UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 20-F

(Mark One)

☐ REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g) OF THE SECURITIES EXCHANGE ACT OF 1934

OR

☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2023

OR

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

OR

☐ SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Date of event requiring this shell company report       

Commission File No.: 001-41404

Woodside Energy Group Ltd

(Exact name of Registrant as specified in its charter)

N/A

(Translation of Registrant’s name into English)

Australia

(Jurisdiction of incorporation or organization)

Woodside Energy Group Ltd

Mia Yellagonga, 11 Mount Street

Perth, Western Australia 6000

Australia

(Address of principal executive offices)

Marcela Louzada

Woodside Energy Group Ltd

Mia Yellagonga, 11 Mount Street

Perth, Western Australia 6000

Australia

Tel: +61 8 9348 4000

+61 410 471 079

E-mail: investor@woodside.com

(Name, Telephone, E-mail and/or Facsimile number and Address of Company Contact Person)

Securities registered or to be registered pursuant to Section 12(b) of the Act.

Title of each class	Trading symbol	Name of each exchange on which registered
American Depositary Shares	WDS	New York Stock Exchange
Ordinary Shares, no par value per share*		New York Stock Exchange

* Not for trading, but only in connection with the registration of American Depositary Shares, pursuant to the requirements of the Securities and Exchange Commission.

Securities registered or to be registered pursuant to Section 12(g) of the Act.

None

(Title of Class)

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act.

None

(Title of Class)

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.

Ordinary Shares: 1,898,749,771

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ☒ Yes ☐ No

If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. ☐ Yes ☒ No

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☒ Yes ☐ No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). ☒ Yes ☐ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or an emerging growth company. See definition of “large accelerated filer,” “accelerated filer,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ☒ Accelerated filer ☐ Non-accelerated filer ☐ Emerging growth company ☐

If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards† provided pursuant to Section 13(a) of the Exchange Act. ☐

† The term “new or revised financial accounting standard” refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards Codification after April 5, 2012.

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 762(b)) by the registered public accounting firm that prepared or issued its audit report. ☒

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☒

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:

U.S. GAAP ☐ International Financial Reporting Standards as issued
by the International Accounting Standards Board ☒ Other ☐

If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow.

☐ Item 17 ☐ Item 18

If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ☐ Yes ☒ No

(APPLICABLE ONLY TO ISSUERS INVOLVED IN BANKRUPTCY PROCEEDINGS DURING THE PAST FIVE YEARS)

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. ☐ Yes ☐ No

ANNUAL REPORT 2023

This Annual Report 2023 is a summary of Woodside’s operations and activities for the 12-month period ended 31 December 2023 and financial position as at 31 December 2023. Woodside Energy Group Ltd (ABN 55 004 898 962) is the ultimate holding company of the Woodside group of companies. In this report, unless otherwise stated, references to ‘Woodside’, the ‘Group’, the ‘company’, ‘we’, ‘us’ and ‘our’ refer to Woodside Energy Group Ltd and/or its controlled entities, as a whole. The text does not distinguish between the activities of the ultimate holding company and those of its controlled entities.

This report contains references to woodside.com, and our Climate Transition Action Plan and 2023 Progress Report. These references are for the readers’ convenience only and are not incorporated by reference into this report. Similarly, the content of any other websites referred to in this report does not form part of it.

Please refer to section 6.7 - Glossary, units of measure and conversation factors for definitions of terms captured in this report.

This document is Woodside’s annual report on Form 20-F for the year ended 31 December 2023 (this “Annual Report”). Reference is made to our Australian Annual Report for the year ended 31 December 2023, which has been furnished to the U.S. Securities and Exchange Commission (the “SEC”) on a Report on Form 6-K on 27 February 2024 and includes information that has been omitted from this Form 20-F. Only information that is included in, or expressly incorporated by reference into, this Form 20-F shall be deemed to form a part of this Annual Report.

The SEC maintains an Internet website that contains reports and other information regarding issuers that file electronically with the SEC. Our filings with the SEC are available to the public through the SEC’s website at http://www.sec.gov.

No material on Woodside’s website forms any part of this Annual Report. References in this Annual Report to documents on Woodside’s website are included as an aid to the location of such documents and such documents are not incorporated by reference. References to websites and our Climate Transition Action Plan and 2023 Progress Report contained in this Annual Report (including all exhibits hereto) are provided for reference only; the information contained on the referenced websites or in the Climate Transition Action Plan 2023 are not incorporated by reference in this Annual Report.

IMPORTANT CAUTIONARY INFORMATION

This report contains forward-looking statements, greenhouse gas emissions data, industry, market and competitive position data and Woodside’s Financial Statements. Please refer to section 6.8 - Information about this report for important cautionary information relating to these matters.

NON-IFRS MEASURES

Certain parts of this report contain financial measures that have not been prepared in accordance with International Financial Reporting Standards (IFRS) and are also ‘non-GAAP financial measures’ (as defined in Item 10(e) of Regulation S-K under the US Securities Act of 1933, as amended). Refer to section 6.6 - Alternative performance measures for further details and a reconciliation of these measures to the most directly comparable IFRS measure presented in Woodside’s Financial Statements. These non-IFRS financial measures are defined in section 6.7 - Glossary, units of measure and conversion factors.

CLIMATE AND SUSTAINABILITY

Climate and sustainability considerations are factored into Woodside’s business activities and investment decisions. A summary of Woodside’s approach to climate change for 2023 and climate-related plans, are included in our Climate Transition Action Plan and 2023 Progress Report.

ACKNOWLEDGING COUNTRY

Woodside recognises Aboriginal and Torres Strait Islander peoples as Australia’s First Peoples. We acknowledge their connection to land, waters and the environment and pay our respects to ancestors and Elders, past and present. We extend this recognition and respect to First Nations peoples and communities around the world.

1

Cross-Reference table to be included in the Form 20-F

Item	Form 20-F Description	Reference in this report
1	Identity of Directors, Senior Management and Advisors	Not applicable
2	Offer Statistics and Expected Timetable	Not applicable
3	Key Information
A	[Reserved]	Not applicable
B	Capitalisation and indebtedness	Not applicable
C	Reasons for the offer and use of proceeds	Not applicable
D	Risk Factors	Section 3.9
4	Information on the Company
A	History and development of the company	Section 1, 3
B	Business overview	Section 1, 2, 3, 6.2, 6.3
C	Organisational structure	Section 5.1, Exhibit 8.1
D	Property, plants and equipment	Section 1.5, 3, 5.1, 6.5
4A	Unresolved Staff Comments	None
5	Operating and Financial Review Prospects
A	Operating results	Section 1, 2, 3, 5.1, 6.2
B	Liquidity and capital resources	Section 2.2, 2.3, 6.2
C	Research and development, patents and licenses, etc.	Section 4.2
D	Trend information	Section 2.3, 5.1, 6.2
E	Critical Accounting estimates	IFRS is applied in the Financial Statements
6	Directors, Senior Management and Employees
A	Directors and senior management	Section 4.1
B	Compensation	Section 4.3
C	Board practices	Section 4.1
D	Employees	Section 6.3
E	Share Ownership	Section 4.3
F	Disclosure of a Registrant’s Action to Recover Erroneously Awarded Compensation	Not applicable
7	Major Shareholders and Related Party Transactions
A	Major shareholders	Section 6.4
B	Related party transactions	Section 4.3, 5.1 (Note E.3)
C	Interests of experts and counsel	Not applicable
8	Financial Information
A	Consolidated Statements and Other Financial Information	Section 2.3, 5.1, 6.2
B	Significant Changes	Section 5.1 (Note E.5)
9	The Offer and Listing
A	Offer and listing details	Section 6.4, Exhibit 2.1
B	Plan of distribution	Not applicable
C	Markets	Section 6.4
D	Selling shareholders	Not applicable
E	Dilution	Not applicable
F	Expenses of the issue	Not applicable
10	Additional Information
A	Share Capital	Not applicable
B	Memorandum and articles of association	Exhibit 2.1
C	Material contracts	Not applicable
D	Exchange controls	Section 6.4
E	Taxation	Section 6.4
F	Dividends and paying agents	Not applicable
G	Statement by experts	Not applicable
H	Documents on display	Section 6.4
I	Subsidiary Information	Section 5.1 (Note E.8), Exhibit 8.1
11	Quantitative and Qualitative Disclosures About Market Risk	Section 5.1 (Note A, C), 6.3
12	Description of Securities Other than Equity Securities
A	Debt Securities	Not applicable
B	Warrants and Rights	Not applicable
C	Other Securities	Not applicable
D	American Depositary Shares	Section 6.4, Exhibit 2.1
13	Defaults, Dividend Arrearages and Delinquencies	None
14	Material Modifications to the Rights of Security Holders and Use of Proceeds	None
15	Controls and Procedures	Section 4.1
16	[Reserved]	Not applicable
16A	Audit committee financial expert	Section 4.1
16B	Code of Ethics	Section 4.1, Exhibit 11.1
16C	Principal Accountant Fees and Services	Section 4.1
16D	Exemptions from the Listing Standards for Audit Committees	Not applicable

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16E	Purchases of Equity Securities by the Issuer and Affiliated Purchasers	Section 6.4
16F	Change in Registrant’s Certifying Accountant	Not applicable
16G	Corporate Governance	Section 4.1
16H	Mine Safety Disclosure	Not applicable
16I	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	Not applicable
16J	Insider Trading Policies	Not applicable
16K	Cybersecurity	Section 4.1, 6.3
17	Financial Statements	Not applicable
18	Financial Statements	Section 5.1, 6.1, 6.2
19	Exhibits	Exhibits

3

 Contents

1.	Overview
1.1	About Woodside	5
1.2	2023 summary	6
1.3	Chair’s report	9
1.4	Chief Executive Officer’s report	10
1.5	Focus areas	11
2.	Strategy and Financial Performance
2.1	Woodside’s strategy	13
2.2	Capital management	14
2.3	Financial overview	17
2.4	Energy markets	19
2.5	Business model and value chain	20
3.	Our Business
3.1	Australian operations	21
3.2	International operations	23
3.3	Marketing and trading	24
3.4	Projects	25
3.5	Decommissioning	27
3.6	Exploration and development	28
3.7	New energy and carbon solutions	29
3.8	Climate and sustainability	31
3.9	Risk factors	40
3.10	Reserves Statement	48

4.	Governance
4.1	Corporate Governance Statement	53
	Corporate governance at Woodside	53
	Board of directors	54
	Board committees	63
	Executive Leadership Team	67
	Promoting responsible and ethical behaviour	69
	Risk management and internal control	71
	Inclusion and diversity	73
	Other governance disclosures	76
	Shareholders	77
4.2	Directors’ report	78
4.3	Remuneration Report	82
5.	Financial Statements
5.1	Financial statements	F-1
6.	Additional Information
6.1	Supplementary information on oil and gas - unaudited	A-1
6.2	Three-year financial analysis	A-7
6.3	Additional disclosures	A-15
6.4	Shareholder statistics	A-28
6.5	Asset facts	A-38
6.6	Alternative performance measures	A-42
6.7	Glossary, units of measure and conversion factors	A-46
6.8	Information about this report	A-51

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1.1 Overview

About Woodside

We are a global energy company founded in Australia, providing reliable and affordable energy to help people lead better lives.

Driven by a spirit of innovation and determination, we established the liquefied natural gas (LNG) industry in Australia 35 years ago and today supply a growing base of customers.

We have reliably delivered gas to homes and businesses in Australia for decades, supporting the development of local industry and driving economic prosperity.

Following our merger with BHP’s petroleum business in 2022, we have become a larger supplier of energy to the world through an expanded global portfolio.

We are contributing to the energy transition by leveraging our track record of reliable operations, strong customer relationships and investing in new energy.

Our strategy is to thrive through this transition by developing a low cost, lower carbon, profitable, resilient and diversified portfolio.¹

Our LNG in particular can help customers in Asia’s major economies meet their energy security needs, while also supporting their decarbonisation goals. We are also investing in new products and services that can help customers reduce or avoid their emissions.

We are working to reduce our net equity Scope 1 and 2 greenhouse gas emissions towards our aspiration of net zero by 2050 or sooner.²

Our quality global portfolio and strong balance sheet enables us to execute major projects today, while pursuing opportunities that will deliver Woodside’s next wave of growth. These opportunities are across gas, oil, new energy products and lower carbon services.

We balance our pursuit of growth with a disciplined investment approach, focused on financial returns and value for our shareholders.

We recognise that to maintain strong operational and financial performance, we need to run our business sustainably. We have a continued focus on safety, environmental and social performance and maintaining meaningful relationships with communities.

We are guided by our values, and we believe that our success is underpinned by our people and culture.

1 Please see section 6.7 – Glossary, units of measure and conversion factors for a definition of how Woodside uses the term lower carbon portfolio.

2 Targets and aspiration are for net equity Scope 1 and 2 greenhouse gas emissions, relative to a starting base of 6.32Mt CO₂-e which is representative of the gross annual average equity Scope 1 and 2 greenhouse gas emissions over 2016-2020 and which may be adjusted (up or down) for potential equity changes in producing or sanctioned assets with a final investment decision prior to 2021. Net equity emissions include the utilisation of carbon credits as offsets.

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1.2 Overview

2023 summary

1 This is an alternative performance measure (APM) which is a non-IFRS measure that is unaudited. Woodside believes this non-IFRS measure provides useful performance information, however it should not be considered as an indication of, or as a substitute for, statutory measures as an indicator of actual operating performance (such as net profit after tax or net cash from operating activities) or any other measure of financial performance or position presented in accordance with IFRS. For more information on non-IFRS measures, including reconciliations to Woodside’s Financial Statements, refer to section 6.6 – Alternative performance measures.

2 Includes production of 186.1 MMboe (2022: 156.8 MMboe) from Woodside reserves and 1.1 MMboe (2022: 0.9 MMboe) from feed gas purchased from Pluto non-operating participants processed through the Pluto-KGP Interconnector.

3 Targets and aspiration are for net equity Scope 1 and 2 greenhouse gas emissions relative to a starting base of 6.32 Mt CO2-e which is representative of the gross annual average equity Scope 1 and 2 greenhouse gas emissions over 2016-2020 and which may be adjusted (up or down) for potential equity changes in producing or sanctioned assets with a final investment decision prior to 2021. Net equity emissions include the utilisation of carbon credits as offsets.

4 Subject to completion of the transaction, targeted in the first quarter of 2024.

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CREATING VALUE We delivered a reported NPAT of $1,660 million, reflecting our strong operational performance amid a lower pricing environment. Our full-year fully franked total dividend was 140 US cps which represents approximately 80% of underlying NPAT, the top end of our targeted dividend payout range.
FINANCIAL STRENGTH Our gearing of 12.1% is at the lower end of our target gearing range of 10-20%. Net debt increased in line with planned major capital expenditure. We maintained our investment grade credit rating and ended the period with liquidity of approximately $7.8 billion.
CONSISTENT OPERATIONS We maintained strong operated LNG reliability at our assets, with Pluto achieving a reliability of 99.9% in the first five months of 2023 prior to the planned turnaround. Our total recordable injury rate (TRIR) of 1.86 increased with 39 recordable injuries in 2023, compared to 30 in 2022. Woodside had a fatality in 2023. Our production cost increased as 2023 includes 12 months of the merged portfolio and planned turnaround activities at Pluto, NWS and Ngujima-Yin.

1 Includes production of 1861.1 MMboe (2022:156.8 MMboe) from Woodside reserves and 1.1 MMboe (2022: 0.9 MMboe) from feed gas purchased from Pluto non-operating participants processed through the Pluto-KGP Interconnector.

2 This is an alternative performance measure (APM) which is a non-IFRS measure that is unaudited. Woodside believes this non-IFRS measure provides useful performance information, however it should not be considered as an indication of, or as a substitute for, statutory measures as an indicator of actual operating performance (such as net profit after tax or net cash from operating activities) or any other measure of financial performance or position presented in accordance with IFRS. For more information on non-IFRS measures, including reconciliations to Woodside’s Financial Statements, refer to section 6.6 – Alternative performance measures.

3 A securities rating is not a recommendation to buy, sell or hold securities and may be subject to revision or withdrawal at any time.

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8

1.3 Overview

Chair’s report

At a time of rising cost of living pressures, we are tremendously proud to return value to our shareholders and communities.

Sadly, our 2023 performance was overshadowed by the fatality of our colleague Michael Jurman at the North Rankin Complex in June. We must improve on safety and do all we can to ensure everyone who works on Woodside’s assets and facilities returns home safely.

Creating value through performance

Record production from our expanded portfolio further established Woodside as a global energy supplier.

We achieved strong financial performance in 2023. While oil and gas prices eased from 2022’s record highs, robust product demand continued. In 2023, we recorded an annual net profit after tax of $1.7 billion and an underlying net profit after tax of $3.3 billion. Based on this, the Board has determined a fully-franked final dividend of 60 US cents per share, resulting in a total full-year dividend of 140 US cents per share.

When Woodside performs well, the communities in which we operate also benefit. In 2023, Woodside paid a record A$5 billion to the Australian Government in tax and royalty payments.

A clear growth strategy

Woodside’s strategy is to thrive through the energy transition, by building a low cost, lower carbon, profitable, resilient and diversified portfolio.¹ Our pipeline of longer-term opportunities across different commodities supports this.

Our major growth projects including Sangomar, Scarborough and Trion are well placed to support the demand needs of our customers. Our strong performance and disciplined capital management will help us to meet this demand and continue delivering growth and returns.

Supporting the energy transition

In 2023, I spoke to many investors who want to learn more about our plans to respond to the challenges of climate change and this was a regular focus of Board meetings throughout the year.

We also continued to review our approach to Scope 3 targets in response to investor feedback and have decided to supplement our existing investment target with a new complementary emissions abatement target. We have evolved our climate disclosures, which will be put to an advisory shareholder vote at our 2024 Annual General Meeting. We will continue to listen carefully to investors to inform our approach, including how we consider future investments.

Reflecting on 2023, conflicts in the Middle East and Europe contributed to another volatile year on global energy markets. Coupled with a strong focus on energy security, this further indicates the transition will not be smooth or linear and our strategy needs to be responsive.

We are confident gas will continue to play a crucial role in the global energy mix, including as back up support for electricity grids powered by renewables. We are also working to diversify our portfolio into new energy products and lower carbon services.

Strong leadership

On behalf of the Board, it was a pleasure to welcome Ashok Belani who started as non-executive director on 29 January 2024. Ashok has extensive experience in new energy and petroleum sector decarbonisation and will be a valuable asset to the Woodside Board.

I would also like to thank our Chief Executive Officer Meg O’Neill and the entire Woodside team for another successful year. Meg is calm, methodical and inclusive. She is the right leader to seize the opportunities the energy transition brings and work through its challenges. Thank you also to our shareholders, for investing and placing your trust in Woodside.

In 2024, Woodside is celebrating its 70th anniversary and 40 years of production from the North West Shelf, the birthplace of Australia’s LNG industry. It is an opportunity to reflect on the significant contribution Woodside has made to Australia’s prosperity and regional energy security. We plan to build on this legacy for years to come.

Richard Goyder, AO

Chair of the Board

27 February 2024

1 Please see section 6.7 – Glossary, units of measure and conversion factors for a definition of how Woodside uses the term lower carbon portfolio.

9

1.4 Overview

Chief Executive Officer’s report

The past year has seen Woodside deliver record production while laying the foundations for future growth and value.

We bedded down our transition to a larger, global energy company following the merger with BHP’s petroleum business, working effectively as one team across multiple locations.

Safety must improve

When I reflect on 2023 I will always think of our colleague Michael Jurman, who lost his life while working at our North Rankin Complex. His death continues to affect many of us, and I again offer my deepest condolences to Michael’s family and friends.

Safety is our number one priority and we must improve. In 2023 we commissioned an external review of our safety systems and this will guide our efforts to improve safety performance.

Strong, reliable production

We achieved record full-year production of 187.2 MMboe (513 Mboe/day) from our expanded global portfolio. Reliability at Pluto LNG and the Karratha Gas Plant (KGP) in Western Australia was excellent at 98%. Planned turnarounds and maintenance activities were successfully completed at major assets.

This strong operational performance allowed us to leverage continued robust demand for our products. Operating revenue for 2023 was $14 billion, driving an annual reported net profit after tax of $1.7 billion.

We achieved this record production while continuing to reduce our net equity Scope 1 and 2 emissions, which in 2023 were 12.5% below our starting base (compared to 11% in 2022).¹

Delivering the next wave of growth

During the year we made good progress at our key growth projects. By the end of 2023, our Scarborough Energy Project was more than 55% complete and on track for first LNG cargo in 2026.² At year end, fabrication of the Pluto Train 2 modules was underway with six of the 51 complete, and site works were well progressed.

Key environmental approvals were accepted in late 2023 and following this our seismic program was successfully completed. Our sale and purchase agreement with LNG Japan, for the sale of a 10% equity interest in the Scarborough Joint Venture, was a key 2023 achievement.³

The Sangomar project off Senegal was 93% complete at the end of 2023, with 17 of 23 wells drilled and completed.⁴ The floating production storage and offloading (FPSO) facility sailed away from the Singapore shipyard in December. We are targeting first oil in mid-2024.

In June, we took a final investment decision (FID) on the Trion Project in the Gulf of Mexico. Procurement activities commenced for the floating production unit (FPU) materials and subsea equipment. We are targeting first oil from Trion in 2028.

In our new energy portfolio, we took FID on the Hydrogen Refueller @H2Perth. We are targeting supply of hydrogen to Western Australian industrial and public customers in 2025. We are also advancing several carbon capture and storage (CCS) projects. Progress is also being made on our proposed H2OK hydrogen project in Oklahoma, United States and the proposed Woodside Solar project near Karratha, Western Australia.

Sustainable performance

As Woodside’s global presence increases, our sustainability performance becomes ever more important. In 2023 we updated our Sustainability Strategy, further embedding sustainability performance into everything we do.

In closing, I am proud of the Woodside team and proud to work in this industry. I have seen first-hand how safe, reliable energy transforms lives. We cannot lose sight of this as we work towards a stable energy transition that benefits future generations.

Meg O’Neill

Chief Executive Officer and Managing Director

27 February 2024

1 Targets and aspiration are for net equity Scope 1 and 2 greenhouse gas emissions, relative to a starting base of 6.32Mt CO₂-e which is representative of the gross annual average equity Scope 1 and 2 greenhouse gas emissions over 2016-2020 and which may be adjusted (up or down) for potential equity changes in producing or sanctioned assets with a final investment decision prior to 2021. Net equity emissions include the utilisation of carbon credits as offsets.

2 The completions % excludes the Pluto Train 1 modifications project.

3 Subject to completion of the transaction, targeted in the first quarter of 2024.

4 The progress of the project has been updated to 93% following a 0.2% correction identified subsequent to the period.

10

1.5 Overview

Focus areas

11

12

2.1 Strategy and Financial Performance

Woodside’s strategy

Woodside’s strategy is to thrive through the energy transition by building a low cost, lower carbon, profitable, resilient and diversified portfolio.¹

There are three goals which drive Woodside’s strategic direction.

Firstly, we strive to have the right portfolio to provide the energy required for future demand. We play to our strengths, providing oil and gas to our customers while advancing new energy products and lower carbon services. Climate is an integrated part of our strategy and we assess investment decisions against a wide range of considerations including climate outcomes. This is important as the demand from our customers becomes increasingly shaped by their decarbonisation goals.

Secondly, we want to create and return value to our shareholders. Our capital management framework aims to optimise value, balance strong shareholder returns, and invest in quality opportunities.

Finally, we aim to conduct our business sustainably. To achieve this, we need to manage our impact on people, communities and the environment in which we operate. The safety of our people and a strong focus on managing our net equity Scope 1 and 2 emissions to meet our targets is critical to the longevity of our business.

All three goals are critical to ensuring that Woodside delivers its strategy and thrives through the energy transition.

1 Please see section 6.7 - Glossary, units of measure and conversion factors for a definition of how Woodside uses the term lower carbon portfolio.

13

2.2 Strategy and Financial Performance

Capital management

Woodside’s capital management framework provides us with the flexibility to optimise value and shareholder returns delivered from our portfolio of opportunities.

CAPITAL MANAGEMENT

Our disciplined and responsible approach to investment ensures we manage financial risks and maintain a strong financial position, enabling us to maximise the value we deliver to our shareholders.

With a robust capital management framework in place, we are striving to ensure that Woodside remains a resilient and diversified company in the future.

Our capital investment requirements are primarily funded by our operating cash flows, which we augment or distribute with a number of capital management levers:

• Debt management, enabling continued access to premium debt markets at a competitive cost to support our growth activities and managing the debt maturity profile of our debt portfolio. Our gearing target is 10-20% and we continue to target maintaining an investment grade credit rating.

• Shareholder returns, to reward our shareholders appropriately. Our dividend policy aims to pay a minimum of 50% of NPAT excluding non-recurring items (underlying NPAT), with a target payout ratio between 50% and 80%. Our dividend reinvestment plan (DRP) remains suspended.

• Hedging, to protect the balance sheet against the commodity cycle.

• Focused expenditure management, enabling prudent and efficient deployment of capital to support delivery of our operating asset and growth opportunities.

• Participating interest management, enabling us to balance capital investment requirements, project execution risk and long- term value.

14

CAPITAL ALLOCATION

Woodside’s high margin portfolio is made up of quality assets which have the scale and resilience to deliver ongoing value. Woodside’s disciplined capital allocation approach includes robust assessment of opportunities, portfolio outcomes and shareholder returns while maintaining focus on safe, reliable and efficient operations.

Our global portfolio includes LNG, oil and gas assets across Australia, the Gulf of Mexico, the Caribbean, Senegal, Timor-Leste and Canada.

We are weighted towards LNG, which we expect to play a sustained role through the energy transition as our customers seek to reduce their emissions. Our LNG assets are geographically advantaged.

Our domestic gas assets deliver steady cash flows, resilience to commodity prices and provide reliable returns.

In our oil assets, we seek high cash generation and shorter payback periods, which boosts our funding capabilities in the short-term, while remaining resilient in the long-term as the demand for oil decreases.

We strive to operate our assets safely, reliably and efficiently to deliver the best value to our customers.

We have major projects in execution phase that will deliver Woodside’s next wave of growth. In Senegal, the Sangomar Field Development Phase 1 is targeting first oil in mid-2024. The Scarborough Energy Project in Australia is targeting first LNG cargo in 2026. In Mexico, the Trion Project achieved a FID in June 2023 and is targeting first oil in 2028.

We have carbon capture and storage (CCS) opportunities in Australia and are progressing hydrogen and ammonia projects in Australia, the United States and New Zealand.

Our investment decisions for both organic and inorganic opportunities are informed by energy market analysis including supply, demand and price outlooks. We test the robustness of potential investments against a wide range of scenarios to support our investment decisions, with the goal of remaining profitable and resilient through various commodity cycles and climate outcomes.

Our capital allocation framework sets target investment criteria for oil, gas and new energy opportunities. We use this capital allocation framework to create a diversified and flexible portfolio, which we believe allows us to respond to changes in demand and supply for our products.

1 CCUS refers to carbon capture utilisation and storage.

2 Payback refers to RFSU + X years.

3 Targets and aspiration are for net equity Scope 1 and 2 greenhouse gas emissions relative to a starting base of 6.32 Mt CO2-e which is representative of the gross annual average equity Scope 1 and 2 greenhouse gas emissions over 2016-2020 and which may be adjusted (up or down) for potential equity changes in producing or sanctioned assets with a final investment decision prior to 2021. Net equity emissions include the utilisation of carbon credits as offsets.

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When assessing opportunities, we consider a broad range of portfolio evaluation and opportunity evaluation factors relevant to the opportunity. These assessments can apply to acquisitions or divestments, and for evaluating the impact of a new project on the portfolio.

SUSTAINABILITY

Our Sustainability Strategy supports our Corporate Strategy and Purpose and places an increased focus on those sustainability topics most relevant to our current business activities. We apply a sustainability mindset to guide decision making at all levels of the business. Our Sustainability Strategy aims to embed environment, social and governance performance in everything we do.

As described further in section 3.8 - Climate and sustainability, in 2023, our sustainability activities and disclosures continued to evolve in response to the strategic importance of sustainability topics, emerging mandatory sustainability standards and investor priorities.

1 Illustrative of the considerations. Not an exhaustive list.

16

2.3 Strategy and Financial Performance

Financial overview

KEY METRICS

The financial summary below includes both IFRS and non-IFRS measures. Woodside uses various alternative performance measures (APM) which are non-IFRS measures to reflect our underlying performance. These measures are identified below and are reconciled to Woodside’s Financial Statements in section 6.6 - Alternative performance measures.

		2023		2022		2021
Operating revenue	$ million		13,994		16,817		6,962
EBITDA excluding impairment1	$ million		9,363		11,234		4,135
EBIT1	$ million		3,307		9,186		3,493
Net profit after tax (NPAT)2,3	$ million		1,660		6,498		1,983
Underlying NPAT1	$ million		3,320		5,230		1,620
Net cash from operating activities	$ million		6,145		8,811		3,792
Dividends distributed	$ million		4,253		3,088		404
Final dividend determined	$ million		60		144		105
Earnings	US cps		87.5		430.0		206.0
Gearing1,7	%		12.1		1.6		21.9
Production volumes8
Gas	MMboe		128.3		113.8		73.3
Liquids	MMboe		58.9		43.9		17.8
Total	MMboe		187.2		157.7		91.1
Sales volumes
Gas	MMboe		144.1		125.0		93.7
Liquids	MMboe		57.4		43.9		17.9
Total	MMboe		201.5		168.9		111.6

1. These are alternative performance measures (APM) which are non-IFRS measures that are unaudited. Woodside believes these non-IFRS measures provide useful performance information, however they should not be considered as an indication of, or as a substitute for, statutory measures as an indicator of actual operating performances (such as net profit after tax or net cash from operating activities) or any other measure of financial performance or position presented in accordance with IFRS. For more information on non-IFRS measures, including a reconciliation of these measures to the most directly comparable financial measure calculated and presented in accordance with IFRS in Woodside’s Financial Statements, refer to the section 6.6 - Alternative performance measures.

2. Net profit after tax attributable to equity holders of the parent.

3. The global operations effective income tax rate (EITR) is 27.5%. As a result of the final investment decision to develop the Trion resource in 2023, the de-recognition of the Pluto PRRT deferred tax asset (DTA) and the impact of impairments, global EITR has reduced from an underlying 31% to 27.5%. The EITR is calculated as Woodside’s income tax expense or benefit divided by profit or loss before income tax. EITR was ~31% for 2022 and ~32% for 2021.

7. The total interest-bearing liabilities used to calculate gearing in 2023 includes $9 million of capitalised costs to be amortised within the next 12 months. This aligns to Note C.2 of section 5 - Financial Statements.

8. Includes production of 186.1 MMboe (2022: 156.8 MMboe) from Woodside reserves and 1.1 MMboe (2022: 0.9 MMboe) from feed gas purchased from Pluto non-operating participants processed through the Pluto-KGP Interconnector.

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CAPITAL MANAGEMENT

Final dividend and dividend reinvestment plan

A 2023 fully franked final dividend of 60 US cps has been determined. The total amount of the final dividend payment is $1,139 million which represents approximately 80% of underlying NPAT for the second half of 2023.¹

The dividend reinvestment plan (DRP) remains suspended.

Liquidity and debt service

Woodside’s primary sources of liquidity are cash and cash equivalents, net cash generated by operating activities, unused borrowing capacity under its bilateral facilities and syndicated facilities, issuances of debt or equity securities, and other sources, such as sales of non-strategic assets.

During the year, Woodside generated $6,145 million of cash flow from operating activities and delivered positive free cash flow of $560 million.^2,3

Woodside increased its standby debt facilities from $4,050 million to $6,050 million and repaid $284 million of maturing debt. At the end of the period, drawn debt was $4,874 million, with no principle debt payable in 2024 and liquidity was $7,790 million.

Additional details of Woodside’s credit facilities, including total commitments, maturity and interest, and amount outstanding as at 31 December 2023, can be found in section 5 - Financial Statements and Note C.2 to the audited Financial Statements of Woodside as at 31 December 2023 and 2022.

Woodside’s principal ongoing uses of cash are to meet working capital requirements, fund debt obligations and finance Woodside’s capital expenditure and acquisitions. We believe working capital is sufficient for our present requirements.

Woodside’s capital expenditure for 2024 is expected to be between $5,000 million and $5,500 million primarily due to Sangomar, Scarborough and Trion project expenditure. This excludes the impact of any subsequent asset sell-downs, acquisitions or other changes in equity. We are targeting first oil in mid-2024 for Sangomar, first LNG cargo in 2026 for Scarborough and first oil in 2028 for Trion.

Woodside has no off-balance sheet arrangements that have, or are reasonably likely to have, a current or future material effect on the Woodside’s financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

Balance sheet

Woodside’s commitment to an investment grade credit rating remains unchanged and supports Woodside’s aims of providing sustainable returns to shareholders and investing in future growth opportunities, in accordance with our capital allocation framework. In 2023, Woodside’s credit ratings of BBB+ and Baa1 by S&P Global and Moody’s respectively were both maintained.⁴

Woodside’s gearing at the end of 2023 was 12.1%, within the lower end of our target range of 10-20%. Woodside’s gearing may at times fall outside the target range of 10-20% as the balance sheet is managed through the investment cycle.⁵

Commodity price risk management

Woodside hedges to protect the balance sheet against downside commodity price risk, particularly during periods of high capital expenditure.

Woodside hedged approximately 22 MMboe of 2023 volumes. The realised value of these oil price hedges was a pre-tax expense of approximately $200 million.

As at 31 December 2023, Woodside has placed oil price hedges for approximately 29 MMboe of 2024 production at an average price of approximately $76 per barrel.

Woodside has also placed hedges for Corpus Christi LNG volumes to protect against downside pricing risk. These hedges are Henry Hub and Title Transfer Facility (TTF) commodity swaps. An average of 63% of 2024 volumes and 17% of 2025 volumes have reduced pricing risk as a result of hedging activities.

1 Underlying NPAT is a non-IFRS measures. Refer to section 6.6 - Alternative performance measures for a reconciliation of these measures to Woodside’s Financial Statements.

2 Free cash flow is a non-IFRS measure. Refer to section 6.6 - Alternative performance measures for a reconciliation of these measures to Woodside’s Financial Statements.

3 Cash flow from operating activities less cash flow from investing activities.

4 Credit ratings are forward-looking opinions on credit risk. S&P Global’s and Moody’s credit ratings express the opinion of each agency on the ability and willingness of Woodside to meet its financial obligations in full and on time. A credit rating is not a recommendation to buy, sell or hold securities and may be subject to suspension, reduction or withdrawal at any time by an assigning rating agency. Any rating should be evaluated independently of any other information.

5 Gearing and net debt are non-IFRS measures. Refer to section 6.6 - Alternative performance measures for a reconciliation of these measures to Woodside’s Financial Statements.

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2.4 Strategy and Financial Performance

Energy markets

Geopolitical events continued to disrupt energy markets throughout 2023, reinforcing the importance of providing customers with reliable, affordable and secure energy.

Recent events, including the energy security situation in Europe and the conflict in the Middle East, have resulted in both positive and negative drivers for the energy transition. Increased demand for oil and natural gas has highlighted the need for continued production of and investment in hydrocarbons, while policy support for renewables and lower carbon services has continued to be robust.

MACROECONOMIC

The global economy proved resilient in 2023 despite the dual challenges of persistently high inflation levels and rising interest rates; gross domestic product (GDP) grew at 3.0%.¹ Hawkish monetary policy from 2022 was adopted, curbing inflation. Many advanced economies are passing peak interest rates; however, longer-term macroeconomic impacts of policy are unknown.

China presents uncertainty as the economy struggles with tepid demand, lower confidence and the real estate sector faces liquidity issues. However, recent government stimulus is a positive sign for future growth enabling China to meet its 2023 official GDP growth target of approximately 5%.

The world’s population is expected to increase by approximately two billion people by 2050 and GDP is forecast to almost double, driving increased energy demand.²

OIL

OPEC+ continues to exert control in balancing oil markets and has committed to further production cuts in 2024.³ However, non-OPEC production volumes, particularly in the US Lower 48, Canada, Brazil and Guyana will continue to grow into 2024 potentially offsetting OPEC+ cuts.

Dated Brent averaged US$83/bbl in 2023, 18% below average 2022 prices which were elevated by the energy crisis, and 14% above the five-year average.⁴ Oil prices are expected to remain elevated into 2024 supported by a geopolitical risk premium, OPEC+ production management and a slower growth rate for non-OPEC production.

LIQUIFIED NATURAL GAS

In 2023, global gas markets began to rebalance but remained tight, exacerbated by Russian LNG sanction uncertainty. Although North East Asian LNG prices averaged half of 2022 average prices at US$14/MMBtu, global gas prices remain robust and consistent with long-term expectations.⁴ Wood Mackenzie forecasts in its base case scenario that global LNG demand will grow 53% to 2033, supported by growth in Europe (until 2029), China, and emerging Asian markets.⁵

NEW ENERGY PRODUCTS

Globally, investment in new energy technology has increased, spurred by government incentives such as REPowerEU and the US Inflation Reduction Act and a common goal to reduce long-term emissions. Subsidies have driven early growth in wind and solar followed by refinement of technology and large-scale manufacturing which has improved affordability. Although the environment for new energy products remains challenged by uncertainty in proving technologies, securing future demand for product, lack of clarity on the application of incentives, and unfavourable project economics, Woodside believes that new energy products will play an important role in the energy transition.

AUSTRALIAN DOMESTIC GAS MARKETS

The Australian domestic gas market experienced supply shortfalls in 2023 as demand outpaced supply. In Western Australia, demand was supported by the progressive retirement of coal fired power generation, numerous outages and project delays. Demand is expected to exceed supply by up to 11% until 2029 with an increasing supply gap to 2032 as coal supply is retired.⁶ Despite the Federal government implementing a price cap of A$12/GJ for new supplies in 2023 to improve affordability, further investment in supply and infrastructure will be needed in the future to ensure that demand can be met.

1 International Monetary Fund, January 2024. “World Economic Outlook Update”.

2 Wood Mackenzie, September 2023. “Energy Transition Outlook 2023”.

3 OPEC Monthly Oil Market Report, January 2024.

4 Thompson Reuters Eikon.

5 Wood Mackenzie, October 2023. “Global Gas Investment Horizon Outlook”.

6 Australian Energy Market Operator, 2023. “Western Australian Gas Statement of Opportunities”.

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2.5 Strategy and Financial Performance

Business model and value chain

Woodside’s business model seeks to optimise returns across the value chain by prioritising competitive growth opportunities; utilising our operational, development and technological capabilities; and investing in customer relationships.

	2023 examples
Acquire, divest, explore and develop We manage our portfolio through acquisitions, divestments and exploration, based on a disciplined approach to optimising shareholder value and appropriately managing risk. We look for material positions in world-class assets and basins that are aligned with our capabilities and existing portfolio. We are focused on value and look to generate low cost, lower carbon development opportunities. During the development phases, we aim to optimise value by selecting the best concept for extracting, processing and delivering energy to our customers.	Took FID on the Trion Project in June 2023. Achieved the sale of a 10% equity interest in the Scarborough Joint Venture.1
Project execution We are building on decades of project execution expertise, investing in opportunities across the globe. Woodside is benefitting from the increased scope and scale of its projects portfolio through knowledge sharing across projects and our relationships with suppliers and contractors. We design and execute projects with a focus on safety, cost and sustainability.	Continued project execution of Sangomar Field Development Phase 1, Scarborough and Trion.
Operate Our operations prioritise safety while focusing on strong reliability and environmental performance in remote and challenging locations. In Australia, our operated assets include the North West Shelf (NWS) Project and Pluto LNG. We also operate Macedon and three FPSO facilities and have non-operated interests in Bass Strait and Wheatstone. Internationally, we operate Shenzi in the Gulf of Mexico and Angostura and Ruby in Trinidad and Tobago and have non-operated interests in Atlantis and Mad Dog in the Gulf of Mexico. We endeavour to adopt technology and a continuous improvement mindset to support operational performance and optimise the value of our assets.	Achieved reliability of 98% at Pluto LNG, KGP and reliability above 97% at Shenzi. Preparing for first oil on Sangomar in 2024.
Market Our relationships with customers have been maintained through a track record of reliable delivery since the NWS Project’s first LNG cargo was delivered to Japan in 1989. We are building scale and flexibility in our portfolio by expanding our global supply presence, through our own liquefied volumes and offtake agreements with third parties. This creates opportunities to optimise our LNG cargoes and capture short-term trading opportunities. We continue to look for opportunities to collaborate with our customers on lower carbon energy solutions.	Signed a sales and purchase agreement (SPA) with Mexico Pacific Limited to purchase 1.3 Mtpa of LNG for 20 years from the Saguaro Energia LNG Project.2
Decommission Decommissioning is integrated into project planning, from the earliest stages of development through to the end of field life. We work with global contractors to safely remove facilities and plug and abandon wells that are no longer required for our operations. We work with regulators to deliver our decommissioning commitments.	Successfully completed removal of the Nganhurra riser turret mooring (RTM). The Enfield plug and abandonment (P&A) campaign continued with all 18 wells permanently plugged and 16 of the 18 xmas trees removed.

1 Subject to completion of the transaction, targeted in the first quarter of 2024.

2 The SPA is subject to Mexico Pacific taking FID on the proposed third train at the Saguaro Energia LNG Project. The FID is expected in the second half of 2024 and commercial operations are targeted to commence in 2029.

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3.1 Our business

Australian operations

Woodside’s Australian portfolio consists of operated and non-operated oil and gas projects across Australia. Woodside’s share of production from Australian operations was 145.1 MMboe in 2023, a 6% increase compared to 2022.¹

PLUTO LNG

Pluto LNG is a gas processing facility in the Pilbara region of Western Australia, comprising an offshore platform and one onshore LNG processing train.

Woodside’s share of Pluto production was 51.8 MMboe in 2023, a 1% decrease compared to 2022 due to planned turnaround activities partly offset by the sustained high reliability of 98.2% in 2023.¹

Woodside successfully completed a major turnaround on the onshore and offshore facilities in the first half of 2023, executing essential maintenance scopes to support continued safe, reliable and efficient production. The major turnaround included installation of additional tie-in points for potential carbon-to-products value streams and for the potential importation of solar energy from the proposed Woodside Solar project.

There was one Tier 1 loss of primary containment process safety event at Pluto LNG. There were no injuries as a result of this event and an investigation was undertaken which identified contributing factors and corrective actions.

The Pluto Remote Operations Centre in Perth, Western Australia became fully operational in June 2023 with day-to-day operations of Pluto LNG now being undertaken remotely by the Perth-based team.

Woodside is operator and holds a 90% participating interest.

Woodside Solar opportunity

Woodside is progressing a potential opportunity to reduce gross Scope 1 greenhouse gas emissions at Pluto LNG by utilising solar energy from the proposed Woodside Solar project. The project plans to generate an initial supply of approximately 50 MW of electricity from a large scale solar photovoltaic farm, located approximately 15 km south-west of Karratha, Western Australia, which will be complemented by a battery energy storage system.

In 2023, Woodside secured planning approvals and State and Federal environmental approvals for the proposed solar facility and associated infrastructure.

In December 2023, Woodside entered into a conditional agreement under which a third-party will develop the proposed solar facility and supply renewable energy from the facility to Woodside. Woodside continues to progress commercial agreements, including for power transmission to support the proposed project.

NORTH WEST SHELF PROJECT

The NWS Project consists of three offshore platforms and the onshore KGP, which includes five onshore LNG processing trains.

Woodside’s share of NWS Project production was 40.8 MMboe in 2023. This was an 11% increase compared to 2022, due to the increase of Woodside’s equity share following completion of the merger with BHP Petroleum in June 2022. In 2023, 11.2 MMboe of Pluto gas was processed at KGP through the Pluto-KGP Interconnector. The Interconnector enables gas from Pluto LNG to be transported to KGP for processing.

In June 2023, a fatality occurred at the North Rankin Complex. The tragic loss of our colleague, a contractor employee, has led to the implementation of additional operational controls based on preliminary investigation insights into the incident. The external investigations into the incident are ongoing.

KGP is expected to have increased ullage in 2024 due to a combination of natural field decline and limited third-party gas processing demand. To optimise utilisation of onshore infrastructure, NWS is planning to take one LNG train offline in 2024.

Discussions continue between NWS and other resource owners for the processing of third-party gas and NWS continues to progress the development of infill and nearfield opportunities to utilise ullage at KGP. The NWS Project started processing Waitsia gas in 2023 at low rates and will commence processing at a large scale when the Waitsia Stage 2 facility comes online which is expected in 2024.

State and Commonwealth regulatory approval processes continue for the North West Shelf Project Extension, which supports long-term operations and processing of future third-party gas resources at KGP.

1 Includes production of 1.1 MMboe (2022: 0.9 MMboe) from feed gas purchased from Pluto non-operating participants processed through the Pluto-KGP Interconnector.

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Woodside successfully completed planned turnaround and maintenance activities on the North Rankin Complex, Goodwyn Platform and KGP in the second half of 2023.

Woodside is operator and holds a 33.33% participating interest.

WHEATSTONE AND JULIMAR-BRUNELLO

Wheatstone is an LNG processing facility near Onslow, Western Australia, comprising an offshore production platform and two onshore LNG processing trains. It processes gas from several offshore gas fields including Julimar and Brunello.

Woodside’s share of Wheatstone production was 13.5 MMboe in 2023, an increase from 12.2 MMboe in 2022, which was impacted by a major facility turnaround.

The FID on Julimar-Brunello Phase 3 was approved in April 2023. The project involves the drilling of up to four development wells tied-back from the Julimar field to the existing Julimar field production system.

Woodside is operator and holds a 65% participating interest in the Julimar-Brunello fields. Woodside holds a 13% non-operated interest in the Wheatstone project.

BASS STRAIT

Bass Strait is located in the south-east of Australia and produces oil and gas through a network of offshore platforms, pipelines and onshore processing facilities. The Bass Strait assets include the Gippsland Basin Joint Venture (GBJV) and the Kipper Unit Joint Venture (KUJV).

Woodside’s share of production from the Bass Strait was 22.8 MMboe in 2023, driven by lower Australian east coast gas market demand due to a number of factors including a warmer winter. All of Woodside’s share of the gas produced by the GBJV is supplied into the eastern Australian domestic gas market, supporting Australia’s energy needs.

As production rates decline, progress has been made to optimise facilities through the Gas Asset Streamlining project. This project will support the implementation of a gas focused business.

The Kipper Compression project has progressed and is expected to enable continued supply of gas to the domestic market in 2024.

Woodside holds a 50% non-operating interest in the GBJV and a 32.5% non-operating interest in the KUJV.

OTHER AUSTRALIAN OIL AND GAS ASSETS

Woodside operates three FPSO facilities off the north-west coast of Western Australia. These are the Ngujima-Yin FPSO (Woodside interest: 60%), Okha FPSO (Woodside interest: 50%), and Pyrenees FPSO (Woodside interest: 40% in WA-43-L and 71.4% in WA-42-L).

Woodside’s share of production from the FPSO assets was 8.0 MMboe, down from 10.6 MMboe in 2022 primarily due to the planned five-yearly Ngujima-Yin FPSO maintenance turnaround.

The Ngujima-Yin FPSO turnaround performed in Singapore was completed safely in June 2023. The Pyrenees turnaround is planned for the first half of 2024.

Macedon (Woodside interest: 71.4%), also operated by Woodside, is a gas project located near Onslow, Western Australia which produces pipeline gas for the Western Australian domestic gas market.

Woodside’s share of production from Macedon in 2023 was 8.2 MMboe. The Macedon facility delivered approximately 17% of the Western Australian domestic gas market supply in 2023.

22

3.2 Our business

International operations

Woodside’s international portfolio includes assets in the US Gulf of Mexico and the Caribbean with embedded growth options. Woodside’s share of production from international operations was 42.1 MMboe in 2023.

SHENZI

Shenzi is a conventional oil and gas field developed through a tension leg platform (TLP) located in the US Gulf of Mexico. There are 16 producers flowing to the TLP and six water injection wells. In addition, two subsea wells are tied back to the non- operated Marco Polo platform.

Shenzi North is a two-well subsea tieback to the Shenzi TLP. The project achieved flowback in September. Production performance has been below expectations due to reservoir connectivity.

The Shenzi facility achieved reliability above 97% in 2023. Woodside’s share of production from Shenzi was 10.8 MMboe. Woodside is operator and holds a 72% participating interest.

ATLANTIS

Atlantis is a conventional oil and gas development and is one of the largest producing fields in the US Gulf of Mexico. The Atlantis development includes a semi-submersible facility with 28 active producer wells and three water injector wells.

Two wells (one producer and one injector) were completed in 2023 alongside an extensive well intervention campaign.

Woodside’s share of production from Atlantis was 12.6 MMboe in 2023. Woodside holds a 44% non-operating participating interest.

MAD DOG

Mad Dog is a conventional oil and gas development located in the US Gulf of Mexico. The Phase 1 development includes a spar facility (A-spar) with drilling capability and ten active producer wells.

Mad Dog Phase 2 is a development of the southern flank of the Mad Dog field through the new Argos floating production facility. First oil was achieved in April 2023 and production ramped up through the year.

A successful appraisal well was drilled in 2023 to extend the field to the southwest. Subsequently, the co-owners have sanctioned a three-well subsea tie back.

Woodside’s share of production from Mad Dog was 7.2 MMboe in 2023. Woodside holds a 23.9% non-operating participating interest.

GREATER ANGOSTURA

Greater Angostura includes the Angostura and Ruby conventional oil and gas fields, located offshore Trinidad and Tobago. The development includes an offshore central processing facility and five wellhead platforms. Woodside is operator and holds a 45% participating interest in the Angostura field and a 68.5% participating interest in the Ruby field.

Woodside’s share of production from Greater Angostura was 11.2 MMboe in 2023. Production enhancement activities implemented in 2023 included gas injector-to-producer well conversions, reducing back-pressure on wells and adding well perforations. These enhancements have led to an increase in reserves.

23

3.3 Our business

Marketing and trading

Woodside has a global portfolio with positions in the Asia-Pacific and Atlantic basins and has a proven track record in our integrated shipping, operations, marketing and trading activities across LNG, condensate, crude and natural gas liquid (NGL) cargoes.

The marketing segment’s profit before tax in 2023 was $375 million. This reflected the optimisation activities and incremental value generated through the marketing, trading and shipping of Woodside’s oil and gas and through third-party purchased values.

Woodside’s LNG portfolio is managed through a mix of short, mid and long-term contracts, supplied with cargoes sourced from producing assets or purchased from third parties. In 2023, Woodside’s exposure of produced LNG to gas hub indices was 30%.

Woodside’s LNG trading activities seek to maximise value of our LNG portfolio. Third-party cargoes are purchased from Corpus Christi LNG through a long-term offtake agreement and from the spot market through our relationships with other producers and traders.

The marketing of crude, condensate and NGLs is predominantly based on short-term sales and supplemented by term arrangements.

In the Gulf of Mexico, crude oil is sold to refiners and traders on the US Gulf Coast. Woodside has also increased its operational flexibility through the ability to export crude oil to international markets. In Trinidad and Tobago, crude oil is sold to international markets and natural gas is sold into the domestic market.

Natural gas is sold domestically in both Western Australia and the east coast of Australia. In Western Australia, Woodside’s domestic gas obligations are met from multiple producing assets. All of Woodside’s production from Bass Strait is sold into the east coast domestic market.

In 2023, Woodside’s Western Australian assets produced 76 petajoules (PJ) of gas, representing approximately 19% of Western Australia’s domestic gas supply. Woodside’s share of Bass Strait production was 97 PJ and that represented approximately 19% of all gas supplied to the east coast market.

Woodside’s marketing and trading portfolio is supported by our shipping capacity which includes six vessels under long-term contract and multiple vessels on short-term charter. Woodside has chartered an additional five new build LNG ships to support the delivery of Scarborough LNG cargoes and growth in trading activities. The new-build vessels are expected to be delivered between 2024 and 2026.

In April 2023, a long-term gas sale and purchase agreement (GSPA) with Perdaman Chemicals and Fertiliser Pty Ltd became unconditional. Supply under the GSPA is for approximately 130 TJ per day of gas over a term of 20 years expected to commence in 2026 or 2027.

Woodside also executed several natural gas sale agreements for the combined supply of approximately 128 PJ of pipeline gas to both the east coast and Western Australian domestic customers including retailers, and commercial and industrial users.

Delivery has commenced and is expected to continue to 2026.

In addition, Woodside also signed a SPA with Pilgangoora Operations Pty Ltd, a 100% owned subsidiary of Pilbara Minerals, for the supply of domestic LNG from the Pluto Truck Loading Facility. Supply under the SPA is contracted to commence in 2024 for a period of five years.

In August 2023, Woodside and LJ Scarborough Pty Ltd (LNG Japan) entered into a non-binding heads of agreement for the sale and purchase of 12 LNG cargoes per year (approximately 0.9 million tonnes per annum (Mtpa)) for ten years commencing in 2026.¹ This agreement is part of a broader strategic relationship with LNG Japan and its parent entities which includes the sale of a 10% non-operating participating interest in Scarborough Joint Venture and collaboration on opportunities in new energy.²

In December 2023, Woodside signed a SPA with Mexico Pacific Limited (Mexico Pacific) for the purchase of 1.3 Mtpa of LNG over 20 years from Mexico Pacific’s Saguaro Energia LNG project on the Pacific coast of Mexico. The SPA is subject to Mexico Pacific taking a FID on the proposed third train which is expected in the second half of 2024. Commercial operations are targeted to commence in 2029.

Subsequent to the period, Woodside and JERA entered into a non-binding heads of agreement for the sale and purchase of six LNG cargoes on a delivered ex-ship basis per year for 10 years commencing in 2026 from Woodside’s global portfolio. This agreement is part of a broader strategic relationship with JERA which includes equity in the Scarborough Joint Venture and collaboration on opportunities in new energy and lower carbon services.

1 LJ Scarborough Pty Ltd is currently a wholly owned subsidiary of LNG Japan Corporation, which is a 50:50 joint venture between Sumitomo Corporation and Sojitz Corporation.

2 Subject to completion of the transaction, targeted in the first quarter of 2024.

24

3.4 Our business

Projects

Woodside’s portfolio of projects is underpinned by project delivery capability that is focused on safety, low cost and lower carbon solutions.

SCARBOROUGH ENERGY PROJECT

The Scarborough gas field is located in the Carnarvon Basin, approximately 375 km off the coast of Western Australia. The field is being developed through new offshore facilities connected by an approximately 430 km pipeline to a second LNG train at the existing Pluto LNG onshore facility.

The development of the Scarborough field includes the installation of a FPU with eight wells drilled in the initial phase and 13 wells drilled throughout the life of the field. Expansion of Pluto LNG includes the construction of a second LNG train (Pluto Train 2), installation of additional domestic gas processing facilities and supporting infrastructure and modifications to the existing Pluto Train 1 to allow it to process Scarborough gas.

Scarborough gas is expected to produce approximately 5 Mtpa of LNG from Pluto Train 2, and up to 3 Mtpa of LNG from the existing Pluto Train 1. The Scarborough reservoir contains less than 0.1% CO₂. Combined with processing design efficiencies at the offshore floating production unit and onshore Pluto Train 2 the Scarborough Energy Project will be one of the lowest carbon intensity sources of LNG delivered into North Asian markets.¹

At the end of 2023, the project was 55% complete.² Fabrication of the FPU is ongoing with the living quarters commissioning underway and the hull and topsides progressing. Subsequent to the period, the hull exited its first drydock and the flare boom was installed on the topsides. Fabrication of the subsea flowlines and trunkline are complete.

