, physical risks, legislative, fiscal and regulatory developments, economic and financial markets conditions in various countries, approvals, conduct of joint venture participants and contractual counterparties and cost estimates. The forward-looking information in this presentation is based on management’s current expectations and reflects judgements, assumptions, estimates and other information available as at the date of this document and/or the date of Santos’ planning processes. Except as required by applicable regulations or by law, Santos does not undertake any obligation to publicly update or review any forward looking statements, whether as a result of new information or future events. Forward looking statements speak only as of the date of this presentation or the date planning process assumptions were adopted, as relevant. Our strategies and targets will adapt given the dynamic conditions in which we operate; it should not be assumed that any particular strategies, targets or implementation measures are inflexible or frozen in time. No representation or warranty, express or implied, is given as to the accuracy, completeness or correctness, likelihood of achievement or reasonableness of any forward looking information contained in this presentation. Forward looking statements do not represent guarantees or predictions of future performance, and involve known and unknown risks, uncertainties and other factors, many of which are beyond Santos’ control, and which may cause actual results to differ materially from those expressed in the statements contained in this presentation.

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

Underlying profit, EBITDAX (earnings before interest, tax, depreciation, depletion, exploration, evaluation 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 audited financial statements. 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 2021. Santos prepares its petroleum reserves and contingent resources estimates in accordance with the 2018 Petroleum Resources Management System (PRMS) and CO2 Storage capacity and contingent resource estimates in accordance with the 2017 CO2 Storage Resources Management System (SRMS) sponsored by the Society of Petroleum Engineers (SPE). Unless otherwise stated, all references to petroleum reserves, contingent resources and CO2 Storage 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.

Cover image: Hela Province, Papua New Guinea

2021 Full-year results

2

Mer er has created a com an of size and scale g p y Well-placed to fund sustainable growth, energy transition and deliver increased returns to shareholders

Strong free cash generation

$2.3 billion proforma free cash flow for the merged group[1]

Diversified portfolio with increased interest in long-life, low-cost assets

Merger added 416 mmboe in 2P reserves

Unrivalled growth opportunities Strengthened balance sheet

Across LNG, low carbon liquids and CCS

Strong liquidity of $5.6 billion and gearing reduced to 27.5%

1 Includes reported for merged group and proforma Oil Search from 1 January 2021 to 10 December 2021.

2021 Full-year results

3

2021 Full- ear results y

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Record sales revenue, free cash flow and underlying profit

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FREE CASH FLOW [1] PROFIT AFTER TAX [2] UNDERLYING PROFIT [2]
112%
-60%
103% 284% 230%
$1,504 $658 $946
million million million
SALES REVENUE EBITDAX FINAL DIVIDEND
39% 48% 70%
$4,713 $2,805 8.5
million million US cents per share
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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, hedging and items that are subject to significant variability from one period to the next.

2021 Full-year results

4

Cash enerative base business throu h the c cle g g y

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Diversified, balanced portfolio that is well positioned to generate strong and sustainable free cash flows

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Free cash flow Oil price
$million US$/bbl
2016 – 21 free cash flow >$5.2 billion [1] FCF breakeven oil price (unhedged)
2,400 2,339 80
Average realised oil price
2,200
2,000
2021 free cash flow 835
1,800 60
breakeven before hedging [~$21 ][per barrel]
1,600
1,400
1,200 1,138 40
2021 free cash flow yield ~14 per cent [2] 1,000 1,006
800 740
618 1,504
600 20
2022 forecast free cash ~$450 million for every 400
206
flow sensitivity $10/bbl above FCF BOP [3] 200
0 0
2016 2017 2018 2019 2020 2021 incl.
1 Includes reported free cash flow of US$1,504 million for 2021. proforma
2 Based on 2021 full-year free cash flow and one-month volume weighted average share price for December 2021.
3 Free cash flow breakeven oil price (FCF BOP). Excludes hedging. 2021 reported including Oil Search from 11 December 2021
Proforma Oil Search from 1 January 2021 to 10 December 2021
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2021 Full-year results

5

Health safet and environment , y

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

Injury frequency rates

Number of injuries per million hours worked

Loss of containment

Number of Tier 1 and Tier 2 incidents

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1.2
1.0
0.8
0.6
0.4
0.2
0.0
2017 2018 2019 2020 2021
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15
10
5
0
2017 2018 2019 2020 2021
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Lost time injury frequency rate ≥ Moderate harm frequency rate

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Tier 1 Tier 2
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• • Disappointing safety performance in 2021 with injury frequency rates increasing due to 12 lost time injuries
• • Continued integrity management focus has delivered a substantial reduction in loss of containment incidents
• • COVID response has focused on protecting our workforce and maintaining production despite state and international border restrictions

2021 Full-year results

6

Diversified reserve and resource osition of 4.9 billion boe p

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Diversified portfolio with increased interest in long-life, low-cost assets

YE21 2C resources and 2P reserves

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mmboe
373
60 30
1,220
2C
3,219
2,282
2C resources
2020 Oil Search Barossa Discoveries Other Total
merger
46 92
373
416
1,676
933
2P reserves
2020 Oil Search Barossa Other 2021 production Total
merger
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• 4.9 billion boe 2P plus 2C:

• • 2P reserves increased by 835 mmboe before production
• • Oil Search merger added 416 mmboe
• • Barossa FID added 373 mmboe
• • Gas comprises 92% of 2P reserves
• • Three-year reserves replacement ratio 355%
• • 2C contingent resources increased 41% to 3,219 mmboe
• • Oil Search merger added 819 mmboe in PNG and 401 mmboe in Alaska
• • ~94% of 2P reserves are externally audited
• • 100 MtCO2 total storage resource booked in the Cooper Basin

2021 Full-year results

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Ener markets gy

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Investment in affordable, reliable and lower emissions energy required to ensure demand is met

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Global Liquids Supply/Demand [1] Oil price [1]
MMbbl/d US$/bbl
110 100
90
105
80
70
100
60
95 50
40
90
30
20
85
10
80 0
2018 2019 H1 2020 H2 2020 H1 2021 H2 2021 2022 2023
Dated Brent (RHS) Indicative OPEC Spare Capacity Global Demand Forecast
Global Demand Global Production
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Investment in new, lower emission oil and gas supply is required to ensure energy supply remains affordable and reliable during the energy transition

• • Oil demand is expected to reach pre-COVID levels in 2022
• • Significant underinvestment in upstream projects is shifting global markets to a state of undersupply
• • LNG demand is at record highs due to the role of natural gas as a reliable and lower carbon fuel
• • Underinvestment is driving significant price increases and limiting access to energy for those who can least afford it

