SANTOS LIMITED — Annual Report 2020

Feb 17, 2021

18 February 2021

Santos reports record annual production and sales volumes, and strong free cash flow and underlying earnings despite impact of COVID-19 and lower commodity prices

Full-year (US$m)	2020	2019	Change
Product salesrevenue	3,387	4,033	-16%
EBITDAX1	1,898	2,457	-23%
Underlying profit1	287	719	-60%
Net(loss)/profit after tax	(357)	674	-153%
Free cash flow1	740	1,138	-35%
Final dividend (UScps)	5.0	5.0	-

Santos today announced its full-year results for 2020, reporting record annual production of 89 mmboe and sales volumes of 107 mmboe, free cash flow of US$740 million and underlying profit of US$287 million. The results reflect significantly lower oil and LNG prices compared to the previous year due to the impact of the COVID-19 pandemic on global energy demand.

The reported net loss after tax of US$357 million includes the previously announced impairments, primarily due to lower oil price assumptions.

The Board has resolved to pay a final dividend of US5.0 cents per share fully-franked, in-line with the previous year's final dividend. This brings full-year dividends to US7.1 cents per share fully-franked, representing 20% of free cash flow and in-line with the company's sustainable dividend policy which targets a range of 10% to 30% payout of free cash flow.

Santos Managing Director and Chief Executive Officer Kevin Gallagher said Santos delivered record annual production and sales volumes in 2020, and strong free cash flow of US$740 million despite significantly lower commodity prices.

"These results again demonstrate the resilience of our cash-generative base business in a lower oil price environment and strong operational performance across our diversified asset portfolio. The improvements in our base business in recent years were perfectly illustrated in 2020 with an average realised oil price of US$47 per barrel generating more than three times the free cash flow as generated in 2016 at a similar average oil price.

"2020 saw us ride through the bottom of the cycle while still generating free cash flow under a sustainable and disciplined operating model. As prices and demand recover, our projects are much better placed than those of our competitor countries. Living by our disciplined approach to

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

cost and capital allocation, and remaining cash flow positive through 2020 means we are well positioned for further efficiency gains and growth initiatives in 2021.

"Consistent application of our low-cost disciplined operating model continues to deliver cost reductions and efficiencies, with unit production costs down 10 per cent to US$6.50/boe (excluding the ConocoPhillips acquisition).

"At the onset of the COVID-19 in early 2020, Santos acted to protect its balance sheet, cash flows and the retention of permanent employees. As a precaution, Santos applied for and received A$4 million in JobKeeper payments from the Australian government up to September 2020. By November 2020, it was clear that the impact of COVID-19 on Santos would be less than expected, so Santos repaid this amount in full to the government during December 2020.

"In December 2020 we announced an ambitious roadmap to net-zero emissions by 2040, new emissions reduction targets and a commitment to work with our customers to reduce their emissions. Our Moomba carbon capture and storage project is FID-ready, subject to eligibility for Australian Carbon Credit Units.

"The Barossa LNG project remains on-track for a final investment decision in the first half of 2021. In December, we signed a long-term LNG offtake agreement with Mitsubishi for 1.5 million tonnes per annum of Santos equity LNG and executed agreements to transport and process Barossa gas through the Darwin LNG facilities. All required consents and approvals are now in place for our sell-down of 25% interests in Bayu-Undan and Darwin LNG to SK E&S, which is now binding and subject only to FID. We also continue to progress the binding sale and purchase agreement with JERA for the sale of a 12.5% interest in Barossa.

"We have made significant progress on our exciting Dorado project and aim to take a FEEDentry decision in the first half of 2021 while also advancing plans to drill the Apus and Pavo prospects in 2021-22.

"The Narrabri gas project received environmental approvals from the state and federal governments in 2020, and planning is now well underway for the two-year appraisal program commencing later this year. Narrabri has the potential to supply up to half of NSW's natural gas demand", Mr Gallagher said.

"Our strongly cash-generative base business and diversified portfolio means that we are well positioned to drive free cash flow as commodity prices recover," Mr Gallagher said.

Live webcast

A video presentation on the 2020 full-year results is available on Santos' website. A live question and answer webcast for analysts and investors will be held today at 11:30am 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 loss after tax and underlying profit is provided in the Appendix of the 2020 full-year results presentation released to ASX on 18 February 2021.