The environment plans for the seismic, drilling, subsea and trunkline installation activities were accepted by the regulator in December. Following this approval, the seismic program was successfully completed. Subsequent to the period, the first subsea flowline was installed, drilling of the production wells commenced and work on the nearshore pipeline installation completed.

Work on the remainder of the pipeline in Commonwealth waters is underway.

Pluto Train 2 site works are well progressed in preparation for delivery of equipment and modules throughout 2024. At the end of 2023, approximately 33,000 m3 of concrete has been poured, 564 tonnes of structural steel erected and three km of piping has been installed. Fabrication of six modules were complete, with a further 38 modules underway. Additional modules were completed subsequent to the period.

The engineering, procurement and construction management (EPCM) contractor was selected for Pluto Train 1 modifications, with engineering and procurement of long-lead items progressing. Preparatory works for the Pluto Train 2 tie-in were carried out during the Pluto LNG turnaround in May 2023.

Woodside took a FID for the Scarborough Integrated Remote Operations Centre (IROC) in November 2023. The IROC will allow Scarborough and the Pluto facility to be remotely operated from Perth.

In August 2023, Woodside entered into an agreement with LNG Japan for the sale of a 10% non-operating participating interest in the Scarborough Joint Venture.³

Subsequent to the period, Woodside entered into an agreement with JERA for the sale of a 15.1% non-operating participating interest in the Scarborough Joint Venture.⁴

Woodside is operator and holds a 100% participating interest in Scarborough, 51% participating interest in Pluto Train 2 and 90% participating interest in Pluto LNG.⁵ Woodside is targeting first LNG cargo in 2026.

1 Wood Mackenzie Emissions Benchmarking.

2 The completion percentage excludes the Pluto Train 1 modifications project.

3 LJ Scarborough Pty Ltd (LNG Japan) is currently a wholly owned subsidiary of LNG Japan Corporation, which is a 50:50 joint venture between Sumitomo Corporation and Sojitz Corporation. Subject to completion of the transaction, targeted in the first quarter of 2024.

4. The sale and purchase agreement is with JERA Scarborough Pty Ltd which is a wholly owned subsidiary of JERA Co., Inc. Subject to completion of the transaction, targeted for the second half of 2024.

5. Following completion of the transactions with LNG Japan and JERA, Woodside will hold a 74.9% interest in the Scarborough Joint Venture and remain as operator. Completion is targeted for the first quarter of 2024 for the transaction with LNG Japan and the second half of 2024 for the transaction with JERA.

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SANGOMAR

The Sangomar oil and gas field, located approximately 100 km south of Dakar, is Senegal’s first offshore oil project.

The Sangomar Field Development Phase 1 is developing the less complex reservoir units and testing other reservoirs to support potential future phases. Oil will be produced through a stand-alone FPSO facility with 23 subsea wells and supporting subsea infrastructure. It is designed to allow the tie-in of subsequent phases.

The FPSO Léopold Sédar Senghor is a converted oil tanker with new topsides, turret and mooring systems and has production capacity of 100,000 bbl/day. The FPSO departed Singapore in December 2023, and arrived offshore Senegal subsequent to the period in February 2024.

The Phase 1 drilling and completions campaign includes 23 production, gas and water injection wells. The reinjection of gas and water is intended to help maximise the recovery of the oil and enable gas to be stored for future use. At the end of 2023, 17 wells were completed and six further wells were partially complete.

As at the end of 2023, Phase 1 of the project was approximately 93% complete.¹

In May 2023, the Sangomar joint venture approved the drilling of an additional production well to optimise field recovery. As at the end of 2023, drilling of this well was partially complete.

Woodside is committed to a robust local content program that includes training initiatives, local employment, supplier business opportunities and capacity building within Senegal. As at June 2023, the main project contractors have reported more than 3,000 jobs fulfilled by Senegalese staff. Capacity building activities are now focusing on the operating phase.

Woodside is operator and holds an 82% participating interest in the Sangomar exploitation area and a 90% participating interest in the remaining Rufisque Offshore, Sangomar Offshore and Sangomar Deep Offshore (RSSD) evaluation area.

TRION

Trion is an oil development located in the Gulf of Mexico, approximately 180 km off the Mexican coastline and 30 km south of the United States/Mexico maritime border at a water depth of approximately 2,500 m.

Woodside announced Trion’s FID in June 2023 and the Mexican regulator, Comision Nacional de Hidrocarburos (CNH), approved the Field Development Plan (FDP) in August 2023.

Woodside competitively tendered major scopes of the development and at FID, approximately 70% of the forecast capital was underpinned by firm tenders that were lump sum or based on fixed rates. Key contracts have been progressively executed since FID.

The FPU engineering, procurement, and construction contract was executed with Hyundai Heavy Industries. Procurement activities are progressing, commensurate with the maturity of the engineering performed to date. Advancing these activities will support the lump sum conversion which is planned to occur in 2024.

The floating storage and offloading (FSO) vessel front-end engineering and design (FEED) and shipyard engineering has commenced with SBM Offshore. The fully negotiated FSO bare boat charter and operating and maintenance contracts are targeting execution at the conclusion of FEED in 2024.

Key contracts have also been awarded across drilling and completions, facilities installation and subsea equipment. Long lead equipment and materials for topsides and subsea facilities have been ordered following contract awards. Transocean was awarded the drilling rig contract in July 2023. The rig will be selected 12 months prior.

The project is maturing opportunities across elements of the Trion local content plan and engaging key stakeholders in Mexico to understand local capabilities and establish prioritisation.

Woodside is operator and holds a 60% participating interest.

1 The progress of the project has been updated to 93% following a 0.2% correction identified subsequent to the period.

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3.5 Our business

Decommissioning

Woodside is committed to executing our decommissioning responsibilities safely, while also ensuring we focus on efficiency and low cost execution.

In 2023, Woodside continued execution of planned decommissioning activities, spending approximately US$447 million across our portfolio.

The Enfield project, located approximately 38 km north of the North West Cape, Western Australia, ceased production in November 2018. All 18 Enfield wells have been plugged and 16 of the 18 xmas trees have now been removed. The remaining two trees are expected to be recovered in the first half of 2024 along with the completion of the wellhead severance program.

In May 2023, Woodside completed award of all major contracts for the decommissioning of subsea infrastructure at the Enfield, Griffin, Stybarrow and Echo Yodel oil and gas fields offshore Western Australia. Drill rig contracts for the P&A of Stybarrow and Minerva wells were also awarded during 2023.

In October 2023, the Nganhurra RTM was safely and successfully removed from its location off the North West Cape in Western Australia and transported to Perth, to be cleaned and deconstructed in preparation for recycling and reuse.

For further information on the Nganhurra RTM removal, refer to the Sustainability section of our website at woodside.com. Decommissioning activities on Griffin commenced following receipt of the regulatory approvals in December 2023.

Decommissioning activity continued in the Bass Strait, with 111 wells permanently plugged. In 2023, the GBJV awarded contracts for a semi-submersible well intervention unit and a jack-up rig to commence P&A work in 2024. The GBJV also progressed the tender process with heavy lift contractors to execute decommissioning activities for a number of facilities within the Gippsland Basin. The contract was awarded subsequent to the period.

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3.6 Our business

Exploration and development

Woodside’s portfolio of developments and targeted exploration program is focused on identifying and addressing key technical and commercial elements to allow resources to compete for capital.

CALYPSO

Calypso is located approximately 220 km off the coast of Trinidad in 2,100 m water depth. The resource comprises several gas discoveries in Block 23(a) and Block TTDAA 14. The development is located in a region with existing infrastructure and a favourable demand outlook.

In the first half of 2023, Woodside completed conceptual studies and selected an infield host as the preferred development concept. Pre-FEED engineering commenced in the second half of 2023 to mature the definition of the concept. Marketing and commercial discussions continue with key stakeholders to evaluate options to monetise the resource. Woodside is operator and holds a 70% participating interest.

BROWSE

Browse comprises the Calliance, Brecknock and Torosa gas and condensate fields in the offshore Browse Basin, located approximately 425 km north of Broome, Western Australia.

Key work activities continued in support of the proposed Browse to NWS Project development, including engagements with environmental regulators on approvals and progressing commercial agreements. A CCS solution has been incorporated into the offshore design to abate a significant proportion of Browse reservoir CO₂. The Browse Joint Venture is evaluating further carbon abatement and energy efficiency opportunities to reduce and manage greenhouse gas emissions.

Woodside is operator and holds a 30.6% participating interest.

LIARD

The Liard field is an unconventional gas field located in British Columbia, Canada. In 2023, Woodside completed a transaction whereby Calgary-based Paramount Resources took a 50% equity interest in, and operatorship of, 28 leases of the Liard field.

Woodside signed an agreement to join the Rockies LNG partnership as an option to potentially export LNG via the west coast of Canada. The Rockies LNG Partnership is collaborating with Western LNG and the Nisga’ Nation, the developers of the Ksi Lisims LNG project in British Columbia. Woodside holds a 50% participating interest in the Liard field.

SUNRISE

Sunrise comprises the Sunrise and Troubadour gas and condensate fields which are located approximately 450 km north-west of Darwin, Australia and 150 km south of Timor-Leste.

In 2023, the Sunrise Joint Venture (SJV) participants continued to engage the Australian and Timor-Leste Governments on a new Greater Sunrise Production Sharing Contract and other related documents. The SJV also agreed with the Timor-Leste and Australian Governments to undertake a concept study for the potential development to inform relevant stakeholders in 2024.

The study will consider the key issues for developing, processing and marketing gas via both Timor-Leste and Australia. In addition to this, retention lease renewals were granted for Australian titles NT/RL2 and NT/RL4. Woodside is operator and holds a 33.44% participating interest.

EXPLORATION

Woodside’s exploration strategy remains focused on accessing, testing and developing low cost, lower carbon, value-adding opportunities with the characteristics and project pace to be resilient through the energy transition.

In the US Gulf of Mexico, Woodside was awarded five leases in lease sale 259 and was the highest bidder on 18 leases in lease sale 261.¹ Woodside acquired a 44% working interest in two leases in the Green Canyon protraction area and participated in the drilling of the Spinel well (non-operated), which did not encounter hydrocarbons. Also acquired, was a 30% working interest in 11 leases in the Atwater Valley protraction area.

The Egyptian regulator approved Woodside’s acquisition of a 27% interest in two non-operated blocks in the Herodotus Basin.

Woodside signed an option agreement to acquire at least a 56% interest in Petroleum Exploration License 87, located offshore Namibia in the Orange Basin. Seismic acquisition was completed and a decision on exercising the option to enter will follow evaluation of the seismic data in 2024.

Woodside continued to optimise its exploration portfolio, exiting blocks no longer considered prospective. This included a decision to exit Block 5 in deepwater Trinidad and Tobago and completing formal exit activities in offshore Canada, Republic of Korea, Peru and Myanmar Block A-6.

1 The final award of leases under lease sale 261 is pending regulatory approval.

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3.7 Our business

New energy and carbon solutions

Woodside is focusing on the development of new energy products and lower carbon services, to help Woodside and our customers reduce emissions.

NEW ENERGY

United States

H2OK

H2OK is a proposed liquid hydrogen project to be located in Ardmore, Oklahoma, expected to produce up to 60 tonnes per day (tpd) of liquid hydrogen. Woodside continued to progress technical, regulatory and contracting activities in 2023.

Woodside is evaluating the proposed US Federal Government tax incentive criteria to determine implications for the project and is working to finalise customer offtake agreements to support a potential FID. Woodside is operator and holds a 100% participating interest.

US Gulf Coast

In 2023, Woodside assessed locations and progressed the early stages of an opportunity for a potential large scale ammonia production and export facility.

Heliogen Collaboration

Woodside and Heliogen have a project agreement to deploy a 5 MW demonstration module of Heliogen’s artificial intelligence- enabled concentrated solar energy technology in California, known as the Capella project. In 2023, the project completed FEED.

Asia-Pacific

H2Perth is a proposed hydrogen and ammonia production facility to be located in Perth, Western Australia. In 2023, primary environmental approval application documents were submitted to both the Commonwealth and Western Australian regulators.

The Hydrogen Refueller @H2Perth is a proposed self-contained hydrogen production, storage and refuelling station which achieved a FID in 2023.

H2TAS is a proposed renewable ammonia and hydrogen production facility to be located in the Bell Bay area of Tasmania. In 2023, Woodside continued to evaluate power solutions and offtake opportunities.

Southern Green Hydrogen is a proposed renewable ammonia production facility to be located in Southland, New Zealand.¹ In 2023, work continued to finalise commercial arrangements for Southern Green Hydrogen.

1 Woodside’s equity in Southern Green Hydrogen is subject to finalising commercial agreements.

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CARBON CAPTURE AND STORAGE (CCS)

Woodside, as a participant in various joint ventures, holds three greenhouse gas assessment permits and is a participant in the proposed South East Australia (SEA) CCS Project.¹ In 2023, Woodside entered into three non-binding memoranda of understanding to enable studies of a potential CCS value chain between Japan and Australia.

Project2	Angel (Operated)	Bonaparte (Non-operated)	SEA CCS (Non-operated)
Description	Proposed large-scale multi-user CCS hub aimed at capturing carbon emitted by multiple industries.	Proposed large-scale multi-user CCS hub aimed at capturing carbon emitted by multiple industries.	Proposed multi-phased CCS project. Phase 1 of the project would use existing infrastructure to store CO2 in the depleted Bream field.
Location	Offshore, North West Australia	Offshore, Northern Australia	Offshore, South East Australia
Interest	20%	21%	50%
2023  Activities	Commenced pre-FEED studies and progressing activities to support submission of the environmental referral.	Commenced concept select in August 2023.	Progressed Phase 1 of the project to FEED.

CARBON CREDITS PORTFOLIO³

Woodside utilises carbon credits to offset equity Scope 1 and 2 greenhouse gas emissions that are above our net emissions reduction targets. In 2023, Woodside planted approximately 2.7 million mixed biodiverse seedlings in Western Australia as part of our Native Reforestation Project across approximately 4,700 hectares of land at Woodside owned properties.⁴ In Senegal, Woodside is funding the restoration of up to 7,000 hectares of mangroves in the Sine Saloum and Casamance regions.

Woodside is expected to receive up to 1.4 million carbon credits from this project over 30 years.

CARBON TO PRODUCTS

Woodside is focused on collaborating with carbon capture and utilisation (CCU) technology developers and is assessing opportunities to deploy their technologies in demonstration-scale pilot projects, ahead of their potential deployment on a larger- scale. Following agreements entered in 2022, Woodside completed a number of engineering studies with CCU technology developers LanzaTech, NovoNutrients, StringBio and several engineering firms in 2023.

1 Refer to section 6.5 – Asset facts for information on our Greenhouse gas assessment permits and the Climate Transition Action Plan for further information on Woodside’s CCS projects.

2 This table provides information about proposed CCS opportunities focused on Scope 3 emissions. We are also working to develop additional opportunities not shown here.

3 Refer to section 3.4 – The use of carbon credits in the Climate Transaction Action Plan and 2023 Progress Report for further information on Woodside’s use of carbon credits.

4 The project has a potential to sequester approximately 2,000 kt CO₂-e over 25 years.

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3.8 Our business

Climate and sustainability

We apply a sustainability mindset to guide decision making at all levels of the business.

In 2023, our sustainability activities and disclosures continued to evolve in response to the strategic importance of sustainability topics, emerging mandatory sustainability standards and investor priorities. As such, we elevated summary disclosures of our material sustainability topics to the Annual Report, retired the publication of a standalone annual Sustainable Development Report and included additional information at woodside.com.

CLIMATE TRANSITION ACTION PLAN AND 2023 PROGRESS REPORT

The Climate Transition Action Plan and 2023 Progress Report summarises Woodside’s climate-related plans, activities, progress and climate-related data for the period 1 January 2023 to 31 December 2023.

SUSTAINABILITY STRATEGY

We refreshed our Sustainability Strategy in 2023, to incorporate relevant sustainability-related risks and opportunities and reflect the direction of our business. The Sustainability Strategy supports our Corporate Strategy and places an increased focus on those sustainability topics most relevant to our current business activities and the communities where we are active.

Our Sustainability Strategy is built on the foundation of the following principles:

• Integrity, accountability and transparency drive our environmental, social and governance aspirations and guide decision making at all levels of our business.

• We strive to operate responsibly across our business activities.

• Enduring and meaningful relationships with communities are fundamental to our social performance.

• We recognise that our success is driven by our people and our culture. We value diversity and we strive to keep each other safe.

More information regarding our Sustainability Strategy is available at woodside.com.

2023 MATERIAL TOPICS

Climate

Woodside’s climate strategy is integrated throughout our company strategy: our aspiration to thrive through the energy transition with a low cost, lower carbon, profitable, resilient and diversified portfolio.¹

Our climate strategy contains two key elements:

• reducing our net equity Scope 1 and 2 greenhouse gas emissions; and

• investing in products and services for the energy transition.

Each element of our strategy is supported by the detail in our Climate Transition Action Plan and 2023 Progress Report which is available at woodside.com. The Climate Transition Action Plan is expected to continue to evolve over time, and will be updated in future disclosures.

Our climate-related opportunities and risks are outlined below and also described in detail in section 5.0 of the Climate Transition Action Plan and 2023 Progress Report. This includes detail of how these processes are integrated into Woodside’s overall risk management framework.

Potential opportunities	The categories of potential climate-related opportunities include: resources efficiency, energy sources, products and services, markets and resilience.
Potential risks	The categories of potential climate-related risks include: transition risks such as policy and legal risks, technology, market, and reputation; physical risks such as acute, and chronic. See also section 3.9 - Risk factors.

1 For Woodside, a lower carbon portfolio is one from which the net equity Scope 1 and 2 greenhouse gas emissions, which includes the use of offsets, are being reduced towards targets, and into which new energy products and lower carbon services are planned to be introduced as a complement to existing and new investments in oil and gas. Our Climate Policy sets out the principles that we believe will assist us achieve this aim.

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Utilising carbon credits

Like our asset decarbonisation plans, our portfolio of carbon credits enables our base business to manage the price risk associated with regulations and our corporate net equity Scope 1 and 2 emissions targets.

One carbon credit is intended to represent a tonne of emissions avoided, reduced or removed outside of our facilities.¹ Because of the importance of carbon credit integrity, Woodside applies our own additional assessment to our carbon credits portfolio. This assessment is described in the Climate Transition Action Plan, and includes:

• additionality of the credited abatement is demonstrable;

• abatement has a high likelihood of permanence;

• abatement is accurately quantified.

INVEST IN PRODUCTS AND SERVICES FOR THE ENERGY TRANSITION

Investing in products and services for the energy transition is also supported by three levers:

• assessing investments for their resilience to the energy transition;

• diversifying our products and services; and

• supporting our customers and suppliers to reduce their emissions.

Assessing investments

The precise shape and pace of the energy transition is uncertain. It is expected to vary across countries because they have different starting points, development requirements, resources and capabilities. However, the scale of the transition is clearer as it will take many trillions of dollars, invested over decades. The International Renewable Energy Agency (IRENA) estimates it will require $150 trillion of cumulative investment by 2050.²

Whilst the scale of the investment required for the energy transition creates opportunity for Woodside, its inherent uncertainty and potential volatility creates risks. We believe that acknowledging the uncertainty and building resilience to it is a better response than picking a single future scenario and acting as if it were certain.

This approach requires us:

• to carefully analyse a wide range of energy market and climate-related scenarios,

• diversify our portfolio to meet changing customer demand,

• have a disciplined capital allocation framework to focus our investments where we believe we will be most competitive,

• work diligently with our customers to understand and meet their needs so that ultimately we secure their purchase of our products and services.

We have developed a ‘transition case’ methodology which, like a business case and a safety case, helps us to manage risk by assessing investment opportunities across a range of climate-related factors. There are currently six elements to our transition case methodology, which was first applied to the final investment decision for the Trion development in the Mexican segment of the Gulf of Mexico in 2023.

Transition case for oil and gas investments
We consider:
1.  Investment attractiveness utilising a range of economic assumptions informed by climate scenarios as well as other factors such as geopolitics and macroeconomics.	4.  Climate-related risks and opportunities by comparing the impact ‘with and without opportunity’ on our portfolio aggregate climate risk exposure. 5.  Scope 1 and 2 portfolio emissions assessing the impact of ‘design out’ work on project emissions, and of residual emissions upon portfolio emissions abatement demand, and portfolio emissions intensity. 6.  Scope 1, 2 and 3 portfolio emissions intensity by comparing the impact ‘with and without opportunity’ on our portfolio.
2.  Cash flow scenario analysis impact by comparing the impact ‘with and without opportunity’ on future cash flows using scenarios, including a 1.5°C case.3
3.  Potential demand resilience analysis considering the competitiveness of the project’s cost of supply relative to the range of demand in IPCC scenarios, including 1.5°C cases.

1. The measurement, verification and reporting of the abatement is prescribed and administered by independently managed Standards (such as Verra or Gold Standard), or by Regulators through legislation (such as the Australian Clean Energy Regulator through the Carbon Farming Initiative Act).

2. IRENA, 2023. “World Energy Transitions Outlook 2023: 1.5°C pathway”. International Renewable Energy Agency, Abu Dhabi. Page 134.

3. IPCC, 2023. “Climate Change 2023: Synthesis Report. Contribution of Working Groups I, II and III to the Sixth Assessment Report of the Intergovernmental Panel on Climate Change”, [Core Writing Team, H. Lee and J. Romero (eds.)]. IPCC, Geneva, Switzerland, doi: 10.59327/IPCC/AR6-9789291691647, https://www.ipcc.ch/report/ar6/syr/downloads/report/IPCC_AR6_SYR_FullVolume.pdf - referred to in subsequent footnotes on this page as IPCC, 2023. “AR6-SYR”.

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Diversifying our portfolio

Woodside is working to diversify its portfolio by adding new products and services alongside our existing products, where we believe we have a competitive advantage to supply them successfully through the energy transition.

In 2021, Woodside set a Scope 3 investment target-aiming to invest $5 billion in new energy products and lower carbon services by 2030.^1,2

At the end of 2023, we have cumulatively spent more than $335 million towards this target, with 2023 expenditure increased by over 135% compared to 2022.^1,2 We expect expenditure to continue to ramp up towards the back end of the target period, subject to markets developing, because most project expenditure occurs in the construction phase.

Woodside has set a complementary Scope 3 emissions abatement target, to indicate the potential abatement impact of these products and services upon customer Scope 1 or 2 emissions. This target is to take final investment decisions on new energy products and lower carbon services by 2030, with total abatement capacity of 5 Mtpa CO₂-e.^1,3

The investment target tracks our work to develop these projects and bring them to market. The emissions abatement target will track their potential impact on customer emissions.

Other elements of our approach are described in more detail in our Climate Transition Action Plan and 2023 Progress Report.

1 Scope 3 targets are subject to commercial arrangements, commercial feasibility, regulatory and Joint Venture approvals, and third-party activities (which may or may not proceed). Individual investment decisions are subject to Woodside’s investment targets. Not guidance. Potentially includes both organic and inorganic investment.

2 Includes pre-RFSU spend on new energy products and lower carbon services that can help our customers decarbonise by using these products and services. It is not used to fund reductions of Woodside’s net equity Scope 1 and 2 emissions which are managed separately through asset decarbonisation plans.

3 Includes binding and non-binding opportunities in the portfolio, subject to commercial arrangements, commercial feasibility, regulatory and Joint Venture approvals, and third-party activities (which may or may not proceed). Individual investment decisions are subject to Woodside’s investment targets. Not guidance.

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Health, safety and wellbeing

Protecting the health and safety of our people, our contractors and our host communities is a top priority at Woodside. We focus on health and safety because we believe that everyone should be able to go home in the same condition as they started the day.

We aim to be an industry leader in health and safety outcomes to protect people, communities and environments. We expect all our workers (including employees and contractors) to prioritise their own health and safety and that of others to keep each other safe. We strongly believe in embedding a safety culture where our people are empowered to take action to prevent injuries and maintain a safe working environment.

The fatality of our colleague, a contractor employee, on the North Rankin Complex (NRC) continues to affect many of us. Our response prioritised the immediate safety and wellbeing of the workforce on the NRC. The Woodside Board convened and members of our Board and Executive Leadership Team visited our operational sites to meet with our workers (including employees and contractors) and offer their support. We completed a significant internal investigation into the incident and presented the findings and agreed actions to the Board and the National Offshore Petroleum Safety and Environmental Management Authority. In the fourth quarter of 2023, we facilitated an external review of our integrated safety and operational systems and plan to incorporate recommendations of this review into actions as part of a continuous improvement to our safety performance.

Highlights	•   Employee survey results showed us that our people feel empowered to speak up and act on health and safety issues. •   The framework for our new Woodside Field Leadership Program was developed and we commenced testing with our Australian based workforce. •   Integration of our global approach to wellbeing, event reporting and investigations, health, safety and environment (HSE) in contracting and performance monitoring was progressed.
Potential opportunities	•   Continue to learn from the incident on the NRC that led to the fatality of our colleague employed by a contractor company and other significant events. •   Embed our Field Leadership Program to strengthen understanding of our work practices and make improvements to HSE risk controls. •   Improve tracking and visibility of leading indicators of HSE performance.
Potential risks	•   Significant loss of primary containment process safety events. •   Failure to effectively plan and execute high-risk work activities. •   Failure to apply lessons from investigations and Field Leadership Program engagements leading to repeated events. See also section 3.9 - Risk factors.

Our approach

At Woodside everything we do is guided by Our Values. Everyone has the right to come to work and feel safe. Woodside continues its longstanding commitment to building and maintaining a work environment that is free from all forms of discrimination and inappropriate behaviour including sexual harassment. Our Code of Conduct defines the expected behaviours of everyone working at Woodside. Implementation of our Working Respectfully Policy supports the psychological safety of our workforce.

Refer to woodside.com for our Code of Conduct and Working Respectfully Policy.

Our We Care value, guides us to keep each other safe and care for communities. We prioritise safety and promote a positive safety culture by encouraging everyone to speak up and intervene on safety issues. We acknowledge providing energy to the world in the form of oil, gas and new energy potentially presents safety risks. We aim to control or mitigate the potential impacts of these risks on people, the economy and the environment.

Our Health and Safety Policy outlines the objectives and principles that shape our approach. This approach is consistent across all our business operations. When assessing safety risks, we consider the potential negative impacts of our business activities to communities and our workforce, including impacts on human rights. We implement systems and processes to identify, assess and control safety risks by applying the hierarchy of controls. Our expectations and procedures set mandatory requirements for managing high-risk work, including obligations to stop unsafe work to prevent potential fatalities and high-consequence injuries.

We take action to protect the health of our workforce and facilitate earliest recovery from work-related injury or illness. We aim to eliminate or mitigate workplace health hazards at the design stage of projects or control them as far as reasonably practicable based on the level of assessed risk. If hazards remain and there is a risk of exposure, we strive to ensure that worker exposure does not exceed legal limits through implementation of the hierarchy of controls method.

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We perform health surveillance in accordance with applicable law to detect the early signs of occupational illness so intervention, and if necessary, rehabilitation, can be initiated. Potentially harmful workplace health hazards include uncontrolled exposure to noise, hazardous substances (e.g. benzene, toluene, ethylbenzene, and xylene (BTEX), and mercury), naturally occurring radioactive material (NORM), infectious disease (e.g. COVID-19), hazardous manual tasks and psychological hazards.

Refer to woodside.com for additional information about our approach to Health, safety and wellbeing.

Our performance

A fatality of our colleague on the NRC occurred in June 2023. Three additional high-consequence injuries were also recorded for 2023. Two musculoskeletal injuries that required surgery with extended recovery beyond six months and partial amputation of a thumb following a crush injury. Following insights from event investigations, we are focusing on field leadership and engagement, risk assessments and equipment management processes.

In 2023, Woodside experienced two Tier 1 and one Tier 2 loss of primary containment (LOPC) process safety events (PSE). All events were investigated, and actions were put in place to address the root causes, including preventative actions across our facilities. We are also embedding lessons learned relating to equipment selection and maintenance.

The workforce exposure hours in 2023 (total hours 20,914,483) increased by 25%, when compared to 2022 (total hours 16,699,730). The increase in exposure hours in 2023 was due to increasing project activity and merger integration.

Our total recordable injury rate (TRIR) of 1.86 increased with 39 recordable injuries in 2023, compared to 30 in 2022. The main injury types were lacerations, wounds and soft tissue injuries.

Our total recordable occupational illness frequency (TROIF) increased to 1.15 per million hours worked from 0.72 in 2022. The 24 recordable occupational illnesses comprised 12 noise induced hearing loss, five psychological illnesses, four musculoskeletal conditions and three skin reactions.

Process safety

We recognise the critical importance of effective Process Safety Management (PSM) to avoid major accident and environmental events due to loss of control of hazardous substances. We continue to focus on process safety leadership to ensure consistent awareness of contemporary PSM approaches, organisational status, personal expectations, and accountabilities. In 2023, we rationalised and improved our competency curriculum and continued with regular assessment and assurance of process safety critical roles across global operations. Future focus areas include continuing our efforts to embed a strong process safety culture, building competency across our hydrocarbon business and increasing process safety applications in our new energy and carbon business areas.

In 2024, we are targeting a 95% company-wide completion of competency assessments for people in process safety critical roles requiring a skilled (advanced) level of competency.

Field Leadership Program

Woodside’s Field Leadership Program provides a structured approach to work team engagement, where leaders build their understanding of onsite work practices and develop the leadership skills that aim to lead to a safer workplace. The program has been designed to be applied at all worksite types from operating assets to the office environment. A key objective is to learn from frontline workers which is aligned with Our Values and Human Organisational Performance (HOP) principles. Outcomes from the program include increased organisational knowledge of risks and controls, a sustainable method to identify and improve organisational factors, and to further develop our culture of care.

In 2023, the Field Leadership Program framework was tested with operational groups. This required extensive workforce engagement to listen and learn from current approaches to HSE and work management so that the program can be tailored to enable a safer Woodside.

In 2024, the program will evolve by listening and supporting end users through training and coaching activities. We aim to develop and implement a strategy to rollout and sustain the program across our global sites.

Mental health and wellbeing

Our wellbeing vision is to be recognised as an employer of choice. We aim to cultivate a work environment where everyone can flourish by focusing on people, empowerment, and quality leadership. To achieve this, we have expanded and refreshed our Global Wellbeing Framework to focus on six key elements: (1) protecting from harm, (2) promoting health and wellbeing, (3) connection and community, (4) work-life balance, (5) opportunities for growth, and (6) meaning and purpose. Each element has a strategic goal, enabling activities and metrics to track progress, including the use of our employee survey to seek regular feedback from our people. In 2024, we plan to launch our refreshed wellbeing framework across our global business areas, and work with our leaders to commence enabling activities.

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Environment and biodiversity

Woodside recognises the importance of managing and conserving the environment and biodiversity to support sustainable development in the communities where we are active. We are committed to doing our part. We understand and embrace our responsibility to undertake activities in an environmentally sustainable way that positively contributes towards biodiversity and assists to reverse biodiversity loss.

Highlights	•   No hydrocarbon spills or hazardous non-hydrocarbon spills greater than 1 bbl. •   In 2023, obtained secondary approvals for construction-related environment plans for the Scarborough Energy project. •   We supported a number of scientific programs and industry working groups to further our knowledge and understanding on noise-related issues and offshore whale species. Through these programs, bespoke underwater noise controls were developed to avoid and minimise marine noise impacts for offshore projects. •   A consultation approach for Environment Plans in Australia which has successfully addressed evolving regulatory requirements was developed. •   Invested in science and biodiversity programs and conservation partnerships to support improved knowledge outcomes. •   Established Woodside’s Biodiversity Positive Program framework. •   In 2023, Woodside planted approximately 2.7 million mixed biodiverse seedlings across approximately 4,700 hectares of land at Woodside owned properties. These activities bring the total number of hectares planted to approximately 10,000 hectares since the Native Reforestation Project began in 2020.
Potential opportunities	•   Integrating the Environment and Biodiversity Policy into environmental management decision-making processes. •   Assess biodiversity positive opportunities for individual Woodside assets. Begin to invest in biodiversity positive projects in the regions where we are active. •   Continue to collect knowledge on environmental and biodiversity benefits of in-situ decommissioning. •   Ongoing development of technology to identify the seasonality of offshore cetaceans and further manage our underwater noise impacts.
Potential risks	•   Increased regulatory landscape and stakeholder expectations leading to extended timeframes for assessment and complexity of environmental approvals. •   Failure to progress biodiversity positive outcomes in a timely manner in the regions and areas where we operate. •   Potential incident resulting in significant loss of hydrocarbon to the environment. See also section 3.9 - Risk factors.

Our approach

The nature of our operations are accompanied by certain environmental impacts and risks. We work to minimise our impacts by integrating environmental management into our activities, including the design, construction, operation and decommissioning of our facilities.

We continue this integration by reviewing our processes and commitments, identifying areas of strength to build on and look to embed renewed environmental standards across Woodside and set appropriate targets and metrics against these. Our focus on implementing leading environmental management and mitigation strategies has allowed us to avoid and minimise our environmental impacts and maintain a more than 30 year record of oil and gas operations without any major environmental incidents.

We recognise that it is not just how we approach environmental management, such as the use of a risk-based assessment which matters, but that we also need to be clear and transparent. We engage with our stakeholders to better understand the possible impacts of our activities and to further understand preferred methods and frequency of engagement.

Our hydrocarbon spill preparedness and response framework continues to be a focus across the company’s global portfolio. The approach is underpinned by a comprehensive process informed by international best practice conventions. These require all activities to assess credible spill scenarios to marine environment, evaluate surface and subsea response options and recommend appropriate response techniques. These activity specific plans are supplemented by corporate plans, regional equipment, and locally trained resources.

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Environmental management

We recognise our activities have an environmental footprint and we seek to avoid or minimise adverse environmental impacts to the natural environment in the regions we operate.

We do this by adopting a risk based approach that allows us to address the environmental impacts and risks associated with our activities in a consistent way. It allows us to focus our effort and resources on the most significant risks associated with our activities no matter where we operate or what a regulatory regime may require.

Our performance

Our operations and growth strategy depends on obtaining and maintaining our social licence to operate. Given this and the growing pressure on our natural environment, the environmental performance and the management of our environmental impacts is critical to the future success of our business.

In 2023, there were no environmental incidents involving hydrocarbon or hazardous non-hydrocarbon spills greater than 1 bbl released to the environment.

As part of our commitment to reducing impacts and risks, our hydrocarbon spill preparedness and response framework was embedded across our global portfolio of activities and operations. This enables our business to plan and evaluate spill risks to the marine environment in accordance with our environmental approach.

In 2023, we developed new oil pollution emergency plans that contributed to regulatory acceptance of 11 environmental approvals across our Australian assets. We also delivered capability and training programs for regions where we operate. We continue to engage with regional and international industry groups to assist in proactively managing and monitoring emerging risks.

From 2023, Woodside has committed to supporting positive biodiversity outcomes in the regions in which we operate. Our approach builds on existing biodiversity positive projects, that commenced in the years prior to 2023. Woodside developed a framework in 2023 to assess and implement future projects. Woodside seeks to support biodiversity positive projects that have a measurable biodiversity outcome, that enhance stakeholder involvement and adequately manage risks.

We continue to invest in science to support better environmental performance and outcomes across our global portfolio.

We also continue to progress our environmental regulatory authorisations across Australia, Trinidad and Tobago, the United States, Mexico and Senegal to advance our projects. See section 3.7 - New energy and carbon solutions.

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First Nations cultural heritage and engagement

We acknowledge the unique connection that First Nations communities have to land, waters and the environment. We believe First Nations cultural heritage and industry can successfully coexist. We seek to ensure Traditional Owners and Custodians are central to heritage management so that cultural values are understood and remain protected. We understand the importance of identifying and working with those who have longstanding cultural and spiritual connections to land and waters where we have a presence, and we are guided by them in our efforts to avoid or minimise potential impact of our operations on those First Nations communities.

We partner with First Nations communities to create positive outcomes that leave a lasting legacy.

We acknowledge the diversity of the First Nations communities in the areas where we are present. When communicating with a wide audience, Woodside uses the term Indigenous and First Nations interchangeably. On a local level, Woodside will be guided by the community as to the appropriate terms of reference.

Highlights	•   Extensive consultations in relation to cultural heritage management approvals. •   Progression of relationships in New Zealand with the Ngāi Tahu iwi relevant to the Southern Green Hydrogen Project, with a continued focus on strengthening stakeholder relationships. •   Provision of support for consultation with First Nations stakeholders relevant to environment plan approvals. •   Continued commitment to support submerged heritage research at Murujuga to inform project implementation and manage possible impacts. •   First Nations Advisory Group Roundtable discussions.
Potential opportunities	•   Pursue initiatives in addition to existing Reconciliation Action Plan targets. •   Further develop relationships with First Nations communities in the areas where we are active. •   Pursue and formalise First Nations partnerships in the areas where we are active.
Potential risks	•   Woodside contributes to negative impacts to Murujuga Rock Art. •   Woodside does not meet local content outcomes for First Nations communities. •   Woodside does not meet expectations of First Nations communities in areas where we are active. See also section 3.9 - Risk factors.

Our approach

Our First Nations Communities Policy defines our approach and is regularly reviewed and updated as required. Woodside employees, contractors and joint venture partners engaged in activities under Woodside’s operational control, are collectively responsible for the application of the Policy and are provided with training to ensure they are able to do so. The Policy notes that Woodside is to be guided by the United Nations Declaration on the Rights of Indigenous Peoples which demonstrates our commitment to understanding the relevant human rights considerations as we engage with different First Nations communities.

In Australia, we maintain relationships with First Nations communities in the Pilbara, Kimberley, South West and Perth. Due to recent changes to regulatory compliance requirements our approach to consultation has been extended. In 2023, Woodside’s First Nations relations team consulted with a range of First Nations communities, in Australia, from Esperance to the Tiwi Islands and as far east as Melbourne. The diversity of the environments we are operating in as a global company has expanded our engagements with a range of community stakeholders in the United States, Mexico, Trinidad and Tobago, and New Zealand.

Refer to woodside.com for our First Nations Community Policy.

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Our performance

In 2023, new relationships were formed and new land use and relationship agreements were executed. Woodside remains committed to close consultation with the relevant persons in the areas in which we operate by way of community and individual meetings, attending community-initiated events, and ensuring accessibility for feedback or questions as needed. A key element of our consultation efforts is our willingness to be flexible and adaptable in our consultation format to suit the audience.

Cultural heritage

Woodside’s Cultural Heritage Management Procedure reflects our publicly available First Nations Communities Policy. This policy includes engaging with affected communities of First Nations peoples in ways that are consistent with the principles of seeking Free, Prior and Informed Consent (FPIC).

Our approach to the identification, management and protection of tangible and intangible cultural heritage seeks to avoid impacts, or if avoidance is not possible, to minimise and mitigate those impacts. We seek to ensure Traditional Owners and Custodians are central to heritage management so that cultural values are understood and remain protected.

Woodside also prepares detailed Cultural Heritage Management Plans (CHMPs) for nearshore and onshore facilities and projects and completes heritage audits and surveys with Traditional Custodians and independent heritage experts. Woodside is also committed to ensuring our management of cultural heritage is thorough, transparent and underpinned by consultation and continued engagement with First Nations communities, which is illustrated through our extensive consultation on our Environment Plans, completed heritage surveys for the proposed Woodside Solar project, and support for Murujuga’s World Heritage Listing.

Cultural heritage management approvals

Woodside’s activities are the subject of environmental assessments by a range of regulators including the Australian National Offshore Petroleum Safety and Environmental Management Authority.

Woodside has consulted extensively with Indigenous stakeholders on a variety of activities in 2023. These consultations have included the tangible and intangible cultural heritage of the environments in which we plan to operate, as well as the environmental values. In 2023, we also agreed the Scarborough Cultural Heritage Management Plan with Murujuga Aboriginal Corporation (MAC), which is publicly available on our website at woodside.com.

The CHMP is designed to ensure that impacts to heritage sites and values, including to Murujuga’s National Heritage Listed and World Tentative Heritage Listed values, are adequately protected in a manner agreed between Woodside and Traditional Owners and Custodians represented through MAC. It aims to preserve the tangible and intangible heritage values and protect the cultural and spiritual values of the Traditional Owners and Custodians. Woodside is also progressing the agreement of a CHMP with Ngarluma Aboriginal Corporation for the development of a proposed solar photovoltaic farm on the Maitland Strategic Industrial Estate.

Our continued commitment to reconciliation

Woodside has been part of Reconciliation Australia’s Reconciliation Action Plan (RAP) program since 2009. Woodside’s vision for reconciliation is to partner with Indigenous communities to create positive economic, social and cultural outcomes. It is also to reflect on our shared history, empower Indigenous voices to speak and be heard so all Australians can learn, and work together towards a better, shared future.

We are continuing to move away from recording completed activities, in favour of measuring longer-term impact outcomes. Woodside reports annually on progress towards the committed outcomes that support our four Reconciliation Action Plan pillars: respect for culture and heritage, capability and capacity, economic participation and stronger communities.

In 2023, Woodside made donations to the Aboriginal and Torres Strait Islander Voice Referendum activities that were aligned with Our Values, the principles set out within our 2021-2025 Reconciliation Action Plan and our First Nations Communities Policy. Our donations supported organisations to disseminate information and advocate in favour of formalising a pathway for Indigenous Australians to share their views on policies that impact them. Woodside’s contribution aligns with our support for the Uluru Statement from the Heart, which called for the establishment of an Indigenous voice to Parliament, agreement making and truth-telling. For further information, please see the Corporate Governance Statement and the Sustainability section of our website at woodside.com.

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3.9 Our business

Risk factors

Woodside recognises that taking risk is necessary for our business and the effective management of risk is vital to meeting our objectives. We are committed to managing risks in a proactive, informed and effective manner as a source of competitive advantage.

Our approach is intended to enable risk informed decision making, which will protect us against potential negative impacts and enable us to seek the right opportunities. The objective of our risk management framework is to provide a single consolidated view of risks across the company to understand our full risk exposure and prioritise risk management and governance.

For more information on our risk management process, refer to our Risk Management Policy, available on our website at woodside.com.

Woodside’s risk management process is presented as an iterative sequence that we undertake in a coordinated manner. The process helps us implement risk management to effectively identify, assess, and control risks, thereby enhancing the likelihood of achieving our objectives. The process involves:

• communication and consultation with key stakeholders

• define risk scope, context and criteria

• risk assessment

• risk treatment

• monitor and review risk management process; and

• record and report risks.

The process is defined in our risk management procedure which is designed to provide a consistent process for the identification, management and reporting of risks that have the potential to materially impact the achievement of Woodside’s business objectives.

The Audit & Risk Committee plays a crucial role in enabling the Board to meet its oversight responsibility in relation to Woodside’s risk management. The Sustainability Committee also focuses on sustainability-related risk management. Refer to section 4.1.3 - Board committees for more information on the Audit & Risk Committee and the Sustainability Committee.

We categorise risks into three categories:

1. Strategic risks: Risks that could affect our organisation’s ability to achieve its strategic objectives.

2. Entity risks: Risks that could affect our organisation’s ability to achieve our business objectives. They can be positive, negative, or both; and can address, create, or result in opportunities and threats.

3. Emerging risks: Risks defined as an external threat or opportunity that has a high degree of uncertainty due to rapid or non- linear evolution. They have the potential to materially impact the achievement of strategic objectives.

Woodside’s risk appetite statement is a vital element of our risk framework. In 2023 the statement was updated to reflect the merged organisation’s appetite to take risk and tolerance to outcomes. The statement is designed to enable our organisation to make risk informed decisions.

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OVERVIEW OF OUR RISK FACTORS

Climate change

The global response to climate change is changing the way the world produces and consumes energy. The complex and pervasive nature of climate change means transition risks are interconnected with and may amplify other risks. Additionally, the inherent uncertainty of potential societal responses to climate change may create a systemic risk to the global economy. Climate change may also create significant physical risks, such as increased frequency and severity of storms, wildfires, floods and other climatic events, as well as chronic shifts in temperature and precipitation patterns.

How is this factor relevant to Woodside?

Woodside’s risks associated with climate change and the transition to a lower carbon economy include possible impacts to demand (and pricing) for oil, gas and its substitutes, the policy and legal environment for its exploration, development and production, and Woodside’s reputation and operating environment. We may also face risks related to climate change’s potential to cause physical damage or disruptions to our assets or our supply chains.

Woodside is an energy company and in order for us to meet the ongoing needs of our customers and the communities in which we operate, we must understand, forecast and manage several critical risks to evolve and prosper through this transition.

These elements include:

• the demand and pricing of oil, gas, new energy products and lower carbon services

• the regulation of oil and gas exploration, production and consumption

• the timing and rate of the global transition to a lower carbon economy

• public perception of Woodside and the broader oil and gas industry

• access to, and value of, carbon credits or emission allowances; and

• uncertainties associated with changing weather patterns.

Examples of how this factor may impact Woodside

• Physical impacts on our assets or those of our suppliers, customers or communities caused by increased frequency or intensity of severe weather events.

• Over or under investing in oil and gas reserves leading to an imbalance between our supply and global demand.

• Failure to transition to new energy at a pace that serves the global demand, or stakeholder sentiments, or to develop and implement lower carbon technologies on which Woodside’s strategy may depend.

• Climate-driven changes to legislation, regulation and policy or climate-related litigation resulting in additional costs, prevent or restrict Woodside from conducting activities and adversely impacting Woodside’s reputation.

• Availability and cost of emission allowances or carbon credits could impact Woodside’s ability to meet its 2025 and 2030 net equity Scope 1 and 2 emissions reduction targets.

• Failure of other organisations to meet emissions targets across the broader oil and gas industry.

• Reputational risks with respect to Woodside or the oil and gas industry in general.

• Financial risks, including limits on availability of funding, changes in financing terms for oil and gas projects or ability to access capital markets.

These impacts may lead to a loss in shareholder value, loss of market share to competitors, delays or stoppages in our operations, reduced capacity to fund capital projects, delayed or suspended regulatory approvals, legal liabilities and adverse impacts on Woodside’s reputation, social licence to operate and on the delivery of our strategy.

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Social licence to operate

Risks associated with actual or perceived deviation from social or business expectations of ethical behaviour (including breaches of laws or regulations) and social responsibility (including environmental impact and community contribution), particularly as these expectations evolve and as Woodside expands its global operations.

How is this factor relevant to Woodside?

Woodside relies on maintaining healthy relationships with our numerous stakeholders in order for us to achieve our objectives. Our employees, host communities, Traditional Owners and Custodians, government authorities, investors and other groups form significant relationships with our organisation. These relationships are built on the trust that Woodside will meet our stakeholders’ expectations. We must also consider the role our commercial agreements play in relation to human rights around the world, as we have a responsibility to ensure the rights of all humans are not negatively affected by our organisation.

Some of the most significant risks to our relationships with stakeholders include:

• Engaging in activities that have real or perceived adverse impacts on the environment, biodiversity, human rights or cultural heritage.

• Failing to meet our net equity Scope 1 and 2 emissions reduction targets or investment targets in new energy.

• Inadequately responding to quickly evolving expectations of Woodside (including expectations that may significantly differ in the various jurisdictions in which we operate).

Additionally, third-party risks that are outside of our control could negatively impact our reputation and licence to operate, such as oil spills or other disasters or scandals that cause collateral damage to Woodside’s licence to operate via reputational damage to the oil and gas industry at large.

Failure to maintain healthy relationships with our various stakeholders may result in violation of local or national laws or regulations, significant reputational damage, delayed approvals, civil suits and ultimately the deterioration of our licence to operate.

Examples of how this factor may impact Woodside

• Limited, delayed or failed approvals from local and national government bodies.

• Lost or limited stakeholder support for our current business and future opportunities.

• Risks related to class action lawsuits, litigation and activism, including allegations of greenwashing.

• Reductions in the availability, or less favourable terms, of financing.

• Decreased ability to attract and retain a talented workforce, and other operational concerns.

These impacts may lead to a loss in shareholder value, loss of market share to competitors, decreases in the value of assets, delays or stoppages in our operations or infringements on our ability to execute and complete transactions, reduced capacity to fund capital projects, delayed or suspended regulatory approvals, legal liabilities and adverse impacts on Woodside’s reputation, social licence to operate and on the delivery of our strategy.

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Growth

Risks associated with delivery of both major and complex multi-year execution project activities and transactions (including acquisitions and divestments) across multiple global locations, including a reliance on third parties for materials, products and services.

How is this factor relevant to Woodside?

Oil and gas

In order to maintain our production levels and deliver shareholder value, Woodside must continue to identify growth opportunities, organic and inorganic, and commercialise them. To maintain a stable pipeline of future projects and realise the full value of growth opportunities, Woodside will need to compete with major oil companies, national oil companies (NOCs), independent oil and gas companies, individual producers and new energy companies. Failure to effectively compete with these companies may result in the inability to continue to expand Woodside’s current operations and meet our objectives.

Woodside must continue to effectively manage relationships with industry partners, for example, at times we enter joint ventures with organisations which may also be a competing oil and gas supplier. It is essential that our voice is heard both within our industry and more broadly. In order for us to effectively communicate, we may at times align with industry bodies to advocate what we believe is right. In addition, our current and planned projects involve uncertainties and operating risks that could prevent us from realising profits or result in the total or partial loss of our investment.

New energy

We have set targets for our new energy products and lower carbon services.^1,2 However, there is uncertainty around the pace of required technological innovation and the reliability of technologies that will be needed to transition to a lower carbon environment. In addition, new sources of energy, such as hydrogen or ammonia, may be more difficult to commercialise than expected or may not be able to be commercialised safely or as efficiently as expected at scale. Woodside may also face unforeseen obstacles in the commercialisation of a future carbon capture business and in the implementation of other lower carbon services and emission reduction efforts.

Examples of how this factor may impact Woodside

• An unbalanced portfolio of oil and gas and new energy, which may not meet the market’s needs.

• Limited or reduced market share resulting in a loss of shareholder value.

• Our competitors may be able to pay more for exploratory prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects, including operatorships and licences, than our financial or human resources permit.

• Our projects could experience project implementation schedule slippage, permitting delays, shortages of or delays in the delivery of equipment or purpose-built components from suppliers, escalation in capital cost estimates, possible shortages of construction or other personnel, other labour shortages, environmental occurrences during construction that result in a failure to comply with environmental regulations or conditions on development, or delays and higher-than-expected costs due to the remote location of the projects, the impact of global conflicts on the relevant workforce or supply chain, other unanticipated natural disasters, accidents, miscalculations, political or other opposition, litigation, acts of terrorism, operational difficulties, climate change related risks or other events associated with that construction that may result in the delay, suspension or termination of our projects.

• An inability to obtain financing at acceptable costs, or at all, for the development of new energy projects.

• Failure to implement our new energy plans within our anticipated time frame and in line with global demands.

• Failure to identify, execute and/or implement strategic transactions, including acquisitions and divestments, or to achieve the full benefits of those transactions.

• Failure to remain commercially and technologically competitive to efficiently develop and operate an attractive portfolio of assets, to obtain access to new opportunities and to keep pace with deployment of new technologies and products.

• Higher than expected competition in the markets for new energy products and lower carbon services in which Woodside expects to participate.

These impacts may lead to a loss in shareholder value, loss of market share to competitors, decreases in the value of assets, delays or stoppages in our operations, reduced capacity to fund capital projects, delayed or suspended regulatory approvals, legal liabilities and adverse impacts on Woodside’s reputation, social licence to operate and on the delivery of our strategy.

1 Please see section 6.7 - Glossary, units of measure and conversion factors for a definition of how Woodside uses the term lower carbon portfolio.

2 Scope 3 targets are subject to commercial arrangements, commercial feasibility, regulatory and Joint Venture approvals, and third-party activities (which may or may not proceed). Individual investment decisions are subject to Woodside’s investment targets. Not guidance. Potentially includes both organic and inorganic investment.

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Operations

Due to the nature of our operations, Woodside and our communities are potentially exposed to a broad range of risks; some are beyond Woodside’s control. This is a result of factors such as the geographical range, operational diversity and technical complexity of our assets.

Health and safety: Our operations are subject to risks related to safety or major hazard events in connection with our activities or facilities, and may also include unanticipated or unforeseeable adverse events which impact our ability to respond, manage and recover from such events.

Commercial: We manage commercial risks within our operations, including third-party relationships such as joint venture partners, contract counterparties and our supply chain.

Regulation: Woodside is subject to extensive governmental oversight and regulation in the jurisdictions in which we operate, and such regulations may change in ways that adversely affect our business, results of operations and financial condition. In addition, we are required to comply with securities regulations in Australia, the US and the UK.

Reserves and resources estimates: We manage the estimation of proved oil and gas reserves by using judgement and the application of complex rules, and subsequent downward adjustments of Woodside’s reported reserves estimates are possible.

How is this factor relevant to Woodside?

General operational risks: Our operating assets are subject to a range of operating risks associated with process safety incidents, breaches of cybersecurity, extreme weather events and supply chain disruptions. Disruptions to our supply chain, or failure of our contractual counterparties to fulfill their obligations, could adversely impact our production, operations and our financial performance, result in litigation or class actions and cause long-term damage to our reputation.

Health and safety: At Woodside, one of our competitive advantages is our ability to operate safely. Failure to continue to do so could result in sustained production interruptions leading to an inability to meet production forecasts, as well as potential reputational damage with customers, employees, commercial partners and other stakeholders.

Commercial: The majority of our major projects and operations are conducted in joint ventures, which may limit our control over, and our ability to effectively manage risks associated with, such projects. Joint venture participants may have economic or business interests or objectives that are inconsistent with or opposed to our interests and objectives. For projects in which we are not the operator, we may be unable to control the behaviour, performance and cost of operations of joint ventures in which we participate. In these cases, we will be dependent on joint venture participants acting as operators and their ability to direct operations or manage the timing and performance of any activity or the costs or risks involved may be reduced.

Regulation: We are subject, in each of the countries in which we operate, to various national and local laws, regulations and approvals relating to the exploration, development, production, marketing, pricing, transportation and storage of our products, as well as the management, decommissioning, clean up and restoration of our properties, and management and disclosure of our operations and impacts. The exploration, production, and transportation of oil and gas involves risk that releases to the environment may occur, which could cause substantial harm to the environment, natural resources, or human health and safety.

These laws and regulations could change, and any such changes could have a material adverse effect on our business and financial condition. Because such laws and regulations are subject to amendment and reinterpretation over time, we are unable to predict the future cost or impact of complying with such laws. Moreover, we cannot predict whether new legislation to regulate the oil and gas industries might be proposed, what proposals, if any, might actually be enacted and what effect, if any, the proposals might have on our operations. The adoption and implementation of new or more stringent legislation, regulations or other regulatory initiatives that result in the imposition of more stringent standards for greenhouse gas emissions from the oil and gas industry could restrict the areas in which this sector may operate, and could result in increased compliance costs and changes in product pricing, which could impact consumer demand for our products.