1 Data sourced from IHS Markit

2021 Full-year results

8

Decarbonisation and carbon stora e g

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Santos’ three operated CCS hubs support the decarbonising of natural gas and enable the production of clean fuels including hydrogen and ammonia

Santos Three-Hub Strategy

Santos’ CCS projects offer a strategic competitive advantage enabling

• • Emission reductions for Santos’ liquids, pipeline gas and LNG products

• Northern Australia and Timor-Leste Hub + Bayu-Undan CCS + CO2 capacity: ~10 Mtpa

• • Hydrogen production from natural gas
• • CCS services to existing and new customers
• • Carbon removal services via direct air capture technology

1. Eastern Australia Hub

• • 100 MtCO2 total storage resource booked in the Cooper Basin

• • Moomba CCS Phase 1

  • • Carbon capture of 1.7 Mtpa (1.1 MtCO2pa Santos share)

• Eastern Australia Hub + Moomba CCS + CO2 capacity: ~20 Mtpa

• • Facilities construction to start in 3Q 2022 and four injector wells to be drilled into depleted gas reservoirs by year-end. First injection expected in 2024
• • Estimated Moomba CCS capacity ~20 MtCO2pa

• Western Australia Hub + Western Australia CCS + CO2 capacity: ~2 Mtpa

2. Northern Australia and Timor-Leste Hub

• • CCS services at DLNG enable development of regional resources and clean fuels production
• • Estimated Bayu-Undan CCS capacity ~10 MtCO2pa

3. Western Australia Hub

• • Desktop studies underway to confirm CO2 injection capacity
• • Estimated Western Australia CCS capacity >2 MtCO2pa, with expansion opportunities

CCUS technologies will play an important role in meeting net zero targets, including as one of few solutions to tackle emissions from heavy industry and to remove carbon from the atmosphere. (IEA, 2021)

2021 Full-year results

9

Our focus is to su l critical fuels more sustainabl pp y y

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Net-zero Scope 1 and 2 emissions target by 2040

Areas of focus	Category	Types of initiatives
		Improving efficiency across operated assets
Operational efficiency	Avoid and minimise	+ Comprises a portfolio of >25 projects planned for 2022 + Includes electrification, renewable integration, power and compression
		optimisation
		Infrastructure-led CCS strategy
		+ Moomba CCS Phase 1 project FID taken in 4Q 2021 with first injection
Carbon capture and storage	Reduce	expected in 2024 + Facilities construction to start in 3Q 2022 and four injector wells to be drilled
		into depleted gas reservoirs by year-end
		+ Investigating potential for CCS at Bayu-Undan, offshore WA and PNG
		Nature-based solutions
		+ Existing forest plantation in Queensland and savanna fire management project
		in the Northern Territory
Carbon reduction solutions	Reduce	+ Investigating potential for nature-based abatement opportunities across Australia and PNG
		New technology
		+ Direct air capture studies to be completed in 2022 investigating potential to
		utilise storage resource booked in the Cooper Basin

2021 Full-year results

10

Portfolio o timisation p

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Optimise portfolio to reduce gearing and conduct a review of the capital management framework including returns to shareholders

Optimise portfolio

Optimise balance sheet

Review capital management framework

Targeting $2-3 billion in asset sale proceeds

Aim for less than 25% gearing through the cycle including major growth

• Returns to shareholders + Reduced debt + Invest in growth + Invest in the energy transition

2021 Full-year results

11

Oil Search inte ration s ner ies g y g

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On track to deliver $90-115 million per annum of integration synergies

Oil Search integration synergies

$30 million initial synergies (run-rate) captured[1]

• • $90-115 million annual run-rate (pre-tax)[1] through:
• • Corporate: Board, ASX-listing costs, insurance, finance costs and overheads
• • Set up integration team using capability from previous acquisitions
• • Day 1 completed with no impact on safety or production
• • Initial synergies captured in corporate overheads
• • Operational Efficiencies: Eliminating duplication of activities, procurement, contracting and centralised operations
• • Review of organisational structure expected to be complete by mid-year
• • SAP Integration partner selected
• • Information Systems: Eliminating duplication of technology and systems
• • Currently reviewing operational and procurement opportunities

Integration synergies

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Guidance range
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$ million (pre-tax)
$90m $115m
Synergies captured
$30m
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1 Excluding integration and other one-off costs.

12

2021 Full-year results

1

2

6

2022 strate ic riorities g p

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3 4 5

Maximise free cash. Sensitivity ~$450m for every $10 above target FCF BE of <$25/bbl Deliver integration and merger synergies target of $90-115 million Optimise portfolio, target $2-3 billion in asset sale proceeds Review capital management framework Continue to execute Barossa LNG and Moomba CCS projects on budget and schedule Dorado Phase 1 and Pikka Phase 1 projects to be FID-ready by mid year

2021 Full-year results

13

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Finance and Capital Management Anthea McKinnell Chief Financial Officer

14

Financial disci line p

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Strong base business and disciplined approach to capital allocation

Strong, cash-generative base business

• • Generated $1.5 billion free cash flow in 2021 + Proforma[1] cash flow of merged group for 2021 was $2.3 billion facilitating final dividend of 8.5 cents per share, 70% franked

• Delivered 2021 free cash flow breakeven oil price of ~$21/bbl before hedging

• • Retained focus on disciplined capital management and operating model

Disciplined capital management

• • Group unit production costs down 3% despite COVID-19 impacts and unfavourable FX + Merged group scale and portfolio provides opportunity to optimise
• • Strong liquidity of $5.6 billion as at 31 December 2021

Balance sheet prepared to fund growth

• • Strong cash flows reduced gearing to 27.5 per cent at 31 December 2021
• • Stable investment grade credit ratings: S&P BBB-, Fitch BBB and Moody’s Baa3 + Optimisation of debt portfolio by cancellation of legacy non-PNG LNG Oil Search facilities

1 Includes reported for merged group and proforma Oil Search from 1 January to 10 December 2021.

2021 Full-year results

15

2021 Full- ear financial sna shot y p

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Strong base business delivered $1.5 billion of free cash flow and record underlying profit. Reported results include Oil Search from 11 December 2021

$ million	2021	2020	Change
Product sales revenue	4,713	3,387	39%
EBITDAX	2,805	1,898	48%
Underlying profit1	946	287	230%
Net profit/(loss) after tax	658	(357)	284%
Operating cash flow	2,272	1,476	54%
Free cash flow2	1,504	740	103%
Full-year dividend (UScps)	14.0	7.1	97%

• 1 For a reconciliation of 2021 full-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.