Santos 2020 Full-year results

18 February 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.

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 2020. 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.

Cover image: Port Bonython Processing Facility and 2MW Solar Project, South Australia

2020 Highlights

Our consistent and successful strategy combined with the disciplined, low-cost operating model continues to drive strong performance

Record production andsales volumes	Strong free cash flow and lowfree cash flow breakeven	FID on high value infrastructureled development
+Production up 18% to 89mmboe+Sales volumes up 13% up to107 mmboe	+Delivered $740m free cashflow+US$24/bblbefore hedging	+Bayu-UndanPhase 3C infill+Van Gogh Phase 2 infill
New emissions reduction targetsand transition roadmap	Major growth project milestonesachieved	Strong balance sheet

2020 Full-year results

Strong operational and cost performance delivered $740 million of free cash flow and $287 million underlying profit. Reported loss includes previously announced impairments

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 loss 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.

Record production volumes in 2020

Diversified and balanced portfolio of conventional and unconventional assets delivered record production of 89.0 mmboe, 18% above 2019

Cash generative base business through the cycle

Diversified and balanced portfolio supportive of strong, sustainable free cash flow through the oil price cycle

1 Includes hedging.

2 Based on 2020 full-year free cash flow and one-month volume weighted average share price for December 2020.

Safety and environment

Santos is committed to being the safest oil and gas operator in Australia and preventing harm to people and the environment

Injury frequency rates

Loss of containment incidents

Emission reductions targets and performance

Ahead of plan to reach 2025 emissions target. Released fourth-annual Climate Change Report

1 Baseline is defined as Santos' net share of Scope 1 and 2 emissions, in mtCO2e, from financial year 19/20 production volumes, adjusted to include Bayu-Undan and DLNG at 68.4% for full baseline year.

Roadmap to net zero

CCS and hydrogen are the pathway to net zero emissions by 2040

1 Baseline is defined as Santos' net share of Scope 1 and 2 emissions, in mtCO2e, from financial year 19/20 production volumes, adjusted to include Bayu-Undan and DLNG at 68.4% for full baseline year.

Planned activities

• • Nature-based offsets include the existing savanna burning program in Arnhem Land
• • Energy Solutions to deliver 0.6 mtCO2e pa emission reduction projects by 2025
• • Moomba CCS Phase 1 is FID-ready with first injection targeted for 2024
• • Cooper Basin electrification with hydrogen fuel and CCS decarbonises energy at the source
• • CCS expansion involves potential scale-up in the Cooper Basin or at other sites
• • Domestic and export opportunities for zero-emissions hydrogen enabled by CCS

Finance and Capital Management

Anthony Neilson Chief Financial Officer

Financial discipline

Strong base business and disciplined approach to capital allocation

Strong, cash-generative basebusiness with steady production	+Generated $740million free cash flow in 2020+Delivered 2020 free cash flow breakeven oil price of+~US$24/bblbefore hedging+~US$17/bblafter hedging+Targeting 2021 free cash flow breakeven oil price of <$25 per barrel before hedging+2021 free cash flow sensitivity of ~$330 million per annum for every $10 above thebreakeven oil price1. At current oil prices, 2021 forecast FCF ~$1.1 billion inclhedging2
Disciplined capital allocation	+Rigorous process to allocate capital across the portfolio+Growth projects will be phased and equity levels reviewed, consistent with disciplinedcapital management and the operating model
Balance sheet prepared to fundgrowth	+No significant debt maturities until 2024+Flexibility to optimise the portfolio through strategically aligned farm-outs and disposals

1Assumes sell-down of 25% interest in Bayu-Undan to SK E&S in 1H 2021. Before hedging.

2 Assumes an average 2021 oil price of US$60 per barrel and 15 million barrels of oil hedged at an average ceiling price of US$55 per barrel.