Additionally, the conduct of Woodside, our employees and our third-party partners could result in actual or alleged breaches of laws, regulations and approvals, including fraud, corruption, anti-competitive behaviour, money laundering, breaching trade or financial sanctions, market manipulation, privacy breaches, ethical misconduct and wider organisational cultural failings. We have incurred and will continue to incur operating and capital expenditures, some of which may be material, to comply with applicable laws, regulations and approvals.

Reserves and resources estimates: Estimating proved oil and gas reserves involves subjective judgements and determinations based on available geological, technical, contractual and economic information. New information from production or drilling activities, changes in economic factors, such as oil and gas prices, alterations in the regulatory policies of host governments in the jurisdictions in which we operate, or other events may cause estimates to change over time. Additionally, estimates may change to reflect acquisitions, divestments, new discoveries, extensions of existing fields and improved recovery techniques.

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 Operations (Cont.)

 Examples of how this factor may impact Woodside

• A loss of containment event or other operational incident on or related to our property or operations could occur, which could have significant impacts including to human health and safety, the environment, natural resources or cultural resources, as well as financial, legal and reputational impacts.

• Certain activities are undertaken in deep waters where operations, support services and decommissioning activities are more difficult and costly than in shallower waters. The deep waters in the Gulf of Mexico, as well as international deepwater locations, lack the physical and oilfield service infrastructure present in shallower waters. As a result, deepwater operations may have additional risks, such as a blowout, and require significant time between a discovery and the time that Woodside can market its production.

• Natural disasters, earthquakes, social unrest, pandemic diseases (such as COVID-19) and criminal actions by external parties could result in injuries, loss of life, disruption of our operations or the loss or suspension of permits or other approvals.

• Our joint venture partners may have the ability to exercise veto rights to block certain key decisions or actions that we believe are in our or the joint venture’s best interests or approve those matters without our support.

• Our partners and contractual counterparties may not be able to meet their financial or other obligations to the projects. In addition, the actions of our partners, contractors and subcontractors could result in legal liability and financial loss for Woodside.

• Applicable laws and regulations may obligate Woodside to identify, avoid, mitigate and disclose environmental risks in various operational practices, which in turn could materially adversely affect our business, financial condition or results of operations. We may also be required to maintain financial assurance through bonds or insurance.

• A failure to comply with applicable laws, regulations and approvals may result in the assessment of sanctions, including administrative, civil, and criminal penalties, the imposition of investigatory, remedial, and corrective action obligations or the incurrence of capital expenditures, the occurrence of restrictions, delays or cancellations in the permitting, development or expansion of current or proposed projects, and issuance of injunctions restricting or prohibiting some or all of our activities in a particular area.

• An operational incident could result in multiple fatalities.

• Supply chain disruptions such as long wait times for critical spares may cause extended outages at our operations.

• Joint participants or contractual counterparties may be primarily responsible for the adequacy of the human or technical competencies and capabilities which they bring to bear on the joint project, which may not be adequate.

• The suspension, revocation, failure to renew or alteration of, or challenges to, the terms of the licences, permits, government contracts or approvals required for our operations.

• Sanctions for non-compliance with laws and regulations may include administrative, civil and criminal penalties, demand for reimbursement for government or regulatory actions, government orders, suspension or revocation of licences, permits, government contracts or approvals, and corrective action orders.

• Government policy objectives in the countries in which we do business, now or in the future, could take the form of increased governmental regulations (including in respect of restoration, protection of the environment, greenhouse gas emissions, natural resources, and worker health and safety), redirection of product distribution (such as domestic gas reservation policies), changes in taxation regulation or enforcement (including, for example, changes in tax rates or increased focus on audits), taxation subsidies or royalties, nationalisation of resource assets or restrictions or moratoriums on our operations on government leases, limitations on periods of lease retention, interference with the confidentiality and availability of information, forced renegotiation of contracts, changes in laws and policies governing operations of foreign-based companies, trade sanctions, currency restrictions and exchange rate fluctuations and other governmental steps.

• Actual or alleged violations of the securities laws that we are subject to could result in private or governmental litigation, civil penalties, regulatory action and shareholder class actions.

• Downward adjustments of our reported reserves estimates could indicate lower future production volumes or the impairment of assets.

These impacts may lead to a loss in shareholder value, loss of market share to competitors, decreases in the value of assets, delays or stoppages in our operations, reduced capacity to fund capital projects, delayed or suspended regulatory approvals, legal liabilities and adverse impacts on Woodside’s reputation, social licence to operate and on the delivery of our strategy.

Woodside had a fatality in 2023. The tragic loss of our colleague, a contractor employee, has led to the implementation of additional controls based on preliminary investigation insights into the incident. The external investigations into the incident are ongoing.

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Finance and market

Risks associated with the ability to capture value whether markets are stable or volatile, and manage the risks associated with interest rate, commodity price and foreign exchange fluctuations and inflation. Generally, Woodside does not have control over the factors that affect market development and prices.

 How is this factor relevant to Woodside?

Woodside must be financially well positioned in order to pursue our strategic objectives and remain resilient during times of economic challenge. Several factors can affect our position, including:

• Market and commodity price: Woodside’s revenues are primarily derived from the sale of hydrocarbons. The prices Woodside receives for these products are variable and are impacted by global economic factors beyond Woodside’s control. We seek to forecast changes in the economic factors to enable us to maintain a strong market position during challenging economic times. Refer to section 6.3 - Additional disclosures and section A in the Notes to the Financial Statements for further information.

• Capital management: For Woodside to continue to operate sustainably we must make risk informed decisions related to allocation of capital. We seek to apply a disciplined and balanced approach to capital management through the commodity price cycle. Refer to section 2.2 - Capital management for further information.

• Foreign exchange risk: Woodside is exposed to foreign currency risk from future commitments, financial assets and financial liabilities that are not denominated in US dollars. Refer to section A in the Notes to the Financial Statements for further information.

• Interest rate risk: This is the risk that Woodside’s financial position will fluctuate due to changes in market interest rates. Woodside’s risk relates primarily to financial instruments with floating interest rates including long-term debt obligations, cash and short-term deposits. Refer to section C in the Notes to the Financial Statements for further information.

 Examples of how this factor may impact Woodside

• A reduced ability to fund our strategy including our projects.

• Significant volatility in energy prices, such as the volatility experienced in recent years, may increase the challenges associated with long-term plans.

• An imbalance in supply and demand can impact commodity prices and our ability to forecast market conditions determines whether we are impacted positively or negatively.

• Woodside may become a less attractive joint venture partner.

• Reduced shareholder returns due to lower commodity prices.

• If we inaccurately forecast the global demand for our LNG products we may face difficulties obtaining longer term sales contracts with desirable commercial terms.

• If counterparties to our derivative instruments are unable to fulfill their obligations, a larger percentage of our future oil and gas production could be subject to price changes.

• Inability to achieve anticipated synergies and cost savings on expected timeline or at all.

• Unforeseen costs relating to the integration of development, extraction and production operational systems, IT systems and financial and accounting systems of both businesses.

• Impairments of assets, goodwill or other intangible assets could have a significant negative effect on our reported net income and our ability to pay dividends in one or more accounting periods if the level of impairment were to exceed profits available for distribution.

These impacts may lead to a loss in shareholder value, loss of market share to competitors, decreases in the value of assets, delays or stoppages in our operations, reduced capacity to fund capital projects, delayed or suspended regulatory approvals, legal liabilities and adverse impacts on Woodside’s reputation, social licence to operate and on the delivery of our strategy.

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People and culture

Risks associated with the ability to attract, retain, develop and motivate key employees to succeed and safeguard both current or future performance and growth.

 How is this factor relevant to Woodside?

People are key to the success of Woodside. We must build and maintain a capable workforce if we are to achieve our objectives. An effective operating model with a balanced organisation structure will allow us to conduct our operations and pursue new energy opportunities. For Woodside to remain an employer of choice, our culture must support our current employees and attract the best new candidates.

 Examples of how this factor may impact Woodside

• During periods of high demand for skilled resources, Woodside may be unable to fill critical roles at acceptable costs or at all, leading to operational impacts.

• A limited ability to operate due to our people leaving critical roles.

• An inability to pursue innovation opportunities due to a skills shortage.

• Loss of key personnel or expert knowledge.

• An inability to reach timely agreements with employees including where represented by third parties may result in industrial action.

These impacts may lead to a loss in shareholder value, loss of market share to competitors, decreases in the value of assets, delays or stoppages in our operations, reduced capacity to fund capital projects, delayed or suspended regulatory approvals, legal liabilities and adverse impacts on Woodside’s reputation, social licence to operate and on the delivery of our strategy.

Digital and cybersecurity

Risks associated with adopting and implementing new technologies, whilst safeguarding our digital information and landscape (including from cyber threats) across our value chain.

 How is this factor relevant to Woodside?

Woodside must relentlessly protect the confidentiality, integrity and availability of digital information and operational technologies. Woodside’s technology systems including artificial intelligence and machine learning technologies, may be targeted by an internal or external malicious act or our systems may be disrupted unintentionally. Additionally, the cost of implementing and maintaining effective technology systems may be higher than anticipated. While our technology controls are designed to protect against all causes of disruption, we cannot be certain that they will protect our systems in all cases.

Refer to section 4.1.6 - Risk management and internal control and section 6.3 - Additional disclosures for further information on cybersecurity.

 Examples of how this factor may impact Woodside

• In the event of a cyber attack, Woodside’s confidential or sensitive information may be made public or held for ransom.

• Our operations may be disrupted if an attacker gains access to our control systems.

• Litigation and governmental proceedings arising from the occurrence of a cyber attack.

• Potential adverse impacts on our reputation and the safety of our employees and the communities in which we operate.

These impacts may lead to a loss in shareholder value, loss of market share to competitors, decreases in the value of assets, delays or stoppages in our operations, loss of revenue, increased expenses, reduced capacity to fund capital projects, delayed or suspended regulatory approvals, legal liabilities and adverse impacts on Woodside’s reputation, social licence to operate and on the delivery of our strategy.

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3.10 Our business

Reserves Statement

ABOUT THE RESERVES STATEMENT

This Reserves Statement presents Woodside’s proved oil and gas reserves, as of 31 December 2023, in accordance with the regulations of the United States Securities and Exchange Commission (SEC).¹

Unless stated otherwise, the following apply to this Reserves Statement: The effective date for reserves estimates is 31 December 2023. Estimates have been prepared in accordance with the reserve definitions of Rules 4-10(a) of SEC Regulations S-X and are calculated using SEC-compliant economic assumptions and pricing. Production is reported for the period from 1 January 2023 to 31 December 2023. Reserves and production stated are Woodside’s net share and inclusive of fuel consumed in operations. See “Methodology” below.

All numbers are internal estimates produced by Woodside. Estimates of reserves should be regarded only as estimates that may change over time as further production history and additional information becomes available. See “forward-looking statements”.

2023 PROVED RESERVES

Woodside produced a total of 201.0 MMboe in 2023, including 186.1 MMboe produced for sale and 15.0 MMboe of production consumed primarily as fuel in operations.² At 31 December 2023, Woodside’s remaining proved reserves were 2,450.1 MMboe (Table 1, 2).

The first-time booking of reserves at Trion in Mexico and Mad Dog Southwest in the US Gulf of Mexico increased proved reserves by 204.1 MMboe (shown as extensions and discoveries in Table 2), of which:

• final investment decision and regulatory approval of the field development plan at Trion in August 2023 increased proved reserves by 194.8 MMboe³; and

• approval of the Mad Dog Southwest Extension project increased proved reserves by 9.3 MMboe.

Revisions of previous estimates and transfers in 2023 resulted in a net increase of 61.8 MMboe for proved reserves. Key drivers for these revisions include:

• asset optimisation, including injector to producer conversions, and field performance at Angostura and Ruby in Trinidad and Tobago contributed to a proved reserves increase of 13.0 MMboe

• improved overall field performance and technical updates in North West Shelf increased proved reserves by 49.7 MMboe

• performance based revisions at Shenzi decreased proved reserves by 13.4 MMboe.

The reclassification of undeveloped reserves to developed reserves is discussed in the 2023 proved undeveloped reserves section of this Reserves Statement.

Table 1: Woodside’s proved reserves^4,5,6 overview (net Woodside share, as at 31 December 2023)

	Natural gas7 Bcf10		NGLs8 MMbbl11		Oil & condensate MMbbl		Total9 MMboe12		Fuel included in total MMboe
Proved13 developed14 and undeveloped15		10,496.9		21.0		587.5		2,450.1		228.1
Proved developed		2,582.1		18.7		266.0		737.7		63.5
Proved undeveloped		7,914.7		2.3		321.6		1,712.5		164.6

 Small differences are due to rounding

2022 PROVED RESERVES

Woodside produced 156.8 MMboe for sale in 2022, including 61.4 MMboe produced from 1 June 2022 from interests acquired as part of the merger with the BHP Petroleum business on 1 June 2022 (Acquired Assets). An additional 14.9 MMboe of production was consumed primarily as fuel in operations in the year ended 31 December 2022 resulting in a total production of 171.7 MMboe for 2022. At 31 December 2022, Woodside’s remaining proved reserves were 2,385.2 MMboe (Table 2).

The acquisition of the Acquired Assets on 1 June 2022 increased Woodside’s proved reserves as at 1 June 2022 by 922.8 MMboe to 2,339.6 MMboe.

2022 included revisions of previous estimates of 202.5 MMboe for proved reserves. Key drivers for the revisions include:

• completion of an Atlantis full field integrated subsurface study that resulted in a 46.3 MMboe increase in proved reserves

• inclusion of offshore fuel gas reserves and favourable commodity prices resulting in a net increase of 51.7 MMboe to proved undeveloped reserves at Scarborough

• inclusion of fuel gas reserves and incorporation of drilling results at Sangomar resulting in a proved undeveloped reserves increase of 24.7 MMboe

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• improved overall field performance at Pluto, North West Shelf, and Julimar-Brunello led to proved reserves increases of 31.7 MMboe, 17.6 MMboe, and 25.7 MMboe, respectively.

METHODOLOGY

Reserves estimates have not been adjusted for risk. Proved reserves are estimated and reported on a net interest basis, excluding royalties owned by others, in accordance with the SEC regulations and have been determined in accordance with SEC Rule 4-10(a) of Regulation S-X. As defined by the SEC, proved reserves are those quantities of crude oil, natural gas, and natural gas liquids that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs and under existing economic conditions, operating methods, operating contracts, and government regulations. Unless evidence indicates that renewal of existing operating contracts is reasonably certain, estimates of economically producible reserves reflect only the period before the contracts expire. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence within a reasonable time.

Proved reserves are estimated by reference to available well and reservoir information, including but not limited to well logs, well test data, core data, production and pressure data, geologic data, seismic data and, in some cases, similar data from analogous, producing reservoirs. A wide range of engineering and geoscience methods, including performance analysis, numerical simulation, well analogues and geologic studies, have been used to develop high confidence in estimated quantities.

GOVERNANCE AND ASSURANCE

Woodside has several processes designed to provide assurance for reserves reporting, including its Reserves and Resources Policy, Petroleum Resources Management Procedure, Reserves and Resources Guideline, annual staff training and minimum experience levels. In addition, Woodside has a dedicated and independent Corporate Reserves Team (CRT) that provides oversight and assurance of the reserves assessments and reporting processes. Reserves are estimated by staff in teams directly responsible for development and production activities. These individuals are trained in the fundamentals of reserves reporting and are approved by the CRT on an annual basis. Reserves assessments are reviewed annually by the CRT to ensure technical quality, adherence to internally published guidelines and compliance with SEC reporting requirements. All reserves are reviewed and approved by Woodside’s Qualified Petroleum Reserves Evaluator and approved by senior management and the Board prior to public reporting.

QUALIFIED PETROLEUM RESERVES EVALUATOR STATEMENT

The estimates of petroleum reserves are based on and fairly represent information and supporting documentation prepared by, or under the supervision of Mr. Ben Stephens, Woodside’s Vice President Reserves and Subsurface, who is a full-time employee of the company and a member of the Society of Petroleum Engineers. The Reserves Statement as a whole has been approved by Mr. Stephens. Mr. Stephen’s qualifications include a Bachelor of Engineering (Petroleum Engineering) from the University of New South Wales, Australia, and 20 years of relevant experience.

Table 2: Proved developed and undeveloped reserves reconciliation (net Woodside share, as at 31 December 2023)

	Australia				International16				Total
	Natural gas	NGLs	Oil & condensate	Total	Natural gas	NGLs	Oil & condensate	Total	Natural gas	NGLs	Oil & condensate	Total
	Bcf	MMbbl	MMbbl	MMboe	Bcf	MMbbl	MMbbl	MMboe	Bcf	MMbbl	MMbbl	MMboe
Reserves as at 31 December 2020	2,502.5	0.0	61.1	500.1	0.0	0.0	0.0	0.0	2,502.5	0.0	61.1	500.1
Acquisitions and divestments17	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0
Extensions and discoveries18	5,146.4	0.0	0.2	903.0	0.0	0.0	81.2	81.2	5,146.4	0.0	81.3	984.2
Revision of previous estimates19	151.2	0.0	12.9	39.5	0.0	0.0	0.0	0.0	151.2	0.0	12.9	39.5
Production	-430.1	0.0	-16.7	-92.1	0.0	0.0	0.0	0.0	-430.1	0.0	-16.7	-92.1
Reserves as at 31 December 2021	7,370.0	0.0	57.5	1,350.5	0.0	0.0	81.2	81.2	7,370.0	0.0	138.7	1,431.6
Acquisitions and divestments	3,096.1	18.3	34.0	595.4	251.2	7.7	275.6	327.4	3,347.4	26.0	309.6	922.8
Extensions and discoveries	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0
Revision of previous estimates	682.3	3.6	12.3	135.6	112.0	2.1	45.2	66.9	794.3	5.7	57.5	202.5
Production	-692.5	-4.5	-24.0	-150.0	-35.4	-0.8	-14.7	-21.7	-728.0	-5.3	-38.7	-171.7
Reserves as at 31 December 2022	10,455.8	17.3	79.7	1,931.4	327.8	9.0	387.3	453.8	10,783.6	26.3	467.0	2,385.2
Acquisitions and divestments	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0
Extensions and discoveries	0.0	0.0	0.0	0.0	177.9	0.4	172.5	204.1	177.9	0.4	172.5	204.1
Revision of previous estimates	308.6	2.2	15.4	71.8	35.6	-0.6	-15.6	-9.9	344.3	1.6	-0.2	61.8
Production	-738.4	-5.9	-22.7	-158.1	-70.6	-1.4	-29.2	-43.0	-809.0	-7.3	-51.8	-201.0
Reserves as at 31 December 202320	10,026.1	13.6	72.5	1,845.1	470.7	7.4	515.0	605.0	10,496.9	21.0	587.5	2,450.1
Fuel included in 31 December 2023 reserves	1,128.4	0.5	0.0	198.5	169.1	0.0	0.0	29.7	1,297.5	0.5	0.0	228.1

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Proved developed and undeveloped reserves
Proved developed reserves
as at 31 December 2020	1,778.5	0.0	51.2	363.3	0.0	0.0	0.0	0.0	1,778.5	0.0	51.2	363.3
as at 31 December 2021	1,744.5	0.0	50.2	356.3	0.0	0.0	0.0	0.0	1,744.5	0.0	50.2	356.3
as at 31 December 2022	2,722.6	16.7	73.3	567.6	202.5	5.9	161.0	202.4	2,925.1	22.5	234.3	770.0
as at 31 December 2023	2,361.3	12.6	67.9	494.8	220.8	6.1	198.0	242.8	2,582.1	18.7	266.0	737.7
Proved undeveloped reserves
as at 31 December 2020	724.0	0.0	9.8	136.8	0.0	0.0	0.0	0.0	724.0	0.0	9.8	136.8
as at 31 December 2021	5,625.5	0.0	7.2	994.2	0.0	0.0	81.2	81.2	5,625.5	0.0	88.4	1,075.3
as at 31 December 2022	7,733.2	0.7	6.4	1,363.8	125.2	3.1	226.3	251.4	7,858.5	3.8	232.8	1,615.2
as at 31 December 2023	7,664.9	1.0	4.6	1,350.3	249.9	1.3	317.0	362.2	7,914.7	2.3	321.6	1,712.5

Small differences are due to rounding

2023 PROVED UNDEVELOPED RESERVES

At 31 December 2023, Woodside’s remaining proved undeveloped reserves were 1,712.5 MMboe, representing an increase of 97.2 MMboe from the 1,615.2 MMboe as at 31 December 2022 (Table 3).

Extensions and discoveries increased proved undeveloped reserves by 204.1 MMboe following the final investment decision and regulatory approval of the field development plan at Trion, and approval of the Mad Dog Southwest Extension project.

In 2023, 87.7 MMboe of proved undeveloped reserves were converted to proved developed reserves with start-up of development wells in Mad Dog Phase 2 (56.0 MMboe), Shenzi North (10.5 MMboe), Atlantis (8.7 MMboe), and Pyrenees (1.1 MMboe), and completion of offshore Pluto water handling (11.3 MMboe). Technical studies and performance resulted in a 3.4 MMboe decrease to proved undeveloped reserves. The effect of commodity prices relative to 2022 resulted in a 15.8 MMboe reduction to proved undeveloped reserves at Sangomar.

Undeveloped reserves in Julimar Brunello have remained undeveloped for longer than five years from the dates they were initially reported and are expected to be developed in a phased manner to meet long-term contractual commitments. The project is included in the company business plan, demonstrating the intent to proceed with the development.

During 2023, Woodside spent $5.3 billion on development activities worldwide. Of this amount, $4.7 billion was spent progressing the conversion of proved undeveloped reserves for projects where development status was achieved in 2023 or is expected to be achieved when development is completed in the future.

2022 PROVED UNDEVELOPED RESERVES

At 31 December 2022, Woodside’s remaining proved undeveloped reserves were 1,615.2 MMboe, which is roughly 68% of the total remaining proved reserves of 2,385.2 MMboe (Table 3). This represents an increase in proved undeveloped reserves of 539.9 MMboe from the 1,075.3 MMboe as at 31 December 2021. The largest element of this increase was a 529.7 MMboe increase as a result of the acquisition of the Acquired Assets.

During 2022, a total of 54.0 MMboe proved undeveloped reserves were converted to proved developed reserves through development activities primarily in the following projects: Greater Western Flank Phase 3 and Lambert Deep developments at North West Shelf in Australia (20.5 MMboe), infill well (XNA02) to support ongoing production from the Pluto LNG Project in Australia (15.8 MMboe), and multiple development opportunities at Shenzi in the US Gulf of Mexico including installation and commissioning of subsea multiphase pumping and well completions (17.1 MMboe).

Development plan changes in Sangomar and Julimar-Brunello Phase 3 resulted in increases to proved undeveloped reserves of 24.7 MMboe and 4.1 MMboe, respectively. Favourable commodity prices resulted in an increase of 15.5 MMboe in proved undeveloped reserves. Additionally, a net increase of 19.9 MMboe in proved undeveloped reserves occurred due to positive revisions in Scarborough and Bass Strait partially offset by negative revisions due to technical studies and performance at Pluto and Julimar-Brunello.

During 2022, Woodside spent $3.8 billion on development activities worldwide. Of this amount, $3.5 billion was spent progressing the conversion of proved undeveloped reserves for projects where development status was achieved in 2022 or is expected to be achieved when development is completed in the future.

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Table 3: Proved undeveloped reserves reconciliation (net Woodside share, as at 31 December)

MMboe		2023		2022
Proved undeveloped reserves opening balance			1,615.2		1,075.3
Extensions and discoveries			204.1		0.0
Revision of previous estimates			-106.9		10.2
	Reclassifications to developed		-87.7		-54.0
	Performance, technical studies, and other		-3.4		19.9
	Development plan changes		0.0		28.8
	Price		-15.8		15.5
Acquisitions and divestments			0.0		529.7
Proved undeveloped reserves closing balance			1,712.5		1,615.2

Small differences are due to rounding

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NOTES TO THE RESERVES STATEMENT

1. Woodside is an Australian company listed on the Australian Securities Exchange, the New York Stock Exchange, and the London Stock Exchange. Woodside reports its proved reserves in accordance with SEC regulations. These guidelines are also compliant with 2018 Society of Petroleum Engineers/World Petroleum Council/American Association of Petroleum Geologists/Society of Petroleum Evaluation Engineers Petroleum Resources Management System (SPE-PRMS).

2. ‘Production’ is the volume of natural gas, natural gas liquids (NGLs), condensate and oil produced during the period from 1 January 2023 to 31 December 2023 and converted to ‘MMboe’ for the specific purpose of reserves reconciliation. The production volume figures in this Reserves Statement differ from the production volume figures reported elsewhere in Woodside’s reports, because the production volume figures reported in this Reserves Statement include all fuel consumed in operations but exclude 1.1 MMboe in excess of reserves working interest percentage from Pluto non-operating participants processed via the Pluto-KGP Interconnector. Small differences are due to rounding.

3. The estimation of material additions to proved reserves was developed through the utilisation of available well and reservoir information. This included, but not limited to, well logs, well test data, core data and analyses, seismic data, pressure data, PVT data, and geologic data. This information formed the basis for a range of engineering and geoscience analyses, including numerical simulation, uncertainty studies, analogue benchmarking, and geologic and petrophysical studies.

4. For offshore oil projects, the reference point is defined as the outlet of the floating production storage and offloading facility (FPSO) or platform, while for the onshore gas projects the reference point is defined as the outlet of the downstream (onshore) gas processing facility.

5. ‘Reserves’ are estimated quantities of petroleum that have been demonstrated to be producible from known accumulations in which the company has a material interest from a given date forward, at commercial rates, under presently anticipated production methods, operating conditions, prices, and costs. Woodside reports reserves inclusive of all fuel consumed in operations. Proved reserves are estimated and reported in accordance with SEC regulations which are also compliant with SPE-PRMS guidelines. SEC-compliant proved reserves estimates use a more restrictive, rules-based approach and are generally lower than estimates prepared solely in accordance with SPE-PRMS guidelines due to, among other things, the requirement to use commodity prices based on the average of first of month prices during the 12-month period in the reporting company’s fiscal year.

6. All proved reserves estimates have been estimated using deterministic methods and reported on a net interest basis in accordance with the SEC regulations, and have been determined in accordance with SEC Rule 4-10(a) of Regulation S-X. Unless otherwise stated, all petroleum estimates reported at the company or region level are aggregated by arithmetic summation by category. The aggregated proved reserves may be a conservative estimate due to the portfolio effects of arithmetic summation.

7. ‘Natural gas’ is defined as the gas product associated with liquefied natural gas (LNG) and pipeline gas. Liquid volumes of crude oil, condensate, and NGLs are reported separately.

8. ‘Natural gas liquids’ or ‘NGLs’ is defined as the product associated with liquified petroleum gas (LPG) and consists of propane, butane, and ethane - individually or as a mixture.

9. ‘Total’ includes fuel consumed in operations.

10. ‘Bcf’ means Billions (10⁹) of cubic feet of gas at standard oilfield conditions of 14.696 psi (101.325 kPa) and 60 degrees Fahrenheit (15.56 degrees Celsius).

11. ‘MMbbl’ means millions (10⁶) of barrels of NGLs, oil and condensate at standard oilfield conditions of 14.696 psi (101.325 kPa) and 60 degrees Fahrenheit (15.56 degrees Celsius).

12. ‘MMboe’ means millions (10⁶) of barrels of oil equivalent. Natural Gas volumes are converted to oil equivalent volumes via a constant conversion factor, which for Woodside is 5.7 Bcf of dry gas per 1 MMboe. Volumes of NGLs, oil and condensate are converted from MMbbl to MMboe on a 1:1 ratio.

13. ‘Proved reserves’ are those quantities of crude oil, condensate, natural gas and NGLs that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs and under existing economic conditions, operating methods, operating contracts, and government regulations. Proved reserves are estimated and reported on a net interest basis in accordance with the SEC regulations and have been determined in accordance with SEC Rule 4-10(a) of Regulation S-X.

14. ‘Developed reserves’ are those reserves that are producible through currently existing completions and installed facilities for treatment, compression, transportation, and delivery, using existing operating methods and standards.

15. ‘Undeveloped reserves’ are those reserves for which wells and facilities have not been installed or executed but are expected to be recovered through future significant investments.

16. ‘International’ consists of Trinidad and Tobago, Senegal, Mexico, and the United States Gulf of Mexico.

17. ‘Acquisitions and divestments’ are revisions that represent changes (either upward or downward) in previous estimates of reserves which result from either purchase or sale of interests and/or execution of contracts conveying entitlement.

18. ‘Extensions and discoveries’ represent additions to reserves that result from increased areal extensions of previously discovered fields demonstrated to exist subsequent to the original discovery and/or discovery of reserves in new fields or new reservoirs in old fields.

19. ‘Revision of previous estimates’ are changes (either upward or downward) in previous estimates of reserves, resulting from new information normally obtained from development drilling and production history, or resulting from a change in economic factors.

20. Scarborough proved undeveloped reserves as at 31 December 2023 are 7,336.0 Bcf (1,287.0 MMboe). Development activities are underway. In this Reserves Statement, Scarborough estimates are based on one hundred per cent interest in the Scarborough Joint Venture until completion of the transaction with LNG Japan referenced in the announcement on 8 August 2023 entitled “Woodside to Sell 10% Scarborough Interest to LNG Japan”.

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4.1 Governance

Corporate Governance Statement

4.1.1 Corporate governance at Woodside

Woodside is committed to a high level of corporate governance and fostering a culture of ethical behaviour, integrity and respect. The Board is responsible for the overall corporate governance of Woodside.

Woodside’s corporate governance model is illustrated in the diagram below. The Woodside Management System (WMS) describes the Woodside way of working, enabling Woodside to understand and manage its business to achieve its objectives. It defines the boundaries within which Woodside employees and contractors are expected to work. The WMS establishes a common approach to how we operate, wherever the location.

Woodside continues to review and, where necessary, enhance our corporate governance policies and practices. We frequently consider developments arising in the markets where Woodside securities are listed, including the Australian Securities Exchange (ASX), London Stock Exchange (LSE) and New York Stock Exchange (NYSE). Our practices will evolve as we continually look to strengthen our governance framework in the context of our multi-jurisdictional business.

The company must comply with the Corporations Act 2001 (Cth), the ASX Listing Rules, UK Listing Rules, UK Disclosure Guidance and Transparency Rules, UK Market Abuse Regulation, relevant provisions of the NYSE Listed Company Manual and US securities laws applicable to Woodside as a foreign private issuer and other applicable Australian and international laws. This Corporate Governance Statement (Statement) reports on Woodside’s key governance principles and practices.

The ASX Listing Rules require the company to report on the extent to which it has followed the Corporate Governance Recommendations contained in the fourth edition of the ASX Corporate Governance Council’s Principles and Recommendations (ASXCGC Recommendations). The UK Disclosure Guidance and Transparency Rules, the NYSE listing standards and US securities laws also require the company to report on its governance arrangements and the governance code that it applies.

The ASXCGC Recommendations are publicly available at https://www.asx.com.au/documents/asx-compliance/cgc-principles-and-recommendations-fourth-edn.pdf.

The ASXCGC Recommendations are not incorporated by reference to this Statement. As shown in this Statement, throughout the year, Woodside complied with all ASXCGC Recommendations. Woodside is also subject to certain governance requirements of the LSE, the NYSE and the SEC. Refer to the section ‘Differences from NYSE corporate governance requirements’ for further information.

The Statement is current as at 27 February 2024 (unless otherwise specified) and has been approved by the Board.

All Board and committee charters and copies of the policies and documents referred to in this Statement are available on the Corporate Governance and Policies section of our website at woodside.com.

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4.1.2 Board of directors

Board role and responsibilities

The Constitution provides that the business and affairs of the company are to be managed by or under the direction of the Board. The central role of the Board is to set the company’s strategic direction, to select and appoint a Chief Executive Officer (CEO) and to oversee the company’s management and business activities.

The Board’s role, powers, duties and functions are formalised in a Board Charter. Each year the Board performs its central role as set out in the Charter. The Charter sets out the matters and functions that are specifically reserved to the Board and the powers that are delegated to the CEO and management.

The Board Charter and the delegation of Board authority to the CEO and management are reviewed regularly.

Some of the key activities of the Board undertaken during the year include overseeing:

• management’s response to key safety events, including the fatality of a colleague employed by a contractor at the North Rankin Complex

• Woodside’s strategy and providing input and guidance including on management’s execution of strategy

• the monitoring of impact of certain macroeconomic and geopolitical events on the global energy market

• the appointment of Liz Westcott as Executive Vice President Australian Operations effective June 2023

• the plan to implement emissions reductions to meet the company’s near and medium-term emissions reduction targets and support Woodside’s pathway towards its aspiration of net zero equity Scope 1 and 2 greenhouse gas emissions by 2050 or sooner¹ and consideration of adopting a Scope 3 emissions abatement target

• the final investment decision to develop the Trion resource in Mexico

• management’s response to policy and regulatory developments, including legal challenges to regulatory decision making in Australia

• the sale of a 10% non-operating participating interest in the Scarborough Joint Venture to LNG Japan²

• the progression of carbon capture and storage studies and the H2OK hydrogen project

• the Scarborough and Pluto Expansion Projects and the Sangomar Field Development

• the commencement of production from the Mad Dog Phase 2 project and the Shenzi North project in the deepwater US Gulf of Mexico

• the appointment of two new directors to the Board.

Board composition

The Constitution provides that the company is not to have more than 12, nor less than three directors. At the date of this report, the Board is comprised of 11 independent non-executive directors and the CEO. The following page shows each of the current directors and those directors who served during the year and the date of their appointment as a director.

1 Target is for net equity Scope 1 and 2 greenhouse gas emissions, relative to a starting base representative of the gross annual average equity Scope 1 and 2 greenhouse gas emissions over 2016-2020 and may be adjusted (up or down) for potential equity changes in producing or sanctioned assets with an FID prior to 2021.

2 Subject to completion of the transaction, targeted in the first quarter of 2024.

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Richard Goyder, AO

BCom, FAICD

Chair: Chair since April 2018.

Term of office: Director since August 2017, re-election required at AGM in 2024.

Independent: Yes

Experience: Mr Goyder spent 24 years with Wesfarmers Limited, where he served as Managing Director and Chief Executive Officer from 2005 to late 2017. Mr Goyder also served as Chair of the Australian B20 (the key business advisory body to the international economic forum which includes business leaders from all G20 economies) from February 2013 to December 2014.

Committee membership: Chair of the Nominations & Governance Committee. Attends other Board committee meetings.

Current directorships/other interests:

Chair: Qantas Airways Limited (since 2018), Channel 7 Telethon Trust (since 2018), West Australian Symphony Orchestra (WASO) (since 2018) and Australian Football League Commission (since 2017). Mr Goyder will retire as chairman of Qantas Airways Limited before the next Qantas Annual General Meeting in late 2024.

Other directorships of listed entities within the past three years: Nil.

Meg O’Neill

BSc (Ocean Engineering), BSc (Chemical Engineering), MSc (Ocean Systems Management)

CEO and Managing Director

Term of office: Director since August 2021.

Independent: No

Experience: Ms O’Neill joined Woodside in 2018 and has performed a number of senior executive positions including Chief Operations Officer, Executive Vice President Development and Executive Vice President Development and Marketing. From April 2021 to August 2021, Ms O’Neill was acting CEO until she was formally appointed to the position.

Prior to joining Woodside, Ms O’Neill spent 23 years with ExxonMobil in a variety of technical, operational and senior leadership roles.

Committee membership: Attends Board committee meetings.

Current directorships/other interests:

Chair: Australian Energy Producers (since 2022).

Director: American Petroleum Institute (API) (since 2022), Reconciliation WA (since 2022), WA Venues & Events Pty Ltd (WAVE) (since 2019) and West Australian Symphony Orchestra (WASO) (since 2019).

Member: Chief Executive Women, National Petroleum Council (US) and UWA Business School Advisory Board.

Other: Honorary Governor of the American Chamber of Commerce (AmCham).

Other directorships of listed entities within the past three years: Nil.

Larry Archibald

BSc (Geosciences), BA (Geology), MBA

Term of office: Director since February 2017, re-election required at AGM in 2026.

Independent: Yes

Experience: Mr Archibald previously worked at ConocoPhillips, where he spent eight years in senior executive positions including Senior Vice President, Business Development and Exploration and Senior Vice President, Exploration. Prior to joining ConocoPhillips, Mr Archibald spent 29 years at Amoco from 1980 to 1998 and BP from 1998 to 2008 in various positions including leading exploration programs covering many world regions.

Committee membership: Audit & Risk, Sustainability and Nominations & Governance Committees.

Current directorships/other interests:

Chair: University of Arizona Geosciences Advisory Board (since 2019).

Other directorships of listed entities within the past three years: Nil.

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Ashok Belani

M.S. Engineering

Term of office: Director since January 2024,

election required at AGM in 2024.

Independent: Yes

Experience: Mr Belani joined SLB (formerly Schlumberger) in 1980 and served as a senior executive of SLB from 2011 until his retirement in 2022, Mr Belani held several senior executive roles at SLB including President Reservoir Characterization, Executive Vice President Technology and most recently, Executive Vice President New Energy where he was responsible for deploying differentiated technologies and practices to decarbonise exploration and production operations, and the development of new avenues of growth in emerging markets with carbon-neutral technologies. Mr Belani continued to work as a Senior Advisor to SLB from 2022.

Committee membership: Member of the Sustainability, Audit & Risk and Nominations & Governance Committees.

Current directorships/other interests:

Director: Gentari Sdn. Bhd. (since 2023), Enervenue, Inc. (since 2021) and AMGreen Group (since 2024).

Member: Board of AStar, the agency for science and technology for the Government of Singapore.

Other directorships of listed entities within the past three years: Nil.

Arnaud Breuillac

MSc Engineering

Term of office: Director since March 2023, re-election required at AGM in 2026.

Independent: Yes

Experience: Mr Breuillac had a 40-year career with TotalEnergies SE, including as President Middle East, Senior Vice President E&P, Continental Europe and Central Asia, and seven years as President Exploration & Production before his retirement at the end of 2021. From 2021 to 2022, Mr Breuillac continued as Senior Advisor to the Chair and Chief Executive Officer of TotalEnergies.

Committee membership: Chair of the Human Resources & Compensation Committee. Member of Sustainability and Nominations & Governance Committees.

Current directorships/other interests:

Director: Trident Energy Ltd (since 2022) and Géosel Manosque SAS (since 2022).

Member: Board of ACL (Association des diplomes de l’ECL).

Other: President of ECL (Ecole Centrale de Lyon) Endowment Fund.

Other directorships of listed entities within the past three years: Nil.

Frank Cooper, AO

BCom, FCA, FAICD

Term of office: Director since February 2013.¹

Independent: Yes

Experience: Mr Cooper was a Partner at PricewaterhouseCoopers from 2006 until his retirement in 2012, and a director of the Insurance Commission of Western Australia until September 2022. Prior to joining PricewaterhouseCoopers, Mr Cooper was a partner of Ernst & Young from 2002 to 2005 and managing partner of Arthur Andersen from 1991 to 2002.

Committee membership: Chair of the Audit & Risk Committee. Member of the Human Resources & Compensation, and Nominations & Governance Committees.

Current directorships/other interests:

Director: Wright Prospecting Pty Ltd (since 2022), St John of God Australia Limited (since 2015) and South32 Limited (since 2015).

Trustee: St John of God Health Care (since 2015).

Other directorships of listed entities within the past three years: Nil.

1 Anticipated to retire from the Board at or before the Annual General Meeting in April 2024.

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Swee Chen Goh

BSc (Information Science), MBA

Term of office: Director since January 2020, re-election required at AGM in 2026.

Independent: Yes

Experience: Ms Goh joined Shell in 2003 and was the Chair of Shell Companies in Singapore from 2014 until her retirement in 2019.

During her tenure at Shell, Ms Goh served on the boards of a number of Shell joint ventures in China, Korea and Saudi Arabia. Prior to joining Shell, Ms Goh worked at Procter & Gamble and IBM.

Committee membership: Member of the Human Resources & Compensation, Sustainability and Nominations & Governance Committees.

Current directorships/other interests:

Chair: Nanyang Technological University (since 2021) and National Arts Council (since 2019).

Director: Carbon Solutions Holdings Pte Ltd (since 2022), Carbon Solutions Platform Pte Ltd (since 2022), Carbon Solutions Investments Pte Ltd (since 2022), Carbon Solutions Services Pte Ltd (since 2022), JTC Corporation (since 2022), Singapore Airlines Ltd (since 2019) and Singapore Power Ltd (since 2019).

Member: Singapore Legal Services Commission, Centre for Liveable Cities Advisory Panel and Singapore Research, Innovation and Enterprise Council.

Other directorships of listed entities within the past three years: CapitaLand Investment Limited (2017 to 2022).

Ian Macfarlane

Former Australian Federal Minister (Resources; Energy; Industry and Innovation), FAICD

Term of office: Director since November 2016, re-election required at AGM in 2026.

Independent: Yes

Experience: Mr Macfarlane served as director of METS Ignited Ltd and was Australia’s longest serving Federal Resources and Energy Minister, and the Coalition’s longest serving Federal Industry and Innovation Minister, with over 14 years of experience in both Cabinet and shadow ministerial positions. Prior to entering politics, Mr Macfarlane was the President of the Queensland Graingrowers Association from 1991 to 1998 and the President of the Grains Council of Australia from 1994 to 1996.

Committee membership: Member of the Human Resources & Compensation, Sustainability and Nominations & Governance Committees.

Current directorships/other interests:

Director: Sovereign Manufacturing Automation for Composites Cooperative Research Centre (since 2023), CSIRO (since 2021) and Toowomba and Surat Basin Enterprise Board (since 2018).

Member: Fellow of the Australian Institute of Company Directors, Toowoomba Community Advisory Committee of the University of Queensland Rural Clinical School and Mooloolaba and the Spit Association.

Other directorships of listed entities within the past three years: Nil.

Angela Minas

MBA Finance, BA Managerial Studies

Term of office: Director since April 2023, re- election required at AGM in 2026.

Independent: Yes

Experience: Ms Minas is an experienced financial executive with strong capital markets experience, including six years as a public company Chief Financial Officer (CFO) at Constellation Energy Partners LLC and DCP Midstream LLC. Ms Minas spent the first 20 years of her career in investment banking and management consulting, including as Arthur Andersen’s Partner leading the North American oil and gas consulting practice and at Leidos (formerly known as SAIC) as Senior VP, global consulting leader.

Committee membership: Member of the Audit & Risk, Sustainability and Nominations & Governance Committees.

Current directorships/other interests: Director: Vallourec S.A. (since 2021).

Member: Rice University Business School Board of Advisors, National Association of Corporate Directors, Women Corporate Directors.

Other directorships of listed entities within the past three years: Westlake Chemical Partners (2016 to 2023) and Crestwood Equity Partners L.P. (2022 to 2023).

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Ann Pickard

BA, MA

Term of office: Director since February 2016, re-election required at AGM in 2025.

Independent: Yes

Experience: Ms Pickard joined Shell in 2000 and served in a number of senior executive positions including as the Director, Global Business and Strategy and as a member of the Shell Gas & Power Executive Committee. Ms Pickard retired from Shell in 2016. Prior to joining Shell, Ms Pickard spent 11 years with Mobil before its merger with Exxon in 1998.

Committee membership: Chair of the Sustainability Committee. Member of the Human Resources & Compensation and Nominations & Governance Committees.

Current directorships/other interests:

Director: Noble Corporation Plc. (since 2021) and KBR Inc (since 2015).

Member: Chief Executive Women and University of Wyoming Foundation Board.

Other directorships of listed entities within the past three years: Nil.

Gene Tilbrook

BSc, MBA, FAICD

Term of office: Director since December 2014.¹

Independent: Yes

Experience: Mr Tilbrook served as a senior executive of Wesfarmers Limited between 1985 and 2009, including as Executive Director Finance and Executive Director Business Development.

Committee membership: Member of the Audit & Risk, Human Resources & Compensation and Nominations & Governance Committees.

Current directorships/other interests:

Director: Orica Limited (since 2013).

Member: Life Fellow of the Australian Institute of Company Directors.

Other directorships of listed entities within the past three years: GPT Group Limited (2010 to 2021).

Ben Wyatt

LLB, MSc

Term of office: Director since June 2021, re-election required at AGM in 2025.

Independent: Yes

Experience: Mr Wyatt served in the Western Australian Legislative Assembly for 15 years, including as the Western Australian Treasurer and Minister for Finance, Energy, Aboriginal Affairs and Lands. Additionally, Mr Wyatt held various shadow cabinet portfolios including Shadow Treasurer (2008 to 2017) and responsibility for Native Title and the Pilbara.

Prior to entering Parliament, Mr Wyatt practised as a lawyer in both private practice and with the Western Australian Office of the Director of Public Prosecutions.

Committee membership: Member of the Human Resources & Compensation, Audit & Risk and Nominations & Governance Committees.

Current directorships/other interests:

Director: APM Group (since 2022), Rio Tinto Ltd (since 2021), Wyatt Martin Pty Ltd (since 2021), West Coast Eagles (since 2021), Perth International Arts Festival (since 2021), Telethon Kids Institute (since 2021).

Member: UWA Business School Advisory Board, Australian Institute of Company Directors and Australian Capital Equity Pty Ltd Advisory Board.

Other directorships of listed entities within the past three years: Nil.

Christopher Haynes, OBE

BSc, DPhil, FREng, CEng, FIMechE, FIEAust

Independent: Yes

Experience: Dr Haynes retired on 28 April 2023 after 11 years of service on Woodside’s Board of Directors.

Dr Haynes served on a number of Woodside Board committees including as a member of the Audit & Risk, Sustainability and Nominations & Governance Committees.

Sarah Ryan

BSc (Geology), BSc (Geophysics) (Hons 1), PhD (Petroleum and Geophysics), FTSE

Independent: Yes

Experience: Dr Ryan retired on 28 April 2023 after ten years of service on Woodside’s Board of Directors.

Dr Ryan served on a number of Woodside Board committees including as a member of the Audit & Risk, Sustainability and Nominations & Governance Committees.

1 Will retire from the Board on 28 February 2024.

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Director appointment, induction training and continuing education

All new non-executive directors are required to sign a letter of appointment which sets out the key terms and conditions of their appointment, including duties, rights and responsibilities, the time commitment envisaged, and the Board’s expectations regarding their involvement with committee work.

Executive Directors and other Senior Executives enter into employment agreements which govern the terms of their employment. Woodside undertakes extensive background and screening checks prior to appointing Senior Executives. Details of Woodside’s Senior Executives are set out in section 4.1.4 - Executive Leadership Team.

Woodside also undertakes extensive background and screening checks prior to nominating a director for election by shareholders, including checks as to character, experience, education, criminal record and bankruptcy history. Woodside provides to shareholders all material information in its possession concerning the director standing for election or re-election in the explanatory notes accompanying the notice of meeting.

Induction training is provided to all new directors. It includes a comprehensive induction manual, discussions with the CEO and Senior Executives, and the option to visit Woodside’s principal operations either upon appointment or with the Board during its next site tour.

Questionnaires are completed annually to assess each director’s skills and knowledge required to discharge their obligations to the company. Woodside considers at least annually the need for new and existing directors to undertake professional development to develop and maintain the skills and knowledge needed to perform their role as directors effectively, and provides directors the opportunity to develop and maintain the required skills and knowledge. Directors attend continuing professional education sessions, including industry seminars and approved education courses, which are paid for by the company, where appropriate.

Director remuneration

Details of remuneration paid to directors (executive and non-executive) are set out in the 2023 Remuneration Report in section 4.3 – Remuneration Report. The Remuneration Report also contains information on the company’s policy for determining the nature and amount of remuneration for directors and Senior Executives and the relationship between the policy and company performance.

Board access to information and independent advice

Subject to the Directors’ Conflict of Interest Policy, directors have direct access to members of company management and to company information in the possession of management. Directors are entitled to obtain independent legal, accounting or other professional advice at the company’s expense where a request for such advice is approved by the Chair. In the case of a request made by the Chair, approval is required by a majority of the non-executive directors.

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Director attendance at meetings

Directors in office, committee membership and directors’ attendance at meetings during 2023

									Human Resources								Nominations
Director	Board				Audit & Risk				& Compensation				Sustainability				& Governance
	Held1		Attended2		Held1		Attended2		Held1		Attended2		Held1		Attended2		Held1		Attended2
Executive Director
Meg O’Neill		12		12				8				5				4				3
Non-Executive Director
Larry Archibald		12		12		8		8				4		4		4		3		3
Arnaud Breuillac3		9		9				6		3		3		3		3		2		2
Frank Cooper		12		12		8		8		5		4				2		3		2
Swee Chen Goh		12		12				7		5		4		4		4		3		3
Richard Goyder		12		12				8				5				4		3		3
Chris Haynes4		4		4		3		3		2		2		2		2		1		1
Ian Macfarlane		12		12				8		5		5		4		4		3		3
Angela Minas4		9		9		6		6				2		3		3		2		2
Ann Pickard		12		12				8		5		5		4		4		3		3
Sarah Ryan4		4		4		3		3		2		2		2		2		1		1
Gene Tilbrook		12		11		8		7		5		5				3		3		3
Ben Wyatt		12		11		8		8		5		5		4		4		3		3

   Current Chair    Current Member   Prior Member

1 ‘Held’ indicates the number of meetings held during the period of each director’s tenure. Where a director is not a member but attended meetings during the period, then only the number of meetings attended rather than held is shown.

2 ‘Attended’ indicates the number of meetings attended by each director. All directors are entitled to and generally attend meetings of the standing committees.

3 Mr Breuillac was appointed on 8 March 2023.

4 Dr Haynes and Dr Ryan retired at the 2023 Annual General Meeting on 28 April 2023. Ms Minas was appointed at the conclusion of the Annual General Meeting.

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Board performance evaluation

Board performance evaluations are conducted annually.

The Board performance evaluation process is conducted by way of questionnaires appropriate in scope and content to effectively review:

• the performance of the Board and each of its committees against the requirements of their respective charters;

• the individual performance of the Chair and each director; and

• the interface between Board and management.

The Board performance evaluation process may also involve interviews with directors and senior management, and observation of Board and committee meetings by an external consultant. The reports on Board and committee performance are provided to all directors and discussed by the Board. The report on the Chair’s performance is provided to the Chair and two committee chairs for discussion.

A report on each individual director is also provided to the individual and to the Chair. The Chair meets individually with each director to discuss the findings of their report. The Board, through the Nominations & Governance Committee, considers and discusses the final report in detail.

The performance of each director retiring at the next AGM is taken into account by the Board in determining whether or not the Board should support the re-election of the director. The directors seeking re-election will be asked to reconfirm that they have sufficient time to meet their responsibilities.

The Human Resources & Compensation Committee reviews and makes recommendations to the Board on the criteria for the evaluation of the performance of the CEO. The Board conducts the evaluation of the performance of the CEO and considers senior executive succession planning.

In 2023, performance evaluations for the Board, its committees, directors and Senior Executives took place in accordance with the process disclosed above, and in the section on ‘Performance evaluation of Executive Leadership Team’ and in the Remuneration Report.

Directors’ retirement and re-election

The Woodside Constitution sets out the requirements for the retirement and re-election of directors. With the exception of the CEO/Managing Director, directors must retire at the third AGM following their election or most recent re-election. At least one director must stand for election at each AGM.

Board support for a director’s re-election is not automatic and is subject to satisfactory director performance and assessment of overall Board composition and capabilities.

Director independence

In accordance with the Policy on Independence of Directors, the Board assesses independence with reference to whether a director is non-executive, not a member of management and is free of any business or other relationship that could materially interfere with, or could reasonably be perceived to materially interfere with, the independent exercise of their judgement.

In making this assessment, the Board considers all relevant facts and circumstances. In particular, the Board focuses on the factors relevant to assessing the independence of a director set out in Box 2.3 of the ASXCGC Recommendations.

The Board has reviewed the independence of each of the non-executive directors in office at the date of this Statement and determined they are all independent. The CEO, Meg O’Neill, is not considered independent as she is an Executive Director and a member of management.

Frank Cooper was re-elected at the 2022 AGM and has served 11 years on the Board in February 2024. The Board reviewed the independence of Mr Cooper and determined that he remained independent, notwithstanding his length of tenure on the Board.

Conflicts of interest

The Board has approved a Directors’ Conflict of Interest Policy which applies if there is, or may be, a conflict between the personal interests of a director, or the duties a director owes to another company, and the duties the director owes to Woodside. Directors are required to disclose circumstances that may affect, or be perceived to affect, their ability to exercise independent judgement so that the Board can assess independence on a regular basis.

Under Woodside’s Constitution, directors must comply with the Corporations Act in relation to disclosure and voting on matters involving material personal interests. Subject to the Corporations Act:

• a director may be counted in a quorum at a Board meeting that considers, and may vote on, any matter in which that director has an interest

• the company may proceed with any transaction that relates to the interest and the director may participate in the execution of any relevant document by or on behalf of the company

• the director may retain benefits under the transaction even though the director has an interest

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• the company cannot avoid the transaction merely because of the existence of the interest.

Under Woodside’s Constitution, a director may be a director of or hold any other office or position in any corporation promoted by the company or in which the company may be interested. The Board may exercise the voting power conferred by the shares in any corporation held or owned by the company, and a director may vote in favour of exercising those voting rights despite the fact that the director is, or may be about to be appointed, a director of that other corporation and may be interested in the exercise of those voting rights. An interested director is to be counted in a quorum despite the interest.

Under Woodside’s Constitution, the Board may exercise all the powers of the company to raise or borrow money, guarantee the debts or obligations of any person or enter into any other financing arrangements on the terms it thinks fit. If any director or officer of the company is personally liable for the payment of any sum which is or may become primarily due from the company, the Board may charge the whole or any part of the assets of the company by way of indemnity to secure the director or officer from any loss in respect of the liability.

About this statement

For more information regarding our Constitution, please refer to the full text of the Woodside Constitution, incorporated by reference as Exhibit 1.1 to this Annual Report. For information regarding the rights attaching to Woodside’s ordinary shares and American Depositary Shares, please refer to Exhibit 2.1 to this Annual Report.

Areas of competence and skills of the Board of Directors

The directors on the Board collectively have a combination of skills and experience which are necessary to direct the company in accordance with high standards of corporate governance and oversee Woodside’s management and business activities.

The competences and skills are set out in the skills matrix below. The Board uses this skills matrix to assess the skills and experience of each director and the combined capabilities of the Board, to identify potential areas of focus for director recruitment and to identify any professional development opportunities that may benefit directors.

Leadership and culture
•   Business leadership	•   Public listed company experience
•   Values and behaviours
Finance
•   Accounting and audit	•   Insurance
•   Financial acumen	•   Taxation
Business strategy
•   Corporate financing and treasury	•   Capital projects
•   Business strategy
Commercial
•   Gas/LNG marketing	•   Legal and regulatory compliance
•   Mergers and acquisitions	•   US regulatory compliance
•   Business development	•   Risk management
Sustainability and stakeholder management
•   Health and safety	•   Environment
•   Community relations	•   Public and regulatory policy
•   Corporate governance
Climate change
•   Policy and legal risks	•   Technology
•   Market	•   Reputation
People and capability
•   People and culture	•   Remuneration
•   Industrial relations
Industry
•   Oil and gas experience	•   Major projects
•   New energy and renewables	•   Digital
•   Technology and innovation	•   Cybersecurity
International
•   International oil and gas exploration, development and production	•   International experience

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The skills matrix is reviewed annually and updated regularly to ensure it remains appropriate for Woodside’s strategy, operations and risk profile and any other emerging issues.