2021 Full-year results

16

Stron free cash flow eneration g g

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On a proforma basis, the merged company delivered more than $2.3 billion free cash flow

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Operating cash flow Investing cash flow [1] Free cash flow [1] Oil price
$ million $ million $ million US$/bbl
3,209 (908)
(870) 2,400 Average realised oil price 2,339 80
(102) 2,200
937 (736) 2,000
835
(634) (630) 1,800
2,046 (572) 1,600
1,400
1,578
1,476 1,200 1,138 40
1,006
1,248 (768) 1,000
2,272 800 740
840 618 1,504
600
400
206
200
0 0
2016 2017 2018 2019 2020 2021 2016 2017 2018 2019 2020 2021 2016 2017 2018 2019 2020 2021
incl. incl. incl.
proforma proforma proforma
2021 reported including Oil Search from 11 December 2021 Proforma Oil Search from 1 January 2021 to 10 December 2021
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1 Excludes acquisitions / divestments, major growth capex and lease liability payments.

2021 Full-year results

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Underl in earnin s y g g

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Record sales revenue, EBITDAX and underlying profit

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Product sales revenue EBITDAX Underlying profit [1]
$ million $ million $ million
Average realised
oil price
2,805 946
5,000 4,713 80
4,500 70 2,457
4,033
4,000 2,160 727 719
3,660 60
3,500 3,387 1,898
3,100
50
3,000
2,594 1,428
2,500 40
1,199
2,000 30 318
287
1,500
20
1,000
500 10 75
0 0
2016 2017 2018 2019 2020 2021 2016 2017 2018 2019 2020 2021 2016 2017 2018 2019 2020 2021
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1 Underlying profit excludes the impacts of asset acquisitions, disposals and impairments, and the impact of hedging.

2021 Full-year results

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Production and sales volumes

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Record production in 2021. 2022 guidance 100-110 mmboe and sales volumes 110-120 mmboe

Production volume

mmboe

Sales volume

mmboe

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+50% ~110-120
~100-110 120 107.1 104.2
89.0 92.1 100 94.5
84.1 83.4
75.5 78.3
80
61.6 59.5 58.9
60
40
20
0
2016 2017 2018 2019 2020 2021 2022F 2016 2017 2018 2019 2020 2021 2022F
Own product Third party
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Factors influencing 2022 production:

• • Higher production in PNG due to the merger
• • Bayu-Undan approaching end of field life. 2022 net entitlement production expected to be ~10 mmboe less than 2021 due to: + Lower average working interest following 25% sell-down to SK E&S in April 2021
• • Lower gross production due to natural field decline
• • Higher forecast average JKM prices result in higher revenue but lower net entitlement production under the Bayu-Undan PSC

2021 Full-year results

19

Production costs

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Lower unit costs in 2021 despite COVID-19 impacts and unfavourable FX impacts

Upstream unit production costs[1]

$/boe

• • Unit production costs reduced by 3% to $7.76/boe
• • Sustained cost improvement and operating efficiencies were offset by COVID-19 cost impacts and unfavourable FX rates
• • COVID-19 impact ~$0.20/boe
• • FX rate impact ~$0.45/boe
• • Factors influencing 2022 unit production costs:
• • Bayu-Undan production decline impacts average unit cost in 2022 by ~$1.20/boe
• • Higher unit cost PNG operated assets
• • 2022 upstream production cost guidance is $8.00$8.50/boe

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8.45 8.00-8.50
8.07 8.05 8.04
7.76
7.24
2016 2017 2018 2019 2020 2021 2022F
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1 Includes all planned shutdown activity and PNG earthquake recovery costs.

2021 Full-year results

20

U stream unit roduction costs p p

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

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Disciplined
Operating
Model
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• 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

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Total unit production cost Western Australia Northern Australia & Timor-Leste
$/boe production cost production cost
-3% $/boe $/boe
10.19 21.75
8.07 8.05 8.04 7.76 8.68 18.75 20.17 19.59
7.30 15.37
7.24 6.34 6.38
2017 2018 2019 2020 2021 2017 2018 2019 2020 2021
Cooper Basin Queensland & NSW
production cost production cost
$/boe $/boe
9.32 9.35 [1] 5.83 5.77 5.51 5.70 5.79
8.17 7.77 7.80
2017 2018 2019 2020 2021 2017 2018 2019 2020 2021 2017 2018 2019 2020 2021
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1 Cooper Basin unit production cost increase due to lower production, unfavourable AUD fx rates and cost impacts of managing the response to COVID-19.

21

2021 Full-year results

Cash enerative O eratin Model continues to drive value g p g

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Diversified portfolio of assets delivering strong margins. Increased exposure to PNG LNG following merger

2021 Full year results summary[1]

Cooper Basin Qld & NSW PNG2 Nth Aust & T-L3 WA Santos	Cooper Basin Qld & NSW PNG2 Nth Aust & T-L3 WA Santos	Cooper Basin Qld & NSW PNG2 Nth Aust & T-L3 WA Santos	Cooper Basin Qld & NSW PNG2 Nth Aust & T-L3 WA Santos	Cooper Basin Qld & NSW PNG2 Nth Aust & T-L3 WA Santos	Cooper Basin Qld & NSW PNG2 Nth Aust & T-L3 WA Santos	Cooper Basin Qld & NSW PNG2 Nth Aust & T-L3 WA Santos
Total revenue $million	1,000	973	736	903	1,105	4,837
Production cost $/boe	9.35	5.79	4.69	15.37	6.38	7.76
Capex $million	329	195	34	377	316	1,387
EBITDAX $million	423	525	615	728	851	2,805
EBITDAX margin	42%	54%	84%	81%	77%	58%

• • Group EBITDAX margin increased to 58% due to higher realised prices across all products
• • EBITDA includes ~$370 million for the Midstream assets (included in the asset results)
• • Average realised oil price up 60% to $76/bbl
• • Average realised LNG price up 45% to $9.25/mmBtu
• • Sustained cost improvement and operating efficiencies were offset by COVID-19 cost impacts and unfavourable FX rates

• 1 Corporate segment not shown.

• 2 Includes Oil Search assets from 11 December 2021.

• 3 Decreased equity in Bayu-Undan & DLNG at 43.4% from 30 April 2021.