2020 Full-year financial snapshot

Strong operational and cost performance delivered $740 million of free cash flow. Underlying profit lower due to lower realised commodity prices in 2020

$ million	2020	2019	Change
Productsales revenue	3,387	4,033	(16%)
EBITDAX	1,898	2,457	(23%)
Underlyingprofit1	287	719	(60%)
Net (loss)/profit aftertax	(357)	674	(153%)
Operating cash flow	1,476	2,046	(28%)
Free cash flow2	740	1,138	(35%)
Full-year dividend(UScps)	7.1	11.0	(35%)

1 For a reconciliation of 2020 Full-year net loss 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 similar average oil prices to 2016, free cash flow in 2020 is over $0.5 billion stronger

Underlying earnings

Underlying profit is 280% stronger than 2016 at similar average oil prices

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

Record production and sales volumes

Strong production growth with volumes increasing by >40% since 2016. 2021 guidance unchanged

• Production volumes were 18% higher than the previous year primarily due to the higher Santos interest in Bayu-Undan following completion in May 2020 of the acquisition of ConocoPhillips' assets in northern Australia and Timor-Leste, combined with stronger gas production in Western Australia, Queensland and the Cooper Basin.

• Sales volumes were 13% higher than the previous year primarily due to the higher Santos interest in Bayu-Undan combined with stronger gas production in Western Australia, Queensland and the Cooper Basin.

184-91 mmboe range assumes sell-down of 25% interest in Bayu-Undan to SK E&S in 1H 2021. 198-105 mmboe range assumes sell-down of 25% interest in Bayu-Undan to SK E&S in 1H 2021.

Production costs

10% reduction in upstream unit production costs (excluding ConocoPhillips acquisition) as cost reduction initiatives announced in Q1 2020 flowed through to the bottom line

Upstream unit production costs1 $/boe

• • Sustained cost improvement and operating efficiencies
  • • $90-105 million pre-tax synergies have been delivered in the Offshore operating division following completion of the ConocoPhillips northern Australia asset acquisition in May 2020
  • • Underlying cost reductions were realised for the Onshore operating division, partially offset by one-off, COVID-related cost impacts to keep our business operating safely, and a stronger AUD/USD exchange rate
  • • Foreign exchange headwinds are likely to be a challenge for 2021
• • 2021 upstream production cost guidance is $8.00-$8.50/boe2

2 2021 cost guidance reflects a full-year average and assumes sell-down of 25% interest in Bayu-Undan to SK E&S in 1H 2021, where 1H 2021 production costs are expected to be higher than 2H 2021.

1Includes all planned shutdown activity and PNG earthquake recovery costs.

Increased equity in Bayu-Undan & DLNG at 68.4% since 28 May 2020

Our Operating Model in action

Santos' disciplined operating model continues to drive costs lower, with 2020 upstream unit production costs of US$8.04/boe at the lower end of the US$8.00-8.50/boe guidance range

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

8.07 6.50 6.50 1.54 8.04 2020 excl. CoP 2017 2018 2019 2020 incl. CoP 7.24 8.05 -19% $/boe

Total unit production cost1

Northern Australia production cost $/boe -10%

2020 Full-year results

1 2020 $6.50/boe excluding CoP acquisition and $8.04/boe including CoP acquisition.

Cash generative Operating Model continues to drive value

Diversified portfolio of core assets delivering strong margins despite lower prices

2020 Full year results summary1

	CooperBasin	Qld& NSW	PNG	Nth Aust& T-L2	WA	Santos
Totalrevenue$million	919	793	451	466	742	3,512
Productioncost$/boe	7.80	5.70	4.21	19.59	6.34	8.04
Capex$million	313	193	39	93	171	858
EBITDAX$million	390	428	354	205	546	1,898
EBITDAXmargin	42%	54%	78%	44%	74%	54%

• • Cost reductions are occurring across our operated assets, which is reflected in the group upstream unit production cost for Santos' base business. This is partially offset by one-off cost impacts related to managing the response to COVID-19 and foreign exchange impacts
• • Group EBITDAX margin remained strong at >50% despite significantly lower oil and LNG prices in 2020

1Corporate segment not shown.

2Increased equity in Bayu-Undan & DLNG at 68.4% from 28 May 2020.