The 2023 review confirmed that the Board collectively have the necessary skills and competencies. As discussed in the Board performance evaluation section, the review also informed and supported the Board’s review of succession priorities.

The Board supplements its expertise with internal and external subject matter experts as appropriate (for example, regular attendance at Board meetings by relevant executives and other independent advisers). The Sustainability Committee received regular briefings and education on climate change from Woodside’s Senior Executive responsible for climate change, to inform its oversight of related matters with input from climate change science and expert advice.

Chair

The Chair of the Board, Richard Goyder, is an independent, non-executive director and an Australian resident and citizen.

The Chair is responsible for leadership and effective performance of the Board and for the maintenance of relations between directors and management that are open, cordial and conducive to productive cooperation. The Board has arrangements in place to ensure ongoing leadership if unforeseen circumstances mean Mr Goyder is not available. Mr Goyder’s office is located in the company’s headquarters in Perth, Western Australia. The Board is satisfied that Mr Goyder commits the time necessary to discharge his role effectively. The Chair’s responsibilities are set out in more detail in the Board Charter.

Company Secretaries

Details of the Company Secretaries are set out in section 4.2 - Directors’ report - Company Secretaries. All directors have direct access to the Company Secretaries who are accountable directly to the Board, through the Chair, on all matters to do with the proper functioning of the Board. The Company Secretaries’ responsibilities are set out in more detail in the Board Charter.

Board succession planning

The Board manages its succession planning with the assistance of the Nominations & Governance Committee which annually reviews the size, composition and diversity of the Board. In conducting the review, the Board skills matrix and the tenure of each director is considered.

The Nominations & Governance Committee is also responsible for evaluating Board candidates and recommending individuals for appointment to the Board. The Committee evaluates prospective candidates against a range of criteria including the skills, experience, expertise and diversity that will best complement Board effectiveness at the time. The Board may engage an independent recruitment firm to undertake a search for suitable candidates.

Refer to the ‘Board composition’ section for information about recent changes to the Board’s composition.

4.1.3 Board committees

The Board has four standing committees to assist in the discharge of its responsibilities. The committees operate principally in a review or advisory capacity, except in cases where powers are specifically conferred on a committee by the Board.

Each committee has a charter, detailing its role, duties and membership requirements. The committee charters are reviewed regularly and updated as required.

Membership of the committees is based on directors’ qualifications, skills and experience. Each standing committee is comprised of:

• only non-executive directors

• at least three members, the majority of whom are independent

• a chair appointed by the Board who is one of the independent non-executive directors.

The Audit & Risk Committee and the Human Resources & Compensation Committee have additional membership requirements as set out in their respective charters.

Each committee is entitled to seek information from any employee of the company and to obtain any professional advice it requires in order to perform its duties. All directors are entitled to and generally attend meetings of the standing committees.

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Audit & Risk Committee

Assists with overseeing the company’s financial reporting, compliance with legal and regulatory requirements, risk management and the internal and external audit functions in accordance with the Committee Charter.

 Members

• Frank Cooper (Committee Chair)

• Larry Archibald

• Ashok Belani (from January 2024)

• Angela Minas

• Gene Tilbrook

• Ben Wyatt (from December 2023)

 Some of the FY23 key activities undertaken by the Committee include:

• overseeing the ongoing integration activities in connection with the merger with BHP Petroleum including Sarbanes-Oxley compliance and monitoring SAP S/4 HANA migration

• overseeing developments in accounting, financial reporting and taxation relevant to Woodside

• reviewing significant accounting policies and practices

• reviewing and making recommendations to the Board for the adoption of the Group’s half-year and annual Financial Statements

• approving the fees and reviewing the external auditor’s scope and plan for the 2023 external audit, considering and approving non-audit services provided by the external auditor and reviewing the independence and performance of the external auditor

• reviewing Internal Audit reports and material post-investment reviews and approval of the 2024/2025 Internal Audit program

• reviewing the Group’s key risks and risk management framework and reviewing reports from management on the effectiveness of the Group’s management of its material business risks including contemporary and emerging risks such as cybersecurity, conduct risk, technology and innovation, privacy and data breaches, sustainability and climate change

• overseeing the establishment of the new ethics and compliance team and revised governance structures post merger

• overseeing matters and informing the Board of any material concerns raised under the Code of Conduct, the Anti-Bribery and Corruption and Whistleblower Policies that call into question the culture of the organisation

• overseeing the revocation of the deed of cross guarantee and entry into a new deed of cross guarantee

• informing the Board of the company’s compliance with material legal and regulatory requirements and any conduct that is materially inconsistent with the company’s values or Code of Conduct.

 Audit committee financial expert

Woodside’s Board has determined that Frank Cooper, who serves on the Audit & Risk Committee, meets the audit committee financial expert requirements under SEC Rules. The Board has also determined that he is independent under applicable NYSE rules.

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Nominations & Governance Committee

Assists the Board with reviewing Board composition, performance and succession planning, including identifying, evaluating and recommending candidates for the Board in accordance with the Committee Charter.

 Members

• Richard Goyder (Committee Chair)

• Larry Archibald

• Ashok Belani (from January 2024)

• Arnaud Breuillac

• Frank Cooper

• Swee Chen Goh

• Ian Macfarlane

• Angela Minas

• Ann Pickard

• Gene Tilbrook

• Ben Wyatt

 Some of the FY23 key activities undertaken by the Committee include:

• identifying and recommending to the Board new directors to join the Woodside Board in 2023

• reviewing the size and composition of the Board

• reviewing the director skills matrix

• reviewing the directors’ material interests

• Board succession planning

• recommending to the Board directors for re-election

• recommending for Board approval the Woodside Corporate Governance Statement

• approving the process for the annual Board performance evaluation.

Human Resources & Compensation Committee

Assists with establishing human resources and compensation policies and practices in accordance with the Committee Charter.

 Members

• Arnaud Breuillac (Committee Chair)

• Frank Cooper

• Swee Chen Goh

• Ian Macfarlane

• Ann Pickard

• Gene Tilbrook

• Ben Wyatt

 Some of the FY23 key activities undertaken by the Committee include:

• overseeing Woodside’s response to key safety events including the North Rankin Complex fatality involving a colleague employed by a contractor

• considering industrial relations issues relevant to Woodside’s onshore and offshore assets

• approving changes to the leadership structure, including the appointment and remuneration packages of executives reporting directly to the CEO

• considering organisation requirements design, and policy changes required to meet changing regulatory requirements

• endorsing for Board approval a new Mandatory Clawback Policy to meet US regulatory requirements

• overseeing amendments to Woodside’s employee and executive equity plans

• overseeing Woodside’s response to Australian, US and UK legislative and corporate governance developments, including Workplace Gender Equality Agency legislation reforms, and stakeholder feedback, in relation to employment and remuneration matters relevant to Woodside

• reviewing the company’s remuneration policies and practices globally and considering advice on the remuneration of Woodside’s key management personnel

• overseeing the implementation of the payroll harmonisation

• reviewing the company’s recruitment and retention strategies

• oversight of programs to assess and monitor culture (including survey findings), including across all areas of our Integrated Culture Framework (values, safety, risk and compliance)

• reviewing progress against the 2021-2025 Inclusion and Diversity strategy and consideration of global differences

• overseeing progress against measurable objectives in respect of gender diversity and endorsing for Board approval the 2024 measurable objectives

• reviewing and making recommendations to the Board on:

• remuneration for non-executive directors

• the remuneration of the CEO

• the criteria for the evaluation of the CEO’s performance

• incentives payable to the CEO

• employee equity-based plans

• the annual Remuneration Report.

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Sustainability Committee

Assists the Board in meeting its oversight responsibilities in relation to the company’s sustainability policies and practices in accordance with the Committee Charter.

 Members

• Ann Pickard (Committee Chair)

• Larry Archibald

• Ashok Belani (from January 2024)

• Arnaud Breuillac

• Swee Chen Goh

• Ian Macfarlane

• Angela Minas

• Ben Wyatt (until December 2023)

 Some of the FY23 key activities undertaken by the Committee include:

• overseeing Woodside’s response to key safety events including the North Rankin Complex fatality involving a colleague employed by a contractor

• overseeing the company’s in-year Scope 1 and 2 greenhouse gas emissions performance, and its plans for meeting emissions targets

• reviewing Woodside’s environmental performance, including major incident prevention

• overseeing the Group’s health and personal safety performance

• considering for Board approval the company’s approach to climate reporting

• overseeing Woodside’s process safety performance including major incident prevention

• reviewing Woodside’s quality management

• considering security and emergency management performance, including major incident prevention and response and business continuity

• considering Woodside’s management of climate change risk and opportunities

• overseeing and reviewing the proposed content for Woodside’s Climate Transition Action Plan and 2023 Progress Report, and approach to climate-related disclosures

• considering First Nations affairs, including cultural heritage and land access matters

• endorsing for Board approval changes to the Group Human Rights Policy

• reviewing Woodside’s activities supporting local content in our supply chain

• overseeing Woodside’s social performance and social contribution in our host communities

• reviewing Woodside’s reputational performance and issues of significance to our communities and stakeholders

• overseeing publication of the Reconciliation Action Plan Report 2022

• endorsing for Board approval Woodside’s Modern Slavery Statement 2022 and reviewing related human rights issues.

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4.1.4 Executive Leadership Team

Graham Tiver¹

Executive Vice President and Chief Financial Officer

BBus, FCPA

Joined Woodside: 2022

Experience: Graham is responsible for Finance; Treasury; Tax; Investor Relations; Governance, Risk and Compliance; Audit; and Mergers and Acquisitions. Prior to joining Woodside, Graham spent 28 years with BHP and WMC Resources where he held significant financial, commercial and leadership roles across multiple business sectors. He has extensive international experience, having worked in North and South America as well as in a variety of roles around Australia.

Directorship: Nil.

Shiva McMahon¹

Executive Vice President International Operations

MA, BA

Joined Woodside: 2022

Experience: Shiva is responsible for Woodside’s International operations portfolio. Shiva has 30 years of industry experience and prior to joining Woodside held senior leadership roles at both BHP and BP. Shiva spent a large part of her career at BP in roles including CFO Global Lubricants, Chief of Staff Upstream Executive Office and CFO Trinidad and Tobago.

Directorship: Greater Houston Partnership (since 2022) and National Ocean Industries Association (NOIA).

Elizabeth (Liz) Westcott¹

Executive Vice President Australian Operations

BCom, BEng (Hons), GAICD

Joined Woodside: June 2023

Experience: Elizabeth (Liz) is responsible for Woodside’s Australian operations portfolio. Liz has 30 years of industry experience in operations and project roles and prior to joining Woodside held senior leadership roles at EnergyAustralia and ExxonMobil. Her roles spanned strategic planning, operations, project management, and safety, technical and commercial leadership.

Directorship: Beyond Bank Australia Limited.

Julie Fallon

Executive Vice President Corporate Services

BEng (Hons) (ChemEng)

Joined Woodside: 1998

Experience: Julie is responsible for Legal; Ethics and Compliance; Health, Safety and Environment; Security and Emergency Management; Supply Chain; and Human Resources. Julie has 30 years of industry experience and has held a number of senior leadership roles at Woodside including Senior Vice President Pluto and Senior Vice President Engineering.

Shaun Gregory

Executive Vice President New Energy

BSc (Hons), MBT

Joined Woodside: 1995

Experience: Shaun is responsible for new energy and carbon solutions. Shaun has over 30 years of industry experience and has had senior leadership roles across Woodside’s value chain from Exploration acreage capture and evaluation, through to Development concept selection and technology development.

Daniel Kalms

Executive Vice President Technical Services

BEng (Hons) (ChemEng), MBA

Joined Woodside: 2001

Experience: Daniel is responsible for Digital; Technology; Surface Engineering; and Subsurface and Reserves. Daniel has over 25 years of industry experience and has held senior leadership roles across development, projects, operations and corporate.

1 Identified as key management personnel (KMP).

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Mark Abbotsford

Executive Vice President Marketing and Trading

BEc (Hons), MPhil, MBA

Joined Woodside: 2002

Experience: Mark is responsible for Woodside’s global commodity marketing, trading and shipping portfolio. Mark has over 20 years’ industry experience and has held a number of senior leadership positions across commercial, finance and marketing in various global locations. Prior to joining Woodside, Mark had roles at Treasury (Western Australia) and BHP Iron Ore.

Tony Cudmore

Executive Vice President Strategy and Climate

BA, GCIR

Joined Woodside: 2022

Experience: Tony is responsible for Corporate Strategy, Climate and Sustainability, External Environment and Corporate Affairs. Tony has over 20 years’ industry experience and prior to joining Woodside, Tony worked for ExxonMobil and BHP where he held senior leadership positions including Chief Public Affairs Officer, and Group Sustainability and Public Policy Officer.

Andy Drummond

Executive Vice President Exploration and Development

BEng (Hons) (ChemEng)

Joined Woodside: 2022

Experience: Andy is responsible for exploration and development activities at Woodside. Andy has over 25 years’ industry experience. Prior to joining Woodside, Andy held senior leadership positions at BHP and Marathon Oil Corporation, including Vice President of Sustainability and Innovation for BHP’s petroleum business.

Matthew Ridolfi

Executive Vice President Projects

BEng (Hons) (MechEng)

Joined Woodside: 2022

Experience: Matthew is responsible for Woodside’s project execution activities globally. Matthew has more than 30 years of industry experience and prior to joining Woodside held a number of senior leadership positions at BHP including Vice President of Major Developments for BHP’s petroleum business and Vice President of Health, Safety, Environment and Community.

Performance evaluation of Executive Leadership Team

With respect to executives, their performance is reviewed annually, which considers and assesses the executive’s performance against a list of key performance indicators.

All executives had a performance evaluation in FY2023 and further details are set out in section 4.3 – Remuneration Report. Details of the CEO’s performance evaluation (process and outcomes) are set out in section 4.3 – Remuneration Report and ‘Board Performance Evaluation’.

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4.1.5 Promoting responsible and ethical behaviour

OUR VALUES

Everything we do is guided by Our Values and inspired by our common purpose. We are one team, we care, we innovate every day, our results matter and we build and maintain trust.

CODE OF CONDUCT AND ANTI-BRIBERY AND CORRUPTION POLICY

The Code of Conduct and the Anti-Bribery and Corruption Policy (ABC Policy) cover matters such as compliance with laws and regulations, responsibilities to shareholders and the community, sound employment practices, confidentiality, privacy, conflicts of interest, giving and accepting business courtesies and the protection and proper use of Woodside’s assets.

All directors, officers and employees are required to comply with the Code of Conduct and the ABC Policy and managers are expected to take reasonable steps to ensure that employees, contractors, consultants, agents and partners under their supervision are aware of both policies.

Substantiated breaches of the Code of Conduct and ABC Policy are reported to the Audit & Risk Committee.

WHISTLEBLOWER POLICY

Woodside’s Whistleblower Policy documents our commitment to maintaining an open working environment in which Woodside personnel and other stakeholders can report instances of unethical, unlawful or undesirable conduct without fear of intimidation or reprisal. Whistleblower submissions are assessed and investigated in accordance with internal investigation guidance and applicable whistleblower protection laws.

The Whistleblower Policy also links the EthicsPoint whistleblower service available for submitting anonymous reports of alleged improper conduct.

Substantiated incidents reported under Woodside’s Whistleblower Policy are reported to the Audit & Risk Committee and in line with applicable whistleblower protection laws.

SECURITIES DEALING POLICY

Woodside’s Securities Dealing Policy applies to all directors, employees, contractors, consultants and advisers. It prohibits directors and employees from dealing in the company’s securities when they are in possession of price-sensitive information that is not generally available to the market. It also prohibits dealings by directors and certain restricted employees during ‘black-out’ periods, such as during the period between the end of the financial half and full-year and the day following the announcement of the results.

The Securities Dealing Policy also sets out our approach to transactions which limit the economic risk of participating in equity- based remuneration schemes.

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WORKING RESPECTFULLY POLICY

Woodside is committed to a safe, inclusive and respectful working environment. Our culture is underpinned by Our Values and Code of Conduct. Sexual and other unlawful discrimination, bullying and harassment are serious violations of those principles and will not be tolerated. The Woodside Working Respectfully Policy sets out our expectation for everyone working for and with our employees, contractors and customers to treat others with respect, in line with our values, Code of Conduct, and the Working Respectfully Policy.

HUMAN RIGHTS POLICY

We conduct business in a way that respects the human rights of all people, including our employees, the communities where we are active and those working throughout our supply chains.

Woodside’s approach to human rights is set out in our Human Rights Policy and overseen by the Board. The Board’s Sustainability Committee is responsible for reviewing and making recommendations and endorsements to the Board on Woodside’s Human Rights Policy and performance.

PAYMENTS TO POLITICAL ENTITIES FOR BUSINESS ENGAGEMENT

Woodside does not donate to campaign funds for any political party, politician or candidate for public office in any country.

In Australia, Woodside makes payments to attend adhoc business engagement events arranged by political stakeholders. Decisions to attend these events are subject to strict governance processes. Our Board considers and approves our approach to political contributions annually.

As reported to the Australian Electoral Commission in compliance with our reporting requirements, our payments for the financial year 2022/2023 totalled A$97,550 down from A$109,930 in 2021/2022.

Our contributions for the year ending 30 June 2023 (being the relevant reporting period) are as follows:

	Value (A$)
Australian Labor Party	38,500
Australian Labor Party (Western Australia Branch)	17,100
Liberal Party of Australia	22,200
Liberal Party (WA Division) Inc	8,250
National Party of Australia	8,500
National Party of Australia (WA) Inc	3,000
Total:	97,550

PAYMENTS TO THE REFERENDUM CAMPAIGN

In October 2023, a referendum was held on a proposal to alter the Australian Constitution to recognise First Nations people by establishing an Aboriginal and Torres Strait Islander Voice (Referendum).

As reported to the Australian Electoral Commission, Woodside’s total reportable payments to the Referendum campaign was A$2,175,000, consisting of three donations:

• Australians for Indigenous Constitutional Recognition A$2,000,000

• Kimberley Land Council A$100,000

• Yamatji Marlpa Aboriginal Corporation A$75,000.

All 2023 Referendum disclosure returns (donor and recipient) will be made publicly available on the Australian Electoral Commission’s online Transparency Register on 1 April 2024.

Woodside made donations to Referendum activities that were aligned with Our Values, the principles set out within our 2021-2025 Reconciliation Action Plan and our First Nations Communities Policy. Our donations supported organisations to disseminate information and advocate in favour of formalising a pathway for Indigenous Australians to share their views on policies that impact them. Woodside’s contribution aligns with our support for the Uluru Statement from the Heart, which called for the establishment of an Indigenous voice to Parliament, agreement making and truth-telling. These contributions will be published on the Australian Electoral Commission’s online Transparency Register.

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4.1.6 Risk management and internal control

RISK MANAGEMENT

Approach to risk management

Woodside is committed to managing risks in a proactive and effective manner as a source of competitive advantage. Our approach is intended to protect us against potential negative impacts and improve our resilience against emerging risks. These include conduct risk, technology and innovation, cybersecurity, privacy and data breaches, sustainability and climate change.

Woodside’s Risk Management Policy describes the manner in which Woodside:

• provides a consolidated view of risks across the company to understand risk exposure and prioritise risk management and governance

• confers responsibility on Woodside staff at all levels to pro-actively identify, assess and treat risks relating to the objectives they are accountable for delivering.

Board, Audit & Risk Committee and management

The Board is responsible for reviewing and approving Woodside’s risk management framework, policy and performance. The Board is also responsible for satisfying itself that management has developed and implemented a sound system of risk management and internal control.

The Board has delegated oversight of the Risk Management Policy, including review (at least annually) of the effectiveness of Woodside’s internal control system and risk management framework, to the Audit & Risk Committee. The Audit & Risk Committee also regularly reviews Woodside’s Risk Appetite Statement and oversees Internal Audit’s activities and reviews Internal Audit’s performance.

Management is responsible for promoting and applying the Risk Management Policy.

In 2023, the Audit & Risk Committee reviewed and confirmed the company’s risk management framework was sound, and that the company was operating with due regard to the risk appetite endorsed by the Board. In 2023, Woodside also identified opportunities to change the risk management framework and updated the risk matrix and risk appetite statement to represent today’s organisation. Additionally, Woodside’s approach to managing risk will follow a three lines model, this model clarifies roles and responsibilities of all areas of the business related to managing risk. These changes enable risk informed decision making and effective management of current risks.

As part of its oversight of the Risk Management Policy, the Audit & Risk Committee oversees risks from cybersecurity threats. The Audit & Risk Committee aims to hold at least five regular meetings a year with cybersecurity risks and the Group’s management of such risks reviewed as part of those meetings.

The identification and direct management of cybersecurity risks and threats are performed by Woodside’s cybersecurity function, with subject matter expertise provided as part of our cyber resilience process.

The cybersecurity function is led by Woodside’s Chief Information Security Officer (CISO) and a group of competent and experienced cybersecurity professionals. Our CISO has over a decade of industry experience and has held multiple technology and business facing roles.

The cyber resilience process as described previously includes the monitoring, prevention, detection, mitigation and remediation of cybersecurity risks and incidents.

The Woodside Board and the Audit & Risk Committee are kept informed of any material cybersecurity risks and incidents through formal risk registers, briefing papers, internal audit reports and periodic reporting in person at Audit & Risk Committee meetings or as required through our Crisis and Emergency Management process if and when a major cyber security incident were to occur.

Woodside’s cybersecurity resilience and risk management strategy and process are based on the National Institute of Standards and Technology Cybersecurity Framework. This process is documented within the WMS.

Internal Audit function

Internal Audit provides assurance that the design and operation of the Group’s risk management and internal control system is effective. A risk-based audit approach is used to ensure that higher risk activities are prioritised in the audit program.

Internal Audit is independent of both business management and of the activities it reviews and has all necessary access to management and information to fulfill its role. Internal Audit is staffed by industry professionals including qualified accountants and engineers. The head of Internal Audit is jointly accountable to the Audit & Risk Committee and the Executive Vice President, Finance and Chief Financial Officer (CFO).

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Governance, Risk and Compliance function

The Governance, Risk and Compliance function is responsible for Woodside’s risk management framework, development of risk management capability, and providing risk management oversight to senior levels of management and the Audit & Risk Committee on the strategic risk profile and the Group’s risk management performance.

Material risks

Our material risks (including environmental and social risks) and how they are managed are disclosed in section 3.9 – Risk factors.

EXTERNAL AUDIT AND REPORTING

External Auditor

In accordance with Woodside’s External Auditor Policy, the Audit & Risk Committee oversees the engagement of Woodside’s external auditor, governed by the External Auditor Guidance Policy. Internal audit and external audit are separate and independent of each other.

The Audit & Risk Committee evaluates the objectivity and independence of the external auditor and the quality and effectiveness of the external audit arrangements, including through:

• review of all non-audit services for actual and perceived independence threats

• confirmation that non-audit service fee commitment does not exceed 70% of audit fees for the year

• confirmation that Woodside fees does not exceed 10% of PricewaterhouseCoopers (PwC) Perth aggregate revenues for the prior period

• annual review of auditor performance.

External Auditor independence

The guidance policy includes provisions directed at maintaining the independence of the external auditor and assessing whether the proposed provision of any non-audit services by the external auditor is appropriate. The External Auditor Guidance Policy classifies a range of non-audit services which could potentially be provided by the external auditor as acceptable within limits, requiring Audit & Risk Committee pre-approval or not acceptable. The Audit & Risk Committee reviews the auditor independence annually.

The Audit & Risk Committee did not waive the pre-approval requirement under paragraph (c)(7)(i) of Rule 2-01 of SEC Regulation S-X in 2023.

With effect from 2022, PwC was appointed as auditor of the Group, replacing Ernst & Young (EY). Under SEC regulations, the remuneration of the auditors (PwC) of $9.6 million (2022: $5.4 million (PwC)) is required to be presented as follows: audit fees represent 84% (2022: 76%); audit-related fees 5% (2022: 18%); tax fees 11% (2022: 5%); and all other fees nil (2022: 1%).

The nature of the services comprising each category of fees is described below:

• Audit – work that constitutes the agreed fees for the audit of Woodside’s consolidated financial statements, report on Woodside’s internal controls over financial reporting, and statutory audits of Woodside’s controlled entities (including interim reviews).

• Audit-related – includes assurance services and agreed upon procedures. This is work that is outside the scope of the statutory audits of Woodside and its controlled entities but is consistent with the role of the external statutory auditor. The work is reasonably related to the performance of an audit or review, is of a compliance or procedural nature, and is work that the external auditors must or are best placed to undertake and is permissible within the framework of the Sarbanes-Oxley Act and other relevant independence standards.

• Tax services – tax related work, including tax compliance services, that is outside the scope of the statutory audits of Woodside and its controlled entities but is permissible within the framework of the Sarbanes-Oxley Act and other relevant independence standards.

• Other services – other work that is permissible within the framework of the Sarbanes-Oxley Act and other relevant independence standards.

Verification of periodic corporate reports

The Board has adopted a Continuous Disclosure and Market Communications Policy (Disclosure Policy) that applies to all disclosures to the market, including periodic corporate reports that are not audited by an external auditor. Management has developed practices and guidance material that are intended to ensure that periodic corporate reports provide clear, concise and effective disclosure, in accordance with the Disclosure Policy. Authority has been delegated to the Disclosure Committee to ensure the implementation of the reporting and communications processes and controls set out in the Disclosure Policy and associated guidance material.

Reports are prepared by, or under the supervision of, subject matter experts and material statements in the reports are reviewed for accuracy. Reports are also reviewed for compliance with applicable legal and regulatory requirements. This process is intended to ensure that all applicable laws, regulations and company policies have been complied with, and that appropriate approvals are obtained before a report is released to the market.

CEO and CFO assurance

Before approving the Financial Statements for a financial period, the Board receives from the CEO and CFO a declaration stating that:

• in their opinion Woodside’s financial records have been properly maintained, comply with the appropriate accounting standards and give a true and fair view of Woodside’s financial position and performance

• the opinion has been formed on the basis of a sound system of risk management and internal control which is operating effectively.

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4.1.7 Inclusion and diversity

INCLUSION AND DIVERSITY POLICY

Our Inclusion and Diversity (I&D) Policy outlines our commitment to an inclusive workplace culture that values diversity and promotes equal opportunities. Our I&D Policy applies throughout Woodside, including the Board and its committees. The Human Resources & Compensation Committee is responsible for monitoring the company’s I&D Policy and setting measurable objectives for achieving diversity in the composition of the Board, Senior Executives and Woodside’s workforce generally.

Our diversity encompasses differences in age, nationality, race, ethnicity, national origin, religious beliefs, sex, sexual orientation, intersex status, gender identity or expression, relationship status, disability, neurodiversity, cultural background, thinking styles, experience, family background, including caregiving commitments and education.

Initiatives to promote inclusion and diversity

Woodside aims to drive I&D and implement the objectives set out in the I&D Policy by, among other things:

• respecting the unique attributes that each individual brings to the workplace and fostering a values-based and leader-led inclusive culture

• providing I&D education and training as well as undertaking initiatives and measuring their effectiveness

• amplifying the voices of employees to inform our activities to achieve inclusion by enabling Employee Resource Groups and conducting employee surveys

• the Board annually reviewing the aspirational goals it has set for achieving improvement in Woodside’s I&D indicators and the progress in achieving those objectives:

› reporting gender equality indicators in accordance with the Workplace Gender Equality Act 2012 (Cth). For further information, refer to our 2023 submission available on our website at woodside.com.

› increased focus on recruiting and developing Indigenous Australian talent will be made in 2024.

2023 MEASURABLE OBJECTIVES

Our 2023 measurable objectives include objectives set out in our I&D policy.

2023 measurable objective	Progress
Continue to track perceived level of inclusion and use inclusion survey insights to inform initiatives to continually improve.	•   Our Voice survey was completed twice in 2023, with belonging, inclusive culture and inclusive leadership measured. Survey feedback will assist to inform 2024 priorities.
Embed Respectful Behaviours at Woodside via increasing a ‘speak up’ culture and proactive employee engagement on this topic.	•   644 people completed the 3.5 hour Working Better Together – Respectful Behaviours program and 661 people completed the 1.5 hour Respect at Woodside education session. •   Inclusive Leadership capability building embedded into Navigator Leadership Program. During 2023, through Navigator, 1,273 completed leadership program immersions; 41 senior leaders completed Inclusive Leadership Assessments; and 109 people participated in two half-day Inclusive Leadership courses. •   Employee perceptions in relation to respect, harassment and discrimination at work improved during 2023 (measured via the employee survey). •   Multi-disciplinary team charged with identifying and embedding improvements related to respect at work.
Ensure diversity of the Board with consideration for gender, racial and cultural diversity.	•   As of 31 December 2023, Board diversity included: -   36% female representation -   9% LGBTIQA+ representation -   country based cultural diversity – Indigenous and non-Indigenous Australian, American, Singaporean Chinese, Greek and French -   racial diversity -9% Asian, 9% Indigenous Australian, 82% white/Caucasian.
Increase the percentage of Indigenous Australian people employed in leadership roles, mid-career and senior roles and overall.	•   The percentage of Indigenous Australian people employed by Woodside in: -   mid-career and senior roles increased to 0.8% (from 0.7%) -   leadership roles decreased to 0.7% (from 0.9 %). •   Overall participation (including third-party pathway program participants) increased to 5.7% (from 5.4%).
Make progress towards our aspirations to increase the percentage of females employed in leadership roles, trade and technician roles and overall.	•   The percentage of females employed by Woodside in: -   trade and technician roles increased to 11.2% (from 9.8%); -   leadership roles increased to 27.7% (from 26.8%); and •   There was an overall increase to 33.6% (from 33.4%).

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2023 measurable objective	Progress
Maintain gender balance1 and meet recruitment goals for Indigenous Australian peoples through all forms of entry to Woodside including pathway programs and experienced hires.	•   Recruitment results for gender were: -   non-tertiary pathways2: 43% female; -   summer vacation and graduates: 56% female for summer vacation 2023/2024 and 48% female for graduates; and -   experienced hires: 39% female. •   Recruitment results for Indigenous Australian people, against goals, were: -   non-tertiary pathways2: 57% (goal of 50%); -   summer vacation and graduates: 15% for summer vacation 2023/2024 and 17% for graduates (goal of 10%); and -   experienced hires: 5% (goal of 2%).
Make progress towards building greater inclusion of people who are differently abled and/or neurodiverse.	•   Progress made with improvements to recruitment process, digital accessibility, introduction of a Workplace Adjustments Guide and awareness raising events held by the Employee Resource Group ADAPT (Advocates for Different Abilities and Personal Traits).
Support LGBTIQA+ individuals to feel safe to be out at work.	•   Authentic Leaders Program for LGBTIQA+ employees commenced in the Americas region. •   488 people completed LGBTIQA+ awareness and inclusion related training in 2023. •   Bronze status achieved in Australian Workplace Equality Index for LGBTQ workplace inclusion.
Make progress towards achieving racial equity.	•   Global approach to Anti-Racism and Cultural Respect developed. •   Annual remuneration review included review for pay equity for Black, Indigenous and People of Colour (BIPOC) in USA and Indigenous Australians (and gender). •   134 people completed Subtle Racism or Racial Equity training. •   EmBRace (Employees Beyond Race) Employee Resource Group led a range of awareness raising campaigns and initiatives throughout the year in the US. •   United Nations Day for the Elimination of Racial Discrimination (known as Harmony Day in Australia) was recognised with events led by Employee Resource Group CALD (Cultural and Linguistic Diversity).

1 Gender balance in the US is defined as representative and reflective of the available talent pool.

2 Non-tertiary pathway data is based on third-party program recruitment information.

WOODSIDE WORKFORCE GENDER PROFILE³

3 Gender profile data reflects all employees engaged on 31 December 2023, excluding temporary personnel such as vacation students, cadets and scholarship students.

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BOARD AND EXECUTIVE MANAGEMENT DIVERSITY

The UK Listing Rules require listed companies to publish information on gender and ethnic representation on their boards and in executive management. In addition, the UK Listing Rules require companies to disclose their progress against three specified diversity targets, being:

• At least 40% of the directors are women

• At least one director is from an ethnic minority background

• At least one of the senior positions on the board is held by a woman

Under the UK Listing Rules, the senior positions on the Board are the Chair, CEO, CFO and Senior Independent Director (SID). For Woodside, the senior positions on the Board are only the Chair and the CEO. In line with market practice for Australian listed companies, the CFO does not sit on the Board and Woodside does not have a SID as this role is not required under the corporate governance code Woodside applies, being the ASXCGC Recommendations.

As at 31 December 2023, Woodside had at least one of the senior positions on the Board held by a woman and at least one director from an ethnic minority background.

36% of the Board were women which is below the 40% figure set out in the UK Listing Rules. The I&D Policy includes a commitment to improve diversity on the Board, with a key focus on reaching 40% female representation. As part of Board succession planning, the Nominations & Governance Committee evaluates prospective candidates against a range of criteria including the skills, experience, expertise and diversity that will best complement Board effectiveness at the time.

The tables below set out the diversity information required under the UK Listing Rules as at 31 December 2023. The data presented in those tables was collected by requesting all members of the Board, Executive Leadership Team and Group Company Secretary to self- report in questionnaires about their cultural background, languages spoken, racial identity, LGBTIQA+ identity and gender.

In accordance with UK Listing Rule 14.3.33, these tables set out the Board and executive management diversity data as at 31 December 2023.

Woodside notes that the ethnic/racial background groupings do not align to groupings common in some regions but has presented the data in this way to comply with UK Listing requirements.

Gender identity

	Number of Board members		Percentage of the Board			Number of senior positions on the Board (CEO, CFO, SID and Chair)1		Number in executive management2		Percentage of executive management
Men		7		64	%		1		8		62	%
Women		4		36	%		1		5		38	%
Not specified/prefer not to say

Ethnic/racial background

	Number of Board members		Percentage of the Board			Number of senior positions on the Board (CEO, CFO, SID and Chair)1		Number in executive management2		Percentage of executive management
White British or other White (including minority-white groups)		9		82	%		2		11		85	%
Mixed/Multiple Ethnic Groups									2		15	%
Asian/Asian British		1		9	%
Black/African/Caribbean/Black British
Other ethnic group, including Arab		1		9	%
Not specified/prefer not to say

1 As noted above, for Woodside the senior positions on the Board are only the Chair and the CEO.

2 In accordance with the UK Listing Rules, ‘executive management’ includes the Executive Leadership Team (the most senior executive body below the Board) and the Group Company Secretary, excluding administrative and support staff.

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4.1.8 Other governance disclosures

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Woodside’s management, with the participation of its CEO and CFO, have evaluated, as required by Rule 13a-15(b) under the US Securities Exchange Act of 1934 (Exchange Act), the effectiveness of Woodside’s disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as at 31 December 2023. Based on that evaluation, the CEO and CFO concluded that Woodside’s disclosure controls and procedures were effective, as at 31 December 2023, in ensuring that information required to be disclosed by Woodside in the reports that it files or submits under the Exchange Act is recorded, processed, summarised and reported within the time periods specified in the SEC’s rules and forms, including that such information is accumulated and communicated to Woodside’s management, including the CEO and CFO, to allow timely decisions regarding required disclosure.

Management’s annual report on internal control over financial reporting

The management of Woodside is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act).

Under the supervision and with the participation of management, including our CEO and CFO, the effectiveness of Woodside’s internal control over financial reporting was evaluated based on the framework and criteria established in Internal Controls – Integrated Framework (2013), issued by the Committee of the Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that internal control over financial reporting was effective as at 31 December 2023.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and, even when determined to be effective, can only provide reasonable assurance with respect to financial statement preparation and presentation. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or the degree of compliance with the policies or procedures may deteriorate.

There were no changes in our internal control over financial reporting during FY2023 that materially affected or were reasonably likely to materially affect our internal control over financial reporting.

Attestation report of the registered public accounting firm

The effectiveness of internal control over financial reporting as of 31 December 2023 has been audited by PwC, an independent registered accounting firm that also audits Woodside’s Consolidated Financial Statements. Their audit report on the internal control over financial reporting is included in the Consolidated Financial Statements.

DIFFERENCES FROM NYSE CORPORATE GOVERNANCE REQUIREMENTS

Woodside’s ADSs are listed on the New York Stock Exchange (NYSE) and, accordingly, Woodside is subject to the listing standards of the NYSE (NYSE Listing Rules). The NYSE Listing Rules include certain accommodations in the corporate governance requirements that allow foreign private issuers, such as Woodside, to follow ‘home country’ corporate governance practices in lieu of the otherwise applicable corporate governance standards of the NYSE. Woodside has elected to comply with certain home country rules in lieu of the applicable NYSE requirements, as more fully described below.

Woodside may in the future decide to use other foreign private issuer exemptions with respect to other NYSE Listing Rules. Following Woodside’s home country governance practices, as opposed to the requirements that would otherwise apply to a company listed on the NYSE, may provide less protection than is accorded to investors under the NYSE Listing Rules applicable to US domestic issuers. If, at any time, Woodside ceases to be a foreign private issuer, it will take all action necessary to comply with the SEC and NYSE Listing Rules.

Quorum

The NYSE Listing Rules generally require that a listed company’s by-laws provide for a quorum for any meeting of the holders of such company’s voting shares that is sufficiently high to ensure a representative vote. Pursuant to the NYSE Listing Rules,

Woodside, as a foreign private issuer, has elected to comply with practices that are permitted under Australian securities laws in lieu of the provisions of the NYSE Listing Rules. The Woodside Constitution provides that a quorum for a meeting of Woodside Shareholders is three eligible Woodside Shareholders entitled to vote.

Audit committee requirements

Under Section 303A.06 of the NYSE Listing Rules and the requirements of Rule 10A-3 under the Exchange Act (Rule 10A- 3), a US listed company is required to have an audit committee of such company’s board of directors consisting entirely of independent members that comply with the requirements of Rule 10A-3. In addition, the audit committee must have a written charter which is compliant with the requirements of Section 303A.07(b) of the NYSE Listing Rules, the listed company must have an internal audit function and the listed company must fulfill all other requirements of the NYSE Listing Rules and Rule 10A-3. Foreign private issuers must comply with the audit committee standard set forth in Rule 10A-3, subject to limited exemptions, but may elect to follow ‘home country’ practices in lieu of the additional audit committee requirements in the

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NYSE Listing Rules. Rule 10A-3 requires NYSE-listed companies to ensure their audit committees are directly responsible for the appointment, compensation, retention and oversight of the work of the external auditor unless the company’s governing law or documents or other home country legal requirements require or permit shareholders to ultimately vote on or approve these matters. While Woodside’s Audit & Risk Committee is directly responsible for remuneration and oversight of the external auditor, ultimate responsibility for the appointment of the external auditor rests with Woodside shareholders, in accordance with Australian law and the Woodside Constitution. However, in accordance with the limited exemptions set forth in Rule 10A-3, the Audit & Risk Committee is responsible for the annual auditor engagement and if there is any proposal to change auditors, the committee does make recommendations to the Woodside Board on any change of auditor, which are then considered by Woodside shareholders at the annual meeting of Woodside shareholders.

Refer to section 4.1.3 – Board committees – Audit & Risk Committee for information on Audit and Risk Committee requirements under the ASX Recommendations.

Code of Ethics

The Woodside Board has adopted the Code of Conduct, which applies to the Woodside Board and Woodside’s CEO and CFO, along with all other Woodside employees.

During 2023, we refreshed our Code of Conduct to align it with global best practices.

4.1.9 Shareholders

Shareholder communications	Shareholders are encouraged to receive electronic communications from the company and can elect to receive email notification when key materials are posted to our website. Shareholders can also receive an email notification of Woodside’s announcements and media releases. Shareholders can communicate directly with Woodside by submitting questions or comments on the Contact Us section of our website. The Shareholder Services section of our website also sets out the email address for Woodside’s share registry, Computershare.
Investor relations program	Woodside has an investor relations program to facilitate effective two-way communication with investors. Our Continuous Disclosure and Market Communications Policy facilitates this by requiring: •   the full and timely disclosure of information about Woodside’s material activities to the ASX and other relevant exchanges and our website (where they are retained for at least three years) •   that all disclosures, including notices of meetings and other shareholder communications, are drafted clearly and concisely •   the conduct of briefings for investors from time to time (such as the annual and half—year results, and Investor Briefing Days). Investor briefings are webcast and presentation material for briefings or speeches containing new and substantive information is first disclosed to the market and other relevant exchanges and posted to our website.
Shareholder meetings	The company recognises the importance of shareholder participation in general meetings and supports and encourages that participation. The company has direct voting arrangements in place, allowing shareholders unable to attend the AGM to vote on resolutions without having to appoint someone else as a proxy. Voting on any substantial resolution at an AGM is conducted by poll.
Continuous disclosure and market communications	Woodside’s Continuous Disclosure and Market Communications Policy and associated guidelines reinforce Woodside’s commitment to continuous disclosure and outline management’s accountabilities and the processes to be followed for ensuring compliance. A Disclosure Committee manages compliance with market disclosure obligations and is responsible for implementing and overseeing reporting processes and controls and setting guidelines for the release of information. The Disclosure Committee is comprised of senior leaders. Employees considered to hold higher risk roles are required to participate in annual continuous disclosure training. The Board and Senior Executives are provided with copies of all information disclosed pursuant to all applicable stock exchange rules.

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4.2 Governance

Directors’ report

The directors of Woodside Energy Group Ltd present their report (including the Remuneration Report) together with the Financial Statements of the consolidated entity, being Woodside Energy Group Ltd and its controlled entities, for the year ended 31 December 2023.

DIRECTORS

The directors of Woodside Energy Group Ltd in office at any time during or since the end of the 2023 financial year and information on the directors (including qualifications and experience and directorships of listed companies held by the directors at any time in the last three years) are set out in section 4.1.2 - Board of directors.

The number of directors’ meetings held (including meetings of committees of the Board) and the number of meetings attended by each of the directors of Woodside Energy Group Ltd during the financial year are shown in section 4.1.2 - Board of directors - Director attendance at meetings.

Details of director and Senior Executive remuneration are set out in section 4.3 – Remuneration Report.

The particulars of directors’ interests in shares of Woodside as at the date of this report are set out at the end of this section.

Principal activities

The principal activities and operations of Woodside during the financial year were hydrocarbon exploration, evaluation, development, production and marketing.

Other than as previously referred to in the operating and financial review section there were no other significant changes in the nature of the activities of the consolidated entity during the year.

Consolidated results

The consolidated profit attributable to equity holders after provision for income tax was $1,660 million ($6,498 million in 2022).

Operating and financial review

A review of the operations of Woodside during the financial year and the results of those operations are set out in section 1 - Overview, section 2 - Strategy and Financial Performance, section 3 - Our Business and section 6.5 – Asset facts.

Significant changes in the state of affairs

The review of operations in sections 1 to 3 sets out a number of matters that have had a significant effect on the state of affairs of the consolidated entity.

Other than those matters, there were no significant changes in the state of affairs of the consolidated entity during the financial year.

Events subsequent to end of financial year

Since the reporting date, the directors have resolved to pay a fully franked dividend. More information is available in the Dividend section below. No provision has been made for this dividend in the financial report as the dividend was not determined by the directors on or before the end of the financial year.

Other than those disclosed in Note E.5 of section 5 - Financial Statements there are no other material subsequent events.

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Dividend

The directors have resolved to pay a final dividend in respect of the year ended 31 December 2023 of 60 US cents per ordinary share (fully franked) payable on 4 April 2024.

Type	2023 final	2023 interim	2022 final
Payment date	4 April 2024	28 September 2023	5 April 2023
Period ends	31 December 2023	30 June 2023	31 December 2022
Cents per share	60	80	144
Value $ million	1,139	1,519	2,734
Fully franked	✓	✓	✓

Likely developments, business strategies, future prospects and expected results

In general terms, the review of operations of Woodside as set out in sections 1-3 gives an indication of likely developments, business strategies, prospects for future financial years, and the expected results of the operations. In the opinion of the directors, disclosure of any further information would be likely to result in unreasonable prejudice to Woodside. Section 6.8 – Information about this report includes further details regarding Woodside’s reliance on the unreasonable prejudice exemption.

Environmental compliance

Woodside is subject to a range of environmental legislation in Australia and other countries in which it operates. In 2023, there were no incidents involving spills of hydrocarbons or hazardous non-hydrocarbons greater than 1 bbl released to the environment.

Through its Environment and Biodiversity Policy, Woodside plans and performs activities so that adverse effects on the environment are avoided or minimised as much as reasonably practicable.

For the financial year ended 31 December 2023, we recorded no fines or prosecutions relating to our environmental performance.

Research and development

Woodside is leveraging technology to drive cost efficiencies and exploring a range of technology options to support step change abatement. Woodside has a number of technology collaborations and pursues opportunities through technology across operations including for emissions reduction.

For further information on examples of the Group’s activities in the field of research and development see section 3.7 – New energy and carbon solutions.

Company Secretaries

The following individuals have acted as Company Secretary during 2023:

Warren Baillie LLB, BCom, Grad. Dip. CSP

Group Company Secretary

Mr Baillie joined Woodside in 2005 and was appointed Group Company Secretary effective 1 February 2012. Mr Baillie is a solicitor and chartered secretary. He is a former President of the board of the Governance Institute of Australia.

Lucy Bowman MA (Oxon), Jurisprudence

Joint Company Secretary

Ms Bowman joined Woodside in 2021 as Senior Legal Counsel and was appointed Joint Company Secretary effective 20 October 2022. She is a graduate member of the Australian Institute of Company Directors.

Branches

Woodside Energy Group Ltd, through various subsidiaries, has established branches in a number of countries.

Indemnification and insurance of directors and officers

Woodside Energy Group Ltd’s constitution requires Woodside Energy Group Ltd to indemnify each director, secretary, executive officer or employee of Woodside Energy Group Ltd or its wholly owned subsidiaries against liabilities (to the extent Woodside Energy Group Ltd is not precluded by law from doing so) incurred in or arising out of the conduct of the business of Woodside Energy Group Ltd or the discharge of the duties of any such person. Woodside Energy Group Ltd enters into deeds of indemnity with directors, secretaries, certain Senior Executives and employees serving as officers on wholly owned or partly owned companies of Woodside in terms consistent with the indemnity provided under Woodside Energy Group Ltd’s constitution.

From time to time, Woodside engages its external auditor, PricewaterhouseCoopers, to conduct non-statutory audit work and provide other services in accordance with Woodside’s External Auditor Guidance Policy. The terms of engagement include an indemnity in favour of PricewaterhouseCoopers:

• against all losses, claims, costs, expenses, actions, demands, damages, liabilities or any proceedings (liabilities) incurred by PricewaterhouseCoopers in respect of third-party claims arising from a breach by Woodside under the engagement terms

• for all liabilities PricewaterhouseCoopers has to Woodside or any third party as a result of reliance on information provided by Woodside that is false, misleading or incomplete.

Woodside Energy Group Ltd has paid a premium under a contract insuring each director, officer, secretary and employee who is concerned with the management of Woodside Energy Group Ltd or its subsidiaries against liability incurred in that capacity.

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Disclosure of the nature of the liability covered by and the amount of the premium payable for such insurance is subject to a confidentiality clause under the contract of insurance. Woodside Energy Group Ltd has not provided any insurance for the external auditor of Woodside Energy Group Ltd or a body corporate related to the external auditor.

During the financial year ended 31 December 2023 and as at the date of this Directors’ report, no indemnity in favour of a current or former director, officer or external auditor of the Group has been called on.

Non-audit services and auditor independence declaration

Based on advice provided by the Audit & Risk Committee, the directors are satisfied that the provision of non-audit services by the external auditor during the financial year is compatible with the general standard of independence for auditors imposed by the Corporations Act 2001 for the following reasons:

• all non-audit services were provided in accordance with Woodside’s External Auditor Policy and External Auditor Guidance Policy

• all non-audit services were subject to the corporate governance processes adopted by the company and have been reviewed by the Audit & Risk Committee to ensure that they do not affect the integrity or objectivity of the auditor.

Financial instruments

For further information on Woodside’s financial risk management objectives and policies, hedging and exposure to price risk, credit risk, liquidity risk and cash flow risk, refer to sections A, C and D in section 5 – Financial Statements and Quantitative and qualitative disclosures about market risk in section 6.3 – Additional disclosures.

Proceedings on behalf of the company

No proceedings have been brought on behalf of the company, nor has any application been made in respect of the company, under section 237 of the Corporations Act 2001.

Rounding of amounts

Woodside Energy Group Limited is an entity to which the Australian Securities and Investments Commission (ASIC) Corporations (Rounding in Financial/Directors’ Reports) Instrument 2016/191 (ASIC Instrument 2016/191) applies. Amounts in this report have been rounded in accordance with ASIC Instrument 2016/191. This means that amounts contained in this report have been rounded to the nearest million dollars unless otherwise stated.

Information in other parts of the Annual Report

Where this Directors’ report refers to other parts of the Annual Report, those pages form part of this report.

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Directors’ relevant interests in Woodside Energy Group Ltd shares as at the date of this report

Director	Relevant interest in shares
Larry Archibald		13,524
Ashok Belani2		Nil
Arnaud Breuillac2		Nil
Frank Cooper		16,142
Swee Chen Goh		14,953
Richard Goyder		26,163
Ian Macfarlane		11,376
Angela Minas2		Nil
Meg O’Neill1		432,621
Ann Pickard		15,870
Gene Tilbrook		9,947
Ben Wyatt		3,054

1 Meg O’Neill is the only Woodside Energy Group Ltd director who has rights on issue and her rights holdings are set out section 4.3 – Remuneration Report. Woodside Energy Group Ltd does not have any options on issue.

2 Mr Breuillac, Ms Minas and Mr Belani are participating in the Non-Executive Directors’ Share Plan and will acquire shares going forward under this plan.

R J Goyder, AO

Chair

Perth, Western Australia

27 February 2024

M E O’Neill

Chief Executive Officer and Managing Director

Perth, Western Australia

27 February 2024

 

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Remuneration Report

CONTENTS
4.3.1 Committee Chair’s letter	Not included
4.3.2 Remuneration Report	84
KMP and summary of Woodside’s five-year performance	84
Executive KMP	85
Remuneration policy	85
Executive Incentive Scheme	85
Executive KMP remuneration structure	87
Remuneration changes and benchmarking	89
Corporate Scorecard measures and outcomes for 2023	91
Executive KMP KPIs and outcomes for 2023	92
Contracts for Executive KMP	98
Non-executive directors (NEDs)	99
Remuneration policy	99
Minimum Shareholding Requirements (MSR) Policy	99
NEDs remuneration structure	99
Human Resources & Compensation Committee	100
Loans and transactions	100
Use of remuneration consultants	100
Reporting notes	100
Reporting in United States dollars	100
Statutory tables	101
4.3.3 Glossary	105

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4.3.1 Committee Chair’s letter

Not required for US Reporting

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4.3.2 Remuneration Report

KMP AND SUMMARY OF WOODSIDE’S FIVE-YEAR PERFORMANCE

This report outlines the remuneration arrangements and outcomes achieved for Woodside’s key management personnel (KMP) during 2023.

Woodside’s KMP are the people who have the authority to shape, influence and control the Group’s strategic direction and performance through their actions, either collectively (in the case of the Board) or as individuals acting under delegated authorities (in the case of the CEO and Senior Executives).

The names and positions of the individuals who were KMP during 2023 are set out in Tables 1A and 1B. Unless otherwise indicated in Table 1A and 1B, all individuals were KMP for the full year in 2023.

Table 1A – Executive KMP

Executive Director
Meg O’Neill (Chief Executive Officer and Managing Director (CEO))
Senior Executive
Graham Tiver (Executive Vice President and Chief Financial Officer)
Shiva McMahon (Executive Vice President International Operations)
Liz Westcott (Executive Vice President Australian Operations)1

1. Ms L Westcott commenced with Woodside on 1 June 2023.

Table 1B – Non-Executive Directors KMP

Non-Executive Directors

Richard Goyder, AO (Chair)

Larry Archibald

Frank Cooper, AO

Swee Chen Goh

Ian Macfarlane

Ann Pickard

Gene Tilbrook

Ben Wyatt

Arnaud Breuillac¹

Angela Minas²

Former Non-Executive Directors

Christopher Haynes, OBE³

Sarah Ryan⁴

1. Mr A Breuillac was appointed as a non-executive director on 8 March 2023.

2. Ms A Minas was appointed as a non-executive director on 28 April 2023.

3. Dr C Haynes ceased being a non-executive director on 28 April 2023.

4. Dr S Ryan ceased being a non-executive director on 28 April 2023.

KMP changes in 2024

Woodside announced on 24 January 2024 that Mr Frank Cooper, AO and Mr Gene Tilbrook are anticipated to retire from the Woodside Board at or before the Annual General Meeting in April 2024. Further, Mr Ashok Belani was appointed as a non-executive director effective 29 January 2024.

Table 2 – Five-year performance

		2023		2022			2021			2020			2019
EBITDA excluding impairment1	(US$million)		9,363		11,234			4,135			1,922			3,531
Operating Expenditure2	(US$million)		2,255		2,063	3		1,030	3		-			-
Net profit after tax (NPAT)4	(US$million)		1,660		6,498			1,983			(4,028	)		343
Basic earnings per share5	(US cents)		87.5		430			206			(424	)		37
Underlying NPAT1	(US$million)		3,320		5,230			1,620			447			1,063
Dividends per share	(US cents)		140		253			135			38			91
Share closing price (last trading day of the year)	(A$)		31.06		35.44			21.93			22.74			34.38	5
Production7,8	(MMboe)		187.2		157.7			91.1			100.3			89.6
Average annual Dated Brent8	($/boe)		83		101			71			42			64

1. This is a non-IFRS measure that is unaudited but derived from audited Financial Statements. This measure is presented to provide further insight into Woodside’s performance and has been calculated as defined in the Alternative performance measures section of the Annual Report.

2. Operating expenditure is a non-IFRS measure that is unaudited. This measure includes only those expenses within production costs and general, administrative and other expenses directly attributable to generating revenue from the sale of hydrocarbons from Woodside’s operating assets. Operating expenditure was not disclosed prior to 2021.

3. As of 2023, Operating Expenditure for the Corporate Scorecard is calculated and reported in USD reflecting the global nature of the organisation post merger. Prior to 2023, the Operating Expenditure was calculated and reported in AUD.

4. Represents profit after tax attributable to equity holders of the parent. This measure is presented to provide further insight into Woodside’s performance.

5. Basic earnings per share from total operations.

6. Share closing price (last trading day) for 2018 was $31.32.

7. From 2022 onwards, production volumes have been calculated using updated conversion factors as defined in the Glossary, units of measure and conversion factors section of the Annual Report.

8. These measures are non-IFRS financial performance measures and therefore are unaudited.

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Executive KMP

Remuneration policy

Woodside’s strategy is to thrive through the energy transition by building a low cost, lower carbon, profitable, resilient and diversified portfolio. There are three goals which drive this strategic direction.

First, we strive to have the right portfolio to provide the energy required for future demand. We play to our strengths, providing oil and gas to our customers while advancing new energy products and lower carbon services. Climate is an integrated part of our strategy and we assess investment decisions against a wide range of considerations including climate outcomes. This is important as the demand from our customers becomes increasingly shaped by their decarbonisation goals.

Secondly, we want to create and return value to our shareholders. Our capital management framework aims to optimise value, balance strong shareholder returns and invest in quality opportunities.