2021 Full-year results

22

Ca ital ex enditure - Sustainin p p g

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Sustaining and restoration capex self-funded within the disciplined operating model and included in forecast free cash flow breakeven of <$25/bbl

• • Increased sustaining capex in 2022 primarily due to higher interest in PNG LNG and PNG operated assets

Sustaining capex

$million

• • Sustaining capex includes Cooper Basin and Queensland drilling, Western Australia, Northern Australia and PNG, corporate and exploration
• • Restoration capex primarily in WA (ME-FF, Harriet, Thevenard) and PNG
• • Sustaining and restoration capex self-funded within the disciplined operating model and included in forecast <$25/bbl free cash flow breakeven in 2022

2022 Western Australia Northern Australia and TL Cooper Basin PNG QLD & NSW Alaska Corporate & Exploration	2022 Western Australia Northern Australia and TL Cooper Basin PNG QLD & NSW Alaska Corporate & Exploration	2022 Western Australia Northern Australia and TL Cooper Basin PNG QLD & NSW Alaska Corporate & Exploration	2022 Western Australia Northern Australia and TL Cooper Basin PNG QLD & NSW Alaska Corporate & Exploration	2022 Western Australia Northern Australia and TL Cooper Basin PNG QLD & NSW Alaska Corporate & Exploration	2022 Western Australia Northern Australia and TL Cooper Basin PNG QLD & NSW Alaska Corporate & Exploration	2022 Western Australia Northern Australia and TL Cooper Basin PNG QLD & NSW Alaska Corporate & Exploration	2022 Western Australia Northern Australia and TL Cooper Basin PNG QLD & NSW Alaska Corporate & Exploration
Base business sustaining and restoration	Cooper B $308 ~$200m includes Apus & Pavo drilling	Qu asin m ~$30m	eensland & NSW ~$310m	~$220m	~$230m	~$40m	~$70m
$260m

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----- Start of picture text -----

976
~200
49
834
~200
748 55
37
927 ~900~900
779
711
2019 2020 2021 2022F
Restoration 2022F sustaining capex
Sustaining capex
----- End of picture text -----

2021 Full-year results

23

Ca ital ex enditure – Ma or Growth Pro ects p p j j

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2022 Major projects capex funded from free cash flow at an average oil price of $65/bbl

• • Major projects ~$1,150-$1,300 million assumes current equity interests in all projects
• • Unsanctioned projects contingent amount of up to ~$400 million for Dorado Phase 1 and Pikka Phase 1 (subject to FID)

Forecast 2022 free cash flow[1] and major projects capex

$million

• • Major projects funded from free cash flow. 2022 free cash flow sensitivity ~$450 million for every $10/bbl above forecast free cash flow breakeven of <$25/bbl
• • At an average Brent oil price of US$65/bbl in 2022, sufficient free cash flow expected to be generated (~$1.8 billion) to fund all committed and contingent major projects[1]

2022 Western Australia Northern Australia and TL Cooper Basin PNG QLD & NSW Alaska Corporate & Exploration	2022 Western Australia Northern Australia and TL Cooper Basin PNG QLD & NSW Alaska Corporate & Exploration	2022 Western Australia Northern Australia and TL Cooper Basin PNG QLD & NSW Alaska Corporate & Exploration	2022 Western Australia Northern Australia and TL Cooper Basin PNG QLD & NSW Alaska Corporate & Exploration	2022 Western Australia Northern Australia and TL Cooper Basin PNG QLD & NSW Alaska Corporate & Exploration	2022 Western Australia Northern Australia and TL Cooper Basin PNG QLD & NSW Alaska Corporate & Exploration	2022 Western Australia Northern Australia and TL Cooper Basin PNG QLD & NSW Alaska Corporate & Exploration	2022 Western Australia Northern Australia and TL Cooper Basin PNG QLD & NSW Alaska Corporate & Exploration
Major projects incl. contingent	Cooper B $308m ~$300m includes Dorado	Qu asin ~$650- $700m includes Barossa	eensland & NSW ~$50- $100m includes Moomba CCS	~$150- $200m includes Angore and Papua LNG	~$50m includes Narrabri appraisal	~$300m includes Pikka	~$50m includes Energy Solutions and Clean Fuels
Western Australia ~~$260m~~

• 1 Forecast free cash flow based on sensitivity of ~$450 million for each $10/bbl$270m above forecast free cash flow breakeven of <$25/bbl in 2022. Excludes hedging.

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----- Start of picture text -----

~400
~2,700
~2,250
~1,800
~1,150-
1,300
$65/bbl $75/bbl $85/bbl 2022F
Forecast free cash flow [1] Major growth
----- End of picture text -----

Major growth capex, including contingent

2021 Full-year results

24

Debt and li uidit at 31 December 2021 q y

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Gearing reduced to 27.5%. Net debt increased due to Oil Search merger

==> picture [261 x 262] intentionally omitted <==

----- Start of picture text -----

Net debt Gearing
$million %
5,500 40
5,157
5,000
4,749 35
4,500
30
4,000
3,664
3,492 3,549
3,500 3,325 25
3,000
2,731
20
2,500
2,000 15
1,500
10
1,000
5
500
0 0
2015 2016 2017 2018 2019 2020 2021
----- End of picture text -----

• • Gearing 27.5%
• • Net debt $5,157 million (includes $873 million AASB 16 lease liabilities)
• • Liquidity in place of $5,611 million:
• • $2,976 million in cash
• • $2,635 million in committed undrawn debt facilities
• • Synergies will be realised by optimisation of the debt portfolio
• • Three stable investment grade credit ratings support access to capital markets

==> picture [167 x 233] intentionally omitted <==

----- Start of picture text -----

Cash, debt and undrawn debt
facilities at 31 December 2021 [1]
$million
Cash
2,976
Drawn
debt
PNG LNG
(non-recourse)
(4,789)
Undrawn
debt
(3,260)
(2,635)
----- End of picture text -----

• 1 Drawn debt includes $873 million AASB 16 lease liabilities and excludes derivatives of $84 million.

AASB16 lease liability Gearing

2021 Full-year results

25

Summar y

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

• • Targeting free cash flow breakeven oil price <$25/bbl in 2022

Disciplined approach

• • Forecast free cash flow for 2022 post hedging is >$2 billion at $70/bbl oil price
• • 2022 free cash flow sensitivity of >$450 million for every $10 above the breakeven oil price, before hedging
• • Maintain cost focus through disciplined operating model

Portfolio optimisation and capital management

• • Disciplined, low-cost operating model sets the framework to deliver value
• • Deliver integration and merger synergies target of $90-105 million
• • Capital management framework to be reviewed with portfolio optimisation
• • Well positioned to fund growth and the energy transition

• Strong free cash flow and liquidity

• • Liquidity of over $5.6 billion comprising ~$3 billion cash and ~$2.6 billion in committed undrawn debt facilities
• • Gearing reduced to 27.5% at 31 December 2021. Net debt including leases of $5.2 billion

2021 Full-year results

26

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Growth Projects and Asset Performance

27

Barossa ro ressin on bud et and schedule p g g g

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Barossa project progressing as planned

Barossa development

• • Project 25 per cent complete and progressing on budget and schedule
• • FPSO hull, topsides, and turret all under construction in Korea, Singapore, and Indonesia respectively
• • Subsea hardware manufacture well advanced in Europe with first subsea tree shipped & fully tested in Perth
• • Preparations to start drilling in 3Q 2022 well advanced