Capital expenditure

At similar sustaining capex for the onshore business as 2016, delivered more than three times the number of wells and higher production

2020 capital expenditure $858 million1

• • Comprising $748m sustaining and $110m major growth, predominantly related to the Barossa project
• • 87 wells drilled in the Cooper Basin
• • 302 wells drilled across the GLNG acreage

Western Australia $270m Queensland & NSW Cooper Basin $308m 49 93 193 313 39 171 Corporate & Exploration PNG Northern Australia and Timor-Leste Queensland & NSW Cooper Basin Western Australia $million Capex by segment

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

Debt and liquidity

Net debt $3,664 million. Liquidity of over $3 billion

• • Net debt $3,664 million (includes $457 million AASB 16 lease liabilities) as at 31 December 2020
• • Gearing 33.6% (including AASB 16 and impairment)
• • Oil price hedging provides protection to downside with 15 mmbbl hedged in 2021
• • Liquidity in place of:
  • • $1,319 million in cash
  • • $1,870 million in committed undrawn debt facilities
• • Flexibility to optimise the broader Santos asset portfolio through strategically aligned farm-outs and disposals

Cash, debt and undrawn debt facilities at 31 December 20201 $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 drive value+Delivered 2020 free cash flow breakeven oil price of ~US$24 per barrel (beforehedging) and ~US$17 per barrel (after hedging)+Maintaining cost control and targeting FCF breakeven oil price lower than <$25/ bblin2021+Sustainable dividend in accordance with our 10-30% FCF payout ratio+Optimise portfolio through strategically aligned acquisitions, farm-outs and disposals
Strong free cash flow andliquidity	+Strong operational and cost performance delivered $740 million of free cash flow+Strong balance sheet. Liquidity of over $3 billion, comprising $1.3 billion in cash and$1.9 billion in committed undrawn debt facilities

Growth Projects and Asset Performance

Kevin Gallagher Managing Director and CEO

Disciplined growth

Major growth projects all Santos-operated. Barossa on track for 1H 2021 FID

	Barossa	Moomba CarbonCapture and Storage	Narrabri Gas ProjectPhase 1	DoradoPhase 1
Milestones	Long term LNG offtakeagreement executedTransportation andprocessing agreementssigned with DLNG	FID-ready, subject toeligibility for AustralianCarbon Credit Units	Commence appraisal drillingin 2H 2021	FEED-entry planned for1H 2021Drill liquids tie-backs (Apusand Pavo) in 2021/22
Target startup	1H 2025	2024	Phase 1 in 1H 2025	Liquids phase end 2025
Santos working interest	62.5%1	100%	80%	80%
2C resource	800 mmboe gross500 mmboe net1	na	1,310 PJ gross21,048 PJ net	150 mmbbl gross120 mmbbl net
Total capex (gross)	$3.6 billion	$125-155 million	~$650 million	~$2 billion

2020 Full-year results 1 Reflects current working interest in the Barossa project. Santos has signed a LOI to sell a 12.5% interest in Barossa to JERA. 2 Reflects total Narrabri gas resource. Phase 1 development targets ~500 PJ gross 2C. 23

Barossa and Darwin LNG life extension

On track for FID in 1H 2021. Targeting cash cost of production of ~$2.00/mmBtu

Barossa development FID-ready

• • Long term LNG offtake agreement signed with DGI, a whollyowned subsidiary of Mitsubishi
• • Capex estimated at ~$3.6 billion gross FID to first gas, assuming a leased FPSO with upfront pre-payment and option to buy-out
• • Targeting cash cost of production post start-up, including lease cost of ~$2.00/mmBtu

Sell-downs

• • Obtained all consents for 25% equity sell-down in DLNG and Bayu-Undan to SK E&S. Binding agreement now subject only to FID
• • Finalising 12.5% Barossa equity sell-down to JERA

Darwin LNG Life Extension Project

• • DLNG and Barossa have approved and executed all agreements to transport and process Barossa gas
• • Darwin Life Extension project ready to execute, subject to Barossa FID