Finally, we aim to conduct our business sustainably. To achieve this, we need to manage our impact on people, communities and the environment in which we operate. The safety of our people and a strong focus on managing our net equity Scope 1 and 2 emissions to meet our targets is critical to the longevity of our business.

All three goals are critical to ensuring that Woodside delivers its strategy and thrives through the energy transition.

To do so, the company must be able to attract and retain executive capability in a globally competitive market. The Board structures remuneration so that it rewards those who perform, is valued by Executives, and is aligned with the company’s values, strategic direction and the creation of enduring value to shareholders, and other stakeholders.

Fixed Annual Reward (FAR) is determined having regard to the scope of each Executive’s role and their level of knowledge, skills and experience.

Variable Annual Reward (VAR) is calculated annually, based on performance measures set by the Board aimed at aligning executive remuneration with short and long-term shareholder returns. VAR aligns shareholder and executive remuneration outcomes by making a significant portion of executive remuneration at risk, while rewarding performance.

Executive remuneration is reviewed annually, having regard to the accountabilities, experience and performance of each individual. FAR and VAR are compared against domestic and international competitors at target, to maintain Woodside’s capacity to attract and retain talent and to ensure appropriate motivation is provided to Executives to deliver on the company’s strategic objectives.

Executive Incentive Scheme

VAR is delivered under the Woodside Executive Incentive Scheme (EIS). The EIS is structured having regard to the key objectives of executive engagement, alignment with the shareholder experience and strategic fit.

EXECUTIVE ENGAGEMENT	ALIGNMENT WITH THE SHAREHOLDER EXPERIENCE	STRATEGIC FIT
Enable Woodside to attract and retain executive capability in a globally competitive environment by providing Executives with a clear remuneration structure giving line of sight to how performance is reflected in remuneration outcomes.	Promote significant share ownership through equity awards. Equity awards are delivered as a combination of Restricted Shares and Performance Rights. The Performance Rights are Relative Total Shareholder Return (RTSR) tested against comparator groups, after five years.	Measures which determine the quantum of the EIS award are selected for alignment with Woodside strategy and award deferral periods reflect Woodside’s strategic time horizons. Together these drive Executives to deliver our strategic objectives with discipline and collaboration, in turn creating shareholder value.

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Individual and Company Performance

The EIS delivers a single variable reward linked to challenging individual and company annual targets set by the Board.

Each Executive KMP’s award is based upon two components: individual performance against KPIs (30% weighting) and the company’s performance against the Corporate Scorecard (70% weighting).

Individual performance measures are designed to ensure Executives focus on driving Woodside’s culture and values whilst executing Woodside’s strategic imperatives. The Board has strong oversight and governance to ensure that appropriate and challenging individual targets are set to create a clear link between performance and reward.

The 2023 Corporate Scorecard for Executive KMP was based on four equally weighted measures that were chosen because they impact short-term and long-term shareholder value. This includes measures selected for alignment with Woodside strategy, covering operational efficiency, financial outcomes and performance against key sustainability measures.

Calculation of Award

The EIS award is subject to performance in each 12-month period and is determined at the conclusion of each performance year.

Individual performance is rated on a scale between 0 and 5 and is assessed by the Board in the case of the CEO, and by the CEO and the Human Resources & Compensation Committee in the case of Senior Executives. Corporate performance is rated on a scale between 0 and 10, with a score of 5 for an outcome at target and a maximum of 10 on each measure. The sum of these two components determines the award.

Exceeding targets results in an increased award with a linear calculation up to the maximum, while under-performance will result in a reduced award. The minimum award that an Executive can receive is zero if the performance conditions are not achieved on either company or individual performance.

The decision to pay or allocate an EIS award is subject to the overriding discretion of the Board, which may adjust outcomes, both upwards and downwards, to better reflect shareholder outcomes and company or management performance. Each year, the Board conducts a holistic assessment of Woodside’s performance on all significant factors, before considering whether it is appropriate to adjust EIS outcomes, either upwards or downwards.

Target variable reward opportunity for 2023

Each Executive is given a target VAR opportunity and a maximum VAR opportunity which is expressed as percentage of the Executive’s FAR. The opportunities for 2023 are outlined below.

Position	Minimum opportunity  (% of FAR)	Target opportunity  (% of FAR)	Maximum opportunity  (% of FAR)
CEO	Zero	280	420
Senior Executives	Zero	160	256

CEO remuneration at target Senior Executives remuneration at target

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Executive KMP remuneration structure

Woodside’s remuneration structure for the CEO and Senior Executives is comprised of two components: FAR and VAR.

FAR

• Based upon the scope of the Executive’s role and their individual level of knowledge, skill and experience.

• Benchmarked for competitiveness against domestic and international peers to enable the company to attract and retain superior executive capability.

VAR

• Executives are eligible to receive a single variable reward linked to individual and company annual targets set by the Board.

• The VAR is subject to performance against individual and corporate performance in the initial 12-month period and is determined at the conclusion of each performance year.

The VAR for the CEO and Senior Executives is outlined below:

CEO EIS structure	Senior Executives EIS structure

1. Allocated using a face value methodology.

2. Award allocated after completion of performance year.

Cash

The cash component is payable following the end of the 12-month performance year, in the March pay-cycle.

Restricted Shares

For the CEO’s VAR award, the Restricted Share component is divided into tranches with three, four and five-year deferral periods and for Senior Executive’s VAR awards, the Restricted Shares are divided into tranches with three and five-year deferral periods. There are no further performance conditions attached to these awards. This element creates a strong retention proposition for Executives as vesting is subject to employment not being terminated with cause or by resignation during the deferral period. The deferral mechanism means that the value of awards reflects fluctuations in share price across the deferral periods, which is intended to reflect the sustainability of performance over the medium and long-term and support alignment between Executives and shareholders.

Performance Rights

The Performance Rights are divided into two portions with each portion subject to a separate RTSR performance hurdle tested over a five-year period. Performance is tested after five years as Woodside operates in a capital intensive industry with long investment timelines. It is imperative that Executives take decisions in the long-term interest of shareholders, focused on value creation across the commodity price cycles of the oil and gas industry.

Our view is that RTSR is the best measure of long-term value creation across the commodity price cycle of our industry.

One-third of the Performance Rights are tested against a comparator group that comprises the entities within the ASX 50 index at 1 December 2023. The remaining two-thirds are tested against an international group of oil and gas companies, set out in Table 11.

RTSR outcomes are calculated by an external adviser after the conclusion of the performance period. The outcome of the test is measured against the schedule below. For EIS awards, any Performance Rights that do not vest will lapse and are not retested.

For valuation purposes all Performance Rights are treated as if they will be equity settled. Each Performance Right is a right to receive a fully paid ordinary share in Woodside on vesting (or, at the Board’s discretion, as cash equivalent payment). No amount is payable by the Executive on the grant or vesting of a Performance Right.

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RTSR performance hurdle vesting

Woodside RTSR percentile position within peer group	Vesting of Performance Rights in the relevant RTSR component
Less than 50th percentile	No vesting
Equal to 50th percentile	50% vest
Between the 50th and 75th percentile	Vesting on a pro-rata basis
Equal to or greater than 75th percentile	100% vest

Table 3 – Key EIS features

Allocation methodology	Restricted Shares and Performance Rights are allocated using a face value allocation methodology. The number of Restricted Shares and Performance Rights is calculated by dividing the value by the volume weighted average price (VWAP) of the Company’s shares traded on each trading day across December of the performance year.
Dividends and voting	Executives are entitled to receive dividends on Restricted Shares. No dividends are paid on Performance Rights prior to vesting. For Performance Rights that do vest, a dividend equivalent payment will be paid by Woodside for dividends paid during the period between allocation and vesting. The dividend equivalent payment will be paid in cash unless the Board determines otherwise. Restricted Shares have voting rights in the same way as other Woodside shareholders. Performance Rights do not have voting rights until shares are allocated following vesting.
Clawback provisions	The Board has broad discretion to reduce vested and unvested entitlements, including where an Executive has acted fraudulently or dishonestly or is found to be in material breach of their obligations; there is a material misstatement or omission in the financial statements; a significant unexpected or unintended consequence or outcome has occurred; or the Board determines that circumstances have occurred that have resulted in an unfair benefit to the Executive. In 2023, the Board adopted a Mandatory Clawback Policy consistent with the requirements of Section 303.A14 of the New York Stock Exchange Listed Company Manual. Where the company is required to prepare an accounting restatement due to material non-compliance with any financial reporting requirements under the securities laws, the Company will recoup the amount of erroneously awarded incentive-based compensation in accordance with such Mandatory Clawback Policy.
Control event	The Board has the discretion to determine the treatment of any EIS award on a change of control event. If an actual change of control occurs during the performance year, an Executive will generally receive at least a prorata cash payment in respect of the unallocated cash and Restricted Share components of the EIS award for that performance year, assessed at target. If an actual change of control occurs during the vesting period for equity awards, unless the Board determines otherwise Restricted Shares will vest in full whilst Performance Rights, will vest on a pro-rata basis having regard to the portion of the vesting period elapsed.
Cessation of employment	During a performance year, should an Executive resign or be terminated for cause, no EIS award will be provided (unless the Board determines otherwise). In any other case, Woodside will have regard to performance against target and the portion of the performance year elapsed in determining any EIS award. During a deferral or performance period, should an Executive resign or be terminated for cause, any EIS award will be forfeited or lapse (unless the Board determines otherwise). In any other case, any Restricted Shares will vest in full from a date determined by the Board while any Performance Rights will remain on foot and vest in the ordinary course subject to the satisfaction of applicable conditions, unless the Board determines otherwise.
No retesting	There will be no retest applied to EIS awards. Performance Rights will lapse if the required RTSR performance is not achieved at the conclusion of the five-year period.

Other equity plans

Woodside has a history of providing employees with the opportunity to participate in ownership of shares in the company and using equity to support a competitive base remuneration position.

Details of prior year allocations are provided in Table 12. The terms applying to prior year grants are described in past Woodside Annual Reports.

Supplementary Woodside Equity Plan (SWEP)

In October 2011, the Board approved the establishment of the SWEP to enable the offering of targeted retention awards of Equity Rights (ERs for key capability.

The SWEP was updated in 2022 to broaden eligibility to all employees of a subsidiary of Woodside Energy Group Ltd and ensure compliance in all jurisdictions in which Woodside operates. This facilitated the offer of replacement unvested incentives as required under transitional arrangements for eligible heritage BHP employees transitioning from BHP Group Long-Term Incentive (LTI) plans to VAR offered under Woodside’s VAR arrangements.

The SWEP awards have service conditions and no performance conditions. Each ER entitles the participant to receive a Woodside share on the vesting date.

ERs under the SWEP may vest prior to the vesting date on a change of control or on a pro-rata basis, at the discretion of the CEO, limited to the following circumstances; redundancy, retirement (after six months’ participation), death, termination due to illness or incapacity or total and permanent disablement of a participating employee. An employee whose employment is terminated by resignation or for cause prior to the vesting date will forfeit all their unvested ERs.

In relation to the applicable cessation of employment treatment for SWEP ERs granted as replacement awards to heritage BHP employees, unless the Board determines otherwise, unvested SWEP ERs will vest on a pro-rata basis in the following circumstances; redundancy, death, termination due to medical illness or incapacity or total and permanent disablement of the participant. For cessation in other circumstances, (and other than where employment is terminated by resignation or for cause), Woodside’s CEO (or Committee of the Board, as applicable) has discretion to permit pro-rata vesting.

There is no entitlement to dividends on ERs and ERs do not carry voting rights.

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Minimum Shareholding Requirements (MSR) Policy

The Executive MSR Policy reflects the long-term focus of management and aims to further strengthen alignment with shareholders.

The MSR Policy requires Senior Executives to have acquired and maintained Woodside shares for a minimum total purchase price of at least 100% of their FAR after a period of five years, and in the case of the CEO a minimum of 200% of FAR after a period of five years.

Of the Executive KMP, Ms O’Neill, Mr Tiver and Ms McMahon meet the MSR requirements. Ms Westcott commenced with Woodside in 2023 and will acquire Woodside shares to meet the MSR requirements. See Table 14 for details.

Remuneration changes and benchmarking

The Board reviewed the remuneration for the CEO and Senior Executives with regard for accountabilities, experience and individual performance, supported by external benchmarking.

In 2023, the Board engaged independent remuneration consultants KPMG (Australia) and Meridian (US) to provide input to this review. The benchmarking conducted by KPMG included ASX 20 companies, selected peers in the Australian materials and energy sector and international oil and gas companies. Meridian benchmarked 18 companies with global operations, primarily in the oil and gas energy sector.

With reference to market benchmarks, the Board has set Ms O’Neill’s FAR at A$2,472,000 effective 1 January 2024. This increase of three percent (compared to Ms O’Neill’s FAR of A$2,400,000 in 2023) recognised the expertise, knowledge and performance of Ms O’Neill and brings the total remuneration to a competitive position in the selected peer groups.

In 2022 the Board approved an increase to the target opportunity for the CEO’s VAR and structure of the EIS. This has applied to the assessment of the CEO’s performance from 1 June 2022 and the 2023 performance year. No changes are proposed to the target opportunity or structure of EIS for 2024.

Benchmarking indicates Ms O’Neill’s remuneration is positioned competitively in the selected peer groups. CEO FAR is comparable to median of the ASX 20 peer group and the upper quartile of global oil and gas peers. CEO Total Target Remuneration (TTR), which includes FAR and at target VAR, is aligned to the upper quartile of the ASX peer group and is below the median compared to global oil and gas peers.

To support the review of Senior Executive remuneration the Board engaged KPMG to provide benchmarking and remuneration recommendations. Following this review, the FAR for Mr Tiver and Ms McMahon was increased by five percent effective 1 April 2023. No changes are proposed to the VAR target opportunity or structure of EIS for 2024.

Woodside CEO 1 January 2024 FAR and TTR comparison to ASX 20 and global oil and gas peers:

CEO FAR comparison	CEO TTR comparison

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2024 Corporate Scorecard

The 2024 Corporate Scorecard has been approved by the Board and reflects Woodside’s balanced approach to setting measures aligned with Woodside’s strategy. The 2024 Scorecard has five individually weighted measures which assess safe, reliable, and efficient operations, implementation of our strategic plan and delivery of sustainable business priorities.

To focus Executives on their leadership contribution to Woodside’s safety performance and delivery against climate plans, each objective has been elevated as a standalone measure in 2024.

Safety metrics make up 15% of the total 2024 scorecard to ensure a focus on our aim to prevent all injuries and the critical importance of effective process safety management and leadership to avoid major accident and environmental events.

Climate metrics make up 15% of the total 2024 scorecard to ensure appropriate emphasis on meeting Scope 1 and 2 emissions targets as well as progress of new energy projects.

The 2024 measures are:

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Corporate Scorecard measures and outcomes for 2023

Financial (25%)		Outcome 3.3
EBITDA excluding impairment is a key contributor to annual profitability and is influenced by both management performance and commodity prices. EBITDA is closely aligned with short-term shareholder value creation. EBITDA is underpinned by efficient operational performance and outcomes are exposed to the upside and downside of oil and gas price and foreign exchange fluctuations, as are returns to shareholders. Controlling Operating Expenditure brings a focus on efficient operations; cost competitiveness; and shareholder returns.
2023 performance: EBITDA excluding impairments was US$9,363 million, below the target of US$11,860 million due to lower realised prices, partially offset by higher production. Operating Expenditure was US$2,255 million, US$47 million higher than the target of US$2,208 million due to higher operating costs on Pluto and Gulf of Mexico assets. Operating Expenditure excludes the foreign exchange impact of a weaker US dollar, and the commodity price and volume impacts on Pluto-KGP Interconnector Operating Expenditure.
Base business (25%)		Outcome 6.1
Revenue is maximised and value generated from Woodside’s assets when they are fully utilised in production. Production must be carefully managed throughout the year to optimise value from the assets. The production target for Corporate Scorecard purposes is set relative to the company’s annual budget and market guidance.
2023 performance: Production of 187.2 MMboe was within production guidance of 180 – 190 MMboe due to higher Pluto-KGP Interconnector production and continued Pluto Train 1 reliability, Mad Dog Phase 2 first oil achieved in April 2023 and strong field performance for Trinidad and Tobago. This is offset by turnaround activities and lower than planned gas demand at Bass Strait.
Material sustainability issues (25%)		Outcome 4.4
The Board considers performance across material sustainability issues including personal and process safety, climate change and greenhouse gas emissions, and our social licence to operate. Strong performance in this area creates and protects value in four ways; it reduces the likelihood of major accident events and catastrophic losses; it maintains Woodside’s licence to operate which enables the development of its growth portfolio; it reflects efficient, optimised and controlled business processes that generate value; and it supports the company’s position as a partner of choice.
2023 performance: The health and safety performance measure, which contributes to 10% of the overall scorecard outcome, was zero. This reflects safety performance below target with a TRIR of 1.86 (compared to a target of 1), which included one fatality at the North Rankin Complex and process safety performance below target with three Tier 1 or 2 process safety events recorded against a maximum target of 1. Gross equity Scope 1 and 2 emissions performance was 6,190kT CO2-e, 5% better than the target. Woodside is on track for 8 of the 9 indicators in the 2021 – 2025 Reconciliation Action Plan.
Strategy & growth (25%)		Outcome 5.3
In 2023, we focused on progressing Scarborough and Sangomar, taking FID on Trion and progressing new energy projects, combined with delivery of annual synergy initiatives following the merger with BHP’s petroleum business.
Scarborough and Pluto Train 2 •   Scarborough and Pluto Train 2 55% complete1, targeting first LNG cargo in 2026. •   Environmental plans for the seismic, drilling, subsea and trunkline installations activities were accepted by the regulator in December. Sangomar •   93% complete at year end and first oil targeted for mid-2024, compared to a first oil target of late 2023.2 •   FPSO sailed from Singapore in late 2023. Trion •   Final investment decision (FID) achieved. •   Contracts for major scopes of work awarded.	Progress on New Energy Projects •   Woodside continued to progress technical, regulatory and contracting activities for H2OK in 2023. FID has been delayed pending more certainty regarding government tax incentive qualifications and customer offtake agreements. •   Secured planning approvals and State and Federal environmental approvals for the proposed Woodside Solar facility and associated infrastructure compared to targeting FID readiness in 2023. •   Pre front-end engineering and design (FEED) commenced on the Angel carbon capture and storage (CCS) opportunity. Merger integration •   Exceeded synergies target of greater than US$400 million realised.3
Overall corporate performance outcome		Outcome 4.8

1. The completion % excludes the Pluto Train 1 modifications project.

2. The progress of the project has been updated to 93% following a 0.2% correction identified subsequent to the period.

3. Synergies realised is unaudited.

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Executive KMP KPIs and outcomes for 2023

CEO FAR

As a result of the Board’s review of CEO remuneration, Ms O’Neill’s FAR increased from A$2,400,000 to A$2,472,000 effective 1 January 2024.

CEO VAR and other incentives

Ms O’Neill’s incentive arrangements are governed under the EIS.

For 2023, the individual performance of the CEO was reviewed by the Board against five equally weighted measures. These metrics, outlined in Table 4, were chosen because the Board considers successful performance in each area to be a key driver of superior shareholder returns.

The same metrics were cascaded to the Senior Executives to measure individual performance.

At the end of the year, the Board reviewed the CEO’s performance for 2023. The CEO was given an individual performance score between 0 and 5, which together with the Corporate Scorecard determined the VAR outcome. This resulted in an EIS award at 104% of the target opportunity. The CEO proposed to the Board her final EIS award be reduced by 5% in light of the fatality at our North Rankin Complex. The Board exercised its discretion to reduce the EIS award to 99% of the target opportunity (66% of the maximum opportunity). The Board will consider whether any further action is appropriate as Woodside’s response to the fatality continues.

Information on the individual performance of the CEO is shown in Table 4.

The 2023 EIS award for the CEO is detailed in Table 7.

In June 2023, Ms O’Neill was paid the second tranche of a one-off cash bonus approved by the Board in 2022, in recognition of Ms O’Neill’s significant contribution towards the merger of Woodside and BHP’s petroleum business. This payment of A$200,000 was subject to satisfactory individual performance and continued service. This payment is detailed in Table 5 and Table 10.

Senior Executive FAR

As a result of the Board’s review of Senior Executive Remuneration, Mr Tiver’s FAR was increased to A$1,155,000 and Ms McMahon’s FAR to US$578,000 effective 1 April 2023. Ms Westcott’s FAR on appointment was A$1,090,000.

Management will continue to monitor market developments to ensure FAR for Senior Executives remains competitive and benchmarks appropriately against peer companies.

Senior Executive VAR and other incentives

For 2023, the individual performance of each Senior Executive was evaluated against the same performance measures as the CEO, with individual KPIs set relevant to each Executive’s area of responsibility. These metrics aim to align individual performance with the achievement of Woodside’s corporate strategy while fostering collaboration between Executives.

The Board approved EIS awards to Senior Executives based on the Corporate Scorecard result and their individual performance assessment.

Information on the individual performance of Senior Executives who were KMP as at 31 December 2023 is shown in Table 4.

Details of the EIS award for each Senior Executive who were KMP as at 31 December 2023 are set out in Table 7.

CEO actual remuneration	Senior Executives actual remuneration1

1. This represents an average of all Senior Executives actual and variable remuneration for 2023.

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Table 4 – CEO and Senior Executive individual performance for 2023 EIS

Meg O’Neill - CEO and Managing Director
KPI	Performance	Outcome
Growth agenda Assesses the alignment of growth opportunities to shareholder return; portfolio balance; the achievement of challenging business objectives.	•   Matured the corporate strategy, focusing the company on areas of LNG, deepwater oil, integrated carbon solutions and lower carbon energy. •   Scarborough selldown of 10% equity to LNG Japan achieved, with associated non-binding agreements on offtake and collaboration on new energy. •   Trion FID achieved with regulatory approval in place. •   Achieved FID on Hydrogen Refueller. Woodside Solar and H2OK hydrogen project progressing.	Above target
Effective execution Assesses the maintenance, operation and profitability of existing assets; project delivery to achieve budget, schedule and stated performance; cost reduction; achievement of health, safety and community expectations.	•   Personal and process safety performance failed to meet targets. External review of safety system ongoing. •   Strong operational performance with above target production and high LNG reliability. •   Commencement of production from the Mad Dog Phase 2 and Shenzi North projects. •   Safe removal of the Nganhurra Riser Turret Mooring. •   Full year net equity Scope 1 and 2 emissions reduced. •   Sangomar project 93% complete.1	On target
Enterprise capability Assesses leadership development; workforce planning; executive succession; Indigenous participation and diversity; effective risk identification and management.	•   Steady improvement in overall female participation including in leadership and technician and trade roles. •   Delivered 2022 Reconciliation Action Plan, with 8 of 9 targets on track and focus areas agreed for 2024. •   Effective succession planning progressed with improved pipeline of talent across senior and critical roles. •   Continued embedding of Woodside’s leadership program with over 50% of employees completing foundational programs.	Above target
Culture and reputation Assesses performance culture and emphasis on values; engagement and enablement; improved employee climate; Woodside’s brand as a partner of choice.	•   Active external representation of Woodside and the Australian energy sector, including Chair of Australian Energy Producers. •   Continued proactive community engagement and relationships in place. •   Steady improvement in workforce engagement scores reflecting improved organisational climate.	Above target
Shareholder focus Assesses whether decisions are made with a long-term shareholder return focus; efficient and timely communication to shareholders, market analysts and fund managers; the focus on shareholder return throughout the organisation.	•   Maintained organisational focus on shareholder returns, delivering strong dividends in a weaker commodity price environment. •   Financially well positioned with strong balance sheet, low gearing, high liquidity, and appropriate strategies in place to protect against changes to the price environment. •   Exceeded synergies target following the merger with BHP Petroleum.	Above target
EIS earned2 as percentage of target opportunity	99.0%3
EIS earned2 as percentage of maximum opportunity	66.0%

1. The progress of the project has been updated to 93% following a 0.2% correction identified subsequent to the period.

2. The award of Restricted Shares and Performance Rights is subject to shareholder approval at the 2024 Woodside Annual General Meeting.

3. The CEO proposed to the Board her final EIS award be reduced by 5% in light of the fatality at our North Rankin Complex. The Board exercised discretion to reduce the EIS award to 99% of the target opportunity.

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Graham Tiver - Executive Vice President and Chief Financial Officer
KPI	Performance	Outcome
Growth agenda Assesses the alignment of growth opportunities to shareholder return; portfolio balance; the achievement of challenging business objectives.	•   Execution of sell down of a 10% non-operating interest in Scarborough to LNG Japan achieved for accretive value. •   Identified and led the evaluation of several potential acquisition and divestment opportunities.	Above target
Effective execution Assesses the maintenance, operation and profitability of existing assets; project delivery to achieve budget, schedule and stated performance; cost reduction; achievement of health, safety and community expectations.	•   Implemented Sarbanes-Oxley (SOX) program for certification / attestation. •   Delivered improved planning and corporate modelling outcomes. •   Submitted first Securities and Exchange Commission (SEC) Form 20-F in parallel with existing reporting requirements. •   Delivery of merger synergies including sustainably locking into future plans.	Above target
Enterprise capability Assesses leadership development; workforce planning; executive succession; Indigenous participation and diversity; effective risk identification and management.	•   Improved commercial capability with an outward focus, tuned to the market. •   Continued to harmonise risk identification and management across the organisation including learnings and improved focus on controls.	On target
Culture and reputation Assesses performance culture and emphasis on values; engagement and enablement; improved employee climate; Woodside’s brand as a partner of choice.	•   Led the Finance division to deliver across critical enterprise-wide initiatives while protecting enterprise value. •   Largely harmonised Finance processes, achieving better ways of working to become more efficient and effective.	On target
Shareholder focus Assesses whether decisions are made with a long-term shareholder return focus; efficient and timely communication to shareholders, market analysts and fund managers; the focus on shareholder return throughout the organisation.	•   Disciplined balance sheet management; well positioned with high liquidity and appropriate hedging to protect against low price environment. •   A strong balance sheet combined with focused capital allocation has facilitated returns to shareholders at 80% of underlying NPAT.	Above target
EIS earned as percentage of target opportunity	105.5%
EIS earned as percentage of maximum opportunity	66.0%

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Shiva McMahon - Executive Vice President International Operations
KPI	Performance	Outcome
Growth agenda Assesses the alignment of growth opportunities to shareholder return; portfolio balance; the achievement of challenging business objectives.	•   Strong collaboration with operator to deliver Mad Dog Phase 2 remediation work and start-up. •   Delivered uplift in Caribbean production and reserves.	On target
Effective execution Assesses the maintenance, operation and profitability of existing assets; project delivery to achieve budget, schedule and stated performance; cost reduction; achievement of health, safety and community expectations.	•   No high consequence injuries in 2023 and continued focus on learning from organisational health and safety events. •   Delivered production higher than target due to asset reliability improvement, production optimisation and minimal weather impacts. •   Safe and on schedule execution of Shenzi turnaround.	On target
Enterprise capability Assesses leadership development; workforce planning; executive succession; Indigenous participation and diversity; effective risk identification and management.	•   Prioritised building process safety capability and competency. •   Managed resourcing to support growth and sustainability priorities such as decarbonisation. •   Led International Operations’ commitment to value capture, innovation, environment and climate outcomes and asset integrity improvement.	On target
Culture and reputation Assesses performance culture and emphasis on values; engagement and enablement; improved employee climate; Woodside’s brand as a partner of choice.	•   Continued improvement in International Operations’ workforce engagement scores. •   Active stakeholder engagement in Gulf of Mexico, Trinidad and Tobago and in Senegal. •   Established Senegal operations organisation and support services in Dakar and Houston in readiness for first oil.	Above target
Shareholder focus Assesses whether decisions are made with a long-term shareholder return focus; efficient and timely communication to shareholders, market analysts and fund managers; the focus on shareholder return throughout the organisation.	•   Strong delivery against value capture targets with ongoing cost optimisation. •   Delivered asset decarbonisation opportunities ahead of plan.	Above target
EIS earned as percentage of target opportunity	101.0%
EIS earned as percentage of maximum opportunity	63.1%

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Liz Westcott - Executive Vice President Australian Operations
KPI	Performance	Outcome
Growth agenda Assesses the alignment of growth opportunities to shareholder return; portfolio balance; the achievement of challenging business objectives.	•   Maximised facility utilisation with focus on optimisation and infill opportunities. •   Pluto-KGP Interconnector opportunities maximised and Waitsia processing commenced.	Above target
Effective execution Assesses the maintenance, operation and profitability of existing assets; project delivery to achieve budget, schedule and stated performance; cost reduction; achievement of health, safety and community expectations.	•   Demonstrated leadership in driving focus and improvement on personal and process safety outcomes. •   Maintained high facility reliability. •   Drove disciplined performance on turnarounds achieving improved maintenance efficiency and cost performance. •   Successfully commissioned the Pluto Remote Operating Centre, enabling future integration of Scarborough.	On target1
Enterprise capability Assesses leadership development; workforce planning; executive succession; Indigenous participation and diversity; effective risk identification and management.	•   Embedded a simpler, asset-based operating model. •   Refocused on safety fundamentals, and commissioned an external assessment of the operational safety system to guide improvement of safety performance.	Above target
Culture and reputation Assesses performance culture and emphasis on values; engagement and enablement; improved employee climate; Woodside’s brand as a partner of choice.	•   Focussed Australian Operations on building pride and strong engagement on strategy. •   Increased open, transparent communication with workforce. •   Led successful Enterprise Bargaining negotiations on NWS Gas Assets.	Above target
Shareholder focus Assesses whether decisions are made with a long-term shareholder return focus; efficient and timely communication to shareholders, market analysts and fund managers; the focus on shareholder return throughout the organisation.	•   Optimised KLE program to ensure ongoing reliability of key assets while minimising costs. •   Implemented asset decarbonisation initiatives at Pluto LNG and KGP. •   Managing reduction in NWS operating costs focused on late life asset management	On target
EIS earned as percentage of target opportunity	105.5%
EIS earned as percentage of maximum opportunity	66.0%

1. Ms Westcott commenced with Woodside on 1 June 2023 and has led the refocus on safety fundamentals following the 2 June 2023 fatality at North Rankin Complex.

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Table 5 – CEO and Senior Executive take home pay table (non-IFRS information)¹

The following table provides greater transparency to shareholders of the take home pay received or receivable by the CEO and Senior Executives, in 2022 and 2023. This includes FAR, EIS cash awards earned in respect of performance for the year and the value of shares and rights which vested during the year calculated using the five-day VWAP leading up to but not including the vesting, forfeiture or lapsing date. Termination benefits are not included in the table below; these amounts are disclosed in Table 10. Amounts are shown in the currency in which the remuneration is paid, either AUD or USD, whereas Table 10 is expressed in USD which is Woodside’s functional and presentational currency.

Take home pay differs from statutory remuneration reported in Table 10 that is prepared in accordance with the Corporations Act 2001 (Cth) and Accounting Standards which require share-based payments to be reported as remuneration from the time of grant, even though actual value may ultimately not be realised from these share-based payments.

Name	Year	Salary,  allowances and  superannuation2  A$		EIS cash  and other  cash  incentives3,4,5  A$		Restricted Shares  vested6   A$		Performance  Rights  vested6  A$		Equity  Rights vested6  A$		Total  remuneration  received  A$		Previous years’  awards  forfeited or  lapsed6  A$
M O’Neill7	2023		2,400,000		1,530,600		534,659		-		-		4,465,259		-
	2022		2,316,667		1,542,075		384,692		-		-		4,243,434		-
G Tiver8	2023		1,145,053		432,900		-		-		1,229,333		2,807,286		-
	2022		1,006,419		859,124		-		-		1,129,782		2,995,325		-
L Westcott9	2023		709,771		239,538		-		-		-		949,309		-
	2022		-		-		-		-		-		-		-
			US$		US$		US$		US$		US$		US$		US$
S McMahon10	2023		731,585		186,800		-		-		327,039		1,245,424		-
	2022		459,638		80,875		-		-		-		540,513		-

1. This is non-IFRS information that is unaudited.

2. Represents the total fixed annual rewards earned in 2023 and 2022 including salaries, fees, allowances and company contributions to superannuation. This reflects pro-rated amounts for the period that Executives were in KMP roles.

3. Includes the EIS cash incentive earned in the respective year, which is actually paid in the following year.

4. In 2022, cash incentives earned by Ms O’Neill (A$200,000) and Mr Tiver (A$50,000) include a one-off cash bonus payment in relation to their significant contribution towards the merger of Woodside and BHP’s petroleum business. Mr Tiver’s cash incentives include a further cash bonus payment (A$500,000) as a sign-on benefit to compensate for benefits forgone on leaving the BHP Group.

5. In 2023, cash incentives earned by Ms O’Neill (A$200,000) include the second tranche of a one-off cash bonus payment in relation to significant contribution towards the merger of Woodside and BHP’s petroleum business.

6. The value of Restricted Shares, Performance Rights and Equity Rights is calculated using the five-day VWAP leading up to but not including the vesting or forfeiture or lapsing date. For Ms McMahon the amount was translated to USD based on the exchange rate reflective of the five-day period leading up to but not including the vesting date.

7. An increase to target opportunity and change to the structure of the EIS for Ms O’Neill was approved by the Board in 2022. This revised target opportunity and structure applied on a pro-rata basis for the period 1 June 2022 to 31 December 2022 and the 2023 performance year.

8. Mr G Tiver commenced with Woodside on 1 February 2022.

9. Ms L Westcott commenced with Woodside on 1 June 2023.

10. Ms S McMahon commenced with Woodside on 1 June 2022. Ms McMahon was paid in Australian dollars for the period 1 June 2022 to 31 July 2022. Take home pay received has been converted to US dollars using the exchange rate reflective of this period.

Table 6 – 2023 vestings

	Executive	Shares		Vesting value  US$1
2019 EIS 3-year Restricted Shares vested on 18 February 2023	M O’Neill		15,025		370,026
2022 Equity Rights sign on benefit vested on 31 August 2023	G Tiver		32,307		791,138
2022 Equity Rights BHP replacement vested on 31 August 2023	S McMahon		13,355		327,039

1. The value of Restricted Shares and Equity Rights is calculated using the five-day VWAP leading up to but not including the vesting date. Amounts were translated to USD based on the exchange rate reflective of the five-day period leading up to but not including the vesting date.

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Table 7 – Valuation summary of Executive KMP EIS for 2023 and 2022

	Year			Cash1 US$		Restricted Shares 3-year vesting period US$		Restricted Shares 4-year vesting period US$		Restricted Shares 5-year vesting period US$		Performance Rights 5-year vesting period US$		Total EIS US$
M O’Neill		2023	2		906,280		463,891		463,891		1,391,714		937,894		4,163,670
		2022	3		910,591		804,166		350,853		1,539,248		1,051,501		4,656,359
G Tiver		2023	2		265,631		339,914		-		373,918		251,988		1,231,451
		2022	3		189,809		414,767		-		452,495		309,111		1,366,182
S McMahon		2023	2		186,800		243,171		-		267,484		180,261		877,716
		2022	3		80,875		177,819		-		193,978		132,511		585,183
L Westcott4		2023	2		146,983		188,091		-		206,902		139,434		681,410
		2022			-		-		-		-		-		-

1. Represents the cash incentive earned in the respective year, which is actually paid in the following year. Amounts were translated to USD using the closing spot rate on 31 December.

2. The number of Restricted Shares and Performance Rights allocated for 2023 was calculated by dividing the amount of the Executive’s entitlement allocated to Restricted Shares by the face value of Woodside shares. The USD fair value of Restricted Shares and Performance Rights at their date of grant has been estimated by reference to the closing share price at 31 December 2023 and preliminary modelling respectively. Grant date for Senior Executives’ awards has been determined to be the date of the Board of Directors’ approval, being 27 February 2024 while grant date for Ms O’Neill’s award will, subject to shareholder approval being given, be the date of the 2024 Woodside Annual General meeting. Any differences between the estimated fair value at 31 December 2023 and the final fair value will be trued-up in the 2024 financial year. The fair value is not indicative of the benefit (if any) that an individual Executive may ultimately realise should these equity instruments vest.

3. The number of Restricted Shares and Performance Rights allocated for 2022 was calculated post year-end by dividing the amount of the Executive’s entitlement allocated to Restricted Shares and Performance Rights by the face value of Woodside shares. The USD fair value shown above was estimated at 31 December 2022 with reference to the closing share price and preliminary modelling respectively. Grant date for Senior Executives’ awards has been determined to be the date of the Board of Directors’ approval, being 27 February 2023 while grant date for Ms O’Neill’s award is the date of shareholder approval at the 2023 Woodside Annual General Meeting. The final fair value was calculated at these dates and was trued-up in the 2023 financial year. The amount above is not indicative of the benefit (if any) that an individual Executive may ultimately realise should these equity instruments vest.

4. Ms L Westcott commenced with Woodside on 1 June 2023.

Contracts for Executive KMP

Each Executive KMP has a contract of employment. Table 8 below contains a summary of the key contractual provisions of the contracts of employment for the continuing Executive KMP.

Table 8 – Summary of contractual provisions for Executive KMP

Name3	Employing company	Contract duration	Termination notice period company1,2	Termination notice period executive
M O’Neill	Woodside Energy Ltd	Unlimited	6 months	6 months
G Tiver	Woodside Energy Ltd	Unlimited	6 months	6 months
S McMahon	Woodside Energy USA Services Inc	Unlimited	6 months	3 months
L Westcott	Woodside Energy Ltd	Unlimited	6 months	3 months

1. Woodside may choose to terminate the contract immediately by making a payment in lieu of notice equal to the fixed remuneration the Executive KMP would have received during the ‘Company Notice Period’. In the event of termination for serious misconduct or other nominated circumstances, Executive KMP are not entitled to this payment. Any payments made in the event of a termination of an executive contract will be consistent with the Corporations Act 2001 (Cth).

2. On termination of employment, Executive KMP will be entitled to the payment of any fixed remuneration calculated up to the termination date, any leave entitlement accrued at the termination date and any payment or award permitted under the EIS and Equity Award Rules. Executive KMP are restrained from certain activities for specified periods after termination of their employment in order to protect Woodside’s interests.

3. Remuneration is reviewed annually or as required to maintain alignment with policy and benchmarks.

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Non-executive directors (NEDs)

Remuneration policy

Woodside’s Remuneration Policy for NEDs aims to attract, retain, motivate and to remunerate fairly and responsibly having regard to:

• the level of fees paid to NEDs relative to other major Australian listed companies.

• the size and complexity of Woodside’s operations.

• the responsibilities and work requirements of Board members.

Fees paid to NEDs are recommended by the Human Resources & Compensation Committee (Committee) based on benchmarking from external remuneration consultants and determined by the Board. In 2023, the Board determined that there would be no increase to the Board or committee fees or any other benefits.

Fees paid to NEDs are subject to an aggregate limit of A$4.675 million per financial year, which was approved by shareholders at the 2023 AGM.

Minimum Shareholding Requirements (MSR) Policy

NEDs are required to have acquired shares for a total purchase price of at least 100% of their pre-tax base annual fee after five years on the Board. The NEDs may utilise the Non-executive Directors’ Share Plan (NEDSP) to acquire the shares on market at market value. As the shares are acquired after tax, the shares in the NEDSP are not subject to any forfeiture conditions.

As at 31 December 2023, all NEDs met the MSR, except Mr Wyatt who joined Woodside in 2021 and Mr Breuillac and Ms Minas who joined Woodside in 2023. Mr Wyatt, Mr Breuillac and Ms Minas are participating in the NEDSP to assist with acquiring shares. See Table 14 for details.

NEDs remuneration structure

NEDs remuneration consists of base Board fees and committee fees, plus statutory superannuation contributions or payments in lieu (currently 11%). Other payments may be made for additional services outside the scope of Board and Committee duties. NEDs do not earn retirement benefits other than superannuation and are not entitled to any form of performance-linked remuneration in order to preserve their independence.

Table 9 shows the 2023 annual base Board and committee fees for NEDs.

In addition to these fees, NEDs are entitled to reimbursement of reasonable travel, accommodation and other expenses incurred attending meetings of the Board, committees or shareholders, or while engaged on Woodside business. NEDs are not entitled to compensation on termination of their directorships.

An allowance is paid to any NED required to travel internationally to attend Board commitments, compensating for factors related to long-haul travel. Where travel is between six and ten hours, an allowance of A$5,000 gross per trip is paid. Where travel exceeds 10 hours, an allowance of A$10,000 gross per trip is paid.

Board fees are not paid to the CEO, as the time spent on Board work and the responsibilities of Board membership are considered in determining the remuneration package provided as part of the normal employment conditions.

The total remuneration paid to, or in respect of, each NED in 2023 is set out in Table 13.

Table 9 – Annual base Board and committee fees for NEDs¹

Position	Board2 A$		Audit & Risk Committee A$		Human Resources & Compensation Committee A$		Sustainability Committee A$		Nominations & Governance Committee A$
Chair of the Board3		759,465		-		-		-		-
Non-executive directors4		230,137		-		-		-		-
Committee chair		-		62,328		54,600		49,770		Nil
Committee member		-		33,562		27,825		24,885		Nil

1. Fees in this table reflect 2023 annual base Board and committee fees for NEDs.

2. NEDs receive Board and committee fees plus statutory superannuation (or payments in lieu where statutory superannuation is not required to be paid).

3. Inclusive of committee work.

4. Board fees paid to NEDs other than the Chair.

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Human Resources & Compensation Committee

The Committee assists the Board to determine appropriate remuneration policies and structures for NEDs and Executives. Further information on the role of the Committee is described in the Corporate Governance section of the Annual Report.

Loans and transactions

No loans or transactions (other than as described in this report) have been made, guaranteed or secured, directly or indirectly, by Woodside or any of its subsidiaries at any time throughout the year, to any KMP including to a KMP related party.

Use of remuneration consultants

From time-to-time, the Committee directly engages independent external advisers to provide input to the process of reviewing the remuneration for NEDs and Executives. The Committee may receive executive remuneration advice directly from external independent remuneration consultants for Executive KMP.

Under communications and engagement protocols adopted by the Company, market data reports are provided directly to the Committee Chair, and a consultant provides a statement to the Committee that reports have been prepared free of undue influence from Executive KMP. This process ensures the Committee has full oversight of the review process and therefore it, and the Board, can be satisfied that the work undertaken by external independent remuneration consultants is free from undue influence by Executive KMP.

In 2023, KPMG was engaged to provide remuneration recommendations related to remuneration packages of Senior Executives, as defined by the Corporations Act 2001. KPMG was engaged in accordance with the Corporations Act and advice was provided directly to the Human Resources & Compensation Committee through the Committee Chair. Remuneration recommendations were provided to the Board as an input into decision-making only, and the Board considered the recommendations, along with other factors, when making remuneration decisions.

Both KPMG and the Board are satisfied that the remuneration recommendations were made free from undue influence from the Executive KMP to whom the remuneration recommendations applied. The Board was satisfied that the remuneration recommendations provided were free from undue influence because of the communications and engagement protocols adopted by the Company, and because the Senior Executives whose remuneration was the subject of the recommendation were not involved in any aspect of the engagement of KPMG to provide such advice or the process of Woodside receiving the advice.

KPMG was paid A$15,000 in relation to remuneration recommendations related to remuneration packages of Senior Executives. KPMG was paid US$6,319,793 for other services not related to remuneration recommendations.

External benchmarking was obtained from external independent remuneration consultants KPMG and Meridian in support of the 2023 review of CEO and Senior Executive remuneration and from KPMG in support of the 2023 NED fee review. No remuneration recommendations were received for the CEO or NEDs during 2023.

REPORTING NOTES

Reporting in United States dollars

In this report, the remuneration and benefits reported have been presented in US dollars, unless otherwise stated. This is consistent with the functional and presentation currency of the Company.

Compensation for Australian-based employees and Australian-based KMP is paid in Australian dollars and, for reporting purposes, converted to US dollars based on the exchange rate reflective of the service period. Compensation for US-based employees and US-based KMP is paid in US dollars. Valuation of equity awards is converted at the spot rate applying when the equity award is granted.

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Statutory tables

Table 10 – Compensation of CEO and Senior Executives for the year ended 31 December 2023 and 2022

			FAR						VAR and other incentives
			Short-term				Post-employment		Short-term		Long-term
			Salaries, fees and allowances		Non- monetary benefits1		Superannuation / Pension Contributions		Cash2,3,4		Equity Rights5		Restricted Shares5		Performance Rights5		Long Service Leave		Termination benefits		Total Remuneration6				Performance related7
				$		$		$		$		$		$		$		$		$		$		A$		%
M O’Neill8		2023		1,672,740		47,576		-		958,405		-		1,521,538		537,298		177,194		-		4,914,751		7,373,431		61
Chief Executive Officer and Managing Director		2022		1,696,133		35,829		-		1,127,634		-		1,344,879		415,137		41,244		-		4,660,856		6,753,540		62
G Tiver9		2023		721,973		9,169		23,486		294,851		599,593		311,868		90,077		25,681		-		2,076,698		3,116,921		62
Executive Vice President and Chief Financial Officer		2022		717,042		24,725		28,453		599,364		1,284,700		160,013		46,231		10,197		-		2,870,725		4,144,816		73
S McMahon10		2023		634,567		60,110		143,997		186,800		335,940		180,375		51,649		-		-		1,593,438		2,392,942		47
Executive Vice President International Operations		2022		361,471		57,012		96,084		80,875		221,627		47,143		13,399		-		-		877,611		1,300,287		41
L Westcott11		2023		443,247		53,174		48,373		163,151		-		50,518		14,216		10,687		-		783,366		1,186,020		29
Executive Vice President Australian Operations		2022		-		-		-		-		-		-		-		-		-		-		-		-
S Gregory12		2023		-		-		-		-		-		-		-		-		-		-		-		-
		2022		244,076		3,876		8,410		130,448		-		250,799		78,947		20,614		-		737,170		1,030,862		62
F Hick13		2023		-		-		-		-		-		-		-		-		-		-		-		-
		2022		542,533		9,651		19,471		41,294		-		(527,204)		(221,628)		26,595		152,531		43,243		69,494		-
S Duhe14		2023		-		-		-		-		-		-		-		-		-		-		-		-
		2022		57,495		882		2,668		-		-		-		-		(94,350)		-		(33,305)		(46,436)		-
Executive KMP Total		2023		3,472,527		170,029		215,856		1,603,207		935,533		2,064,299		693,240		213,562		-		9,368,253		14,069,314		57
	2022		3,618,750		131,975		155,086		1,979,615		1,506,327		1,275,630		332,086		4,300		152,531		9,156,300		13,252,563		56

1. Reflects the value of allowances and non-monetary benefits (including relocation, travel, health insurance, car parking and any associated fringe benefit tax).

2. The amount includes the EIS cash incentive earned in the respective year, which is actually paid in the following year. Amounts were translated to USD using the closing spot rate on 31 December.

3. Cash incentives earned by Ms O’Neill include an accrual (US$52,125) for the second tranche of a one-off cash bonus payment (US$130,817) paid during the year in relation to significant contribution towards the merger of Woodside and BHP’s petroleum business.

4. In 2022, cash incentives earned, by Mr Tiver (US$33,677), Mr Gregory (US$61,941) and Ms Hick (US$41,294) include a one-off cash bonus payment in relation to their significant contribution towards the merger of Woodside BHP’s petroleum business. Mr Tiver’s cash incentives include a further cash bonus payment (US$355,948) as a sign-on benefit to compensate for benefits forgone on leaving the BHP Group.

5. In accordance with the requirements of AASB 2 Share-based Payment, the fair value of equity instruments as at their date of grant has been determined with reference to the closing share price at grant date, or by applying the Black-Scholes option pricing technique or applying the binomial valuation method combined with a Monte Carlo simulation. The fair value of equity instruments is amortised over the vesting period from the commencement of the service period, such that ‘total remuneration’ includes a portion of the fair value of unvested equity compensation during the year. The portion of the expense relating to the 2023 EIS has been measured using estimated fair values as disclosed in footnote 2 in Table 7. The amount included as remuneration is not indicative of the benefit (if any) that individual Executives may ultimately realise should these equity instruments vest.

6. The total remuneration in AUD is converted from USD using the exchange rate reflective of the service period. This non-IFRS unaudited information is included for the purposes of showing the total annual cost of benefits to the company in Australian dollars for the service period.

7. Performance related outcome percentage is calculated as total variable annual reward divided by the USD total remuneration figure.

8. Ms M O’Neill elected to receive a cash payment in lieu of all superannuation contributions in accordance with the Superannuation Guarantee (Administration) Act 1992, on the basis of being a Senior Foreign Executive. The cash payment is subject to (PAYG) income tax and paid as part of Ms O’Neill’s normal monthly salary. The amount is included in salaries, fees and allowances.

9. Mr G Tiver commenced employment with Woodside on 1 February 2022.

10. Ms S McMahon commenced employment with Woodside on 1 June 2022.

11. Ms L Westcott commenced employment with Woodside on 1 June 2023.

12. Mr S Gregory ceased being an Executive KMP on 31 May 2022.

13. Ms F Hick ceased being an Executive KMP on 28 November 2022. Ms Hick’s termination benefit of US$152,531 includes salaries, fees and allowances received for the period of 29 November 2022 to 24 February 2023 while on gardening leave.

14. Ms S Duhe ceased being an Executive KMP on 4 February 2022.

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Table 11 – Peer group of international oil and gas companies

APA Corporation (previously Apache Corporation)	ENI S.p.A	Marathon Oil Company
Canadian Natural Resources	EOG Resources	Occidental Petroleum
ConocoPhillips	Equinor ASA	Santos Ltd
Coterra Energy	Hess Corporation
Devon Energy	Inpex Corporation

Table 12 – Summary of CEO and Senior Executive KMP allocated, vested or lapsed equity

Name	Type of equity1	Grant date	Vesting date2,3	Awarded but not vested		Vested in 2023		% of total vested		Lapsed in 2023		Fair value of equity4,5,6		Unamortised value $7
M O’Neill8	Restricted Shares	13 February 2019	19 February 2024		15,379		-		-		-		24.71		8,958
	Restricted Shares	12 February 2020	18 February 2023		-		15,025		100		-		22.76		-
	Restricted Shares	12 February 2020	18 February 2025		16,391		-		-		-		22.76		69,085
	Restricted Shares	17 February 2021	24 February 2024		17,697		-		-		-		20.18		12,956
	Restricted Shares	17 February 2021	24 February 2026		17,697		-		-		-		20.18		124,922
	Restricted Shares	19 May 2022	19 May 2025		46,861		-		-		-		20.91		309,269
	Restricted Shares	19 May 2022	19 May 2027		51,122		-		-		-		20.91		566,595
	Restricted Shares	28 April 2023	28 April 2026		33,143		-		-		-		22.28		400,632
	Restricted Shares	28 April 2023	28 April 2027		14,591		-		-		-		22.28		203,012
	Restricted Shares	28 April 2023	28 April 2028		64,013		-		-		-		22.28		975,503
	Restricted Shares	24 April 2024	February 2027		21,923		-		-		-		21.16		352,423
	Restricted Shares	24 April 2024	February 2028		21,923		-		-		-		21.16		374,018
	Restricted Shares	24 April 2024	February 2029		65,771		-		-		-		21.16		1,165,947
	Performance Rights	13 February 2019	19 February 2024		15,379		-		-		-		16.87		6,116
	Performance Rights	12 February 2020	18 February 2025		16,391		-		-		-		15.81		47,989
	Performance Rights	17 February 2021	24 February 2026		23,596		-		-		-		14.44		119,186
	Performance Rights	19 May 2022	19 May 2027		51,122		-		-		-		13.40		363,098
	Performance Rights	28 April 2023	28 April 2028		64,013		-		-		-		14.92		653,254
	Performance Rights	24 April 2024	February 2029		65,771		-		-		-		14.26		785,747
G Tiver	Equity Rights	18 February 2022	31 August 2023		-		32,307		100		-		18.42		-
	Equity Rights	18 February 2022	31 August 2024		32,307		-		-		-		17.60		147,125
	Equity Rights	18 February 2022	31 August 2025		27,460		-		-		-		16.82		215,048
	Restricted Shares	27 February 2023	7 March 2026		17,249		-		-		-		23.63		217,147
	Restricted Shares	27 February 2023	7 March 2028		18,818		-		-		-		23.63		305,099
	Restricted Shares	27 February 2024	February 2027		16,064		-		-		-		21.16		258,460
	Restricted Shares	27 February 2024	February 2029		17,671		-		-		-		21.16		313,427
	Performance Rights	27 February 2023	7 March 2028		18,818		-		-		-		16.18		208,908
	Performance Rights	27 February 2024	February 2029		17,671		-		-		-		14.26		211,222
S McMahon	Equity Rights	1 June 2022	31 August 2023		-		13,355		100		-		20.50		-
	Equity Rights	1 June 2022	31 August 2024		14,118		-		-		-		19.59		81,997
	Equity Rights	1 September 2022	31 August 2025		11,061		-		-		-		18.38		112,966
	Restricted Shares	27 February 2023	7 March 2026		7,395		-		-		-		23.63		101,214
	Restricted Shares	27 February 2023	7 March 2028		8,067		-		-		-		23.63		138,240
	Restricted Shares	27 February 2024	February 2027		11,492		-		-		-		21.16		184,899
	Restricted Shares	27 February 2024	February 2029		12,641		-		-		-		21.16		224,111
	Performance Rights	27 February 2023	7 March 2028		8,067		-		-		-		16.18		94,656
	Performance Rights	27 February 2024	February 2029		12,641		-		-		-		14.26		151,098
L Westcott	Restricted Shares	27 February 2024	February 2027		8,889		-		-		-		21.16		158,805
	Restricted Shares	27 February 2024	February 2029		9,778		-		-		-		21.16		185,907
	Performance Rights	27 February 2024	February 2029		9,778		-		-		-		14.26		125,285

1. For valuation purposes all Performance Rights and Equity Rights are treated as if they will be equity settled. Each Performance Right and Equity Right is a right to receive a fully paid ordinary share in Woodside (or, at the Board’s discretion, as cash equivalent). No amount is payable by the Executive on the grant or vesting of a Performance Right or Equity Right.

2. Vesting date and exercise date are the same. Vesting is subject to satisfaction of vesting conditions. Full details of the vesting conditions for all prior year equity grants to Executive KMP are included in the remuneration report for the relevant year.

3. Vesting of Restricted Shares and Performance Rights granted in 2024 will occur following the release of full-year results in the relevant vesting year. Where the vesting date is not yet known the estimated vesting month is shown.

4. In accordance with the requirements of AASB 2 Share-based Payment, the fair value of Performance Rights and Equity Rights as at their date of grant has been determined by applying the BlackScholes option pricing technique or binomial valuation method combined with a Monte Carlo simulation. The amount included as remuneration is not indicative of the benefit (if any) that individual Executives may ultimately realise should these equity instruments vest.

5. The fair value of Restricted Shares as at their date of grant has been determined by reference to the share price at acquisition. The fair value is not indicative of the benefit (if any) that individual Executive KMP may ultimately realise should these equity instruments.

6. Fair values for the 2023 EIS with grant date being 27 February 2024 and expected to be 24 April 2024 have been estimated as disclosed in footnote 2 of Table 7. Fair values for the 2022 EIS with grant dates of 27 February 2023 and 28 April 2023 have been trued-up as disclosed in footnote 3 of Table 7.