Equity sell-downs

• • Binding agreement executed to sell a 12.5 per cent stake in Barossa to JERA in December 2021
• • Completion is expected in the first half 2022, with net proceeds of around ~US$300 million

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----- Start of picture text -----

Proposed Barossa development concept
----- End of picture text -----

Darwin LNG life extension project

• • Darwin LNG life extension project remains on schedule and budget

Proposed Bayu-Undan CCS

• • Progressing technical, commercial and regulatory engagement for proposed carbon capture and storage (CCS) project at Bayu-Undan
• • Preliminary civil works completed on site

2021 Full-year results

28

Moomba CCS rovides ste chan e in emission reduction p p g

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FID taken in November on one of the largest and lowest-cost CCS projects, with first injection expected in 2024

==> picture [336 x 247] intentionally omitted <==

----- Start of picture text -----

Existing CO2 separation units
New facilities:
compression &
dehydration
----- End of picture text -----

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

2021 milestones achieved

• • ACCU registration obtained and FID taken in November 2021
• • Key equipment orders placed for compressor, facilities equipment and pipeline
• • Booked 100 MtCO2 storage resource capacity

2022 key milestones

• • Facilities construction to start in 3Q 2022
• • Four injector wells expected to commence drilling in 4Q 2022

2021 Full-year results

29

PNG Growth

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Sequential development planned for Papua LNG and P’nyang

Papua LNG

• • Significant activity during 2021 in preparation for FEED-entry in 2022
• • Fiscal Stability Agreement executed in 2021
• • Retention Licence extended a further 5 years
• • Technical work underway focusing on facilities optimisation

P’nyang

• • Negotiations recommenced in July with a Heads of Agreement outlining key fiscal terms executed in September 2021
• • Next steps are a fully termed Gas Agreement expected to be executed in 2022
• • P’nyang development anticipated as back-fill to the PNG LNG foundation two trains with construction following Papua

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----- Start of picture text -----

P’nyang
----- End of picture text -----

2021 Full-year results

30

Dorado

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FEED continues targeting FID-ready mid-2022

Phase 1 liquids development

• • Estimated gross capital cost of ~$2 billion[1]
• • Low CO2 (~1.5%) and high-quality fluid expected to earn a premium to regional pricing benchmarks
• • Entered Stage 2 Assessment Phase of Offshore Project Proposal

• (OPP)

• • Production Licence assessment in progress

Phase 2 gas development

• • Integrated development concept established for both liquids and gas
• • Gas export is a potential source of supply for Santos’ existing WA domestic gas infrastructure
• • Flexibility retained for tieback of future exploration success
• • Drilling of exploration well Pavo has commenced, to be followed by Apus

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1 Subject to detailed FEED for build and own FPSO.

2021 Full-year results

31

For Internal Use only

Pikka Phase 1

==> picture [70 x 19] intentionally omitted <==

Targeting FID-ready by mid year. Low GHG intensity first phase of Pikka development

Phase 1 nearing completion of FEED activities and targeting FID-ready by mid year

Indicative production profile for Pikka Phase 1 kbbl/d

• • First step in developing world-class oil discovery located in prolific North Slope of Alaska
• • Project benefits from existing pipeline and other infrastructure
• • All major regulatory and environmental approvals have been received for FID
• • Phase 1 consists of ~80kbopd single drill-site development
• • Low breakeven cost of supply with significant expansion and backfill opportunity

100

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----- Start of picture text -----

Indicative production profile for Pikka Phase 1FPSO
Year 0 Year 5 Year 10
----- End of picture text -----

Phase 2 expansion options provide value upside

• • Phase 1 commercialises first of multiple potential drill-sites within Pikka Unit and adjacent proposed Quokka Unit (Mitquq discovery)
• • Expansion benefits from efficient and phased project execution and modular facilities

2021 Half-year results

32

Creatin value from midstream infrastructure ortfolio g p

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Unique portfolio of strategic midstream infrastructure assets generating stable and material EBITDA of ~$370 million per annum, excluding GLNG

	MIDSTREAM INFRASTRUCTURE ASSETS	MIDSTREAM INFRASTRUCTURE ASSETS	MIDSTREAM INFRASTRUCTURE ASSETS	MIDSTREAM INFRASTRUCTURE ASSETS	MIDSTREAM INFRASTRUCTURE ASSETS
	Moomba	Port Bonython	Darwin LNG	Varanus Island	Devil Creek
Annual capacity Gas: 400 TJ/d Storage: 70 PJ Liquids: 20 mmboe LNG: 3.7 mtpa with approvals up to 10 mtpa Gas: 390 TJ/d Gas: 220 TJ/d
2021 throughput (gross) 298 TJ/d 13.3 mmboe 3.1 mtpa 273 TJ/d 152 TJ/d
Utilisation (%) 75 63 80 70 69
Existing tolling structure Internal and external tolls Internal and external tolls Internal tolls Internal tolls Internal tolls
2021 EBITDA ~$370 million1

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

2021 Full-year results

33

Pa ua New Guinea roducin assets p p g

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Merger increased equity in Tier 1 PNG LNG project and added operatorship of PNG’s oil fields

PNG LNG

PNG Operated Assets

• • PNG LNG continues to perform consistently with 8.4 million tonnes of LNG and 110 cargoes loaded during 2021
• • PNG EBITDAX margin improved to 84% in 2021
• • 2021 unit production costs $4.69/boe[1]
• • Increased cash flow ~2026 once project finance repaid
• • Angore FID in 3Q21: next tranche of backfill gas to maintain PNG LNG production with first gas expected in 2024
• • Santos now operates all oil fields in Papua New Guinea
• • Strong performance from Agogo and Moran fields
• • A coiled tubing campaign commenced in 4Q21 on the Moran and Agogo fields to deliver incremental production in 2022

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• 1 Includes Santos operated assets from 11 December 2021.