Offshore conventional business

Santos supplies ~45% of Western Australia's domestic gas requirements

Strongcashmargin, lowcost operatingbusiness	+WA EBITDAX margin maintained at 74%highlighting benefit of fixed price domesticgas contracts+WA unit production cost $6.34 per boe,down 38% since 2017
Portfolio ofhigh qualityinfill projects	+Located near existing infrastructure+Lower-cost brownfield projects with shortpayback periods
Near term,near-field	+Bayu-Undaninfill FID announced inJanuary 2021+Van Gogh Phase 2 to commence in 2H21
growthopportunitiesutilisingexisting	+FID taken on Spartan gas backfill toVaranus Island
infrastructure	+Varanus Island compression to recoverlow pressure reserves

Growing production and improving efficiency

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

Strong gas production

• • Western Australia's largest domestic gas producer
• • Domestic gas production and sales increased to over 500 TJ/d during 2H 2020

Western Australia production1 mmboe

Includes Quadrant Energy acquisition from 27 Nov 2018.

ConocoPhillips acquisition

• On 28 May 2020, Santos' interest in Bayu-Undan increased to 68.4%

1 Includes ConocoPhillips acquisition from 28 May 2020.

ConocoPhillips acquisition + Unit production costs reduced by 38% since 2017 production cost $/boe 10.19 8.68 7.30 6.34 2017 2018 2019 2020 -38% production cost

• Since assuming operatorship production costs have been reduced in 2020 through the application of Santos' disciplined operating model and acquisition synergies

Lowered production costs

Northern Australia upstream

Western Australia upstream

Backfill opportunities for Varanus Island and Devil Creek

High-return, near-field development opportunities close to existing infrastructure

Integrated onshore business with market optionality

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

Australia's lowest costonshore operator	+Growth self-funded within the low costdisciplined Operating Model+Driving capital efficiency to unlock additionalresources
Cooper Basin highvalue swing producer	+Exploration success opens new plays and drivesproduction to16.8 mmboe in 2020+Technology enhancing deliverability+Australian record for highest production ratefrom an onshore stimulated horizontal gas well	McArthurSouth Nicholson
GLNG	+GLNG sales ~6.2 mtpa from 2021onwards+Arcadia production exceeding expectation andnow lowest upstream unit cost field	Surat & Bowen
Preparing for Narrabriappraisal	+Workover program completedand FEEDcommenced+Preparing for appraisal program in 2021	AmadeusCooperNarrabri
Northern Territory	+Two horizontal wells planned to commencedrilling in 2Q 2021+Increased acreage position in South Nicholson

Cooper Basin

Operating model is delivering higher production, cost discipline and self-funded growth

Strong gas production

• • Expect to maintain annual production around current levels
• • Horizontal wells efficiency delivers more for less

Cooper Basin production mmboe

Targeting ~73 wells in 2021

• • Well count is subject to well type and joint venture participation levels
• • 5 pilot horizontal wells in 2020 with 3 wells online and 9 planned for 2021
• • Production maintained due to expected higher equity levels in wells

Wells drilled

Targeting >100% 2P RRR

• • Strong SW Qld NFE results
• • Field development by area and play expected to result in larger, discrete reserves bookings
• • 2C resource to 2P conversion on a three year rolling average is 69%

Reserves replacement ratio (RRR) % three year rolling average

Maintaining well cost discipline

• • Well costs reduced by ~40% since 2016
• • Unit development cost of horizonal wells 25% better than vertical offset wells
• • Vertical well costs continue to decline

wells (drill, stimulate, complete).

Well cost1 $million per well

2020 Full-year results

29

Strong GLNG upstream production and cost out

Record upstream GLNG production driven by strong ramp at Roma and Arcadia supporting ~6.2 mtpa LNG run-rate from 2021. Maintaining cost discipline and improving performance

Strong gas production

• • Record upstream gas production
• • Strong Roma ramp-up
• • Arcadia production increased to ~60 TJ/d in February 2021 and on track to be lowest unit cost of production GLNG field

GLNG sales gas production TJ/d (gross)

Driving down operating cost by increasing production

• • Implementation of new well design
• • Continuous improvement of technologies and processes

Fit for purpose rigs, experienced crews

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

2020 Full-year results

Days - development drilling

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

Creating midstream infrastructure value and optionality

Established Midstream Infrastructure business to realise cost-out and operating efficiency benefits. Business generates stable and material EBITDA of ~$400 million per annum1