7. The maximum value of the equity instruments awarded for future financial years has been determined as the fair value amount at grant date multiplied by the number of equity instruments awarded, less what has been amortised to date. The minimum total value of the equity instruments awarded for future financial years is nil if relevant vesting conditions are not satisfied.

8. Ms M O’Neill was granted Performance Rights and Restricted Shares on 28 April 2023 as approved by shareholders at the 2023 Woodside Annual General Meeting under Listing Rule 10.14. The grant of the Performance Rights and Restricted Shares components of Ms O’Neill’s 2023 EIS award is subject to shareholder approval at the 2024 Woodside Annual General Meeting. The grant date for Performance Rights and Restricted Shares is the date of shareholder approval.

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Table 13 – Total remuneration paid to NEDs in 2023 and 2022

The following table provides a detailed breakdown of the components of remuneration for each of the company’s NEDs.

		Short-term				Post-employment
		Cash salary and allowances				Pension/Superannuation
Non-executive director		Board and   Committee fees $		Other fees and allowances $		Company contributions to superannuation $		Total $		Total A$8
R Goyder	2023		504,188		36,710		17,490		558,388		841,108
	2022		501,606		41,407		16,942		559,955		807,438
L Archibald2	2023		191,583		33,873		-		225,456		339,607
	20221		190,602		55,150		-		245,752		353,013
F Cooper	2023		212,632		6,639		22,858		242,129		364,721
	20221		211,543		14,809		21,683		248,035		356,304
S C Goh2	2023		187,774		27,106		-		214,880		323,677
	2022		186,813		27,768		-		214,581		309,419
I Macfarlane3	2023		187,774		26,824		-		214,598		323,253
	2022		186,813		28,807		-		215,620		310,917
A Pickard2	2023		204,295		35,239		-		239,534		360,813
	2022		203,248		34,703		-		237,951		343,119
G Tilbrook	2023		210,092		6,639		22,582		239,313		360,480
	2022		210,228		6,935		21,548		238,711		344,214
B Wyatt	2023		188,169		13,277		20,229		221,675		333,912
	20221		186,813		14,809		22,885		224,507		322,377
A Breuillac2,4	2023		153,106		36,298		-		189,404		287,704
	2022		-		-		-		-		-
A Minas2,5	2023		127,853		20,465		-		148,318		225,936
	2022		-		-		-		-		-
C Haynes2,6	2023		65,411		20,467		-		85,878		126,295
	2022		190,602		47,276		-		237,878		343,013
S Ryan7	2023		65,411		-		6,868		72,279		106,295
	2022		190,602		6,935		19,536		217,073		313,013
NEDs total	2023		2,298,288		263,537		90,027		2,651,852		3,993,801
	2022		2,258,870		278,599		102,594		2,640,063		3,802,827

1. A proportion of 2022 other fees and allowances includes an additional payment of A$20,000 each for services outside the scope of Board and committee duties, in connection with the merger with BHP’s petroleum business.

2. As non-residents for Australian tax purposes Mr L Archibald, Ms S C Goh, Ms A Pickard, Mr A Breuillac, Ms A Minas and Dr C Haynes have elected to receive a cash payment in lieu of all superannuation contributions, in accordance with the Superannuation Guarantee (Administration) Act 1992. The cash payment is subject to (PAYG) income tax and paid as part of their normal monthly fees. The amount is included in Other fees and allowances.

3. Mr I Macfarlane has elected to receive a cash payment in lieu of all superannuation contributions in accordance with the Superannuation Guarantee (Administration) Act 1992, on the basis that he works with multiple employers. The cash payment is subject to (PAYG) income tax and paid as part of his normal monthly fees. The amount is included in Other fees and allowances.

4. Mr A Breuillac was appointed as a non-executive director on 8 March 2023.

5. Ms A Minas was appointed as a non-executive director on 28 April 2023.

6. Dr C Haynes ceased being a non-executive director on 28 April 2023.

7. Dr S Ryan ceased being a non-executive director on 28 April 2023.

8. This non-IFRS information is included for the purposes of showing the total annual cost of benefits to the company in Australian dollars for the service period.

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Table 14 – KMP share and equity holdings

Details of shares held by KMP including their personally related entities¹ for the 2023 financial year are as follows:

Name	Type of Equity	Opening holding at 1 January 20232	NEDSP3	Rights   granted	Rights vested	Restricted shares granted	Restricted shares vested	Net changes - Other	Closing holding at 31 December 20234,5
Non-executive directors
R Goyder	Shares	26,163	-	-	-	-	-	-	26,163
L Archibald	Shares	13,524	-	-	-	-	-	-	13,524
F Cooper	Shares	14,895	1,247	-	-	-	-	-	16,142
S C Goh	Shares	13,949	1,004	-	-	-	-	-	14,953
I MacFarlane	Shares	10,891	485	-	-	-	-	-	11,376
A Pickard	Shares	15,870	-	-	-	-	-	-	15,870
G Tilbrook	Shares	9,947	-	-	-	-	-	-	9,947
B Wyatt	Shares	1,639	1,415	-	-	-	-	-	3,054
A Breuillac6	Shares	-	-	-	-	-	-	-	-
A Minas7	Shares	-	-	-	-	-	-	-	-
C Haynes	Shares	16,009	615	-	-	-	-	(16,624)	-
S Ryan	Shares	13,168	549	-	-	-	-	(13,717)	-
Executive KMP
M O’Neill	Equity Rights	-	-	-	-	-	-	-	-
	Performance Rights	106,488	-	64,013	-	-	-	-	170,501
	Restricted Shares	180,172	-	-	-	111,747	(15,025)	-	276,894
	Shares	147,463	-	-	-	-	15,025	(6,761)	155,727
G Tiver	Equity Rights	92,074	-	-	(32,307)	-	-	-	59,767
	Performance Rights	-	-	18,818	-	-	-	-	18,818
	Restricted Shares	-	-	-	-	36,067	-	-	36,067
	Shares	27,076	-	-	32,307	-	-	(14,538)	44,845
S McMahon	Equity Rights	38,534	-	-	(13,355)	-	-	-	25,179
	Performance Rights	-	-	8,067	-	-	-	-	8,067
	Restricted Shares	-	-	-	-	15,462	-	-	15,462
	Shares	1,212	-	-	13,355	-	-	(3,368)	11,199
L Westcott8	Equity Rights	-	-	-	-	-	-	-	-
	Performance Rights	-	-	-	-	-	-	-	-
	Restricted Shares	-	-	-	-	-	-	-	-
	Shares	-	-	-	-	-	-	-	-

1. Includes personally related entities such as a KMP’s spouse, dependants or entities over which they have direct control or significant influence.

2. Opening holding represents amounts carried forward in respect of KMP.

3. Related to participation in the Non-executive Directors’ Share Plan (NEDSP).

4. Closing Shares and Restricted Shares holdings represents Shares and Restricted Shares held by the NEDs and KMP at 31 December 2023. The total Shares and Restricted Shares held by the NEDs and KMP is 651,223 which constitutes less than 1% of all outstanding shares. None of these shares have different voting rights.

5. Closing rights holdings represents unvested options and rights held at the end of the reporting period. There are no options or rights vested but unexercised as at 31 December 2023.

6. Mr A Breuillac was appointed as a NED on 8 March 2023. Mr Breuillac is participating in the NEDSP and will acquire shares under this plan going forward.

7. Ms A Minas was appointed as a NED on 28 April 2023. Ms Minas is participating in the NEDSP and will acquire shares under this plan going forward.

8. Ms L Westcott commenced employment with Woodside on 1 June 2023.

104

4.3.3 Glossary

Key terms used in the Remuneration Report

Term	Meaning
Committee	The Human Resources & Compensation Committee
Corporate Scorecard	A corporate scorecard of key measures that aligns with Woodside’s overall business performance
EIS	The Executive Incentive Scheme
Equity Award Rules	The rules which govern offers of incentive securities to eligible employees
ER or Equity Right	Equity Right. ERs are awarded under the WEP and SWEP and each one entitles participants to receive a fully paid share in Woodside on the vesting date (or a cash equivalent in the case of international assignees). No amount is payable by the participants on the grant or vesting of an ER
Executive	A senior employee whom the Board has determined to be eligible to participate in the EIS
Executive Director	Meg O’Neill
Executive KMP	The Executive Director and Senior Executives listed in Table 1A
FAR	Fixed Annual Reward
KMP	Key management personnel
KPI	Key performance indicator
MSR	Minimum shareholding requirements
NED	Non-executive director
NEDSP	The Non-executive Directors’ Share Plan
Operating Expenditure	Operating and general, administrative and other expenses incurred in generating revenue from the sale of hydrocarbons from Woodside’s operating assets
Performance Rights	Each Performance Right is a right to receive a fully paid ordinary share in Woodside (or, at the Board’s discretion, as cash equivalent). No amount is payable by the Executive on the grant or vesting of a Performance Right
Restricted Shares	Woodside ordinary shares that are awarded to Executives as the deferred component of their STA or as a part of their VAR under the EIS. No amount is payable by the Executive on the grant or vesting of a Restricted Share
Rights	ERs and Performance Rights
RTSR	Relative total shareholder return
Senior Executive	A Senior Executive listed as KMP in Table 1A, excluding the Executive Director
SWEP	The Supplementary Woodside Equity Plan
TTR	Total Target Remuneration
VAR	Variable Annual Reward

105

SECTION 5.1

Financial Statements

Table of Contents

Financial Statements		F-3
Consolidated income statement		F-3
Consolidated statement of comprehensive income		F-4
Consolidated statement of financial position		F-5
Consolidated statement of cashflows		F-6
Consolidated statement of changes in equity		F-7
Notes to the financial statements		F-8
About these statements		F-8
Climate change and energy transition		F-9
A.	Earnings for the year	F-13
A.1	Segment revenue and expenses	F-14
A.2	Finance costs	F-19
A.3	Dividends paid and proposed	F-19
A.4	Earnings per share	F-19
A.5	Taxes	F-20
B.	Production and growth assets	F-23
B.1	Segment production and growth assets	F-24
B.2	Exploration and evaluation	F-26
B.3	Oil and gas properties	F-28
B.4	Impairment of exploration and evaluation, oil and gas properties and goodwill	F-29
B.5	Business combination	F-35
B.6	Goodwill	F-37
B.7	Significant production and growth asset acquisitions	F-37
B.8	Disposal of assets	F-38
C.	Debt and capital	F-40
C.1	Cash and cash equivalents	F-41
C.2	Interest-bearing liabilities and financing facilities	F-42
C.3	Contributed equity	F-44
C.4	Other reserves	F-45
D.	Other assets and liabilities	F-46
D.1	Segment assets and liabilities	F-47
D.2	Receivables	F-47
D.3	Inventories	F-48
D.4	Payables	F-48
D.5	Provisions	F-49
D.6	Other financial assets and liabilities	F-51
D.7	Leases	F-55
E.	Other items	F-58
E.1	Contingent liabilities and assets	F-59
E.2	Employee benefits	F-59
E.3	Related party transactions	F-61
E.4	Auditor remuneration	F-61
E.5	Events after the end of the reporting period	F-61
E.6	Joint arrangements	F-61
E.7	Parent entity information	F-63
E.8	Subsidiaries	F-63
E.9	Other accounting policies	F-67
Directors’ declaration		F-68
PwC - Report of Independent Registered Public Accounting Firm (PricewaterhouseCoopers, Australia, Auditor Firm ID: 1379)		F-69
EY - Report of Independent Registered Public Accounting Firm (Ernst and Young, Australia, Auditor Firm ID: 1435)		F-72

F-1

Significant changes in the current reporting period

As a result of the acquisition of BHP Petroleum International Pty Ltd (BHPP) on 1 June 2022, financial performance for the comparative year ended 31 December 2022 includes seven months of BHPP results, compared to twelve months for the year ended 31 December 2023.

The financial performance and position of the Group were particularly affected by the following events and transactions during the reporting period:

· In April 2023, Mad Dog Phase 2 in the US Gulf of Mexico achieved first production at the Argos platform. During the year ended 31 December 2023, Mad Dog Phase 2 produced 3.1 MMboe of hydrocarbons.

· In April 2023, conditions precedent were achieved in the long-term gas sale and purchase contract (GSPA) with Perdaman. The contract price contains an embedded derivative linked to the price of urea, which is recognised as a net liability of $35 million at 31 December 2023 (refer to Note D.6).

· On 20 June 2023, the Group made a final investment decision (FID) to develop the Trion resource in Mexico. Related exploration and evaluation assets were transferred to oil and gas properties (refer to Notes B.2 and B.3). Upon FID, the Group recognised a deferred tax asset (DTA) of $319 million (refer to Note A.5).

· On 8 August 2023, the Group and LJ Scarborough Pty Ltd (LNG Japan) entered into a Sale and Purchase Agreement for LNG Japan to acquire a 10% non-operating participating interest in the Scarborough Joint Venture. The transaction is expected to complete in the first quarter of 2024. As a result, $823 million of assets have been reclassified as assets held for sale and $94 million of liabilities have been reclassified to liabilities directly associated to assets held for sale (refer to Note B.8). A reduction in the deferred tax liability due to the change to a held for sale basis resulted in a tax benefit of $78 million being recognised for the year ended 31 December 2023.

· During the year ended 31 December 2023, the Group reduced the Pluto petroleum resource rent tax (PRRT) DTA by $637 million ($446 million post-tax) on the basis of future taxable profits not being available to utilise the deductible expenditure. This is primarily driven by decreases in forecast pricing assumptions and actual pricing realised during the year ended 31 December 2023 (refer to Note A.5).

· The Group recognised pre-tax impairments of $1,917 million for the Shenzi, Wheatstone and Pyrenees cash-generating units (refer to Note B.4).

· In 2023, the Group completed the purchase price accounting for the BHPP merger (refer to Note B.5).

F-2

Financial Statements

Consolidated income statement

for the year ended 31 December 2023

	Notes	2023 US$m		2022 US$m		2021 US$m
Operating revenue	A.1		13,994		16,817		6,962
Cost of sales	A.1		(7,519)		(6,540)		(3,845)
Gross profit			6,475		10,277		3,117
Other income	A.1		322		735		139
Other expenses	A.1		(1,573)		(2,726)		(811)
Impairment losses	A.1		(1,917)		-		(10)
Impairment reversals	A.1		-		900		1,058
Profit before tax and net finance costs			3,307		9,186		3,493
Finance income			273		155		27
Finance costs	A.2		(307)		(167)		(230)
Profit before tax			3,273		9,174		3,290
Petroleum resource rent tax (PRRT) (expense)/benefit	A.5		(898)		313		(297)
Income tax expense	A.5		(653)		(2,912)		(957)
Profit after tax			1,722		6,575		2,036
Profit attributable to:
Equity holders of the parent			1,660		6,498		1,983
Non-controlling interest	E.8		62		77		53
Profit for the period			1,722		6,575		2,036
Basic earnings per share attributable to equity holders of the parent (US cents)	A.4		87.5		430.0		206.0
Diluted earnings per share attributable to equity holders of the parent (US cents)	A.4		86.9		426.3		204.1

The accompanying notes form part of the Financial Statements.

F-3

Consolidated statement of comprehensive income

for the year ended 31 December 2023

	2023 US$m	2022 US$m	2021 US$m
Profit for the period	1,722	6,575	2,036
Other comprehensive income/(loss)
Items that may be reclassified to the income statement in subsequent periods:
Gains/(losses) on cash flow hedges	459	(1,097)	(390)
Losses on cash flow hedges reclassified to the income statement	299	847	66
Tax recognised within other comprehensive income	(84)	64	(5)
Exchange fluctuations on translation of foreign operations taken to equity	(1)	3	-
Items that will not be reclassified to the income statement in subsequent periods:
Remeasurement gains on defined benefit plan	14	34	13
Net (loss)/gain on financial instruments at fair value through other comprehensive income	(32)	2	-
Other comprehensive income/(loss) for the period, net of tax	655	(147)	(316)
Total comprehensive income for the period	2,377	6,428	1,720
Total comprehensive income attributable to:
Equity holders of the parent	2,315	6,351	1,667
Non-controlling interest	62	77	53
Total comprehensive income for the period	2,377	6,428	1,720

The accompanying notes form part of the Financial Statements.

F-4

Consolidated statement of financial position

as at 31 December 2023

	Notes	2023 US$m		2022 US$m
Current assets
Cash and cash equivalents	C.1		1,740		6,201
Receivables	D.2		1,517		1,578
Inventories1	D.3		616		678
Other financial assets	D.6		209		677
Assets held for sale	B.8		826		-
Tax receivable			118		73
Other assets			92		83
Total current assets			5,118		9,290
Non-current assets
Receivables	D.2		839		845
Inventories1	D.3		120		65
Other financial assets	D.6		120		120
Exploration and evaluation assets	B.2		668		807
Oil and gas properties	B.3		40,791		39,919
Deferred tax assets	A.5		1,717		1,959
Lease assets	D.7		1,230		1,264
Investments accounted for using the equity method			249		265
Goodwill	B.6		3,995		4,614
Other assets1			514		173
Total non-current assets			50,243		50,031
Total assets			55,361		59,321
Current liabilities
Payables	D.4		1,724		2,094
Interest-bearing liabilities	C.2		-		260
Other financial liabilities	D.6		67		654
Liabilities directly associated with assets held for sale	B.8		94		-
Provisions	D.5		1,506		1,219
Tax payable			1,108		1,854
Lease liabilities	D.7		298		324
Other liabilities			185		203
Total current liabilities			4,982		6,608
Non-current liabilities
Interest-bearing liabilities	C.2		4,883		4,878
Deferred tax liabilities	A.5		1,627		2,457
Other financial liabilities	D.6		42		67
Provisions	D.5		6,451		5,960
Tax payable			40		36
Lease liabilities	D.7		1,317		1,310
Other liabilities			849		878
Total non-current liabilities			15,209		15,586
Total liabilities			20,191		22,194
Net assets			35,170		37,127
Equity
Issued and fully paid shares	C.3		29,001		29,001
Shares reserved for employee share plans	C.3		(49)		(38)
Other reserves	C.4		5,261		4,031
Retained earnings			186		3,342
Equity attributable to equity holders of the parent			34,399		36,336
Non-controlling interest	E.8		771		791
Total equity			35,170		37,127

1. Inventories include carbon credits which were previously presented within other assets (non-current). The 2022 amounts have been reclassified to be presented on the same basis.

The accompanying notes form part of the Financial Statements.

F-5

Consolidated statement of cashflows

for the year ended 31 December 2023

	Notes	2023 US$m		2022 US$m		2021 US$m
Cash flows from/(used in) operating activities
Profit after tax for the period			1,722		6,575		2,036
Adjustments for:
Non-cash items
Depreciation and amortisation			3,960		2,808		1,582
Depreciation of lease assets			179		140		108
Change in fair value of derivative financial instruments			349		960		31
Net finance costs			34		12		203
Tax expense			1,551		2,599		1,254
Exploration and evaluation written off			77		164		265
Impairment losses	B.4		1,917		-		10
Impairment reversals	B.4		-		(900)		(1,058)
Restoration movement			147		272		68
Gain on disposal of oil and gas properties (including revaluation gain)			-		(494)		-
Movement in onerous contracts provision			-		(245)		(95)
Other			(226)		(254)		30
Changes in assets and liabilities
Decrease/(increase) in trade and other receivables			107		(77)		(39)
Increase in inventories			(31)		(146)		(4)
Increase in lease assets			-		-		(16)
(Decrease)/increase in provisions			(114)		131		(75)
Decrease in lease liabilities			-		(31)		(25)
Increase in other assets and liabilities			(736)		(961)		(128)
(Decrease)/Increase in trade and other payables			(135)		184		75
Cash generated from operations			8,801		10,737		4,222
Purchases of shares and payments relating to employee share plans			(57)		(45)		(47)
Interest received			264		108		11
Dividends received			20		19		6
Borrowing costs relating to operating activities			(26)		(21)		(91)
Income tax and PRRT paid			(2,916)		(1,218)		(271)
Payments for restoration			(447)		(263)		(38)
Receipts/(payments) for hedge collateral			506		(506)		-
Net cash from operating activities			6,145		8,811		3,792
Cash flows from/(used in) investing activities
Cash received on business combination, including cash acquired	B.5		-		1,082		-
Payments for capital and exploration expenditure			(5,291)		(3,136)		(2,406)
Borrowing costs relating to investing activities			(311)		(287)		(126)
Advances to other external entities			-		(48)		(206)
Proceeds from disposal of non-current assets			19		132		9
Funding of equity accounted investments			(2)		(8)		-
Payments for acquisition of joint arrangements	B.7		-		-		(212)
Net cash used in investing activities			(5,585)		(2,265)		(2,941)
Cash flows from/(used in) financing activities
Repayment of borrowings	C.2		(284)		(283)		(784)
Borrowing costs relating to financing activities			(4)		(18)		(15)
Repayment of the principal portion of lease liabilities			(340)		(248)		(155)
Borrowing costs relating to lease liabilities			(21)		(10)		(89)
Purchases of shares and payments relating to Dividend Reinvestment Plan			-		(144)		-
Contributions to non-controlling interests			(98)		(98)		(92)
Dividends paid (net of Dividend Reinvestment Plan)			(4,253)		(2,558)		(289)
Net payments from share issuance			-		(5)		-
Net cash used in financing activities			(5,000)		(3,364)		(1,424)
Net (decrease)/increase in cash held			(4,440)		3,182		(573)
Cash and cash equivalents at the beginning of the period			6,201		3,025		3,604
Effects of exchange rate changes			(21)		(6)		(6)
Cash and cash equivalents at the end of the period	C.1		1,740		6,201		3,025

The accompanying notes form part of the Financial Statements.

F-6

Consolidated statement of changes in equity

for the year ended 31 December 2023

	Issued and fully paid shares		Reserved shares		Employee benefits reserve		Foreign currency translation reserve		Hedging reserve		Distributable profits reserve		Other reserves		Retained earnings		Equity holders of the parent		Non- controlling interest		Total equity
Notes	C.3 US$m		C.3 US$m		C.4 US$m		C.4 US$m		C.4 US$m		C.4 US$m		C.4 US$m		US$m		US$m		E.8 US$m		US$m
At 1 January 2023		29,001		(38)		278		796		(586)		3,541		2		3,342		36,336		791		37,127
Profit for the period		-		-		-		-		-		-		-		1,660		1,660		62		1,722
Other comprehensive income/(loss)		-		-		-		(1)		674		-		(32)		14		655		-		655
Total comprehensive income/(loss) for the period		-		-		-		(1)		674		-		(32)		1,674		2,315		62		2,377
Transfers		-		-		-		-		-		4,830		-		(4,830)		-		-		-
Employee share plan purchases		-		(57)		-		-		-		-		-		-		(57)		-		(57)
Employee share plan redemptions		-		46		(46)		-		-		-		-		-		-		-		-
Share-based payments (net of tax)		-		-		58		-		-		-		-		-		58		-		58
Dividends paid		-		-		-		-		-		(4,253)		-		-		(4,253)		(82)		(4,335)
At 31 December 2023		29,001		(49)		290		795		88		4,118		(30)		186		34,399		771		35,170
At 1 January 2022		9,409		(30)		232		793		(400)		58		-		3,381		13,443		786		14,229
Profit for the period		-		-		-		-		-		-		-		6,498		6,498		77		6,575
Other comprehensive income/(loss)		-		-		-		3		(186)		-		2		34		(147)		-		(147)
Total comprehensive income/(loss) for the period		-		-		-		3		(186)		-		2		6,532		6,351		77		6,428
Transfers		-		-		-		-		-		5,553		-		(5,553)		-		-		-
Shares purchased for Dividend Reinvestment Plan		-		(144)		-		-		-		-		-		-		(144)		-		(144)
Dividend Reinvestment Plan		332		144		-		-		-		-		-		-		476		-		476
Shares issued for acquisition of BHPP		19,265		-		-		-		-		-		-		-		19,265		-		19,265
Replacement employee share plan issued for acquisition of BHPP		-		-		18		-		-		-		-		-		18		-		18
Employee share plan purchases		-		(45)		-		-		-		-		-		-		(45)		-		(45)
Employee share plan redemptions		-		37		(37)		-		-		-		-		-		-		-		-
Share-based payments (net of tax)		-		-		65		-		-		-		-		-		65		-		65
Dividends paid		-		-		-		-		-		(2,070)		-		(1,018)		(3,088)		(72)		(3,160)
Transaction costs associated with the issue of shares		(5)		-		-		-		-		-		-		-		(5)		-		(5)
At 31 December 2022		29,001		(38)		278		796		(586)		3,541		2		3,342		36,336		791		37,127
At 1 January 2021		9,297		(23)		219		793		(71)		462		-		1,398		12,075		800		12,875
Profit for the period		-		-		-		-		-		-		-		1,983		1,983		53		2,036
Other comprehensive income/(loss)		-		-		13		-		(329)		-		-		-		(316)		-		(316)
Total comprehensive income/(loss) for the period		-		-		13		-		(329)		-		-		1,983		1,667		53		1,720
Dividend Reinvestment Plan		112		-		-		-		-		-		-		-		112		-		112
Employee share plan purchases		-		(47)		-		-		-		-		-		-		(47)		-		(47)
Employee share plan redemptions		-		40		(40)		-		-		-		-		-		-		-		-
Share-based payments (net of tax)		-		-		40		-		-		-		-		-		40		-		40
Dividends paid		-		-		-		-		-		(404)		-		-		(404)		(67)		(471)
At 31 December 2021		9,409		(30)		232		793		(400)		58		-		3,381		13,443		786		14,229

The accompanying notes form part of the Financial Statements.

F-7

Notes to the financial statements

for the year ended 31 December 2023

About these statements

Woodside Energy Group Ltd and its controlled entities (Woodside or the Group) is a for-profit entity limited by shares, incorporated and domiciled in Australia. Its shares are publicly traded on the Australian Securities Exchange (ASX), on the Main Market for listed securities of the London Stock Exchange (LSE) (with trades settled in the form of UK Depository Interests) and on the New York Stock Exchange (NYSE) (in the form of Woodside American Depositary Shares). The nature of the operations and the principal activities of the Group are described in the Directors’ Report and in the segment information in Note A.1.

The financial statements were authorised for issue in accordance with a resolution of the Directors on 27 February 2024.

Statement of compliance

The financial statements are general purpose financial statements, which have been prepared in accordance with the requirements of the International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board. They also include additional disclosures required for foreign registrants by the United States Securities and Exchange Commission (US SEC).

The Group’s accounting policies are consistent with those disclosed in the Group’s 2022 Financial Statements. Adoption of new or amended standards and interpretations effective 1 January 2023 did not result in any significant changes to the Group’s accounting policies.

Estimates have been revised, where required, to reflect current market conditions including the impact of climate change. Updated assumptions used for depreciation methodology and asset useful lives, impairment assessments, business combinations and restoration obligations are disclosed in Notes B.3, B.4, B.5 and D.5 respectively; these assumptions could change in the future. New estimates and judgements relating to the sell-down of the Scarborough joint venture and an embedded commodity derivative are disclosed in Notes B.8 and D.6 respectively.

Currency

The functional and presentation currency of Woodside and all its material subsidiaries is the US dollar.

Transactions in foreign currencies are initially recorded in the functional currency of the transacting entity at the exchange rates ruling at the date of transaction. Monetary assets and liabilities denominated in foreign currencies at the reporting date are translated at the rates of exchange ruling at that date. Exchange differences in the consolidated financial statements are taken to the income statement.

Rounding of amounts

The financial statements are rounded to the nearest million dollars, except where otherwise indicated.

Basis of preparation

The financial statements have been prepared on a historical cost basis, except for derivative financial instruments and certain other financial assets and financial liabilities, which have been measured at fair value or amortised cost adjusted for changes in fair value attributable to the risks that are being hedged in effective hedge relationships. Where not carried at fair value, if the carrying value of financial assets and financial liabilities does not approximate their fair value, the fair value has been included in the notes to the financial statements.

The financial statements comprise the financial position and results of the Group as at and for the year ended 31 December 2023 (refer to Note E.8).

Subsidiaries are fully consolidated from the date on which control is obtained by the Group and cease to be consolidated from the date at which the Group ceases to have control.

The material subsidiaries of the Group apply the same reporting period and accounting policies as the parent company in their financial statements. All intercompany balances and transactions, including unrealised profits and losses arising from intra-group transactions, have been eliminated in full.

Non-controlling interests are allocated their share of the net profit after tax in the consolidated income statement and their share of other comprehensive income net of tax in the consolidated statement of comprehensive income, and are presented within equity in the consolidated statement of financial position, separately from parent shareholders’ equity.

The consolidated financial statements provide comparative information in respect of the previous periods. Where required, a reclassification of items in the financial statements of the previous periods has been made in accordance with the classification of items in the financial statements of the current period.

F-8

Notes to the financial statement

for the year ended 31 December 2023

Climate change and energy transition

Climate considerations

Woodside has considered the impact of climate and the energy transition in assessing the carrying values of its assets and liabilities. This note describes climate-related assumptions that underpin key areas of the financial statements and the potential short-term and long-term impacts differing scenarios could have on the financial results and financial position of Woodside.

Financial planning and assumptions

Woodside considers a range of climate and macroeconomic scenarios to help benchmark our long-term price assumptions and inform our decision-making to maintain a resilient financial position. These scenarios are informed by a wide range of externally published data, including Paris-aligned and non-Paris-aligned outcomes, and are part of a broad consideration of risks, opportunities, competitiveness and resilience. The assumptions applied in assessing amounts within the financial statements require significant judgement and are in each case calculated in accordance with the requirements of the applicable accounting standards.

Our long-term price assumptions reflect management’s current ‘best estimate’ scenario in which global governments pursue decarbonisation goals as well as other goals such as energy security and economic development. Price assumptions consider current legislation in the locations where Woodside operates and place some weight on scenarios in which the transition to a lower carbon energy system is sufficiently rapid to meet the goals of the Paris Agreement, as well as scenarios in which the transition is not, or may not be, sufficiently rapid. They also place some weight on a range of other assumptions which can drive prices (e.g. inflation) and which are not related to the Paris goals.

Woodside’s facilities are subject to physical risks such as oceanic conditions and are located in regions that experience tropical cyclones, hurricanes and high ambient temperatures. Woodside has significant experience designing and operating facilities located in challenging environments.

The high degree of uncertainty around the nature, timing and magnitude of climate-related risks, and the uncertainty as to how the energy transition will evolve, makes it difficult to determine the risks and their potential impacts with precision.

Woodside continues to monitor the uncertainty around climate change risks and expects to take into account ongoing developments into its assumptions, including assumptions concerning commodity and carbon pricing, as considered appropriate. Oil and gas investment cases include a carbon price assumption which takes into consideration uncertainty around the impact of climate change. Commodity pricing assumptions are key value drivers with greater significance to assets and liabilities than carbon pricing.

Impairment of exploration and evaluation, oil and gas properties and goodwill

In accordance with the Group’s accounting policies and applicable accounting standards, elements of Woodside’s financial statements are based on reasonable and supportable assumptions that represent management’s current best estimate of the range of economic conditions that may exist in the foreseeable future.

The estimation of recoverable amounts for impairment testing includes estimating what an independent market participant would pay to acquire the asset as at the reporting date. Market participants will be guided by their own views on future economic and technical conditions and therefore Woodside considers a range of data sources in determining a future price forecast, including industry and market benchmarks along with asset sales transaction data to support the recoverable amount. The sale of the 10% non-operating participating interest in the Scarborough Joint Venture to LNG Japan announced in August 2023 is a clear example of an independent market valuation fully supporting the carrying value of the multi-decade asset.

Price forecasts are adjusted for premiums and discounts based on the nature and quality of the product. Commodity oil price estimates have considered the impacts of climate policies along with other factors such as industry investment and cost trends. There remains significant uncertainty around how society will respond to the climate challenge.

The energy transition is expected to bring volatility and there is uncertainty as to how commodity prices will develop. The IEA’s World Energy Outlook 2023 (WEO) explores three main climate change scenarios. The IEA scenarios are not predictions and the IEA does not have a single view on the future of the energy system. There is significant uncertainty as to whether any of these scenarios will eventuate. Because Woodside considers what a market participant would pay to acquire an asset in assessing impairments, these external scenarios are not necessarily consistent with the pricing assumptions used for the Group’s impairment assessment as disclosed in Table A below and Note B.4.

The WEO explores three main scenarios1:

• The Net Zero Emissions by 2050 Scenario (NZE)

• The Announced Pledges Scenario (APS)

• The Stated Policies Scenario (STEPS)

Table A: Average real terms 2022 oil price (US$/bbl, Brent) 2, North Asian LNG price (US$/MMbtu) 2 and carbon price (US$/tCO2-e) 3 consistent with IEA dataset compared against Woodside’s assumptions:

Average Brent (RT US$/bbl)	2024-2027		2028-2032		2033-2036		2037-2040
NZE		52		41		34		31
APS		76		74		72		69
STEPS		84		85		84		84
Woodside		73		70		70		70

Average North Asian LNG (RT US$/MMbtu)	2024-2027		2028-2032		2033-2036		2037-2040
NZE		8		5		5		5
APS		10		8		7		7
STEPS		11		9		9		8
Woodside		11		9		9		9

Average Carbon (RT US$/tonne)	2024-2027		2028-2032		2033-2036		2037-2040
NZE		101		139		169		195
APS		100		133		153		169
STEPS		80		80		80		80
Woodside		80		80		80		80

1. IEA 2023. ‘World Energy Outlook 2023’. All rights reserved.

2. Based on data from IEA 2023. ‘World Energy Outlook 2023’ as modified by Woodside analysis. Woodside used interpolation techniques to estimate Brent annual price points in between the years that the IEA disclose prices for. For gas pricing assumptions all non-contracted LNG volumes were assessed at IEA’s Japan import price, as a proxy for North Asian LNG spot price. Woodside used interpolation techniques to estimate annual gas price points in between the years that the IEA disclose prices for. For oil linked LNG contracts, prices are derived from the Brent forecasts and the terms of the contracts.

3. Based on data from IEA 2023. ‘World Energy Outlook 2023’ as modified by Woodside analysis. The IEA only provide carbon prices from 2030 onwards. As a result, Woodside used a starting point of US$80/tCO2-e consistent with internal carbon pricing. Woodside used the 2022 starting price point and the IEA’s published 2030 and 2040 carbon prices for each scenario to interpolate annual price points through to 2040.

Refer to Note B.4 for the sensitivity analysis performed on Woodside’s commodity pricing assumptions and the potential impact on the carrying value of Woodside’s non-current assets.

The benchmarked pricing above has limitations and is based on a wide range of assumptions. The impact of the benchmark pricing assumptions may be addressed to varying degrees by decisions Woodside could make in response such as acquisitions, divestments or cost reductions as well as other consequential changes. The scenarios must therefore not be interpreted as Woodside’s investment guidance. These are scenarios, not forecasts, and no likelihood is assigned to any of these scenarios eventuating.

Impact on remaining life of assets

Oil and gas properties relating to transferred exploration and evaluation and offshore plant and equipment are depreciated using the unit of production basis over either proved or proved plus probable reserves. The energy transition may result in changes to the expected useful life of oil and gas properties and economically recoverable reserves and resources thereby accelerating depreciation charges or resulting in an impairment.

F-9

Notes to the financial statement

for the year ended 31 December 2023

Restoration and other provisions

The energy transition may result in restoration activities occurring earlier than expected. 55% (2022: 54%) of the Group’s non-current restoration liabilities are expected to be settled more than 10 years in the future.

Restoration cost estimates require judgemental assumptions regarding removal date, environmental legislation and regulations and the extent of restoration activities required.

These cost estimates may change in the future, as a result of increased regulatory scrutiny and the energy transition. This includes the demand and related costs for offshore services which can be influenced by renewable energy construction. Woodside continues to monitor the uncertainty around climate change risks to assess if additional changes to restoration provisions should be recognised.

Long term contracts

Climate risks may impact underlying assumptions used to assess the forecast cash flows of long-term contracts. These judgemental assumptions include pricing forecast and discount rate adjustments based on the nature of the product.

As at 31 December 2023, the Corpus Christi contract has a positive value and therefore is not currently onerous (2022: not onerous). This and other contractual arrangements could be impacted by adverse market conditions arising from climate-related factors.

Given the uncertainty in climate events, Woodside continues to review the forecast cash flows of long-term contracts.

Deferred tax assets

The Group has determined that it is probable that sufficient future taxable income will be available to utilise the deferred tax assets relating to carry forward unused tax losses and credits recognised as at 31 December 2023. The recoverability of deferred tax assets is dependent on the Group’s future taxable income which can be impacted by the uncertainty of commodity and carbon pricing.

Regulatory environment

Regulation of climate-related emissions can change over time. The Australian Government has passed reforms to its Safeguard Mechanism which applies to regulatory limits on greenhouse gas emissions from Woodside’s Australian facilities. Some elements of the reform, such as the method for determining limits at new facilities, continue to be developed. In December 2023, the United States Environmental Protection Agency (EPA) issued a final rule to establish performance standards for methane and other emissions from existing and new oil and gas operations. Woodside is not aware of any proposal that would materially affect the information in these financial statements.

F-10

Notes to the financial statement

for the year ended 31 December 2023

Financial and capital risk management

The Board of Directors has overall responsibility for the establishment and oversight of the Group’s risk management framework, including review and approval of the Group’s risk management strategy, policy and key risk parameters. The Board of Directors and the Audit and Risk Committee have oversight of the Group’s internal control system and risk management process, including oversight of the internal audit function.

The Group’s management of financial and capital risks is aimed at ensuring that available capital, funding and cash flows are sufficient to:

· meet the Group’s financial commitments as and when they fall due;

· maintain the capacity to fund its committed project developments;

· pay a reasonable dividend; and

· maintain a long-term credit rating of not less than ‘investment grade’.

The Group monitors and tests its forecast financial position against these criteria and, in general, will undertake hedging activity when necessary to ensure that these objectives are achieved.

Other circumstances that may lead to hedging include the management of exposures relating to trading activities. It is, and has been throughout the period, the Group Treasury policy that no speculative trading in financial instruments shall be undertaken. Refer to Section 3.9 Risk factors for more information on the Group’s objectives, policies and processes for managing financial risk.

The below risks arise in the normal course of the Group’s business. Risk information can be found in the following sections:

Section A	Commodity price risk management	Page F-13
Section A	Foreign exchange risk management	Page F-13
Section C	Capital risk management	Page F-40
Section C	Liquidity risk management	Page F-40
Section C	Interest rate risk management	Page F-40
Section D	Credit risk management	Page F-46

F-11

Notes to the financial statement

for the year ended 31 December 2023

Key estimates and judgements

In applying the Group’s accounting policies, management regularly evaluates judgements, estimates and assumptions based on experience and other factors, including expectations of future events that may have an impact on the Group. All judgements, estimates and assumptions made are believed to be reasonable based on the most current set of circumstances known to management, and actual results may differ. Significant judgements, estimates and assumptions made by management in the preparation of these financial statements are found in the following notes:

Note A.1	Revenue from contracts with customers	Page F-14
Note A.5	Taxes	Page F-20
Note B.2	Exploration and evaluation	Page F-26
Note B.3	Oil and gas properties	Page F-28
Note B.4	Impairment of exploration and evaluation, oil and gas properties and goodwill	Page F-29
Note B.5	Business combination	Page F-35
Note B.6	Goodwill	Page F-37
Note B.7	Significant production and growth asset acquisitions	Page F-37
Note B.8	Disposal of assets	Page F-38
Note D.5	Provisions	Page F-49
Note D.6	Other financial assets and liabilities	Page F-51
Note D.7	Leases	Page F-55
Note E.6	Joint arrangements	Page F-61

F-12

Notes to the financial statements A. Earnings for the year

for the year ended 31 December 2023

In this section

This section addresses financial performance of the Group for the reporting period including, where applicable, the accounting policies applied and the key estimates and judgements made. This section also includes the tax position of the Group for and at the end of the reporting period.

A.	Earnings for the year
A.1	Segment revenue and expenses	Page F-14
A.2	Finance costs	Page F-19
A.3	Dividends paid and proposed	Page F-19
A.4	Earnings per share	Page F-19
A.5	Taxes	Page F-20

Key financial and capital risks in this section

Commodity price risk management

The Group’s revenue is exposed to commodity price fluctuations through the sale of hydrocarbons. Commodity price risks are measured by monitoring and stress testing the Group’s forecast financial position to sustained periods of low oil and gas prices. This analysis is regularly performed on the Group’s portfolio and as required for discrete projects and transactions.

The Group’s management of commodity price risk includes the use of commodity derivatives to hedge its exposure (refer to Note D.6). The hedged exposure includes oil-linked revenue related to produced volumes and revenues derived from trading operations. Commodity derivatives protect the Group against downside price risk within its corporate and trading portfolios.

As at the reporting date, the Group held commodity hedging financial instruments with a net asset carrying value of $123 million (2022: $557 million net liability) exposed to commodity price risk. An increase in relevant commodity prices of 10% would decrease the instruments’ carrying value by $172 million, the effect of which would be recognised within reserves and/or the income statement in accordance with hedge accounting application. A 10% decrease would have the same but opposite effect. This analysis assumes that all other variables remain constant (including the price on underlying physical exposures).

Foreign exchange risk management

Foreign exchange risk arises from future commitments, financial assets and financial liabilities that are not denominated in US dollars. The majority of the Group’s revenue is denominated in US dollars. The Group is exposed to foreign currency risk arising from operating and capital expenditure incurred in currencies other than US dollars, particularly Australian dollars.

The Group’s management of foreign exchange risk relating to capital expenditure includes the use of forward exchange contract derivatives to hedge its exposure (refer to Note D.6).

The Group entered into foreign exchange forward contracts to fix the Australian dollar to US dollar exchange rate in relation to a portion of the Australian dollar denominated capital expenditure incurred or expected to be incurred under the Scarborough development (refer to Note D.6). Through the use of foreign exchange forward contracts, the Group also hedged its Australian dollar to US dollar exchange rate exposure in relation to the Australian dollar denominated tax payments which have matured.

As at the reporting date, the Group held hedging foreign currency financial instruments with a net asset carrying value of $8 million (2022: net liability carrying value of $17 million) exposed to foreign exchange risk.

Measuring the exposure to foreign exchange risk is achieved by regularly monitoring and performing sensitivity analysis on the Group’s financial position.

A reasonably possible change in the exchange rate of the US dollar to the Australian dollar (+12%/-12% (2022: +12%/-12%)), with all other variables held constant, would not have a material impact on the Group’s equity or the income statement. Refer to Notes C1, C2, D2, D4 and D7 for details of the denominations of cash and cash equivalents, interest-bearing liabilities, receivables, payables and lease liabilities held at 31 December 2023.

F-13

Notes to the financial statements A. Earnings for the year

for the year ended 31 December 2023

A.1 Segment revenue and expenses

Operating segment information

The Group has identified its operating segments based on the internal reports that are reviewed and used by the Chief Executive Officer (Chief Operating Decision Maker) in assessing performance and determining the allocation of resources.

The disclosed operating segments in 2023 remain consistent to 2022. In the prior reporting period, the 2021 amounts were restated to be presented on the same basis.

Operating segments outlined below are identified by management based on the nature and geographical location of the business and venture.

  Australia:   Exploration, evaluation, development, production and sale of liquified natural gas, pipeline gas, crude oil and condensate and natural gas liquids in Australia.   International:   Exploration, evaluation, development, production and sale of pipeline gas, crude oil and condensate and natural gas liquids in international jurisdictions outside of Australia.   Marketing:   Marketing, Shipping and Trading of Woodside’s oil and gas portfolio (including purchased volumes) and optimisation activities attributed to Marketing which generate incremental value.   Corporate/Other items:   Corporate/Other items comprise primarily corporate non-segmental items of revenue and expenses and associated assets and liabilities not allocated to operating segments as they are not considered part of the core operations of any segment.  

Customer concentration

The Group has two major customers which respectively account for 8% and 7% of the Group’s external revenue. The sales are generated by the Australia and Marketing operating segments (2022: two major customers; 12% and 9% generated by the Australia and Marketing operating segments and 2021: two major customers; 8% and 6% generated by the Australia operating segment).

Geographical information

Geographical Information	Revenue from external customers1						Non-current assets2
	2023 US$m		2022 US$m		2021 US$m		2023 US$m		2022 US$m
Asia Pacific		9,823		12,521		6,342		36,060		36,966
Americas		2,564		1,545		-		7,171		7,057
Africa		-		-		-		5,295		4,049
Europe		1,607		2,751		620		-		-
Consolidated		13,994		16,817		6,962		48,526		48,072

1. Revenue is attributable to geographic location based on the location of the customers.

2. Non-current assets exclude deferred tax of $1,717 million (2022: $1,959 million).

Recognition and measurement

Revenue from contracts with customers

Revenue is recognised when or as the Group transfers control of products or provides services to a customer at the amount to which the Group expects to be entitled. If the consideration includes a variable component, the Group estimates the amount of the expected consideration receivable. Variable consideration is estimated throughout the contract and is recognised to the extent that it is highly probable a significant reversal will not occur.

· Revenue from sale of hydrocarbons - Revenue from the sale of hydrocarbons is recognised at a point in time when control of the product is transferred to the customer. Revenue from take or pay contracts is recorded as unearned revenue until the product has been drawn by the customer (transfer of control), at which time it is recognised in earnings.

· Other operating revenue - Revenue earned from LNG processing and other services is recognised over time as the services are rendered.

Expenses

· Royalties, excise and levies - Royalties, excise and levies are considered to be production-based taxes and are therefore accrued on the basis of the Group’s entitlement to physical production.

· Depreciation and amortisation - Refer to Note B.3.

· Impairment and impairment reversals - Refer to Note B.4.

· Leases - Refer to Note D.7.

· Employee benefits - Refer to Note E.2.

F-14

Notes to the financial statements A. Earnings for the year

for the year ended 31 December 2023

Key estimates and judgements

(a) Revenue from contracts with customers

The transaction price at the date control passes for sales made subject to provisional pricing periods in oil and condensate contracts is determined with reference to quoted commodity prices.

Judgement is also used to determine if it is highly probable that a significant reversal will not occur in relation to revenue recognised during open pricing periods in LNG contracts. The Group estimates variable consideration based on available information from contract negotiations and market indicators.

F-15

Notes to the financial statements A. Earnings for the year

for the year ended 31 December 2023

	Australia		International		Marketing		Corporate/ Other		Consolidated
	2023 US$m		2023 US$m		2023 US$m		2023 US$m		2023 US$m
Liquefied natural gas	6,867		-		1,298		-		8,165
Pipeline gas	1,088		286		-		-		1,374
Crude oil and condensate	1,611		2,246		124		-		3,981
Natural gas liquids	218		32		31		-		281
Revenue from sale of hydrocarbons	9,784		2,564		1,453		-		13,801
Intersegment revenue1	(166	)	(15	)	181		-		-
Processing and services revenue	184		-		-		-		184
Shipping and other revenue	-		-		9		-		9
Other revenue	18		(15	)	190		-		193
Operating revenue2	9,802		2,549		1,643		-		13,994
Production costs	(1,173	)	(389	)	-		-		(1,562	)
Royalties, excise and levies	(462	)	(41	)	-		-		(503	)
Insurance	(41	)	(11	)	-		(8	)	(60	)
Inventory movement	(40	)	3		-		-		(37	)
Costs of production	(1,716	)	(438	)	-		(8	)	(2,162	)
Land and buildings	(62	)	(5	)	-		-		(67	)
Transferred exploration and evaluation	(101	)	(24	)	-		-		(125	)
Plant and equipment	(2,591	)	(1,139	)	-		(34	)	(3,764	)
Oil and gas properties depreciation and amortisation	(2,754	)	(1,168	)	-		(34	)	(3,956	)
Shipping and direct sales costs	(164	)	(83	)	(54	)	(18	)	(319	)
Trading costs	(12	)	-		(1,056	)	-		(1,068	)
Other hydrocarbon costs	(7	)	-		-		-		(7	)
Other cost of sales	(7	)	-		-		-		(7	)
Movement in onerous contract provision	-		-		-		-		-
Other cost of sales	(190	)	(83	)	(1,110	)	(18	)	(1,401	)
Cost of sales	(4,660	)	(1,689	)	(1,110	)	(60	)	(7,519	)
Gross profit	5,142		860		533		(60	)	6,475
Other income3	160		54		26		82		322
Exploration and evaluation expenditure4	(24	)	(253	)	-		(2	)	(279	)
Amortisation of permit acquisition	-		(4	)	-		-		(4	)
Write-offs	(31	)	(46	)	-		-		(77	)
Exploration and evaluation	(55	)	(303	)	-		(2	)	(360	)
General, administrative and other costs	-		-		-		(453	)	(453	)
Depreciation of other plant and equipment	-		-		-		-		-
Depreciation of lease assets	(50	)	(14	)	(75	)	(40	)	(179	)
Restoration movement	(125	)	(22	)	-		-		(147	)
Other5	(51	)	-		(109	)	(274	)	(434	)
Other costs	(226	)	(36	)	(184	)	(767	)	(1,213	)
Other expenses	(281	)	(339	)	(184	)	(769	)	(1,573	)
Impairment losses	(534	)	(1,383	)	-		-		(1,917	)
Impairment reversals6	-		-		-		-		-
Profit/(loss) before tax and net finance costs	4,487		(808	)	375		(747	)	3,307

1. Intersegment revenue comprises the incremental income net of all associated expenses generated by the Marketing segment’s optimisation of the oil and gas portfolio. The value is incremental income net of incremental costs.

2. Operating revenue includes revenue from contracts with customers of $13,985 million and sub-lease income of $9 million disclosed within shipping and other revenue.

3. Includes fees and recoveries, foreign exchange gains and other income not associated with the ongoing operations of the business.

4. Includes seismic and general permit activities and other exploration costs.

5. Includes losses on hedging activities, fair value losses on embedded derivatives and other expenses not associated with the ongoing operations of the business.

6. Impairment on oil and gas properties. Refer to Note B.4 for more details.

F-16

Notes to the financial statements A. Earnings for the year

for the year ended 31 December 2023

	Australia			International			Marketing			Corporate/ Other			Consolidated
	2022 US$m			2022 US$m			2022 US$m			2022 US$m			2022 US$m
Liquefied natural gas		8,855			-			2,434			-			11,289
Pipeline gas		1,086			276			-			-			1,362
Crude oil and condensate		2,467			1,273			18			-			3,758
Natural gas liquids		171			26			9			-			206
Revenue from sale of hydrocarbons		12,579			1,575			2,461			-			16,615
Intersegment revenue1		(455)			(5)			460			-			-
Processing and services revenue		175			-			-			-			175
Shipping and other revenue		-			-			27			-			27
Other revenue		(280)			(5)			487			-			202
Operating revenue2		12,299			1,570			2,948			-			16,817
Production costs		(975)			(313)			-			7			(1,281)
Royalties, excise and levies		(540)			(39)			-			(17)			(596)
Insurance		(35)			(7)			-			(1)			(43)
Inventory movement		44			(3)			-			-			41
Costs of production		(1,506)			(362)			-			(11)			(1,879)
Land and buildings		(51	)		(3	)		-			-			(54	)
Transferred exploration and evaluation		(107	)		-			-			-			(107	)
Plant and equipment		(2,168	)		(436	)		-			(33	)		(2,637	)
Oil and gas properties depreciation and amortisation		(2,326	)		(439	)		-			(33	)		(2,798	)
Shipping and direct sales costs		(312	)		(36	)		(73	)		142			(279	)
Trading costs		(14	)		-			(1,763	)		-			(1,777	)
Other hydrocarbon costs		(19	)		-			-			-			(19	)
Other cost of sales		(4	)		-			-			-			(4	)
Movement in onerous contract provision3		-			-			216			-			216
Other cost of sales		(349	)		(36	)		(1,620	)		142			(1,863	)
Cost of sales		(4,181	)		(837	)		(1,620	)		98			(6,540	)
Gross profit		8,118			733			1,328			98			10,277
Other income4		722			4			5			4			735
Exploration and evaluation expenditure5		(20	)		(277	)		-			1			(296	)
Amortisation of permit acquisition		(1	)		(9	)		-			-			(10	)
Write-offs6		-			(164	)		-			-			(164	)
Exploration and evaluation		(21	)		(450	)		-			1			(470	)
General, administrative and other costs7		(13	)		(21	)		(10	)		(747	)		(791	)
Depreciation of other plant and equipment		-			-			-			-			-
Depreciation of lease assets		(49	)		(11	)		-			(80	)		(140	)
Restoration movement		(234	)		(46	)		-			8			(272	)
Other8		(8	)		(84	)		(475	)		(486	)		(1,053	)
Other costs		(304	)		(162	)		(485	)		(1,305	)		(2,256	)
Other expenses		(325	)		(612	)		(485	)		(1,304	)		(2,726	)
Impairment losses		-			-			-			-			-
Impairment reversals9		900			-			-			-			900
Profit/(loss) before tax and net finance costs		9,415			125			848			(1,202	)		9,186

1. Intersegment revenue comprises the incremental income net of all associated expenses generated by the Marketing segment’s optimisation of the oil and gas portfolio. The value is incremental income net of incremental costs.

2. Operating revenue includes revenue from contracts with customers of $16,790 million and sub-lease income of $27 million disclosed within shipping and other revenue.

3. Comprises changes in estimates of $245 million offset by provisions used of $29 million. Refer to Note D.5 for further details.

4. Includes initial gain on Train 2 sell-down of $427 million, revaluation gain on the remeasurement of the Train 2 sell-down variable consideration of $71 million, fees and recoveries, foreign exchange gains and other income not associated with the ongoing operations of the business.

5. Includes $142 million for various costs relating to the Group’s exit from the Orphan Basin exploration licences in Canada.

6. $125 million relates to costs of unsuccessful wells that have been written off. Refer to Note B.2.

7. Transaction costs of $419 million incurred as a result of the BHPP merger on 1 June 2022 are included in the Corporate/Other segment. Refer to Note B.5 for details.

8. Includes losses on hedging activities and changes in fair value of derivative financial instruments of $960 million in the Marketing and Corporate/Other segments and other expenses not associated with the ongoing operations of the business.