2021 Full-year results

34

Offshore conventional business

==> picture [70 x 19] intentionally omitted <==

Bayu-Undan approaching end of field life in 2022-23 with Barossa as backfill for Darwin LNG from 1H 2025. Western Australia’s largest domestic gas supplier

Strong cash margin, low- cost operating business	+ Western Australia EBITDAX margin improved to 77% + WA unit production cost at $6.38 per boe
	+ Northern Australia & Timor-Leste EBITDAX margin strengthened to over 80% + NA & TL unit cost lowered ~30% to $15.4/boe since assuming operatorship
Near term, near-field growth opportunities utilising existing infrastructure	+ Successful infill wells programs at Bayu- Undan Phase 3C and Van Gogh Phase 2 delivered incremental production in 2021 + FID taken on Spartan gas backfill to VI + FID taken on Pyrenees Ph IV Infill + Varanus Island compression to recover low pressure reserves startup 4Q 21

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2021 Full-year results

35

Growin roduction and im rovin efficienc g p p g y

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Applying Santos’ disciplined low cost operating model has delivered significant cost reductions

==> picture [675 x 302] intentionally omitted <==

----- Start of picture text -----

Maintaining strong production Western Australia production [1] Stable unit production costs Western Australia upstream
mmboe production cost
+ Western Australia’s largest + Benefits of strong $/boe
domestic gas producer production volumes offset
33.7 10.19
30.9 31.1 by unfavourable FX rates
+ Increased oil production due to 8.68
three dual lateral wells from 7.30
6.34 6.38
the Phase 2 infill campaign
brought online in 4Q21 12.5
10.5
1 Includes Quadrant Energy acquisition from 27 Nov 2018. Includes Quadrant Energy acquisition from 27 Nov 2018.
2017 2018 2019 2020 2021 2017 2018 2019 2020 2021
Strong infill well performance Northern Australia and Timor- CoP ABU acquisition synergies Northern Australia and Timor-
Leste production [1] drive cost reductions Leste upstream production cost
+ Increased gas production from mmboe 15.2 $/boe -29%
Phase 3C infill program at 14.5 + Cost reductions reflect
21.75
Bayu-Undan acquisition synergies, partially 18.75 20.17 19.59
+ Bayu-Undan end of field life offset by the cost impacts of 15.37
managing COVID-19
expected in 2022-23
4.0 3.7
3.1
1 Includes ConocoPhillips ABW acquisition from 28 May 2020. Includes ConocoPhillips ABW acquisition from 28 May 2020.
2017 2018 2019 2020 2021 2017 2018 2019 2020 2021
----- End of picture text -----

1 Includes Quadrant Energy acquisition from 27 Nov 2018. Includes Quadrant Energy acquisition from 27 Nov 2018.

==> picture [326 x 116] intentionally omitted <==

----- Start of picture text -----

+ mmboe
15.2
Phase 3C infill program at 14.5
Bayu-Undan
+ Bayu-Undan end of field life
expected in 2022-23
4.0 3.7
3.1
1 Includes ConocoPhillips ABW acquisition from 28 May 2020. Includes ConocoPhillips ABW acquisition from 28 May 2020.
2017 2018 2019 2020 2021
----- End of picture text -----

~~2021 Full-year results~~

~~36~~

Inte rated onshore business with market o tionalit g p y

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

• • Growth self-funded within the low cost disciplined Operating Model

• Australia’s lowest cost + Driving capital efficiency to unlock additional onshore operator resources

• • COVID-19 and joint venture budget constraints in 1H 2021 impacted activity levels
• • Increased focus on oil development to

• Cooper Basin high complement stable gas production program value swing producer + Using underbalanced drilling and enhanced stimulation technology to improve deliverability

• • Upstream production supported GLNG sales of 6.4 million tonnes in 2021

• GLNG + First gas from the Arcadia Phase 2 project expected the second half of 2022

• Narrabri Gas Project + Appraisal planned to commence in 2022 + 300-day flow test underway for the two

• Northern Territory Tanumbirini horizontal wells

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----- Start of picture text -----

McArthur
South Nicholson
Surat & Bowen
Amadeus
Cooper Narrabri
----- End of picture text -----

2021 Full-year results

37

Coo er Basin p

==> picture [70 x 19] intentionally omitted <==

Operating model is delivering reserve replacement, cost discipline and self-funded growth

~~Lower production~~

~~Cooper Basin production~~

==> picture [28 x 7] intentionally omitted <==

----- Start of picture text -----

mmboe
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----- Start of picture text -----

+ Production impacted by lower
drilling activity, natural field 15.1 15.5 15.8 16.8 15.3
decline and higher downtime 14.4
+ Well type mix to maximise
deliverability in a variety of
plays
+ Continuous focus on cycle time
reduction
2016 2017 2018 2019 2020 2021
----- End of picture text -----

Wells drilled

Drilled 68 wells in 2021

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----- Start of picture text -----

Number per year 115
84 87
68
60
40
2016 2017 2018 2019 2020 2021
Prospective resource 2P undeveloped reserves
----- End of picture text -----

• • Well count is subject to well type and joint venture participation levels
• • 11 horizontal wells in 2021 with 10 wells online
• • ~100 wells planned in 2022

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----- Start of picture text -----

Targeting >100% 2P RRR Reserves replacement ratio (RRR)
% three year rolling average
+ Sustained 2P reserves
replacement ratio Reserves replacement target 98 102 99
+ Reduced number of appraisal
37
wells in 2021 resulting in
lower 2C to 2P conversion
2016 2017 2018 2019 2020 2021
+ Increased number of
appraisal wells planned in -73
2022
-118
Maintaining well cost Deep gas well cost [1]
discipline $million per well
4.30
+ Well costs reduced by
~40% since 2016 3.50 3.20
2.90
2.70 2.60
+ Unit development cost of
horizonal wells 25% better
than vertical offset wells
+ Vertical well costs continue
to decline
2016 2017 2018 2019 2020 2021
1 Vertical, deviated and horizontal gas development
----- End of picture text -----

• ~~1 Vertical, deviated and horizontal gas development~~ wells to >3km (drill, stimulate, complete).

• 2C contingent resource

2021 Full-year results

38

Stron GLNG u stream roduction and cost out g p p Record upstream GLNG production driven by strong ramp at Roma and Arcadia

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----- Start of picture text -----

Strong gas production GLNG sales gas production Driving down operating cost Mean time between failure
TJ/d (gross) by increasing production Years (Roma)
+ Strong upstream production at
690TJ/d 690 + Implementation of new well +720%
660
+ Roma Field continuing to 554 587 622 design 4.1
increase production, + Innovative operational tools to 3.1 3.6
approaching 200TJ/d mitigate solids-related failures
2.0
1.7
+ Arcadia ramp-up, field and + Continuous improvement of 1.4
0.9
facilities debottlenecking technologies and processes 0.5
delivering >90TJ/d
Dec-17 Dec-18 Dec-19 Dec-20 Dec-21 Jan-15 Jan-16 Jan-17 Jan-18 Jan-19 Jan-20 Jan-21 Jan-22
Fit for purpose rigs, Days - development drilling Maintaining well cost Roma well cost - GLNG [1]
experienced crews Average days rig release to rig release -71% discipline $million per well
-83%
+ High volume, sequential and 11.3 + Relentless focus on optimising 5.20
repeatable scope well cost
+ Technical limit focus 6.3 + Expect to drill ~350 wells 3.20
5.3
in 2022
+ Performance improvement has 3.6 3.3 3.3
1.60
offset impact of increase depth 0.90 0.85 0.84 0.84 0.90
for Roma SD20 wells
Roma Roma- Roma- Roma- Roma Roma
Phase 2A 2B 3A East SD20 1 Drill, complete, connect. Roma Roma- Roma- Roma- Roma Roma Roma Roma
2021 Full-year results 1 (pre 2015) (2015) (2016) (2017) (2018 -20) (2020 -21) 1 (pre Phase (2015)2A (2016)2B (2017)3A (2018)East (2019)East (2020)East (2021)East 39
2015)
----- End of picture text -----