	Phase 1: 2019 -2020	Phase 2: 2021+
	Operate processing facilities asMidstream assets	Apply learnings to other assets to embedMidstream mindset	Provides structuraloptionality
Priorities	+Reduce processing costs and increaseutilisation in the Cooper Basin+Provide internal earnings visibility	+Apply cost reduction learnings from Phase 1to DLNG, Varanus Island and Devil Creek+Increase returns across business+Scalable business with future opportunities	+Business operational,commercial and legalstructure
Keyprograms	+Deliver operational improvement initiativesin the Cooper Basin+Develop organisational structure, corecompetencies and internal financialreporting+Established term capacity tollingagreements	+Deliver operational improvement initiativesacross broader asset suite+Run assets separately+Deliver increasing contract term over time	+Future funding andownership level flexibilityacross assets+Maintain operatorship andcontrol

1 This amount is already included in Santos financials as existing earnings and costs at asset level and reflects proforma 2020 full-year earnings.

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
• • Rig contracted to commence drilling of two horizontal wells in 2Q 2021

South Nicholson Project

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

Papua New Guinea

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

Strongcashmargin, lowcost operatingasset	+PNG EBITDAX margin maintained at 78%in 2020+Production cost $4.21/boe+Increased cash flow ~2026 once project
	finance repaid
ConsistentabovenameplateLNGproductionsince start-up	+Record production since project start-upwas achieved in 2020 with 8.8 milliontonnes of LNG produced+115 cargoes loaded during 2020
	+Hides F2
Future backfill	+P'nyang1
options toextend PNG	+Muruk
LNG plateau	+Working with JV partners and PNGGovernment

1Santos P'nyang (PRL 3) farm-in subject to the execution of a sale and purchase agreement and government approval.

Strong financial results in 2020

Disciplined, low-cost operating model is delivering consistent results

Cash generative base business

Disciplined and phased growth: targeting Barossa and Moomba CCS FID in 2021

Strong balance sheet supportive of phased growth

Appendix

EBITDAX down 23% to $1,898 million. Underlying profit down 60% to $287 million

$million	2020	2019	Variance
Totalrevenue	3,512	4,186	(16%)
Productioncosts	(716)	(546)	31%
Other operating costs	(274)	(306)	(10%)
Third party product purchases	(612)	(885)	(31%)
Other1	(44)	25	nm
Foreign exchange losses	(13)	(11)	nm
Fair value gains/(losses) on commodity hedges	45	(6)	nm
EBITDAX	1,898	2,457	(23%)
Explorationand evaluation expense	(59)	(103)	(43%)
Depreciation and depletion	(1,015)	(1,000)	2%
Impairment losses	(895)	(61)	nm
Change in future restoration	(1)	2	nm
EBIT	(72)	1,295	nm
Net finance costs	(234)	(277)	(16%)
(Loss)/profitbefore tax	(306)	1,018	(130%)
Tax (expense)	(51)	(344)	(85%)
(Loss)/profit after tax	(357)	674	(153%)
Underlyingprofit	287	719	(60%)

2020 Full-year results

• • Total revenue down 16% due to lower realised prices
• • Average realised oil price down 34% to $47.70/bbl and average realised LNG price down 35% to $6.39/mmBtu
• • Lower unit production costs/boe. Absolute production costs higher due to ConocoPhillips acquisition
• • Net impairment loss of $895 million (before tax) mainly relates to revised oil price assumptions resulting from the effects of the COVID-19 pandemic on energy market demand fundamentals and a reserves revision in Western Australia gas
• • Normalised effective tax rate 44% including PRRT, after adjusting for impairment and other significant items. Effective tax rate is higher than 2020 due to higher PRRT in WA

Sales revenue

Fixed-price domestic gas contracts shield sales revenues from impact of lower oil prices

$million	2020	2019	Variance
Sales Revenue (incl. third party)
Gas, ethane and liquefied gas	2,505	2,687	(7%)
Crude oil	531	927	(43%)
Condensate and naphtha	256	335	(24%)
Liquefied petroleum gas	95	84	13%
Total1	3,387	4,033	(16%)

1 Total product sales include third-party product sales of $753 million (2019: $1,022 million)

• • Sales revenue down 16% to $3.4 billion
• • Average realised oil price down 34% to $47.7/bbl
• • Average realised LNG price down 35% to $6.39/mmBtu

Average realised crude oil price Average realised LNG price

Free cash flow

Calculation of 2020 full-year free cash flow

$million	2020
Operatingcash flows	1,476
Deduct Investing cash flows	(1,461)
Add Net acquisitions and disposals	734
Add Major growthcapex	110
Deduct Lease liability payments	(119)
Free cash flow	740

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 audited financial statements.