9. Impairment reversals on oil and gas properties. Refer to Note B.4 for more details.

F-17

Notes to the financial statements A. Earnings for the year

for the year ended 31 December 2023

	Australia			International			Marketing			Corporate/ Other			Consolidated
	20218 US$m			20218 US$m			20218 US$m			20218 US$m			2021 US$m
Liquefied natural gas		3,910			-			1,449			-			5,359
Pipeline gas		43			-			-			-			43
Crude oil and condensate		1,316			-			-			-			1,316
Natural gas liquids		60			-			-			-			60
Revenue from sale of hydrocarbons		5,329			-			1,449			-			6,778
Intersegment revenue1		(236)			-			236			-			-
Processing and services revenue		143			-			-			-			143
Shipping and other revenue		4			-			37			-			41
Other revenue		(89)			-			273			-			184
Operating revenue2		5,240			-			1,722			-			6,962
Production costs		(489)			-			-			8			(481)
Royalties, excise and levies		(218)			-			-			-			(218)
Insurance		(32)			-			-			1			(31)
Inventory movement		17			-			-			-			17
Costs of production		(722)			-			-			9			(713)
Land and buildings		(51	)		-			-			-			(51	)
Transferred exploration and evaluation		(79	)		-			-			-			(79	)
Plant and equipment		(1,419	)		-			-			-			(1,419	)
Oil and gas properties depreciation and amortisation		(1,549	)		-			-			-			(1,549	)
Shipping and direct sales costs		(197	)		-			(45	)		32			(210	)
Trading costs		(3	)		-			(1,492	)		-			(1,495	)
Other hydrocarbon costs		(6	)		-			-			-			(6	)
Other cost of sales		(11	)		-			-			(1	)		(12	)
Movement in onerous contract provision3		-			-			140			-			140
Other cost of sales		(217	)		-			(1,397	)		31			(1,583	)
Cost of sales		(2,488	)		-			(1,397	)		40			(3,845	)
Gross profit/(loss)		2,752			-			325			40			3,117
Other income4		97			(2	)		1			43			139
Exploration and evaluation expenditure		(16	)		(27	)		-			(11	)		(54	)
Amortisation of permit acquisition		-			(2	)		-			(1	)		(3	)
Write-offs5		-			(265	)		-			-			(265	)
Exploration and evaluation		(16	)		(294	)		-			(12	)		(322	)
General, administrative and other costs		(5	)		(1	)		-			(152	)		(158	)
Depreciation of other plant and equipment		-			-			-			(30	)		(30	)
Depreciation of lease assets		(28	)		-			-			(80	)		(108	)
Restoration movement		(80	)		12			-			-			(68	)
Other6		(57	)		(32	)		28			(64	)		(125	)
Other costs		(170	)		(21	)		28			(326	)		(489	)
Other expenses		(186	)		(315	)		28			(338	)		(811	)
Impairment losses		(10	)		-			-			-			(10	)
Impairment reversals7		1,058			-			-			-			1,058
Profit/(loss) before tax and net finance costs		3,711			(317	)		354			(255	)		3,493

1. Intersegment revenue comprises the incremental income net of all associated expenses generated by the Marketing segment’s optimisation of the oil and gas portfolio. The value is incremental income net of incremental costs.

2. Operating revenue includes revenue from contracts with customers of $6,923 million and sub-lease income of $39 million disclosed within shipping and other revenue.

3. Comprises provisions used of $45 million and changes in estimates of $95 million.

4. Includes other income of $67 million relating to Pluto volumes delivered into Wheatstone’s sales commitments and net foreign exchange gains of $44 million.

5. $56 million relates to costs of unsuccessful wells. $209 million relates to capitalised costs written off due to the Group’s decision to withdraw from its interests in Myanmar.

6. Includes net loss on hedging activities of $91 million, various costs relating to Woodside’s exit from the Kitimat LNG development of $33 million and other expenses not associated with the ongoing operations of the business.

7. Impairment reversals on oil and gas properties.

8. In the prior reporting period, the 2021 amounts were restated to reflect the changes in operating segments and portfolio reporting for LNG revenue.

F-18

Notes to the financial statements A. Earnings for the year

for the year ended 31 December 2023

A.2 Finance costs

	2023 US$m		2022 US$m		2021 US$m
Interest on interest-bearing liabilities		229		212		201
Interest on lease liabilities		102		103		97
Accretion charge		238		110		29
Other finance costs		49		36		26
Less: Finance costs capitalised against qualifying assets		(311)		(294)		(123)
		307		167		230

A.3 Dividends paid and proposed

Woodside Energy Group Ltd, the parent entity, paid and proposed dividends set out below:

	2023 US$m		2022 US$m		2021 US$m
(a) Dividends paid during the financial year
Prior year fully franked final dividend1		2,734		1,018		115
Current year fully franked interim dividend2		1,519		2,070		289
		4,253		3,088		404
(b) Dividend declared subsequent to the reporting period (not recorded as a liability)
Final dividend3		1,139		2,734		1,018
(c) Other information
Current year dividends per share (US cents)		140		253		135

1. 2023: US$1.44, paid on 5 April 2023

2022: US$1.05, paid on 23 March 2022

2021: US$0.12, paid on 24 March 2021

2. 2023: US$0.80, paid on 28 September 2023

2022: US$1.09, paid on 6 October 2022

2021: US$0.30, paid on 24 September 2021

3. 2023: US$0.60, to be paid on 4 April 2024

2022: US$1.44, paid on 5 April 2023

2021: US$1.05, paid on 23 March 2022

The Dividend Reinvestment Plan (DRP) was approved by the shareholders at the Annual General Meeting in 2003 for activation as required to fund future growth. The DRP was reactivated in 2019 and suspended by the Board of Directors on 27 February 2023.

A.4 Earnings per share

	2023		2022		2021
Profit attributable to equity holders of the parent (US$m)		1,660		6,498		1,983
Weighted average number of shares on issue for basic earnings per share		1,896,498,169		1,511,257,404		962,604,811
Effect of dilution from contingently issuable shares		14,444,802		13,061,376		9,023,439
Weighted average number of shares on issue adjusted for the effect of dilution		1,910,942,971		1,524,318,780		971,628,250
Basic earnings per share (US cents)		87.5		430.0		206.0
Diluted earnings per share (US cents)		86.9		426.3		204.1

Earnings per share is calculated by dividing the profit for the year attributable to ordinary equity holders of the parent by the weighted average number of ordinary shares on issue during the year. The weighted average number of shares makes allowance for shares reserved for employee share plans. Diluted earnings per share is calculated by adjusting basic earnings per share by the number of ordinary shares that would be issued on conversion of all the dilutive potential ordinary shares into ordinary shares. At 31 December 2023, 14,444,802 awards (2022: 13,061,376 awards and 2021: 9,023,439 awards) granted under Woodside employee share plans are considered dilutive.

There have been no significant transactions involving ordinary shares between the reporting date and the date of completion of these financial statements.

F-19

Notes to the financial statements A. Earnings for the year

for the year ended 31 December 2023

A.5 Taxes

	2023     US$m	2022     US$m	2021     US$m
(a) Tax expense comprises
Petroleum resource rent tax (PRRT)
Current tax expense	367	501	-
Deferred tax expense/(benefit)	531	(814)	297
PRRT expense/(benefit)	898	(313)	297
Income tax
Current year
Current tax expense	1,872	2,256	658
Deferred tax (benefit)/expense	(1,255)	701	301
Adjustment to prior years
Current tax benefit	14	(276)	(20)
Deferred tax expense	22	231	18
Income tax expense	653	2,912	957
Tax expense	1,551	2,599	1,254

	2023     US$m	2022     US$m	2021     US$m
(b) Reconciliation of income tax expense
Profit before tax	3,273	9,174	3,290
PRRT (expense)/benefit	(898)	313	(297)
Profit before income tax	2,375	9,487	2,993
Income tax expense calculated at 30%	712	2,847	898
Effect of tax rate differentials	91	(141)	(42)
Effect of deferred tax assets not recognised	155	150	114
Effect of tax losses and credits previously unrecognised1	(332)	-	-
Effect of goodwill impairment2	109	-	-
Reduction in deferred tax liability due to held for sale basis3	(78)	-	-
Foreign exchange impact on tax benefit	(58)	(44)	(18)
Adjustment to prior years	36	(45)	(2)
Integration and transaction costs non-deductible	4	142	-
Other	14	3	7
Income tax expense	653	2,912	957

	2023     US$m	2022     US$m	2021     US$m
(c) Reconciliation of PRRT expense
Profit before tax	3,273	9,174	3,290
Non-PRRT assessable profit	(1,780)	(6,197)	(2,134)
PRRT projects profit before tax	1,493	2,977	1,156
PRRT expense calculated at 40%	598	1,191	462
Derecognition/(recognition) of Pluto general expenditure4	611	(1,362)	-
Recognition of transferred exploration spend	(18)	-	-
Augmentation	(292)	(175)	(166)
Other	(1)	33	1
PRRT expense/(benefit)	898	(313)	297

	2023     US$m	2022     US$m	2021     US$m
(d) Deferred tax income statement reconciliation
PRRT
Production and growth assets	1,206	(710)	455
Augmentation for current year	(292)	(175)	(166)
Provisions	(372)	(12)	(29)
Other	(11)	83	37
PRRT expense/(benefit)	531	(814)	297
Income tax
Oil and gas properties	(529)	292	674
Exploration and evaluation assets	38	14	(204)
Lease assets and liabilities	(20)	25	1
Provisions	(232)	151	(10)
PRRT assets and liabilities	(175)	236	(88)
Unused tax losses and tax credits	(221)	19	149
Assets held for sale	(86)	205	(205)
Derivatives	(21)	21	(11)
Other	13	(31)	13
Income tax deferred tax (benefit)/expense	(1,233)	932	319
Deferred tax (benefit)/expense	(702)	118	616

	2023     US$m	2022     US$m	2021      US$m
(e) Deferred tax other comprehensive income reconciliation
Income tax
Derivatives	77	(64)	5
Other	7	(2)	5
Deferred income tax expense/(benefit) via other comprehensive income	84	(66)	10

	2023 %	2022 %	2021 %
(f) Effective income tax rate: Australian and global operations
Effective income tax rate1,5
Australia	30.2	30.0	30.6
Global	27.5	30.7	32.0

1. As a result of the FID to develop the Trion resource in 2023, the Group has recognised deferred tax assets of $319 million.

2. Tax effect of the non-deductible impairment of goodwill relating to Shenzi.

3. Recognition of the tax base associated with the expected sale of Woodside’s 10% share in the Scarborough Project. This will offset future assessable income on the completion of the sale.

4. In 2023, the $637 million decrease of the Pluto PRRT deferred tax asset is due to the derecognition of previously recognised deductible expenditure that is now not considered to be recoverable on the basis of future taxable profits not being available to utilise the expenditure. In 2022, the $1,362 million increase of the Pluto PRRT deferred tax asset was due to the recognition of previously unrecognised deductible expenditure that is now expected to be utilised to offset future taxable profits.

5. The global operations effective income tax rate (ETR) is calculated as the Group’s income tax expense divided by profit before income tax. The Australian operations ETR is calculated with reference to all Australian companies and excludes foreign exchange on settlement and revaluation of income tax liabilities. The global effective income tax rate is lower in 2023 primarily as a result of the deferred tax asset recognised upon taking FID on Trion.

F-20

Notes to the financial statements A. Earnings for the year

for the year ended 31 December 2023

	2023    US$m		2022    US$m
(g) Deferred tax balance sheet reconciliation
Deferred tax assets
PRRT
Production and growth assets		455		1,460
Augmentation for current year		231		113
Provisions		445		271
Other		(30)		(23)
PRRT deferred tax assets		1,101		1,821
Income tax
Oil and gas properties		(1,388)		(1,496)
Exploration and evaluation assets		60		30
Lease assets and liabilities		40		23
Unused tax losses and tax credits		1,686		1,464
Derivatives		-		23
Provisions		227		60
Other		(9)		34
Income tax deferred tax assets		616		138
Deferred tax assets		1,717		1,959
Deferred tax liabilities
PRRT
Production and growth assets		1,309		1,281
Augmentation for current year		(38)		(62)
Provisions		(995)		(743)
Other		113		137
PRRT deferred tax liabilities		389		613
Income tax
Oil and gas properties		2,939		2,857
Exploration and evaluation assets		127		67
Lease assets and liabilities		(48)		(22)
Provisions		(1,856)		(1,280)
PRRT assets and liabilities		118		347
Assets held for sale		36		-
Derivatives		(2)		(36)
Other		(76)		(89)
Income tax deferred tax liabilities		1,238		1,844
Deferred tax liabilities		1,627		2,457

Tax transparency code

Woodside participates in the Australian Board of Taxation’s voluntary Tax Transparency Code (TTC). To increase public confidence in the contributions and compliance of corporate taxpayers, the TTC recommends public disclosure of tax information. Part A of the recommended disclosures are addressed within this Taxes note and Part B disclosed within the Sustainability section on our website.

Recognition and measurement

Current tax assets and liabilities are measured at the amount expected to be recovered from or paid to the taxation authorities. Deferred tax assets and liabilities are measured at the tax rates that are expected to apply in the period in which the liability is settled or the asset is realised. The tax rates and laws used to determine the amount are based on those that have been enacted or substantially enacted by the end of the reporting period. Income taxes relating to items recognised directly in equity are recognised in equity.

Current taxes

Current tax expense is the expected tax payable on the taxable income for the current year and any adjustment to tax paid in respect of previous years.

Deferred taxes

Deferred tax expense represents movements in the temporary differences between the carrying amount of an asset or liability in the consolidated statement of financial position and its tax base.

With the exception of those noted below, deferred tax liabilities are recognised for all taxable temporary differences.

Deferred tax assets are recognised for deductible temporary differences, unused tax losses and tax credits only if it is probable that sufficient future taxable income will be available to utilise those temporary differences and losses.

Deferred tax is not recognised if the temporary difference arises from goodwill or from the initial recognition (other than in a business combination) of assets and liabilities in a transaction that affects neither accounting profit nor the taxable profit.

F-21

Notes to the financial statements A. Earnings for the year

for the year ended 31 December 2023

In relation to PRRT, the impact of future augmentation on expenditure is included in the determination of future taxable profits when assessing the extent to which a deferred tax asset can be recognised in the consolidated statement of financial position.

Offsetting deferred tax balances

Deferred tax assets and liabilities are offset only if there is a legally enforceable right to offset current tax assets and liabilities and when they relate to income taxes levied by the same taxation authority on either the same taxable entity or different taxable entities that the Group intends to settle its current tax assets and liabilities on a net basis. Refer to Notes E.8 and E.9 for detail on the tax consolidated groups.

Key estimates and judgements

(a) Income tax classification

Judgement is required when determining whether a particular tax is an income tax or another type of tax. PRRT is considered, for accounting purposes, to be an income tax. Accounting for deferred tax is applied to income taxes as described above, but is not applied to other types of taxes, e.g. North West Shelf royalties, excise and levies which are recognised in cost of sales in the income statement.

(b) Deferred tax asset recognition

The Group has two separate USA Tax Consolidation Groups (USA TCG) as at 31 December 2023.

Income tax losses and credits: Deferred tax assets (DTAs) relating to carry forward unused tax losses and credits arising from the USA TCG of $1,248 million (2022: $1,371 million) and $333 million (2022: $93 million) arising from countries other than Australia and the USA have been recognised. The Group has determined that it is probable that sufficient future taxable income will be available to utilise those losses and credits within those countries. Refer to Note E.9(a) for details of tax consolidated groups.

DTAs relating to carry forward unused tax losses and credits of $232 million (2022: $250 million) from the USA TCG, $189 million (2022: $146 million) from USA entities outside of the USA TCG and $763 million (2022: $1,061 million) from countries other than Australia and the USA have not been recognised as it is not currently probable that the losses and credits will be utilised based on current planned activities in those countries.

As a result of the FID to develop the Trion resource in 2023, the Group has recognised deferred tax assets of $319 million.

PRRT: The recoverability of PRRT deferred tax assets is primarily assessed with regard to future oil price assumptions impacting forecast future taxable profits. During the year ended 31 December 2023, the Group reduced the Pluto PRRT DTA by $637 million ($446 million post-tax) on the basis of future taxable profits not being available to utilise the deductible expenditure. This is primarily driven by decreases in forecast pricing assumptions and actual pricing realised during the year ended 31 December 2023. In determining the amount of DTA that is considered probable and eligible for recognition, forecast future taxable profits are risk-adjusted where appropriate by a market premium risk rate to reflect uncertainty inherent in long-term forecasts. A long-term bond rate of 3.2% (31 December 2022: 3.2%) was used for the purposes of augmentation.

Certain deferred tax assets on deductible temporary differences have not been recognised on the basis that deductions from future augmentation of the recognised deductible temporary difference will be sufficient to offset future taxable profits. $7,428 million (2022: $6,523 million) relates to the North West Shelf Project, $872 million (2022: $189 million) relates to remaining Pluto quarantined exploration expenditure and $758 million (2022: $831 million) relates to Wheatstone. A long-term bond rate of 3.2% (31 December 2022: 3.2%) was used for the purposes of augmentation.

Had an alternative approach been used to assess recovery of the deferred tax assets, whereby future augmentation was not included in the assessment, additional deferred tax assets would be recognised, with a corresponding benefit to tax expense. It was determined that the approach adopted provides the most meaningful information on the implications of the PRRT regime, whilst ensuring compliance with IAS 12 Income Taxes.

(c) Uncertain tax positions

The Group has tax matters, litigation and other claims, for which the timing of resolution and potential economic outflows are uncertain. Where the Group assesses an outcome for any tax matter, litigation or other claim as more likely than not to be accepted by the relevant tax authority, the position is adopted in the reported tax balances.

Because of the complexity of some of these positions, the ultimate outcome may differ from the current estimate of the position. These differences will be reflected as increases or decreases to tax expense in the period in which new information is available. Tax matters without a probable economic outflow and/or presently cannot be measured reliably are contingent liabilities and disclosed in Note E.1 Contingent liabilities and assets.

F-22

Notes to the financial statements B. Production and growth assets

for the year ended 31 December 2023

In this section

This section addresses the strategic growth (exploration and evaluation), core producing and development (oil and gas properties) assets position of the Group at the end of the reporting period including, where applicable, the accounting policies and key estimates and judgements applied. This section also includes the impairment position of the Group at the end of the reporting period.

B.	Production and growth assets
B.1	Segment production and growth assets	Page F-24
B.2	Exploration and evaluation	Page F-26
B.3	Oil and gas properties	Page F-28
B.4	Impairment of exploration and evaluation, oil and gas properties and goodwill	Page F-29
B.5	Business combination	Page F-35
B.6	Goodwill	Page F-37
B.7	Significant production and growth asset acquisitions	Page F-37
B.8	Disposal of assets	Page F-38

F-23

Notes to the financial statements B. Production and growth assets

for the year ended 31 December 2023

B.1 Segment production and growth assets

	Australia 2023 US$m		International 2023 US$m		Marketing 2023 US$m		Corporate/Other 2023 US$m		Consolidated 2023 US$m
Balance as at 31 December
Asia Pacific		568		-		-		-		568
Americas		-		76		-		-		76
Africa		-		24		-		-		24
Total exploration and evaluation		568		100		-		-		668
Balance as at 31 December
Land and buildings		669		32		-		-		701
Transferred exploration and evaluation		360		417		-		-		777
Plant and equipment		16,498		6,893		-		198		23,589
Projects in development		7,825		7,655		-		244		15,724
Total oil and gas properties		25,352		14,997		-		442		40,791
Balance as at 31 December
Land and buildings		96		89		-		245		430
Plant and equipment1		194		60		539		7		800
Total lease assets		290		149		539		252		1,230
Additions to exploration and evaluation:
Exploration		29		59		-		-		88
Evaluation		55		108		-		-		163
Restoration2		(5)		-		-		-		(5)
		79		167		-		-		246
Additions to oil and gas properties:
Oil and gas properties		3,127		2,000		-		190		5,317
Capitalised borrowings costs3		188		123		-		-		311
Restoration2		779		188		-		-		967
		4,094		2,311		-		190		6,595
Additions to lease assets:
Land and buildings		-		-		-		8		8
Plant and equipment		6		-		114		-		120
		6		-		114		8		128

1. In 2023, certain shipping activities, previously undertaken by the Corporate/Other segment, are now undertaken by the Marketing segment. As a result of this change, $539 million of lease assets are now reported within the Marketing segment as at 31 December 2023.

2. Relates to changes in restoration provision assumptions.

3. Borrowing costs capitalised were at a weighted average interest rate of 4.0%.

Refer to Note A.1 for descriptions of the Group’s segments and geographical regions.

F-24

Notes to the financial statements B. Production and growth assets

for the year ended 31 December 2023

	Australia 2022 US$m		International 2022 US$m		Marketing 2022 US$m		Corporate/Other 2022 US$m		Consolidated 2022 US$m
Balance as at 31 December
Asia Pacific		529		-		-		-		529
Americas		-		240		-		-		240
Africa		-		38		-		-		38
Total exploration and evaluation		529		278		-		-		807
Balance as at 31 December
Land and buildings		802		37		-		1		840
Transferred exploration and evaluation		481		-		-		-		481
Plant and equipment		18,249		4,647		-		161		23,057
Projects in development1		5,623		9,795		-		123		15,541
Total oil and gas properties		25,155		14,479		-		285		39,919
Balance as at 31 December
Land and buildings		93		107		-		264		464
Plant and equipment		214		131		-		455		800
Total lease assets		307		238		-		719		1,264
Additions to exploration and evaluation2:
Exploration		1		121		-		-		122
Evaluation		19		100		-		-		119
Restoration3		(1)		-		-		-		(1)
		19		221		-		-		240
Additions to oil and gas properties2:
Oil and gas properties		2,252		1,560		-		92		3,904
Capitalised borrowings costs4		115		179		-		-		294
Restoration3		(346)		(28)		-		-		(374)
		2,021		1,711		-		92		3,824
Additions to lease assets2:
Land and buildings		4		-		-		-		4
Plant and equipment		139		90		-		9		238
		143		90		-		9		242

1. Projects in development include the fair value ascribed to future phases of certain projects acquired through business combinations.

2. Additions exclude acquisitions through business combinations.

3. Relates to changes in restoration provision assumptions.

4. Borrowing costs capitalised were at a weighted average interest rate of 3.8%.

F-25

Notes to the financial statements B. Production and growth assets

for the year ended 31 December 2023

B.2 Exploration and evaluation

	Asia Pacific US$m		Americas US$m		Africa US$m		Total US$m
Year ended 31 December 2023
Carrying amount at 1 January 2023		529		240		38		807
Additions		79		161		6		246
Amortisation of licence acquisition costs		-		(2)		(2)		(4)
Expensed1		(31)		(28)		(18)		(77)
Transferred exploration and evaluation2		(9)		(295)		-		(304)
Carrying amount at 31 December 2023		568		76		24		668
Year ended 31 December 2022
Carrying amount at 1 January 2022		546		-		68		614
Acquisitions through business combination3		-		180		-		180
Additions		19		204		17		240
Disposals		-		(10)		-		(10)
Amortisation of licence acquisition costs		-		(8)		(2)		(10)
Expensed1		-		(126)		(45)		(171)
Transferred exploration and evaluation		(36)		-		-		(36)
Carrying amount at 31 December 2022		529		240		38		807
Exploration commitments
Year ended 31 December 2023		3		1		35		39
Year ended 31 December 2022		1		1		27		29

1. $77 million (2022: $125 million) relates to costs of unsuccessful wells.

2. On 20 June 2023, the Group made a final investment decision to develop the Trion resource in Mexico. Related exploration and evaluation assets of $274 million were transferred to oil and gas properties.

3. Refer to Note B.5 for details of business combination.

Recognition and measurement

Expenditure on exploration and evaluation is accounted for in accordance with the area of interest method.

Areas of interest are based on a geographical area for which the rights of tenure are current. All exploration and evaluation expenditure, including general permit activity, geological and geophysical costs and new venture activity costs, is expensed as incurred except for the following:

· where the expenditure relates to an exploration discovery for which the assessment of the existence or otherwise of economically recoverable hydrocarbons is not yet complete; or

· where the expenditure is expected to be recouped through successful exploitation of the area of interest, or alternatively, by its sale.

The costs of acquiring interests in new exploration and evaluation licences are capitalised. The costs of drilling exploration wells are initially capitalised pending the results of the well.

Costs are expensed where the well does not result in the successful discovery of economically recoverable hydrocarbons and the recognition of an area of interest.

Subsequent to the recognition of an area of interest, all further evaluation costs relating to that area of interest are capitalised.

Upon approval for the commercial development of an area of interest, accumulated expenditure for the area of interest is transferred to oil and gas properties.

In the consolidated statement of cash flows, those cash flows associated with capitalised exploration and evaluation expenditure, including unsuccessful wells, are classified as cash flows used in investing activities.

Exploration commitments

The Group has exploration expenditure obligations which are contracted for, but not provided for in the financial statements. These obligations may be varied from time to time and are expected to be fulfilled in the normal course of the Group’s operations.

Impairment

Refer to Note B.4 for details on impairment, including any write-offs.

F-26

Notes to the financial statements B. Production and growth assets

for the year ended 31 December 2023

Key estimates and judgements

(a) Area of interest

Typically, an area of interest (AOI) is defined by the Group as an individual geographical area whereby the presence of hydrocarbons is considered favourable or proved to exist. The Group has established criteria to recognise and maintain an AOI.

(b) Transfer to projects in development

Development activities commence after project sanctioning by the appropriate level of management. Judgement is applied by management in determining when the project is technically feasible and economically viable to transfer to projects in development.

F-27

Notes to the financial statements B. Production and growth assets

for the year ended 31 December 2023

B.3 Oil and gas properties

	Land and buildings	Transferred exploration and evaluation	Plant and equipment	Projects in development	Total
	US$m	US$m	US$m	US$m	US$m
Year ended 31 December 2023
Carrying amount at 1 January 2023	840	481	23,057	15,541	39,919
Additions1	-	-	836	5,759	6,595
Disposals at written down value	(8)	-	(2)	-	(10)
Depreciation and amortisation	(67)	(125)	(3,764)	-	(3,956)
Impairment losses2	(64)	(20)	(1,028)	(328)	(1,440)
Completions and transfers	-	441	4,496	(4,633)	304
Transfer to assets held for sale3	-	-	(6)	(615)	(621)
Carrying amount at 31 December 2023	701	777	23,589	15,724	40,791
At 31 December 2023
Historical cost	1,745	1,979	50,272	16,443	70,439
Accumulated depreciation and impairment	(1,044)	(1,202)	(26,683)	(719)	(29,648)
Net carrying amount	701	777	23,589	15,724	40,791
Year ended 31 December 2022
Carrying amount at 1 January 2022	739	526	12,465	4,919	18,649
Acquisitions through business combinations4	64	-	11,952	7,337	19,353
Additions	-	-	(508)	4,332	3,824
Disposals at written down value	(3)	(10)	(32)	-	(45)
Depreciation and amortisation	(54)	(107)	(2,637)	-	(2,798)
Impairment reversal2	87	30	783	-	900
Completions and transfers	7	42	1,034	(1,047)	36
Carrying amount at 31 December 2022	840	481	23,057	15,541	39,919
At 31 December 2022
Historical cost	1,765	1,538	45,273	15,937	64,513
Accumulated depreciation and impairment	(925)	(1,057)	(22,216)	(396)	(24,594)
Net carrying amount	840	481	23,057	15,541	39,919

1. Includes $5,317 million of capital additions, $311 million of capitalised borrowing costs and $967 million following changes in restoration provision.

2. Refer to Note B.4 for details on impairment losses and impairment reversals.

3. Refer to Note B.8 for details of the sell-down of the Scarborough Joint Venture.

4. Refer to Note B.5 for details of business combination. Projects in development include the fair value ascribed to future phases of certain projects acquired through business combinations.

Recognition and measurement

Oil and gas properties are stated at cost less accumulated depreciation and impairment charges. Oil and gas properties include the costs to acquire, construct, install or complete production and infrastructure facilities such as pipelines and platforms, capitalised borrowing costs, transferred exploration and evaluation assets, development wells and the estimated cost of dismantling and restoration.

Subsequent capital costs, including major maintenance, are included in the asset’s carrying amount only when it is probable that future economic benefits associated with the item will flow to the Group and the cost of the item can be reliably measured.

Depreciation and amortisation

Oil and gas properties are depreciated to their estimated residual values at rates based on their expected useful lives.

Upstream oil and conventional gas assets have been depreciated using the unit of production basis over proved reserves (2022: proved plus probable, except for certain assets considered late life). Upstream LNG assets are depreciated over proved plus probable reserves. Multi-product assets are assessed on a case-by-case basis and aligned to the most appropriate representation of useful life.

The depreciable amount for the unit of production basis excludes future development costs necessary to bring probable reserves into production. Downstream assets (primarily onshore plant and equipment) are depreciated using a straight-line basis over the lesser of useful life and the life of proved plus probable reserves. On a straight-line basis the assets have an estimated useful life of 5-50 years.

All other items of oil and gas properties are depreciated using the straight-line method over their useful life. They are depreciated as follows:

· Buildings – 24-50 years;

· Plant and equipment – 2-40 years; and

· Land is not depreciated.

Impairment

Refer to Note B.4 for details on impairment.

Capital commitments

The Group has capital expenditure commitments contracted for, but not provided for in the financial statements, of $4,245 million as at 31 December 2023 (revised 20221: $6,469 million). Capital expenditure commitments relate predominantly to the Scarborough and Sangomar projects.

1. The 2022 Financial Statements disclosed capital expenditure commitments of $7,762 million which duplicated certain amounts post-merger. This has now been revised to reflect the Group’s share of commitments.

F-28

Notes to the financial statements B. Production and growth assets

for the year ended 31 December 2023

Key estimates and judgements

(a) Reserves

The estimation of reserves requires significant management judgement and interpretation of complex geological and geophysical models in order to make an assessment of the size, shape, depth and quality of reservoirs, and their anticipated recoveries.

Estimates of oil and natural gas reserves are used to calculate depreciation and amortisation charges for the Group’s oil and gas properties. Judgement is used in determining the economic reserve base applied to each asset.

Estimates are reviewed at least annually or when there are changes in the economic circumstances impacting specific assets or asset groups. These changes may impact depreciation, asset carrying values, restoration provisions and deferred tax balances. If reserves estimates are revised downwards, earnings could be affected by higher depreciation expense or an immediate write-down of the asset’s carrying value.

(b) Depreciation and amortisation

Judgement is required to determine when assets are available for use to commence depreciation and amortisation. Depreciation and amortisation generally commences on first production.

(c) Change in depreciation methodology and asset useful lives

The Group has undertaken a review of the depreciation methodology and asset useful lives for oil and gas properties in accordance with its accounting policies and the accounting standards, considering the scale and diversity of the post-merger portfolio.

In assessing useful lives of certain oil and gas assets, these have been determined with reference to either their proved (1P) or proved plus probable (2P) reserves, which is then used in the units of production depreciation calculation.

From 1 January 2023, upstream oil and conventional gas assets have been depreciated over proved reserves (previously proved plus probable, except for certain assets considered late life). Upstream LNG assets have continued to be depreciated over proved plus probable reserves. Multi-product assets are assessed on a case-by-case basis and aligned to the most appropriate representation of useful life.

The changes in depreciation methodology and asset useful lives have been applied from 1 January 2023, resulting in an increase in depreciation expense of $416 million for the year ended 31 December 2023.

B.4 Impairment of exploration and evaluation, oil and gas properties and goodwill

Exploration and evaluation

Impairment testing

The recoverability of the carrying amount of exploration and evaluation assets is dependent on successful development and commercial exploitation, or alternatively sale of the respective AOI.

Each AOI is reviewed half-yearly to determine whether economic quantities of hydrocarbons have been found, or whether further exploration and evaluation work is underway or planned to support continued carry forward of capitalised costs. Where a potential impairment is indicated for an AOI, an assessment is performed using a fair value less costs to dispose (FVLCD) method to determine its recoverable amount. Upon approval for commercial development, exploration and evaluation assets are assessed for impairment before they are transferred to oil and gas properties.

Impairment calculations

If the carrying amount of an AOI exceeds its recoverable amount, the AOI is written down to its recoverable amount and an impairment loss is recognised in the consolidated income statement.

F-29

Notes to the financial statements B. Production and growth assets

for the year ended 31 December 2023

Oil and gas properties

Impairment testing

The carrying amounts of oil and gas properties are assessed half-yearly to determine whether there is an indicator of impairment or impairment reversal for those assets which have previously been impaired. Indicators of impairment and impairment reversals include changes in reserves, expected future sales prices or costs.

Oil and gas properties are assessed for impairment indicators and impairments on a cash-generating unit (CGU) basis. CGUs are determined as offshore and onshore facilities, infrastructure and associated oil and/or gas fields.

If there is an indicator of impairment or impairment reversal for a CGU, its recoverable amount is calculated and compared with the CGU’s carrying value (refer to impairment calculations below).

Goodwill

For the purpose of impairment testing, goodwill acquired in a business combination is, from the acquisition date, allocated to each of the Group’s cash-generating units (CGUs) that are expected to benefit from the combination, irrespective of whether other assets or liabilities of the acquiree are assigned to those units. Goodwill is tested for impairment at least annually and more frequently if events or changes in circumstances indicate that it might be impaired. Impairment of goodwill is determined by assessing the recoverable amount of each CGU to which the goodwill relates and comparing it with its carrying value which includes deferred taxes (refer to impairment calculations below and Note B.5).

When part of an operation is disposed of, any goodwill associated with the disposed operation is included in the carrying amount of the operation in determining the gain or loss on disposal.

Goodwill and oil and gas impairment calculations

The recoverable amount of an asset or CGU is determined as the higher of its value in use (VIU) and FVLCD.

VIU is determined by estimating future cash flows after taking into account the risks specific to the asset and discounting these to present value using an appropriate discount rate.

FVLCD is the price that would be received to sell the asset in an orderly transaction between market participants and does not reflect the effects of factors that may be specific to the Group. In determining FVLCD, recent market transactions are considered. If no such transactions can be identified, an appropriate valuation model, such as discounted cash flow techniques, is applied on a post-tax basis using an appropriate discount rate and estimates are made about the assumptions market participants would use when pricing the asset or CGU.

If the carrying amount of an asset or CGU, including any allocated goodwill, exceeds its recoverable amount, the asset or CGU is written down to its recoverable amount and an impairment loss is recognised in the consolidated income statement. Any impairment losses are first allocated to reduce the carrying amount of any goodwill allocated, with the remaining impairment losses allocated to the relevant assets.

If the recoverable amount of an asset or CGU exceeds its carrying amount, and that asset has previously been impaired, the impairment is reversed. The carrying amount of the asset or CGU is increased to its recoverable amount, but only to the extent that the carrying amount does not exceed the value that would have been determined, net of depreciation or amortisation, if no impairment had been recognised. Impairments of goodwill are not reversed.

For the year ended 31 December 2023

Goodwill allocation

The Group performed its annual goodwill impairment test as at 31 December 2023.

The carrying amount of goodwill allocated to each CGU, or groups of CGUs and excess recoverable amounts are as follows:

Segment	CGU	Goodwill carrying amount	Excess of recoverable amount over CGU carrying amount1
		US$m	US$m
Australia	Pluto-Scarborough2	2,743	3,051
Australia	NWS Gas	442	784
International	Atlantis	522	338
International	Other goodwill	288	1,176
Total		3,995

1. Amounts are with reference to the total CGU value including goodwill.

2. A portion of the goodwill allocated to Pluto-Scarborough was transferred to assets held for sale (refer to Note B.8).

Other goodwill of $288 million (2022: $283 million) has been allocated across a number of CGUs within the International segment. This represents less than one percent of net assets as at 31 December 2023.

F-30

Notes to the financial statements B. Production and growth assets

for the year ended 31 December 2023

Recognised impairment and impairment reversals

As at 30 June 2023, the Group assessed each AOI and CGU to determine whether an indicator of impairment or impairment reversal existed. The Group identified the following indicators of impairment on CGUs where an impairment loss has been recognised:

CGU	Description	Indicator of impairment
Pyrenees	Oil asset consisting of a floating production storage and offloading (FPSO) facility off the north-west coast of Western Australia.	Reduction in future production volumes, reflecting a lower-than-expected outcome of drilling activities.

For CGUs where goodwill has been allocated, no impairment was recognised as the recoverable amount exceeds the carrying amount of the CGU.

An impairment was recognised for the Pyrenees CGU (refer to Note A.1), with results as follows:

Impairment loss

Oil and gas properties

Segment

CGU

Recoverable amount US$m

Land and buildings US$m

Transferred   exploration and evaluation US$m

Plant and equipment US$m

Projects in development US$m

Total US$m

Australia

Pyrenees

159

-

-

68

-

68

Following Following the impairment recognised at 30 June 2023, no further impairment or impairment reversal for Pyrenees was identified.

As at 31 December 2023, the Group assessed each AOI and CGU to determine whether an indicator of impairment or impairment reversal existed. The Group identified the following indicators of impairment on CGUs where an impairment loss has been recognised:

CGU	Description	Indicator of impairment
Shenzi	Conventional oil and gas field developed through a tension leg platform (TLP) located in the US Gulf of Mexico.	Reduction in future production volumes, reflecting lower-than-expected performance of infill sidetracks and performance of the Shenzi North development following start-up.
Wheatstone	LNG processing facility in Western Australia, comprising an offshore production platform and two onshore LNG processing trains, a domestic gas plant and associated infrastructure.	Updated short-term price assumptions (in particular the Japan/Korea Marker (JKM)).

An impairment was recognised in the profit and loss, refer to Note A.1. The results as follows:

					Impairment loss
					Goodwill		Oil and gas properties
Segment	CGU	Recoverable amount US$m		Goodwill US$m		Land and buildings US$m		Transferred   exploration and evaluation US$m		Plant and equipment US$m		Projects in development US$m		Total US$m
International	Shenzi		1,862		477		-		-		589		317		1,383
Australia	Wheatstone		2,418		-		64		20		371		11		466

For CGUs where goodwill has been allocated, with the exception of Shenzi, no impairment was recognised as the recoverable amount exceeds the carrying amount of the CGU.

Recoverable amounts have been determined using the FVLCD method using discounted cash flow projections, classified as Level 3 on the fair value hierarchy. The carrying amount of each CGU includes all assets allocated to the respective CGU. Refer to key estimates and judgements for further details.

Sensitivity analysis

Recoverable amount valuations are sensitive to changes in certain key accounting estimates and judgements (refer to key estimates and judgements for further details). Reasonably possible changes to these key assumptions are set out below:

· Post-tax discount rate – plus or minus 1.0% (representing a change of 100 basis points)

· Commodity pricing – plus or minus 10%

· Foreign exchange (FX) rate – plus or minus 12%

· Production volumes – plus or minus 4%

Management’s analysis on the impact of reasonably possible changes to these assumptions on recoverable amounts is detailed below.

CGUs with impairment or impairment reversals

Changes in the following key assumptions have been estimated to result in a higher or lower carrying amount1 than what was determined as at 31 December 2023:

				Sensitivity (US$m)2
CGU	Discount rate increase3			Discount rate decrease3		Commodity price increase3		Commodity price decrease3			FX increase3			FX decrease3		Production increase3		Production decrease3
Shenzi		(67	)		71		359		(359	)		N/A			N/A		47		(46	)
Wheatstone		(88	)		94		431		(370	)		(36	)		87		90		(42	)

1. Increases to carrying amounts are limited to historical impairment losses recognised, net of depreciation and amortisation, that would have been recognised had no impairment taken place.

2. The sensitivities represent the reasonably possible changes to discount rate, commodity price, FX and production volumes assumptions.

3. The relationship between the discount rate, commodity price, FX and production and the carrying amount is non-linear in certain circumstances which may include fixed costs impacts as well as economic cut off modelling. As such, sensitivities are unlikely to result in a symmetrical impact and should not be interpreted in isolation

A change in any of the above assumptions would likely have an impact on other assumptions which, when considered together, may offset. This does not incorporate decisions management may take in order to mitigate the change in assumptions.

F-31

Notes to the financial statements B. Production and growth assets

for the year ended 31 December 2023

CGUs with goodwill

The valuation of CGUs with goodwill are most sensitive to changes in commodity prices and discount rates. Reasonably possible changes in these estimates which could result in the estimated recoverable amount being equal to the carrying amount, assuming all other variables are held constant, are as follows:

	CGU	Commodity price1			Nominal discount rate
		% change			(absolute terms)
Oil and gas properties	Pluto-Scarborough		N/A	2		N/A	2
Oil and gas properties	NWS Gas		N/A	2		N/A	2
Oil and gas properties	Atlantis		(5%	)		N/A	2

1. Brent price applies to Pluto-Scarborough and NWS Gas. WTI price (Brent - $3/bbl) applies to Atlantis.

2. Management considers there to be no reasonably possible change in the respective estimate which, in isolation, would result in the estimated recoverable amount being equal to the carrying amount.

A change in any of the above assumptions would have an impact on other assumptions which when considered together may offset. This does not incorporate decisions management may take in order to mitigate the change in assumptions. Management considers there to be no reasonably possible changes in production volumes, carbon prices or foreign exchange rates that would, in isolation, result in the estimated recoverable amount being equal to the carrying amount. Analysis of key assumptions which could result in the carrying value to equal the recoverable value provides a basis to assess the magnitude of a reasonably possible change to the carrying amounts of respective CGUs.

F-32

Notes to the financial statements B. Production and growth assets

for the year ended 31 December 2023

For the year ended 31 December 2022

Goodwill allocation

The Group performed its annual goodwill impairment test as at 31 December 2022.

The carrying amount of goodwill allocated to each CGU, or groups of CGUs and excess recoverable amounts were as follows:

Segment	CGU	Goodwill carrying amount1	Excess of recoverable amount over CGU carrying amount2
		US$m	US$m
Australia	Pluto-Scarborough	2,955	7,656
Australia	NWS Gas	394	1,399
International	Shenzi	469	401
International	Atlantis	513	189
International	Other goodwill	283	107
Total		4,614

1. Carrying amount of goodwill as at 31 December 2021 was nil.

2. Amounts are with reference to the total CGU value including goodwill.

Other goodwill of $283 million (2021: nil) has been allocated across a number of CGUs within the International segment. This represents less than one percent of net assets as at 31 December 2022.

Recognised impairment and impairment reversals

As at 31 December 2022, the Group assessed each AOI and CGU to determine whether an indicator of impairment or impairment reversal existed. The Group identified the following indicators of impairment reversals:

• Wheatstone CGU – revision in short-term and long-term LNG price assumptions and updated cost and production profiles.

For CGUs where goodwill has been allocated, no impairment was recognised as the recoverable amount exceeds the carrying amount of the CGU.

An impairment reversal was recognised for Wheatstone (refer to Note A.1), with results as follows:

					Impairment reversal
					Oil and gas properties
Segment	CGU	Recoverable  amount  US$m		Land and buildings US$m		Transferred exploration and evaluation US$m		Plant and equipment US$m		Total US$m
Australia	Wheatstone		3,456		87		30		783		900

Recoverable amounts have been determined using the FVLCD method using discounted cash flow projections, classified as Level 3 on the fair value hierarchy. The carrying amount of each CGU includes all assets allocated to the respective CGU. Refer to key estimates and judgements for further details.

Sensitivity analysis

Recoverable amount valuations are sensitive to changes in certain key accounting estimates and judgements (refer to key estimates and judgements for further details). Reasonably possible changes to these key assumptions are set out below:

· Post tax discount rate – plus or minus 1.5% (representing a change of 150 basis points)

· Commodity pricing – plus or minus 10%

· Foreign exchange (FX) rate – plus or minus 12%

· Production volumes – plus or minus 4%

Management’s analysis on the impact of reasonably possible changes to these assumptions on recoverable amounts is detailed below.

F-33

Notes to the financial statements B. Production and growth assets

for the year ended 31 December 2023

CGUs with impairment or impairment reversals

Changes in the following key assumptions have been estimated to result in a higher or lower carrying amount1 than what was determined as at 31 December 2022:

				Sensitivity (US$m)2
CGU	Discount rate increase3			Discount rate decrease3		Brent price increase		Brent price decrease			FX increase			FX decrease		Production increase4		Production decrease4
Wheatstone		(117	)		127		294		(294	)		(79	)		79		116		(43	)

1. Increases to carrying amounts are limited to historical impairment losses recognised, net of depreciation and amortisation, that would have been recognised had no impairment taken place.

2. The sensitivities represent the reasonable possible changes to discount rate, oil price, FX and production volumes assumptions.

3. The relationship between the discount rate and the carrying amount is non-linear and as such, sensitivities are unlikely to result in a symmetrical impact. Due to the non-linear relationship, the impact of changing the discount rate is likely to be greater at a lower discount rate than at a higher discount rate.

4. The relationship between production and the carrying amount is non-linear due to the proportion of fixed costs. Sensitivities are therefore unlikely to result in a symmetrical impact. A significant change in production volumes would typically require a reassessment of the asset concept and should not be interpreted in isolation.

A change in any of the above assumptions would likely have an impact on other assumptions which, when considered together, may offset. This does not incorporate decisions management may take in order to mitigate the change in assumptions.

CGUs with goodwill

The valuation of CGUs with goodwill are most sensitive to changes in commodity prices and discount rates. Reasonably possible changes in these estimates which could result in the estimated recoverable amount being equal to the carrying amount, assuming all other variables are held constant, are as follows:

	CGU	Commodity price1			Nominal discount rate
		% change			(absolute terms)
Oil and gas properties	Pluto-Scarborough		N/A	2		N/A	2
Oil and gas properties	NWS Gas		N/A	2		N/A	2
Oil and gas properties	Shenzi		(7%	)		N/A	2
Oil and gas properties	Atlantis		(2%	)		10%

1. Brent price applies to Pluto-Scarborough and NWS Gas. WTI price (Brent - $3/bbl) applies to Shenzi and Atlantis.

2. Management considers there to be no reasonably possible change in the respective estimate which, in isolation, would result in the estimated recoverable amount being equal to the carrying amount.

A change in any of the above assumptions would have an impact on other assumptions which when considered together may offset. This does not incorporate decisions management may take in order to mitigate the change in assumptions. Management considers there to be no reasonably possible changes in production volumes, carbon prices or foreign exchange rates that would, in isolation, result in the estimated recoverable amount being equal to the carrying amount. Analysis of key assumptions which could result in the carrying value to equal the recoverable value provides a basis to assess the magnitude of a reasonable possible change to the carrying amounts of respective CGUs.

F-34

Notes to the financial statements B. Production and growth assets

for the year ended 31 December 2023

Key estimates and judgements

(a) CGU determination

Identification of a CGU requires management judgement. Management has determined CGUs based on the smallest group of assets that generate significant cash inflows that are independent from other assets or groups of assets.

(b) Allocation of goodwill

Allocation of goodwill to the relevant CGUs requires management judgement. The goodwill arising from the merger has been allocated to relevant CGUs which are expected to benefit from the expected synergies as a result of the merger.

(c) Recoverable amount calculation key assumptions

In determining the recoverable amount of CGUs, estimates are made regarding the present value of future cash flows when determining the FVLCD. These estimates require significant management judgement and are subject to risk and uncertainty, and hence changes in economic conditions can also affect the assumptions used and the rates used to discount future cash flow estimates.

The basis for each estimate used to determine recoverable amounts as at 31 December 2023 and 31 December 2022 is set out below:

·  Resource estimates – 2P and a portion of 2C reserves (where applicable) for oil and gas properties. The reserves are as disclosed in the Reserves and Resources Statement in the 31 December 2023 and 31 December 2022 Annual Reports.

·  Inflation rate – an inflation rate of 2.0% (2022: 2.0%) has been applied for US based assets and 2.5% (2022: 2.5%) for Australian based assets.

·  Foreign exchange rates – a rate of $0.75 (2022: $0.75) US$:AU$ is based on management’s view of long-term exchange rates.

·  Discount rates – a range of post-tax discount rates between 8.5% and 10.5% (2022: 8% and 11.5%) for CGUs has been applied. The discount rate reflects an assessment of the risks specific to the asset.

·  Carbon pricing – a long-term price of US$80/tonne (2022: US$80/tonne) of emissions (real terms 2022) is based on management’s assumptions on carbon cost pricing and incorporates an evaluation of climate risk. This is applicable to Australian emissions that exceed facility-specific baselines in accordance with Australian regulations, as well as global emissions that exceed voluntary corporate net emissions targets. Woodside continues to monitor the uncertainty around climate change risks and will revise carbon pricing assumptions accordingly. Refer to Climate change and energy transition section within the basis of preparation for further information.

·  LNG price – the majority of LNG sales contracts are linked to an oil price marker and therefore dependent on oil price assumptions. LNG sold into spot markets is typically based on a gas-hub linked price (for example the Title Transfer Facility (TTF) or JKM) and therefore these pricing assumptions are also of relevance in forecasting future revenues.

·  Brent oil prices – derived from long-term views of global supply and demand, building upon past experience of the industry and consistent with external sources. Prices are adjusted for premiums and discounts based on the nature and quality of the product. Brent oil price estimates have considered the risk of climate policies along with other factors such as industry investment and cost trends. There is significant uncertainty around how society will respond to the climate challenge; Woodside’s pricing assumptions reflect a ‘best estimate’ scenario in which global governments pursue decarbonisation goals as well as other goals such as energy security and economic development. As with carbon pricing, Woodside continues to monitor this uncertainty and will revise its oil pricing assumptions accordingly in its transition to a lower carbon economy. Further information on climate change risk is provided in the Climate change and energy transition section within the basis of preparation. The nominal Brent oil prices (US$/bbl) used for the year ended 31 December 2023 were:

		2024	2025	2026	2027	2028	2029
	31 December 20231	82	80	76	77	79	80
	31 December 20222	78	74	76	77	79	80
	1. Long-term oil prices are based on US$70/bbl (2022 real terms) from 2026 and prices are escalated at 2.0% onwards. 2. Long-term oil prices are based on US$70/bbl (2022 real terms) from 2025 and prices are escalated at 2.0% onwards.

The nominal Brent oil prices (US$/bbl) used for the year ended 31 December 2022 were:
		2023	2024	2025	2026	2027	2028
	31 December 20223	87	78	74	76	77	79
	31 December 20214	71	68	69	70	72	73
	3. Long-term oil prices are based on US$70/bbl (2022 real terms) from 2025 and prices are escalated at 2.0% onwards. 4. Long-term oil prices are based on US$65/bbl (2022 real terms) from 2024 and prices are escalated at 2.0% onwards.

B.5 Business combination

BHP Petroleum merger

Refer to the 2022 Financial Statements for details of the BHPP merger. Except for changes noted below, the disclosures are consistent with Note B.5 of the 2022 Financial Statements.

On 1 June 2022, the Group acquired 100% of the issued share capital of BHP Petroleum International Pty Ltd (subsequently renamed Woodside Energy Global Holdings Pty Ltd), which held BHP Group’s (BHP) oil and gas business. In exchange, the Group issued 914,768,948 new Woodside shares to BHP as part of the merger consideration. The transaction was accounted for as a business combination with an acquisition date of 1 June 2022.

F-35

Notes to the financial statements B. Production and growth assets

for the year ended 31 December 2023

The Group had 12 months from the acquisition date to make adjustments to the fair value of net identifiable assets acquired and the resultant value of goodwill. As at 1 June 2023, the Group finalised the purchase price allocation which has resulted in goodwill of $4,669 million, a net increase of $55 million from the provisional amount reported at 31 December 2022.

Details of the purchase consideration and the fair value of goodwill, identifiable assets and liabilities of BHPP acquired are as follows:

Fair value of net identifiable assets and goodwill arising on acquisition date	US$m
Cash and cash equivalents		399
Receivables		1,164
Inventories		295
Investments accounted for using the equity method		267
Other financial assets		59
Other assets		284
Exploration and evaluation assets		180
Oil and gas properties		19,353
Lease assets		142
Payables		(1,035	)
Provisions		(4,827	)
Tax payable		(365	)
Deferred tax liabilities		(653	)
Lease liabilities		(268	)
Other liabilities		(1,054	)
Net identifiable assets acquired		13,941
Goodwill arising on acquisition		4,669
Purchase consideration		18,610

Purchase consideration	US$m
Shares issued, at fair value		19,265
Other reserves (share replacement awards)		18
Locked box payment received1		(683	)
Adjustments to locked box payment		10
Total purchase consideration		18,610

1. Represents the positive net cash flow of $1,513 million generated by BHPP assets from the effective date of the business combination offset by the notional dividend distribution of $830 million paid to BHP.

Analysis of cash flows on acquisition	US$m
Cash acquired on acquisition		399
Locked box payment received		683
Net cash flow on acquisition		1,082

Shares issued, at fair value

The fair value of 914,768,948 shares issued as part of the consideration paid to BHP was $19,265 million. This was based on the published share price on 1 June 2022 of US$21.06 per share.

Locked box payment received

For the year ended 31 December 2022, the Group received $683 million as part of the merger consideration which includes the locked box payment of $1,513 million representing the positive net cash flow generated by BHPP assets from the effective date of the transaction to completion date offset by the notional dividend distribution of $830 million paid to BHP. The initial purchase consideration was subsequently adjusted by $10 million against the locked box payment received.

Goodwill

Goodwill arising from the acquisition has been recognised as the excess of consideration paid above the fair value of the assets acquired and liabilities assumed as part of the business combination. $2,035 million of the goodwill arises from the deferred tax liability recognised on acquisition as a consequence of asset tax bases received in the merger being lower than the fair value of the assets acquired. The remaining goodwill of $2,634 million reflects the value expected to be generated from the Pluto-Scarborough CGU as a result of the merger. The goodwill is not deductible for tax purposes.

F-36

Notes to the financial statements B. Production and growth assets

for the year ended 31 December 2023

Key estimates and judgements

(a) Fair value determination for net assets acquired

Judgement is required to determine the fair value of assets acquired and liabilities assumed in a business combination, which can have a material impact on resultant goodwill. This includes the use of a cash flow model to estimate the expected future cash flows of the oil and gas assets acquired, based on reserves and resources at acquisition date and the discount rate used. The expected future cash flows are based on estimates of future production, commodity and carbon prices, operating costs, and forecast capital expenditures at acquisition date.

Restoration provisions require judgemental assumptions regarding removal date, environmental legislation and regulations and the extent of restoration activities required in determining the cost estimate.

Carry forward tax losses are recognised only if it is probable that sufficient future taxable income will be available to utilise the losses.

B.6 Goodwill

	US$m
Year ended 31 December 2023
Carrying amount at 1 January 2023		4,614
Adjustment to purchase price allocation1		55
Impairment2		(477	)
Transfer to assets held for sale3		(197	)
Carrying amount at 31 December 2023		3,995
At 31 December 2023
Cost		4,472
Accumulated impairment		(477	)
Net carrying amount		3,995
Year ended 31 December 2022
Carrying amount at 1 January 2022		-
Acquisitions through business combinations1		4,614
Carrying amount at 31 December 2022		4,614
At 31 December 2022
Cost		4,614
Accumulated impairment		-
Net carrying amount		4,614

1. Refer to Note B.5 for details on business combination.

2. Refer to Note B.4 for details on impairment.

3. Refer to Note B.8 for details of the sell-down of the Scarborough Joint Venture.

Recognition and measurement

Goodwill is initially measured at cost and is subsequently measured at cost less any accumulated impairment losses. For the purposes of impairment testing, goodwill acquired in a business combination is, from the acquisition date, allocated to each of the Group’s CGUs or groups of CGUs no larger than an operating segment that are expected to benefit from the combination, irrespective of whether other assets or liabilities of the acquiree are assigned to those units.

Where goodwill has been allocated to a CGU and part of the operation within that unit is disposed of, the goodwill associated with the disposed operation is included in the carrying amount of the operation when determining the gain or loss on disposal.

Goodwill is not amortised but will be assessed at least annually for impairment and more frequently if events or changes in circumstances indicate that it might be impaired.

Key estimates and judgements

(a) Goodwill allocation

Judgement is required in the allocation of goodwill to the Group’s CGUs that are expected to benefit from the synergies of the business combination. Refer to Note B.4 for the details of the goodwill allocation.

B.7 Significant production and growth asset acquisitions

Sangomar – Acquisition from FAR Senegal RSSD SA

On 7 July 2021, Woodside completed the acquisition of FAR Senegal RSSD SA’s interest in the RSSD Joint Venture (13.67% interest in the Sangomar exploitation area and 15% interest in the remaining RSSD evaluation area), for an aggregate purchase price of $212 million. The transaction was accounted for as an asset acquisition.

Additional payments of up to $55 million are contingent on future commodity prices and timing of first oil. The contingent payments terminate on the earliest of 31 December 2027, three years from first oil being sold, and a total contingent payment of $55 million being reached.