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Appendix

40

Financial erformance p

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EBITDAX up 48% to $2,805 million. Underlying profit up 230% to $946 million

$million	2021 2020
Total revenue Production costs Other operating costs Third party product purchases Other1 Foreign exchange losses Fair value (losses)/gains on commodity hedges EBITDAX	4,837 3,512 (715) (716) (347) (274) (654) (612) (66) (44) (4) (13) (246) 45
	2,805 1,898
Exploration and evaluation expense	(126) (59)
Depreciation and depletion	(1,243) (1,015)
Impairment losses	(8) (895)
Change in future restoration	(6) (1)
EBIT	1,422 (72)
Net finance costs	(217) (234)
Profit/(loss) before tax	1,205 (306)
Tax expense	(547) (51)
Profit/(loss) after tax	658 (357)
Underlying profit	946 287

• • Total revenue up 38% due to higher realised prices across all products
• • Average realised oil price up 60% to $76/bbl and average realised LNG price up 45% to $9.25/mmBtu
• • Lower unit production costs/boe. Absolute production costs steady
• • Excluding the impacts of gain on disposal of Bayu-Undan and DLNG to SK and other one-off items, the effective tax rate is 39%

• 1 Other includes product stock movement, corporate expenses, other expenses, other income and share of profit of joint ventures. nm denotes not meaningful.

2021 Full-year results

41

Sales revenue

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Higher realised prices across all products

$million	2021 2020 Variance
Sales Revenue (incl. third party) Gas, ethane and liquefied gas Crude oil Condensate and naphtha Liquefied petroleum gas	3,464 2,505 38% 688 531 30% 428 256 67% 133 95 40%
Total1	4,713 3,387 39%

• 1 Total product sales include third-party product sales of $936 million (2020: $753 million)

• • Sales revenue up 39% to $4.7 billion

==> picture [323 x 145] intentionally omitted <==

----- Start of picture text -----

Average realised crude oil price Average realised LNG price
US$/bbl US$/mmBtu
+60% +45%
76.11 9.25
6.39
47.70
2020 2021 2020 2021
----- End of picture text -----

2021 Sales revenue by asset

==> picture [8 x 7] intentionally omitted <==

----- Start of picture text -----

%
----- End of picture text -----

• • Average realised oil price up 60% to $76.1/bbl
• • Average realised LNG price up 45% to $9.25/mmBtu

==> picture [119 x 120] intentionally omitted <==

----- Start of picture text -----

17% 19%
6%
19%
15%
23%
----- End of picture text -----

Northern Australia Corporate & Trading PNG Western Australia Queensland & NSW Cooper Basin

2021 Full-year results

42

Free cash flow

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Calculation of 2021 full-year free cash flow

$million 2021	$million 2021
Operating cash flows	2,272
Deduct Investing cash flows	(137)
Deduct Net acquisitions and disposals	(1,008)
Add Major growth capex	524
Deduct Lease liability payments	(147)
Free cash flow	1,504

Lease liability payments are 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 nonIFRS information is unaudited however the numbers have been extracted from the audited financial statements.

2021 Full-year results

43

Si nificant items g

==> picture [70 x 19] intentionally omitted <==

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

$million 2021 2020	$million 2021 2020	$million 2021 2020
Net profit/(loss) after tax	658	(357)
Add/(deduct) significant items after tax
Impairment losses	6	653
Net gains on asset sales	(44)	-
Fair value losses/(gains) on hedges	173	(30)
One-off acquisition and disposal costs	80	21
One-off tax adjustments	73	-
Underlying profit	946	287

2021 Full-year results

44

Drawn debt maturit rofile y p

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No significant near-term debt maturities until 2024, excluding PNG LNG project finance which is funded from project cash flows

Drawn debt maturity profile[1]

Breakdown of drawn Drawn debt maturity profile excluding PNG debt facilities[1] LNG project finance[1]

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$million % $million
1,500 1,500
1,189
Senior unsecured
1,010 1,000 51% 1,000
1,000 883 947 $3.7 bn 1,000
815 815
740 PNG LNG
600 project finance 620 600
(non-recourse) 500
500 45% 500
$3.3 bn
212
160
0 0
2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 Secured bank loans, 4% 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031
$0.3 bn
Bank term loans Reg-S/144A bond + Weighted average term Bank term loans Reg-S/144A bond
Long-term notes Secured bank loans to maturity ~4.3 years Long-term notes Secured bank loans
PNG LNG project finance
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¹ As at 31 December 2021. Excludes leases and derivatives.

2021 Full-year results

45

Li uidit and net debt as at 31 December 2021 q y

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Net debt $5,157 million. Liquidity of $5,611 million

Liquidity ($million)	Liquidity ($million)	31 Dec 2021	31 Dec 2020
Cash		2,976	1,319
Undrawn bilateral bank debt facilities		2,635	1,870
Total liquidity		5,611	3,189
Debt ($million)
Export credit agency supported loan facilities	Senior, unsecured	Nil	283
Bank Loans - unsecured	Senior, unsecured	1,043	1,441
Bank Loans - secured	Secured (legacy Oil Search)	255	Nil
US Private Placement	Senior, unsecured	238	252
Reg-S / 144A bonds	Senior, unsecured	2,380	1,382
PNG LNG project finance	Non-recourse, secured	3,260	1,184
Leases	Leases	873	457
Other	Derivatives	84	(16)
Total debt		8,133	4,983
Total net debt		5,157	3,664

2021 Full-year results

46

2022 uidance g

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2022 guidance item Guidance	2022 guidance item Guidance
Production (mmboe)	100-110 mmboe
Sales volumes (mmboe)	110-120 mmboe
Capital expenditure – base including restoration ($m)	~1,100 million
Capital expenditure – major projects ($m)	~1,150-1,300 million
Capital expenditure – contingent major projects, subject to FID ($m)	Up to ~400 million
Upstream production costs ($/boe)	8.00-8.50/boe