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

$million	2020	2019
Net (loss)/profitafter tax	(357)	674
Add/(deduct)significant items after tax
Impairmentlosses	653	46
Net gains on asset sales	-	(8)
Fair value (gains)/losses on hedges	(30)	7
One-off acquisition and disposal costs	21	-
Underlying profit	287	719

Drawn debt maturity profile

No significant near-term debt maturities until 2024

Drawn debt maturity profile1

• Weighted average term

Drawn debt maturity profile excluding PNG LNG project finance1

¹ As at 31 December 2020. Excludes leases and derivatives.

Liquidity and net debt as at 31 December 2020

Net debt $3,664 million. Liquidity of over $3.1 billion

Liquidity($million)		31Dec 2020	31Dec 2019
Cash
Undrawn bilateral bank debt facilities
Total liquidity		3,189	2,937
Debt ($million)
Export credit agency supported loan facilities	Senior, unsecured	283	343
Bank term loan facilities	Senior, unsecured	1,441	695
US Private Placement	Senior, unsecured	252	255
Reg-S bond	Senior, unsecured	1,382	1,380
PNG LNG project finance	Non-recourse, secured	1,184	1,323
Leases	Leases	457	425
Other	Derivatives	(16)	(29)
Total debt		4,983	4,392
Total net debt		3,664	3,325

2021 guidance

2021 guidance maintained

2021 guidance item	Guidance1
Production (mmboe)	84-91 mmboe
Sales volumes (mmboe)	98-105 mmboe
Capital expenditure –base ($m)	~900 million
Capital expenditure –major growth ($m)	~700 million
Upstream production costs ($/boe)	8.00-8.50/boe

1 All 2021 guidance items reflect the full-year and assume sell-down of 25% interest in Bayu-Undan to SK E&S in 1H 2021, so 1H 2021 volumes and costs are expected to be higher than 2H 2021.

2020 Full-year segment results summary

US$million	Cooper Basin	Queensland& NSW	PNG	NorthernAustralia &Timor-Leste	WesternAustralia	Corporateexplor'n &elimins	Total
Revenue	919	793	451	466	742	141	3,512
Production costs	(131)	(76)	(56)	(284)	(198)	29	(716)
Otheroperating costs	(60)	(78)	(41)	-	(4)	(91)	(274)
Thirdparty product purchases	(303)	(173)	(1)	-	(1)	(134)	(612)
Inter-segmentpurchases	-	(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

2019 Full-year segment results summary

US$million	Cooper Basin	Queensland& NSW	PNG	NorthernAustralia &Timor-Leste	WesternAustralia	Corporateexplor'n &elimins	Total
Revenue	1,164	1,055	663	165	955	184	4,186
Production costs	(123)	(71)	(80)	(67)	(225)	20	(546)
Otheroperating costs	(74)	(87)	(51)	-	(13)	(81)	(306)
Thirdparty product purchases	(475)	(242)	(1)	-	-	(167)	(885)
Inter-segmentpurchases	(2)	(72)	-	-	-	74	-
Product stock movement	33	4	(1)	(2)	(12)	-	22
Other income	22	46	24	-	7	8	107
Other expenses	(15)	(9)	(14)	(2)	(27)	(45)	(112)
FX gains and losses	(1)	-	-	-	(1)	(9)	(11)
Fair value losses on commodity hedges	-	-	-	-	-	(6)	(6)
Share of profit of joint ventures	-	-	-	8	-	-	8
EBITDAX	529	624	540	102	684	(22)	2,457

Oil price hedging

Oil price hedging provides protection to oil price downside

Open oil price positions	2021	2022
Zero cost collars (barrels)	15,000,000	2,000,000
Average floor price ($/bbl)	42	50
Average ceiling price ($/bbl)	55	61