2021 Full-year results

47

2021 Full- ear se ment results summar y g y

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US$million Cooper Basin Queensland & NSW PNG Northern Australia & Timor-Leste Western Australia Corporate explor’n & elimins Total	US$million Cooper Basin Queensland & NSW PNG Northern Australia & Timor-Leste Western Australia Corporate explor’n & elimins Total	US$million Cooper Basin Queensland & NSW PNG Northern Australia & Timor-Leste Western Australia Corporate explor’n & elimins Total	US$million Cooper Basin Queensland & NSW PNG Northern Australia & Timor-Leste Western Australia Corporate explor’n & elimins Total	US$million Cooper Basin Queensland & NSW PNG Northern Australia & Timor-Leste Western Australia Corporate explor’n & elimins Total	US$million Cooper Basin Queensland & NSW PNG Northern Australia & Timor-Leste Western Australia Corporate explor’n & elimins Total	US$million Cooper Basin Queensland & NSW PNG Northern Australia & Timor-Leste Western Australia Corporate explor’n & elimins Total	US$million Cooper Basin Queensland & NSW PNG Northern Australia & Timor-Leste Western Australia Corporate explor’n & elimins Total
Revenue	1,000	973	736	903	1,105	120	4,837
Production costs	(143)	(79)	(67)	(234)	(215)	23	(715)
Other operating costs	(101)	(98)	(61)	-	(4)	(83)	(347)
Third party product purchases	(340)	(191)	-	-	-	(123)	(654)
Inter-segment purchases	(1)	(64)	-	-	-	65	-
Product stock movement	4	(33)	(16)	-	22	-	(23)
Other income	17	25	43	28	2	3	118
Other expenses	(13)	(8)	(21)	7	(59)	(92)	(186)
FX gains and losses	-	-	-	-	-	(3)	(3)
Fair value losses on commodity hedges	-	-	-	-	-	(247)	(247)
Share of profit of joint ventures	-	-	1	24	-	-	25
EBITDAX	423	525	615	728	851	(337)	2,805

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48

2020 Full- ear se ment results summar y g y

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US$million Cooper Basin Queensland & NSW PNG Northern Australia & Timor-Leste Western Australia Corporate explor’n & elimins Total	US$million Cooper Basin Queensland & NSW PNG Northern Australia & Timor-Leste Western Australia Corporate explor’n & elimins Total	US$million Cooper Basin Queensland & NSW PNG Northern Australia & Timor-Leste Western Australia Corporate explor’n & elimins Total	US$million Cooper Basin Queensland & NSW PNG Northern Australia & Timor-Leste Western Australia Corporate explor’n & elimins Total	US$million Cooper Basin Queensland & NSW PNG Northern Australia & Timor-Leste Western Australia Corporate explor’n & elimins Total	US$million Cooper Basin Queensland & NSW PNG Northern Australia & Timor-Leste Western Australia Corporate explor’n & elimins Total	US$million Cooper Basin Queensland & NSW PNG Northern Australia & Timor-Leste Western Australia Corporate explor’n & elimins Total	US$million Cooper Basin Queensland & NSW PNG Northern Australia & Timor-Leste Western Australia Corporate explor’n & elimins Total
Revenue	919	793	451	466	742	141	3,512
Production costs	(131)	(76)	(56)	(284)	(198)	29	(716)
Other operating costs	(60)	(78)	(41)	-	(4)	(91)	(274)
Third party product purchases	(303)	(173)	(1)	-	(1)	(134)	(612)
Inter-segment purchases	-	(69)	-	-	-	69	-
Product stock movement	(31)	-	(1)	(2)	8	-	(26)
Other income	10	33	13	2	3	4	65
Other expenses	(12)	(6)	(11)	(11)	(25)	(51)	(116)
FX gains and losses	(2)	4	-	1	21	(37)	(13)
Fair value losses on commodity hedges	-	-	-	-	-	45	45
Share of profit of joint ventures	-	-	-	33	-	-	33
EBITDAX	390	428	354	205	546	(25)	1,898

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49

Oil Search ac uisition accountin q g

Purchase price allocation

• • Under AASB 3 Business Combinations, all assets acquired and liabilities assumed in a business combination are recognised at acquisition date fair value, known as purchase price allocation (PPA).
• • Santos has provisionally recognised the fair values of the identifiable assets and liabilities of Oil Search based upon information available at reporting date as shown in Note 6.2 (a) to the 2021 Consolidated Financial Statements.
• • Goodwill on acquisition of $1,080 million has been recognised. The goodwill has arisen due to the net deferred tax liability of $1,080 million generated on acquisition.
• • Exploration and evaluation assets recognised of $2,050 million primarily relate to the Pikka project in Alaska, Papua LNG, P’nyang and the remaining acreage positions across PNG.
• • Oil and gas assets recognised of $6,549 million predominantly arises from the additional 29% interest acquired in PNG LNG.
• • Restoration provision of $800 million has been recognised based on the most recent information, assumptions and forecasts.
• • LNG sales contracts are fair valued on acquisition. This results in a contract assets of $318 million which will be amortised to the profit and loss over the period of the contract.

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Income statement

Year-ended 31 Dec 2021	Oil Search post- acquisition	Santos standalone	Consolidated
Production volume (mmboe)	1.7	90.4	92.1
Sales volume (mmboe)	1.5	102.7	104.2
Product sales ($million)	101	4,612	4,713
EBITDA ($million)	62	2,603	2,665

Balance sheet

$million As at 31 Dec 2021	Oil Search fair value post-PPA	Santos standalone	Consolidated1
Current assets	1,162	3,620	4,751
Non current assets1	11,131	20,259	25,258
Total assets1	12,293	23,879	30,009
Current liabilities	(1,158)	(1,884)	(3,011)
Non current liabilities	(5,083)	(8,399)	(13,388)
Total liabilities	(6,241)	(10,283)	(16,399)
Net assets1	6,052	13,596	13,610

• 1 Consolidated total shown is net of eliminations on consolidation, including purchase consideration of $6,038 million.

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50

Oil rice hed in and dividend frankin p g g g

Open oil price positions1	2022
Zero cost collars (barrels)	4,000,000
Average floor price ($/bbl)	50
Average ceiling price ($/bbl)	66.14
Three-way Participating (barrels)	2,000,000
Average floor price ($/bbl)	50
Average ceiling price ($/bbl)	60
Average re-participation price ($/bbl)	65.05

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Dividend franking

• • Dividend franking account balance as at 31 Dec 2021: US$94 million
• • 2021 final dividend will substantially deplete franking account balance and will be franked to 70%
• • Dividend will be designated Conduit Foreign Income (CFI) allowing it to be paid to non-resident shareholders free of withholding tax

• 1 As at 31 December 2021.

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51