With first oil in Sangomar targeted in mid-2024, the Group has recognised the additional payments as a provision for the year ended 31 December 2023. For the years ended 31 December 2022 and 31 December 2021, the contingent payments were accounted for as contingent liabilities in accordance with the Group’s accounting policies.

As at 31 December 2021, Woodside held an 82% interest in the Sangomar exploitation area (2020: 68.33%) and a 90% interest in the remaining RSSD evaluation area (2020: 75%).

Assets acquired and liabilities assumed

The identifiable assets and liabilities acquired as at the date of the acquisition inclusive of transaction costs are:

	US$m
Oil and gas properties		205
Exploration and evaluation		7
Cash acquired		3
Payables		(13)
Net other assets and liabilities assumed		10
Total identifiable net assets at acquisition		212

Cash flows on acquisition

	US$m
Purchase cash consideration		212
Transaction costs		-
Total purchase consideration		212
Net cash outflows on acquisition		212

F-37

Notes to the financial statements B. Production and growth assets

for the year ended 31 December 2023

Key estimates and judgements

(a) Nature of acquisition

Judgement was required to determine if the transaction was the acquisition of an asset or a business combination. The Sangomar project was in the early phase of development and a substantive process that had the ability to convert inputs to outputs was not present and therefore the acquisition in 2021 was treated as an asset acquisition.

B.8 Disposal of assets

(a) Sell-down of Scarborough Joint Venture

On 8 August 2023 the Group entered into a sale and purchase agreement with LNG Japan for the sale of a 10% non-operating participating interest in the Scarborough Joint Venture.

As at 31 December 2023, the Group has reclassified $823 million of assets, being the carrying value of the 10% interest in the Scarborough Joint Venture within the Australia segment, to assets held for sale. Liabilities of $94 million have been reclassified to liabilities directly associated with assets held for sale. No impairment of assets occurred on reclassification to held for sale.

The following assets and liabilities were reclassified as held for sale as at 31 December 2023:

	US$m
Assets classified as held for sale
Inventories		4
Oil and gas properties		618
Lease assets		3
Goodwill		197
Other assets		1
Total assets held for sale		823
Liabilities directly associated with assets held for sale
Payables		(26	)
Deferred tax liabilities		(61	)
Lease liabilities		(7	)
Total liabilities directly associated with assets held for sale		(94	)

The purchase price is $500 million, subject to adjustments. The total proceeds from the sale are expected to exceed the net carrying value of the assets and liabilities classified as held for sale as LNG Japan will reimburse the Group for its share of expenditure for the Scarborough project from the effective date of 1 January 2022. Delays to the first cargo or cost overruns in specific circumstances may result in payments by Woodside to LNG Japan of up to a maximum of $50 million. The transaction is expected to complete in the first quarter of 2024.

Completion of the transaction is subject to the remaining Western Australian Government approvals.

In addition to the above, a reduction in the deferred tax liability due to the change to a held for sale basis resulted in a tax benefit of $78 million being recognised for the year ended 31 December 2023.

Recognition and measurement

The Group classifies assets and liabilities as held for sale if their carrying amounts will be recovered principally through sale rather than through continuing use. Such assets and liabilities classified as held for sale are measured at the lower of their carrying amount and fair value less costs to dispose. Costs to dispose are the incremental costs directly attributable to the sale, excluding finance costs and income tax expense.

The criteria for held for sale classification are considered met only when the sale is highly probable, and the asset is available for sale in its present condition. Actions required to complete the sale should indicate that it is unlikely that significant changes to the sale will be made or that the decision to sell will be withdrawn. Management must be committed to the sale, expected within one year from the date of the classification.

Assets are not depreciated or amortised once classified as held for sale. Assets and liabilities classified as held for sale are presented separately as current items in the statement of financial position.

F-38

Notes to the financial statements B. Production and growth assets

for the year ended 31 December 2023

Assets and liabilities reclassified as held for sale

In addition to the assets and liabilities reclassified as held for sale for the Scarborough Joint Venture, the Group has reclassified $3 million for the North West Shelf vessels to assets held for sale. There are no recognised liabilities associated with the North West Shelf vessels.

Key estimates and judgements

(a) Goodwill allocation

In accordance with IAS 36 Impairment of assets, if goodwill has been allocated to a CGU and the entity disposes of an operation within that unit, the goodwill associated with the operation disposed shall be included in the carrying value of the operation when determining the gain or loss on disposal and measured on the basis of the relative values of the operation disposed of and the portion of the CGU retained.

The Pluto-Scarborough CGU includes goodwill allocated from the merger with BHPP in 2022. Judgement is required to determine the amount of goodwill allocated to the 10% participating interest in the Scarborough assets being disposed.

The Group used fair value measurements of Pluto and Scarborough assets within the CGU as a basis to allocate goodwill between the Pluto and Scarborough assets. The goodwill associated with the participating interest of the Scarborough assets being disposed of was determined based on the percentage participating interest disposed of in proportion to the participating interest being retained.

(b) Sell-down of Train 2

On 15 November 2021 the Group entered into a sale and purchase agreement with Global Infrastructure Partners (GIP) for the sale of a 49% non-operating participating interest in the Pluto Train 2 Joint Venture.

As at 31 December 2021, the Group reclassified the carrying value of the 49% interest in the Pluto Train 2 assets to assets held for sale. There were no recognised liabilities associated with the assets held for sale.

The transaction completed on 18 January 2022, reducing the Group’s participating interest from 100% to 51%. The Group recognised an initial pre-tax gain on sale of $427 million for the year ended 31 December 2022.

The arrangements require GIP to fund its 49% share of capital expenditure from 1 October 2021 and an additional amount of construction capital expenditure of $822 million on behalf of the Group. If the total capital expenditure incurred is less than $5,800 million, GIP will pay Woodside an additional amount equal to 49% of the under-spend. In the event of a cost overrun, Woodside will fund up to $822 million of GIP’s share of the overrun. Delays to the expected start-up of production will result in payments by Woodside to GIP in certain circumstances. The arrangements include provisions for GIP to be compensated for exposure to additional Scope 1 emissions liabilities above agreed baselines, and to sell its 49% interest back to Woodside if the status of key regulatory approvals materially changes.

Given judgement was used to determine the consideration received, the Group is required to remeasure the variable consideration at each reporting period. As at 31 December 2023, the variable consideration has been reassessed with no revaluation gain or loss being recognised (2022: $71 million revaluation gain recognised as other income, with a corresponding reduction to other liabilities). The fair value of the remaining unpaid funding from GIP has been netted against the other liabilities and will be recognised as oil and gas properties in the future.

Key estimates and judgements

(a) Sell-down of Train 2

Given the arrangements include provisions for GIP to sell its 49% interest back to Woodside if the status of key regulatory environmental approvals materially changes and the requirement for Woodside to fund up to $822 million of GIP’s share in the event of a cost overrun, judgement is required to determine if the sell-down of Train 2 constitutes a sale and if a portion of the transaction price should be considered as variable consideration.

Judgement was used to determine that the sell-down of Train 2 constituted a sale given the various conditions included in the sale and purchase agreement. The Group determined that a sale occurred as control of the 49% interest was passed to GIP on completion date. Control is determined as the ability to direct the use of, and obtain substantially all of the economic benefits of, the associated interest.

Judgement was used to determine if it is highly probable that a significant reversal will not occur in relation to the consideration received. The Group estimated the variable consideration based on the construction capital expenditure cost profile, the development schedule, and assessing the probability and impact of any event which may result in a significant reversal. The constraining estimates of variable consideration have been applied resulting in the initial pre-tax gain on sale of $427 million for the year ended 31 December 2022.

The variable consideration is remeasured at each reporting period with any changes recognised through the consolidated income statement. As at 31 December 2023, the variable consideration has been reassessed with no revaluation gain or loss being recognised (2022: $71 million revaluation gain recognised as other income).

F-39

Notes to the financial statements C. Debt and capital

for the year ended 31 December 2023

In this section

This section addresses cash, debt and the capital position of the Group at the end of the reporting period including, where applicable, the accounting policies applied and the key estimates and judgements made.

C.	Debt and capital
C.1	Cash and cash equivalents	Page F-41
C.2	Interest-bearing liabilities and financing facilities	Page F-42
C.3	Contributed equity	Page F-44
C.4	Other reserves	Page F-45

Key financial and capital risks in this section

Capital risk management

Group Treasury is responsible for the Group’s capital management including cash, debt and equity. Capital management is undertaken to ensure that a secure, cost-effective and flexible supply of funds is available to meet the Group’s operating and capital expenditure requirements. A stable capital base is maintained from which the Group can pursue its growth aspirations, whilst maintaining a flexible capital structure that allows access to a range of debt and equity markets to both draw upon and repay capital.

The Dividend Reinvestment Plan (DRP) was approved by shareholders at the Annual General Meeting in 2003 for activation as required to fund future growth. The DRP was reactivated in 2019 and suspended by the Board of Directors on 27 February 2023.

A range of financial metrics are monitored, including gearing and cash flow leverage, and Treasury policy breaches and exceptions.

Liquidity risk management

Liquidity risk arises from the financial liabilities of the Group and the Group’s subsequent ability to meet its obligations to repay financial liabilities as and when they fall due. The liquidity position of the Group is managed to ensure sufficient liquid funds are available to meet its financial commitments in a timely and cost-effective manner.

The Group’s liquidity is continually reviewed, including cash flow forecasts to determine the forecast liquidity position and maintain appropriate liquidity levels. At 31 December 2023, the Group had a total of $7,790 million (2022: $10,239 million) of available undrawn facilities and cash at its disposal. The maturity profile of interest-bearing liabilities is disclosed in Note C.2, trade and other payables are disclosed in Note D.4 and lease liabilities are disclosed in Note D.7. Financing facilities available to the Group are disclosed in Note C.2.

Interest rate risk management

Interest rate risk is the risk that the Group’s financial position will fluctuate due to changes in market interest rates.

The Group’s exposure to the risk of changes in market interest rates relates primarily to financial instruments with floating interest rates including long-term debt obligations, cash and short-term deposits. The Group manages its interest rate risk by maintaining an appropriate mix of fixed and floating rate debt. To manage the ratio of fixed rate debt to floating rate debt, the Group may enter into interest rate swaps. The Group holds interest rate swaps to hedge the interest rate risk associated with the $600 million syndicated facility. Refer to Notes C.2 and D.6 for further details.

At the reporting date, the Group was exposed to various benchmark interest rates that were not designated in cash flow hedges, primarily through $1,605 million (2022: $6,143 million) on cash and cash equivalents, nil (2022: $83 million) on interest-bearing liabilities (excluding transaction costs), nil (2022: $167 million) of other financial assets and nil (2022: $5 million) on cross-currency interest rate swaps.

A reasonably possible change in the Secured Overnight Financing Rate (SOFR) (+2.0%/-2.0% (2022: USD London Interbank Offered Rate (USD LIBOR) +1.5%/-1.5%)), with all variables held constant, would not have a material impact on the Group’s equity or the income statement in the current period.

During the period, the Group has completed the transition of its financial liabilities from USD LIBOR to SOFR. The transition during the year ended 31 December 2023 did not result in a material impact to the Group.

F-40

Notes to the financial statements C. Debt and capital

for the year ended 31 December 2023

C.1 Cash and cash equivalents

	2023     US$m		2022     US$m
Cash and cash equivalents
Cash at bank		1,198		1,222
Term deposits		542		4,967
Restricted cash		-		12
Total cash and cash equivalents		1,740		6,201

Recognition and measurement

Cash and cash equivalents in the consolidated statement of financial position comprise cash at bank and short-term deposits with an original maturity of three months or less. Cash and cash equivalents are stated at face value in the consolidated statement of financial position. There are no cash and cash equivalents (2022: $12 million) restricted by legal or contractual arrangements.

Foreign exchange risk

The following table summarises the Group’s cash and cash equivalents by currency.

	2023     US$m		2022     US$m
US dollar		1,480		5,886
Australian dollar		112		182
Other		148		133
Total cash and cash equivalents		1,740		6,201

F-41

Notes to the financial statements C. Debt and capital

for the year ended 31 December 2023

C.2 Interest-bearing liabilities and financing facilities

	Liquidity Facilities			Bilateral Facilities			Syndicated Facilities			JBIC Facility			US Bonds			Medium Term Notes			Total
	US$m			US$m			US$m			US$m			US$m			US$m			US$m
Year ended 31 December 2023
At 1 January 2023		-			(5	)		591			83			4,084			385			5,138
Repayments1		-			-			-			(83	)		-			(201	)		(284	)
Fair value adjustment and foreign exchange movement		-			-			-			-			-			16			16
Transaction costs capitalised and amortised		(1	)		(1	)		3			-			3			-			4
Carrying amount at 31 December 2023		(1	)		(6	)		594			-			4,087			200			4,874
Current2		(1	)		(2	)		(3	)		-			(3	)		-			(9	)
Non-current		-			(4	)		597			-			4,090			200			4,883
Carrying amount at 31 December 2023		(1	)		(6	)		594			-			4,087			200			4,874
Undrawn balance at 31 December 2023		1,800			2,250			2,000			-			-			-			6,050
Year ended 31 December 2022
At 1 January 2022		-			(4	)		595			166			4,081			592			5,430
Repayments1		-			-			-			(83	)		-			(200	)		(283	)
Fair value adjustment and foreign exchange movement		-			-			-			-			-			(7	)		(7	)
Transaction costs capitalised and amortised		-			(1	)		(4	)		-			3			-			(2	)
Carrying amount at 31 December 2022		-			(5	)		591			83			4,084			385			5,138
Current		-			(2	)		(3	)		83			(3	)		185			260
Non-current		-			(3	)		594			-			4,087			200			4,878
Carrying amount at 31 December 2022		-			(5	)		591			83			4,084			385			5,138
Undrawn balance at 31 December 2022		-			2,050			2,000			-			-			-			4,050

1. Included in cash flows classified within financing activities in the consolidated statement of cash flows.

2. The balance relates to capitalised costs to be amortised within the next 12 months. This balance has been reclassified to other assets (current) for presentation on the statement of financial position.

Recognition and measurement

All borrowings are initially recognised at fair value less transaction costs. Borrowings are subsequently carried at amortised cost. Any difference between the proceeds received and the redemption amount is recognised in the income statement over the period of the borrowings using the effective interest method.

Borrowings designated as a hedged item are measured at amortised cost adjusted to record changes in the fair value of risks that are being hedged in fair value hedges. The changes in the fair value risks of the hedged item resulted in a loss of $16 million being recorded (2022: gain of $7 million), and a loss of $6 million being recorded on the hedging instrument (2022: loss of $7 million).

All bonds, notes and facilities are subject to various covenants and negative pledges restricting future secured borrowings, subject to a number of permitted lien exceptions. Neither the covenants nor the negative pledges have been breached at any time during the reporting period.

Fair value

The carrying amount of interest-bearing liabilities approximates their fair value, with the exception of the Group’s unsecured bonds and the medium term notes. The unsecured bonds have a carrying amount of $4,087 million (2022: $4,084 million) and a fair value of $3,936 million (2022: $3,852 million). The medium term notes have a carrying amount of $200 million (2022: $385 million) and a fair value of $188 million (2022: $372 million). Fair value is calculated based on the present value of future principal and interest cash flows, discounted at the market rate of interest at the reporting date and classified as Level 1 on the fair value hierarchy. Where these cash flows are in a foreign currency, the present value is converted to US dollars at the foreign exchange spot rate prevailing at the reporting date. The Group’s repayment obligations remain unchanged.

Foreign exchange risk

All interest-bearing liabilities are denominated in US dollars, excluding the CHF175 million medium term note which was settled in December 2023.

F-42

Notes to the financial statements C. Debt and capital

for the year ended 31 December 2023

Maturity profile of interest-bearing liabilities

The table below presents the contractual undiscounted cash flows associated with the Group’s interest-bearing liabilities, representing principal and interest. The figures will not necessarily reconcile with the amounts disclosed in the consolidated statement of financial position.

	2023     US$m		2022     US$m
Due for payment in:
1 year or less		212		483
1-2 years		1,181		206
2-3 years		962		1,181
3-4 years		907		962
4-5 years		883		908
More than 5 years		1,534		2,416
		5,679		6,156

Amounts exclude transaction costs.

Liquidity facilities

In October 2023, the Group obtained 12-month liquidity facilities to the value of $1,800 million in aggregate. Interest rates are based on daily SOFR plus credit adjustment spread (CAS) and margins, fixed at the commencement of the drawdown period. 

Bilateral facilities

The Group has 15 bilateral loan facilities totalling $2,250 million (2022: 14 bilateral loan facilities totalling $2,050 million). Details of bilateral loan facilities at the reporting date are as follows:

Number of facilities	Term (years)	Currency	Extension option
1	5 - 6	US$	Evergreen
5	4 - 5	US$	Evergreen
4	3 - 4	US$	Evergreen
5	3 years or less	US$	Evergreen

Interest rates are based on SOFR plus CAS and margins are fixed at the commencement of the drawdown period. Interest is paid at the end of the drawdown period. Evergreen facilities may be extended continually by a year subject to the bank’s agreement.

Syndicated facility

During the year ended 31 December 2022, Woodside refinanced and increased the existing facilities to $2,000 million, with $800 million expiring on 11 October 2024, $600 million expiring on 12 July 2025 and $600 million expiring on 12 July 2027. Interest rates are based on SOFR plus CAS and margins are fixed at the commencement of the drawdown period.

On 17 January 2020, the Group completed a $600 million syndicated facility with a term of seven years. Interest is based on SOFR plus CAS plus 1.2%. Interest is paid on a quarterly basis.

Japan Bank for International Cooperation (JBIC) facility

On 24 June 2008, the Group entered into a two tranche committed loan facility of $1,000 million and $500 million respectively. The $500 million tranche was repaid in 2013. There is a prepayment option for the remaining balance. Interest rates are based on LIBOR. Interest is payable semi-annually in arrears and the principal amortises on a straight-line basis, with equal instalments of principal due on each interest payment date (every six months).

Under this facility, 90% of the receivables from designated Pluto LNG sale and purchase agreements are secured in favour of the lenders through a trust structure, with a required reserve amount of $30 million.

To the extent that this reserve amount remains fully funded and no default notice or acceleration notice has been given, the revenue from Pluto LNG continues to flow directly to the Group from the trust account.

This facility was settled in July 2023. During the period, the Group repaid $83 million on the JBIC facility.

Medium term notes

On 28 August 2015, the Group established a $3,000 million Global Medium Term Notes Programme listed on the Singapore Stock Exchange. One note is currently issued under this programme as set out below:

Maturity date	Currency		Carrying amount (million)		Nominal interest rate
29 January 2027		US$		200		3.07	%

The unutilised program is not considered to be an unused facility.

The CHF medium term note was settled in December 2023. During the period, the Group repaid $201 million of the CHF medium term note.

F-43

Notes to the financial statements C. Debt and capital

for the year ended 31 December 2023

US bonds

The Group has four series of unsecured bonds issued in reliance on Rule 144A of the US Securities Act of 1933 as set out below:

Maturity date		Carrying amount US$m		Nominal interest rate
5 March 2025			1,000		3.65	%
15 September 2026			800		3.70	%
15 March 2028			800		3.70	%
4 March 2029			1,500		4.50	%

Interest on the bonds is payable semi-annually in arrears.

C.3 Contributed equity

Recognition and measurement

Issued capital

Ordinary shares are classified as equity and recorded at the value of consideration received. The cost of issuing shares is shown in share capital as a deduction, net of tax, from the proceeds.

Reserved shares

Reserved shares are the Group’s own equity instruments, which are used in employee share-based payment arrangements or the Dividend Reinvestment Plan (DRP). The DRP was suspended on 27 February 2023. These shares are deducted from equity. No gain or loss is recognised in the income statement on the purchase, sale, issue or cancellation of the Group’s own equity instruments.

(a) Issued and fully paid shares

	Number of shares		US$m
Year ended 31 December 2023
Opening balance		1,898,749,771		29,001
Amounts as at 31 December 2023		1,898,749,771		29,001
Year ended 31 December 2022
Opening balance		969,631,826		9,409
DRP – ordinary shares issued at US$23.14 (2021 final dividend) 1		14,348,997		332
Ordinary shares issued at US$21.06 for the acquisition of BHPP2		914,768,948		19,265
Transaction costs associated to the issue of shares		-		(5)
Amounts as at 31 December 2022		1,898,749,771		29,001
Year ended 31 December 2021
Opening balance		962,225,814		9,297
DRP – ordinary shares issued at US$19.03 (2020 final dividend)		1,354,072		26
DRP – ordinary shares issued at US$14.21 (2021 interim dividend)		6,051,940		86
Amounts as at 31 December 2021		969,631,826		9,409

1. Relates to ordinary shares issued for the DRP as part of the 2021 final dividend. The Group purchased on-market shares for the issuance of DRP as part of the 2022 interim dividend. Refer to Note C.3(b) for details of the on-market purchases and allocation.

2. 914,768,948 new Woodside shares were issued as consideration for the BHPP merger. Refer to Note B.5 for details.

All shares are a single class with equal rights to dividends, capital, distributions and voting. Woodside does not have authorised capital nor par value in relation to its issued shares.

F-44

Notes to the financial statements C. Debt and capital

for the year ended 31 December 2023

(b) Reserved shares

	Employee share plans				Dividend reinvestment plan
	Number of shares		US$m		Number of shares		US$m
Year ended 31 December 2023
Opening balance	1,873,777		(38)		-		-
Purchases during the year	2,332,121		(57)		-		-
Vested/allocated during the year	(2,064,971)		46		-		-
Amounts at 31 December 2023	2,140,927		(49)		-		-
Year ended 31 December 2022
Opening balance		1,819,744		(30)		-		-
Purchases during the year		2,232,589		(45)		6,823,092		(144)
Vested/allocated during the year		(2,178,556)		37		(6,823,092)		144
Amounts at 31 December 2022		1,873,777		(38)		-		-
Year ended 31 December 2021
Opening balance		1,766,099		(23)		-		-
Purchases during the year		2,683,469		(47)		-		-
Vested during the year		(2,629,824)		40		-		-
Amounts at 31 December 2021		1,819,744		(30)		-		-

C.4 Other reserves

	2023      US$m		2022      US$m		2021      US$m
Other reserves
Employee benefits reserve		290		278		232
Foreign currency translation reserve		795		796		793
Hedging reserve1		88		(586)		(400)
Distributable profits reserve2		4,118		3,541		58
Other reserves		(30)		2		-
		5,261		4,031		683

1. For the year ended 31 December 2023, the portion of the hedging reserve relating to settled hedges is $80 million (2022: $226 million).

2. For the year ended 31 December 2023, the Group transferred $4,830 million (2022: $5,553 million) of retained earnings to the distributable profits reserve. The increase was offset by the 2022 final and 2023 interim dividend payments of $4,253 million (2022 interim dividend payment: $2,070 million). 

Nature and purpose

Employee benefits reserve

Used to record share-based payments associated with the employee share plans.

Foreign currency translation reserve

Used to record foreign exchange differences arising from the translation of the financial statements of foreign entities from their functional currency to the Group’s presentation currency.

Hedging reserve

Used to record gains and losses on effective portion of hedges designated as cash flow hedges, and foreign currency basis spread arising from the designation of a financial instrument as a hedging instrument. Gains and losses accumulated in the cash flow hedge reserve for qualifying assets are capitalised against the carrying amount of that asset and recognised in the income statement as the asset is depreciated.

Distributable profits reserve

Used to record distributable profits generated by the Parent entity, Woodside Energy Group Ltd.

Other reserves

Used to record gains and losses on financial instruments at fair value through other comprehensive income.

F-45

Notes to the financial statements D. Other assets and liabilities

for the year ended 31 December 2023

In this section

This section addresses the other assets and liabilities position at the end of the reporting period including, where applicable, the accounting policies applied and the key estimates and judgements made.

D.	Other assets and liabilities
D.1	Segment assets and liabilities	Page F-47
D.2	Receivables	Page F-47
D.3	Inventories	Page F-48
D.4	Payables	Page F-48
D.5	Provisions	Page F-49
D.6	Other financial assets and liabilities	Page F-51
D.7	Leases	Page F-55

Key financial and capital risks in this section

Credit risk management

Credit risk is the risk that a counterparty will not meet its payment obligation under a financial instrument or customer contract, leading to a financial loss to the Group. Credit risk arises from the financial assets of the Group, which comprise trade and other receivables, loans receivables and deposits with banks and financial institutions.

The Group manages its credit risk on trade receivables and financial instruments by predominantly dealing with counterparties with an investment grade credit rating. Sufficient financial security is obtained to mitigate the risk of financial loss when transacting with counterparties with below investment grade credit ratings. Customers who wish to trade on unsecured credit terms are subject to credit assessment procedures. Receivable balances are monitored on an ongoing basis. As a result, the Group’s exposure to bad debts is not significant. The Group’s maximum credit exposure is limited to the carrying amount of its financial assets.

Customer credit risk is managed by the Treasury function subject to the Group’s established policy, procedures and controls relating to customer credit risk management. The credit quality of a customer is assessed based on various credit metrics, including its credit rating, and individual credit limits and requirements are defined in accordance with this assessment. Outstanding customer receivables are regularly monitored.

At 31 December 2023, the Group had nineteen customers (2022: nineteen customers) that owed the Group more than $10 million each and accounted for approximately 82% (2022: 79%) of product-related trade receivables. Depending on the product, standard settlement terms are 7 to 30 days from the date of invoice or bill of lading.

The Group considers the probability of default upon initial recognition of the asset and whether there has been a significant depreciation in credit quality on an ongoing basis. A significant decrease in credit quality is defined as a debtor being greater than 30 days past due in making a contractual payment. Credit losses for trade receivables (including lease receivables) and contract assets are determined by applying the simplified approach and are measured at an amount equal to lifetime expected loss. Under the simplified approach, determination of the loss allowance provision and expected loss rate incorporates past experience and forward- looking information, including the outlook for market demand and forward-looking interest rates. A default on other financial assets is considered to be when the counterparty fails to make contractual payments within 60 days of when they fall due.

At 31 December 2023, the Group had a provision for credit losses of nil (2022: nil). Subsequent to 31 December 2023, 97% (2022: 99%) of product-related trade receivables balance of $885 million (2022: $1,067 million) has been received.

Credit risk from balances with banks is managed by the Treasury function in accordance with the Group’s policy. The Group places funds from time to time as short-term deposits with reputable financial institutions with investment grade credit ratings. At 31 December 2023 and 31 December 2022, there were no significant concentrations of credit risk within the Group and financial instruments are spread amongst a number of financial institutions to minimise the risk of counterparty default. The maximum exposure to financial institution credit risk is represented by the sum of all cash deposits plus accrued interest, bank account balances and fair value of derivative assets. The Group’s counterparty credit policy limits this exposure to commercial and investment banks, according to approved credit limits based on the counterparty’s credit rating.

F-46

Notes to the financial statements D. Other assets and liabilities

for the year ended 31 December 2023

D.1 Segment assets and liabilities

	2023    US$m		2022 US$m
(a) Segment assets
Australia		31,602		31,240
International		17,923		18,084
Marketing1		835		182
Corporate/Other1		5,001		9,815
		55,361		59,321

	2023    US$m		2022 US$m
(b) Segment liabilities
Australia2		7,833		7,552
International		2,624		2,677
Marketing1		751		561
Corporate/Other1,2		8,983		11,404
		20,191		22,194

1. In 2023, certain shipping activities are now undertaken by the Marketing segment. As a result of this change, $539 million of lease assets and $677 million of lease liabilities are now reported within the Marketing segment as at 31 December 2023. The impact of this change on revenue and expenses is not material.

2. 2022 comparatives have been revised to reflect the appropriate allocation of intercompany liabilities between Australia and Corporate/Other segments post-merger. As a result of this change, $552 million has been reclassified to the Corporate/Other segment.

Refer to Note A.1 for descriptions of the Group’s segments. Corporate/Other assets mainly comprise cash and cash equivalents, deferred tax assets and lease assets. Corporate/Other liabilities mainly comprise interest-bearing liabilities, deferred tax liabilities and lease liabilities.

D.2 Receivables

	2023    US$m		2022 US$m
(a) Receivables (current)
Trade receivables1		963		1,067
Other receivables1		456		381
Loans receivable		73		76
Lease receivables		24		35
Interest receivable		1		19
		1,517		1,578
(b) Receivables (non-current)
Other receivables		21		75
Loans receivable		771		724
Lease receivables		47		46
		839		845

1. Interest-free and settlement terms are usually between 14 and 30 days.

Recognition and measurement

Trade receivables are initially recognised at the transaction price determined under IFRS 15 Revenue from Contracts with Customers. Other receivables are initially recognised at fair value. Receivables that satisfy the contractual cash flow and business model tests are subsequently measured at amortised cost less an allowance for uncollectable amounts. Uncollectable amounts are determined using the expected loss impairment model. Collectability and impairment are assessed on a regular basis.

Subsequent recoveries of amounts previously written off are credited against other expenses in the consolidated income statement. Certain receivables that do not satisfy the contractual cash flow and business model tests are subsequently measured at fair value (refer to Note D.6).

The Group’s customers are required to pay in accordance with agreed payment terms. Depending on the product, settlement terms are 7 to 30 days from the date of invoice or bill of lading and customers regularly pay on time. There are no significant overdue product-related trade receivables as at the end of the reporting period (2022: nil).

Fair value

The carrying amount of trade and other receivables approximates their fair value.

Foreign exchange risk

The Group held $305 million of receivables at 31 December 2023 (2022: $174 million) in currencies other than US dollars (predominantly Australian dollars).

F-47

Notes to the financial statements D. Other assets and liabilities

for the year ended 31 December 2023

Loans receivable

On 9 January 2020, Woodside Energy Finance (UK) Ltd entered into a secured loan agreement with Petrosen (the Senegal National Oil Company), to provide up to $450 million for the purpose of funding Sangomar project costs. The facility has a maximum term of 12 years and semi-annual repayments of the loan are due to commence at the earlier of 12 months after RFSU or 30 June 2025. The carrying amount of the loan receivable is $435 million at 31 December 2023 (2022: $408 million), which approximates its fair value. The remaining balance of loans receivable is due from non-controlling interests.

D.3 Inventories

	2023    US$m		2022    US$m
(a) Inventories (current)
Petroleum products
Goods in transit		41		95
Finished stocks		93		103
Warehouse stores and materials		476		480
Carbon credits1		6		-
		616		678
(b) Inventories (non-current)
Warehouse stores and materials		3		11
Carbon credits1		117		54
		120		65

1. Inventories include carbon credits which were previously presented within other assets (non-current). The 2022 amounts have been reclassified to be presented on the same basis.

Recognition and measurement

Inventories include hydrocarbon stocks, consumable supplies, maintenance spares and carbon credits expected to be utilised to offset future emissions. Inventories are valued at the lower of cost and net realisable value. Cost is determined on a weighted average basis and includes direct costs and an appropriate portion of fixed and variable production overheads where applicable. Inventories determined to be obsolete or damaged are written down to net realisable value, being the estimated selling price less selling costs.

D.4 Payables

	2023    US$m		2022    US$m
Trade and other payables1		1,655		2,029
Interest payable2		69		65
		1,724		2,094

1. Interest-free and normally settled on 30 day terms.

2. Details regarding interest-bearing liabilities are contained in Note C.2.

Recognition and measurement

Trade and other payables are carried at amortised cost and are recognised when goods and services are received, whether or not billed to the Group, prior to the end of the reporting period.

Fair value

The carrying amount of payables approximates their fair value.

Foreign exchange risk

The Group held $534 million of payables at 31 December 2023 (2022: $657 million) in currencies other than US dollars (predominantly Australian dollars).

Maturity profile of payables

The Group’s payables balances at 31 December 2023 and 31 December 2022 are due for payment within 12 months.

F-48

Notes to the financial statements D. Other assets and liabilities

for the year ended 31 December 2023

D.5 Provisions

	Restoration1 US$m		Employee benefits US$m		Onerous   contracts US$m		Other   US$m			Total   US$m
Year ended 31 December 2023
At 1 January 2023		6,253		517		-		409			7,179
Change in provision		664		5		-		(128	)		541
Unwinding of present value discount		237		-		-		-			237
Carrying amount at 31 December 2023		7,154		522		-		281			7,957
Current		1,011		351		-		144			1,506
Non-current		6,143		171		-		137			6,451
Net carrying amount		7,154		522		-		281			7,957
Year ended 31 December 2022
At 1 January 2022		2,218		286		214		106			2,824
Acquisitions through business combination2		4,310		329		-		165			4,804
Change in provision		(382)		(98)		(216)		137			(559)
Unwinding of present value discount		107		-		2		1			110
Carrying amount at 31 December 2022		6,253		517		-		409			7,179
Current		575		331		-		313			1,219
Non-current		5,678		186		-		96			5,960
Net carrying amount		6,253		517		-		409			7,179

1. 2023 change in provision is due to increase in estimates of $1,111 million and accretion of $237 million offset by provisions used of $447 million. Changes in estimates are due to new activities, revisions to cost and removal scope assumptions and rate escalations, supported by the most recent estimates and benchmarks and the alignment of the ‘expected value approach’ across all assets.

2. Refer to Note B.5 for details of business combination.

Recognition and measurement

Provisions are recognised when the Group has a present obligation (legal or constructive) as a result of a past event, it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation.

Restoration

The restoration provision is first recognised in the period in which the obligation arises. The nature of restoration activities includes the removal of facilities, abandonment of wells and restoration of affected areas. Restoration provisions are updated annually, with the corresponding movement recognised against the related exploration and evaluation assets or oil and gas properties or expensed for late life projects with no corresponding asset.

Over time, the liability is increased for the change in the present value based on a pre-tax discount rate appropriate to the risks inherent in the liability. The unwinding of the discount is recorded as an accretion charge within finance costs. The carrying amount capitalised in oil and gas properties is depreciated over the useful life of the related asset (refer to Note B.3).

Costs incurred that relate to an existing condition caused by past operations, and which do not have a future economic benefit, are expensed.

Employee benefits

Provision is made for employee benefits accumulated as a result of employees rendering services up to the end of the reporting period. These benefits include wages, salaries, annual leave and long service leave.

Liabilities in respect of employees’ services rendered that are not expected to be wholly settled within one year after the end of the period in which the employees render the related services are recognised as long-term employee benefits.

These liabilities are measured at the present value of the estimated future cash outflow to the employees using the projected unit credit method. Liabilities expected to be wholly settled within one year after the end of the period in which the employees render the related services are classified as short-term benefits and are measured at the amount due to be paid.

Onerous contract provision

Provision is made for loss-making contracts at the present value of the lower of the net cost of fulfilling and the cost arising from failure to fulfil each contract.

F-49

Notes to the financial statements D. Other assets and liabilities

for the year ended 31 December 2023

Key estimates and judgements

(a) Restoration obligations

The Group estimates the future decommissioning and remediation costs of offshore oil and gas platforms, offshore and onshore production facilities, wells and pipelines at different stages of the development and construction of assets or facilities. In many instances, decommissioning of assets occurs many years into the future.

The Group’s restoration obligations are based on compliance with the requirements of relevant regulations which vary for different jurisdictions. For example Australian regulations require full removal for offshore assets unless regulator approval is received to decommission in-situ. It is currently the Group’s assumption that in some regulatory jurisdictions and environments, certain infrastructures are decommissioned in-situ where it can be demonstrated that this will deliver equal or better environmental outcomes than full removal and that regulatory approval is obtained where arrangements are satisfactory to the regulator. The Group maintains technical expertise to ensure that industry learnings, scientific research and local and international guidelines are reviewed in assessing its restoration obligations.

The restoration obligation requires judgemental assumptions regarding removal date, environmental legislation and regulations, the extent of restoration activities required, the engineering methodology for estimating cost, technologies used in determining the decommissioning cost, and liability-specific discount rates to determine the present value of these cash flows.

For the year ended 31 December 2022, the Group applied either the ‘expected outcome’ approach or ‘expected value’ approach in assessing the cost estimate. Both approaches are supported by IAS 37 Provisions, Contingent liabilities and Contingent Assets, produced reliable estimates and are widely used in practice. The ‘expected outcome’ approach was used for heritage Woodside assets (assets held by the Group prior to the BHPP merger) and those assets commonly held by both heritage entities. The ’expected value’ approach was used for heritage BHPP assets (assets acquired from BHP) but excludes assets held by both heritage entities.

For the year ended 31 December 2023, the Group has aligned to the ‘expected value’ approach and consistently applied it across all assets. This has not resulted in a material change to the prior estimate. The alignment reflects a change to the estimate and not a policy change, therefore no retrospective restatement is required.

Expected value approach

For both onshore and offshore assets, provision has been made taking into consideration a risked range of possible removal outcomes, including full removal of certain assets or project-specific risks (where applicable). Individual site provisions are an estimate of the expected value of future cash flows required to rehabilitate the relevant site using current restoration standards and techniques and taking into account risks and uncertainties. Individual site provisions are discounted to their present value using risk free country-specific discount rates aligned to the estimated timing of cash outflows. This approach takes into consideration the possibility that full removal of all assets may be required.

Inherent uncertainties

The basis of the restoration obligation provision for assets with approved decommissioning plans or general directions issued by the regulator can differ from the assumptions disclosed above. Whilst the provisions reflect the Group’s best estimate based on current knowledge and information, further studies and detailed analysis of the restoration activities for individual assets will be ongoing to ensure that the most accurate information is available when detailed decommissioning plans are required to be submitted to the relevant regulatory authorities. Actual costs and cash outflows can materially differ from the current estimate as a result of changes in regulations and their application, prices, analysis of site conditions, further studies, timing of restoration and changes in removal technology. These uncertainties may result in actual expenditure differing from amounts included in the provision recognised as at 31 December 2023.

A range of pre-tax discount rates between 3.7% and 5.0% (2022: 3.4% to 4.7%) has been applied. If the discount rates were decreased by 0.5% then the provision would be $365 million higher. If the cost estimates were increased by 10% then the provision would be $718 million higher. The proportion of the non-current balance not expected to be settled within 10 years is 55% (2022: 54%).

(b) Onerous contracts

The onerous contract provision assessment requires management to make certain estimates regarding the unavoidable costs and the expected economic benefits from the contract. These estimates require significant management judgement and are subject to risk and uncertainty, and hence changes in economic conditions can affect the assumptions.

As at 31 December 2023, the Corpus Christi contract has a positive value and therefore is not currently onerous (2022: nil onerous contract provision). Changes in assumptions predominantly relating to the narrowing of the spread between the sales price and purchase price could result in the contract becoming onerous in the future.

F-50

Notes to the financial statements D. Other assets and liabilities

for the year ended 31 December 2023

Assumptions used to determine the present value as at 31 December 2023 are set out below:

· Discount rate – a pre-tax, risk free US government bond rate of 4.04% (2022: 4.10%) has been applied.

· LNG pricing – forecast sales and purchase prices are subject to a number of price markers. Price assumptions are based on the best information on the market available at measurement date and derived from short- and long-term views of global supply and demand, building upon past experience of the industry and consistent with external sources. The forecasted sales are linked to gas hub prices (Title Transfer Facility (TTF)) at which physical sales are expected to occur and incorporate known sales pricing information1. The long-term gas sales price is estimated on the basis of the Group’s Brent price forecast. The estimated purchase price is linked to US gas hub prices (Henry Hub (HH)) at which physical purchases are expected to occur. The nominal TTF, Brent oil prices and HH gas prices used at 31 December 2023 were:

		2024	2025	2026	2027	2028
	TTF (US$/MMBtu)	13.9	14.2	8.8	8.9	9.1
	Brent (US$/bbl)	82	80	76	77	79	²
	HH (US$/MMBtu)	3.4	3.5	3.5	3.5	3.6	3

1. For committed volumes, contracted pricing has been applied.

2. Long-term oil prices are based on US$70/bbl (2022 real terms) from 2026 and prices are escalated at 2.0% onwards.

3. Long-term gas prices are based on US$3.2/MMBtu (2022 real terms) from 2026 and US$3.8/MMBtu (2022 real terms) from 2030. All long-term prices are escalated at 2.0%.

D.6 Other financial assets and liabilities

	2023    US$m		2022    US$m
Other financial assets
Financial instruments at fair value through profit and loss
Derivative financial instruments designated as hedges		248		207
Other financial assets		53		22
Financial instruments at amortised cost
Hedge collateral (including interest)		-		509
Other financial assets		-		30
Financial instruments at fair value through other comprehensive income
Other financial assets		28		29
Total other financial assets		329		797
Current		209		677
Non-current		120		120
Net carrying amount		329		797
Other financial liabilities
Financial instruments at fair value through profit and loss
Derivative financial instruments designated as hedges		74		721
Embedded derivative		35		-
Total other financial liabilities		109		721
Current		67		654
Non-current		42		67
Net carrying amount		109		721

Recognition and measurement

Other financial assets and liabilities

Receivables subject to provisional pricing adjustments are initially recognised at the transaction price and subsequently measured at fair value with movements recognised in the consolidated income statement.

Derivative financial instruments

Derivative financial instruments that are designated within qualifying hedge relationships are initially recognised at fair value on the date the contract is entered into. For relationships designated as fair value hedges, subsequent fair value movements of the derivative are recognised in the consolidated income statement.

For relationships designated as cash flow hedges, subsequent fair value movements of the derivative for the effective portion of the hedge are recognised in other comprehensive income and accumulated in reserves in equity; fair value movements for the ineffective portion are recognised immediately in the consolidated income statement. Costs of hedging have been separated from the hedging arrangements and deferred to other comprehensive income and accumulated in reserves in equity. Amounts accumulated in equity are reclassified to the consolidated income statement in the periods when the hedged item affects profit or loss.

Hedge effectiveness is determined at the inception of the hedge relationship, and through periodic prospective effectiveness assessments to ensure that an economic relationship exists between the hedged exposure and the hedging instrument. The Group assesses whether the derivative designated in each hedging relationship has been, and is expected to be, effective in offsetting changes in cash flows of the hedged exposure using the hypothetical derivative method.

F-51

Notes to the financial statements D. Other assets and liabilities

for the year ended 31 December 2023

Ineffectiveness is recognised where the cumulative change in the designated component value of the hedging instrument on an absolute basis exceeds the change in value of the hedged exposure attributable to the hedged risk.

Ineffectiveness may arise where the timing of the transaction changes from what was originally estimated such as delayed shipments or changes in timing of forecast sales. This may also arise where the commodity swap pricing terms do not perfectly match the pricing terms of the revenue contracts.

Fair value

Except for the other financial assets and other financial liabilities set out in this note, there are no material financial assets or financial liabilities carried at fair value.

The fair value of commodity derivative financial instruments is determined based on observable quoted forward pricing and swap models and is classified as Level 2 on the fair value hierarchy. The most frequently applied valuation techniques include forward pricing and swap models that use present value calculations. The models incorporate various inputs including the credit quality of counterparties and forward rate curves of the underlying commodity.

The fair value of interest rate swaps is calculated by discounting estimated future cash flows based on the terms of maturity of each contract, using market interest rates for a similar instrument at the reporting date, and is classified as Level 2 on the fair value hierarchy.

The fair value of foreign exchange forward contracts is determined using quoted forward exchange rates at the reporting date and present value calculations based on high credit quality yield curves in the respective currencies and is classified as Level 2 on the fair value hierarchy.

The fair values of other financial assets and other financial liabilities are predominantly determined based on observable quoted forward pricing and are predominantly classified as Level 2 on the fair value hierarchy.

Embedded commodity derivatives are classified as Level 3 on the fair value hierarchy with no market observable inputs.

Foreign exchange

The derivative financial instruments include foreign exchange forward contracts that are denominated in Australian dollars. The Group had no material other financial assets and liabilities denominated in currencies other than US dollars.

Hedging activities

During the period, the following hedging activities were undertaken:

· As at 31 December 2023, the Group hedged approximately 29.3 MMboe of 2024 production at an average price of approximately $75.7 per barrel.

· Through the use of foreign exchange forward contracts, the Group hedged its Australian dollar to US dollar exchange rate in relation to a portion of the Australian dollar denominated capital expenditure expected to be incurred under the Scarborough development.

· In 2022, the Group placed $506 million (excluding interest) as collateral against the oil hedge positions to reduce counterparty credit risk exposure. The collateral was returned to the Group in 2023.

· Through the use of foreign exchange forward contracts, the Group also hedged its Australian dollar to US dollar exchange rate in relation to the Australian dollar denominated tax payments which have matured.

F-52

Notes to the financial statements D. Other assets and liabilities

for the year ended 31 December 2023

	2023		2022
Oil swaps (cash flow hedges)
Carrying amount (US$m)		(14)		(114	)
Notional amount (MMbbl)1		29		18
Maturity date		2024		2023
Hedge ratio		1:1		1:1
Weighted average hedged rate (US$/MMbbl)		76		79
HH Corpus Christi commodity swaps (cash flow hedges)
Carrying amount (US$m)		(44)		26
Notional amount (TBtu)1		38		58
Maturity date		2024-2025		2023-2024
Hedge ratio		1:1		1:1
Weighted average hedged rate (US$/MMBtu)		4		4
TTF Corpus Christi commodity swaps (cash flow hedges)
Carrying amount (US$m)		181		(469	)
Notional amount (TBtu)1		32		50
Maturity date		2024-2025		2023-2024
Hedge ratio		1:1		1:1
Weighted average hedged rate (US$/MMBtu)		18		16
Interest rate swap (cash flow hedges)
Carrying amount (US$m)		43		55
Notional amount (US$m)1		600		600
Maturity date		2027		2027
Hedge ratio		1:1		1:1
Weighted average hedged rate		1.7%		1.7%
Cross currency interest rate swap (cash flow and fair value hedges)
Carrying amount (US$m)		-		5
Notional amount (Swiss Franc)1		-		175
Maturity date		-		2023
Hedge ratio		-		1:1
Weighted average hedged rate		-		Three month USD LIBOR +2.8%
FX forwards (cash flow hedges)
Carrying amount (US$m)		8		(17	)
Notional amount (AUD$m)1		1,834		1,037
Maturity date		2024-2025		2023-2025
Hedge Ratio		1:1		1:1
Weighted average hedged rate (AUD:USD)		0.68		0.68

1. The notional amounts relate to unrealised volumes of the hedge item included in the cash flow hedge reserve.

Hedge ineffectiveness loss of $15 million (2022: $72 million loss) has been recognised in the profit and loss.

Interest Rate Benchmark Reform

A fundamental reform of major interest rate benchmarks is being undertaken globally, including the replacement of some interbank offered rates (IBORs) with alternative nearly risk-free rates (referred to as ‘IBOR reform’). In 2020, the Federal Reserve announced that the three-month and six-month LIBOR will be phased out and eventually replaced by June 2023. The Group had exposures to IBORs on its financial instruments that were impacted as part of these market-wide initiatives.

During the period, the Group has transitioned its financial liabilities from USD London Inter-Bank Offered Rate (USD LIBOR) to SOFR. The transition of a number of the Group’s financial liabilities from USD LIBOR to SOFR during the year ended 31 December 2023 did not result in a material impact to the Group.

Embedded commodity derivative

In 2023, the Group entered into a revised long-term gas sale and purchase contract (GSPA) with Perdaman with conditions precedent being satisfied during the year, where a component of the selling price is linked to the price of urea. The contract has been assessed to contain an embedded commodity derivative that is required to be separated and recognised at fair value through profit and loss. The carrying value of the embedded derivative at 31 December 2023 amounted to a net liability of $35 million (31 December 2022: nil). The derivative is remeasured to fair value at each reporting date in accordance with the Urea price at that date. As at 31 December 2023, the unrealised loss of $35 million has been recognised through other expenses.

F-53

Notes to the financial statements D. Other assets and liabilities

for the year ended 31 December 2023

Key estimates and judgements

(a) Embedded commodity derivative

The fair value of the Perdaman embedded derivative has been estimated using a Monte Carlo simulation model. The assessment requires management to make certain assumptions about the model inputs, including forecast cash flows, discount rate, credit risk and volatility. These assumptions require significant management judgement and are subject to risk and uncertainty. The present value of the embedded derivative was estimated using the assumptions set out below.

· Inflation rate – 2.5% has been applied.

· Discount rate – a pre-tax interest rate curve (range: 5.39% to 7.12%).

· Domestic gas pricing – forecast sales are subject to urea pricing. Price assumptions are based on the best market information available at measurement date and derived from short- and long-term views of global supply and demand, building upon past experience of the industry and consistent with external sources. The long-term urea price is determined with reference to the prevailing gas hub (Title Transfer Facility (TTF)) prices available in the market at reporting date.

The embedded derivative is most sensitive to changes in discount rates and pricing, which may result in unrealised gains or losses recognised in other income/expenses in the future. The nominal impact of the effects of changes to discount rate and long-term price assumptions are estimated as follows:

	Change in assumption1	US$m
	Urea sales price: increase of 10%	145
	Urea sales price: decrease of 10%	(145	)
	Discount rate: increase of 1.5%2	(208	)
	Discount rate: decrease of 1.5%2	258

1. Amounts shown represent the change of the present value of the contract keeping all other variables constant.

2. A change of 1.5% represents 150 basis points.

F-54

Notes to the financial statements D. Other assets and liabilities

for the year ended 31 December 2023

D.7 Leases

	Land and buildings		Plant and equipment		Total
	US$m		US$m		US$m
Lease assets
Year ended 31 December 2023
Carrying amount at 1 January 2023		464		800		1,264
Additions		8		120		128
Transfer to assets held for sale1		-		(3)		(3)
Lease remeasurements		7		184		191
Depreciation		(49)		(301)		(350)
Carrying amount at 31 December 2023		430		800		1,230
At 31 December 2023
Historical cost and remeasurements		600		1,612		2,212
Accumulated depreciation, impairment and disposals		(170)		(812)		(982)
Net carrying amount		430		800		1,230
Lease liabilities
Year ended 31 December 2023
At 1 January 2023		623		1,011		1,634
Additions		24		121		145
Transfer to liabilities directly associated with assets held for sale1		-		(7)		(7)
Repayments (principal and interest)		(78)		(391)		(469)
Accretion of interest		27		75		102
Lease remeasurements		11		199		210
Carrying amount at 31 December 2023		607		1,008		1,615
Current		54		244		298
Non-current		553		764		1,317
Carrying amount at 31 December 2023		607		1,008		1,615
Lease assets
Year ended 31 December 2022
Carrying amount at 1 January 2022		377		703		1,080
Acquisitions through business combination2		120		22		142
Additions		4		238		242
Lease remeasurements		5		103		108
Depreciation		(42)		(266)		(308)
Carrying amount at 31 December 2022		464		800		1,264
At 31 December 2022
Historical cost and remeasurements		591		1,311		1,902
Accumulated depreciation, impairment and disposals		(127)		(511)		(638)
Net carrying amount		464		800		1,264
Lease liabilities
Year ended 31 December 2022
At 1 January 2022		437		930		1,367
Acquisitions through business combination2		245		23		268
Additions		1		189		190
Repayments (principal and interest)		(60)		(305)		(365)
Accretion of interest		25		78		103
Lease remeasurements		(25)		96		71
Carrying amount at 31 December 2022		623		1,011		1,634
Current		48		276		324
Non-current		575		735		1,310
Carrying amount at 31 December 2022		623		1,011		1,634

1. Refer to Note B.8 for details of the sell-down of the Scarborough Joint Venture.

2. Refer to Note B.5 for details of business combination.

F-55

Notes to the financial statements D. Other assets and liabilities

for the year ended 31 December 2023

Recognition and measurement

When a contract is entered into, the Group assesses whether the contract contains a lease. A lease arises when the Group has the right to direct the use of an identified asset which is not substitutable and to obtain substantially all economic benefits from the use of the asset throughout the period of use. The leases recognised by the Group predominantly relate to LNG vessels, property and drilling rigs.

The Group separates the lease and non-lease components of the contract and accounts for these separately. The Group allocates the consideration in the contract to each component on the basis of their relative stand-alone prices.

Leases as a lessee

Lease assets and lease liabilities are recognised at the lease commencement date, which is when the assets are available for use. The assets are initially measured at cost, which is the present value of future lease payments adjusted for any lease payments made at or before the commencement date, plus any make-good obligations and initial direct costs incurred.

Lease assets are depreciated using the straight-line method over the shorter of their useful life and the lease term. Refer to Note B.3 for the useful lives of assets. Periodic adjustments are made for any re-measurements of the lease assets and for impairment losses, assessed in accordance with the Group’s impairment policies.

Lease liabilities are initially measured at the present value of future minimum lease payments, discounted using the Group’s incremental borrowing rate if the rate implicit in the lease cannot be readily determined, and are subsequently measured at amortised cost using the effective interest rate. Minimum lease payments are fixed payments or index-based variable payments incorporating the Group’s expectations of extension options and do not include non-lease components of a contract. A portfolio approach was taken when determining the implicit discount rate for LNG vessels with similar terms and conditions on transition.

The lease liability is remeasured when there are changes in future lease payments arising from a change in rates, index or lease terms from exercising an extension or termination option. A corresponding adjustment is made to the carrying amount of the lease assets, with any excess recognised in the consolidated income statement.

There are no restrictions placed upon the lessee by entering into these leases.

Short-term leases and leases of low value

Short-term leases (lease term of 12 months or less) and leases of low value assets are recognised as incurred as an expense in the consolidated income statement. Low value assets comprise plant and equipment.

Foreign exchange risk

The Group held $447 million of lease liabilities at 31 December 2023 (2022: $441 million) in currencies other than the US dollar (predominantly Australian dollars).

F-56

Notes to the financial statements D. Other assets and liabilities

for the year ended 31 December 2023

Maturity profile of lease liabilities

The table below presents the contractual undiscounted cash flows associated with the Group’s lease liabilities, representing principal and interest. The figures will not necessarily reconcile with the amounts disclosed in the consolidated statement of financial position.

	2023        US$m	2022       US$m
Due for payment in:
1 year or less	415	433
1-2 years	240	272
2-3 years	194	199
3-4 years	180	186
4-5 years	181	176
More than 5 years	1,032	966
	2,242	2,232

Lease commitments

The table below presents the contractual undiscounted cash flows associated with the Group’s future lease commitments for non-cancellable leases not yet commenced, representing principal and interest.

	2023       US$m	2022      US$m
Due for payment in:
Within one year	33	67
After one year but not more than five years	889	263
Later than five years	1,242	1,288
	2,164	1,618

Payments of $121 million (2022: $162 million) for short-term leases (lease term of 12 months or less) and payments of $12 million (2022: $12 million) for leases of low value assets were expensed in the consolidated income statement. Total payments for leases in the consolidated statement of cash flows are $575 million (2022: $525 million), with $361 million (2022: $258 million) included in financing activities.

The Group has short-term and low value lease commitments for marine vessels and carriers, property, drill rigs and plant and equipment contracted for, but not provided for in the financial statements, of $232 million (2022: $60 million).

Key estimates and judgements

(a) Control

Judgement is required to assess whether a contract is or contains a lease at inception by assessing whether the Group has the right to direct the use of the identified asset and obtain substantially all the economic benefits from the use of that asset.

(b) Lease term

Judgement is required when assessing the term of the lease and whether to include optional extension and termination periods. Option periods are only included in determining the lease term at inception when they are reasonably certain to be exercised.

Lease terms are reassessed when a significant change in circumstances occurs. On this basis, possible additional lease payments amounting to $2,000 million (2022: $2,323 million) were not included in the measurement of lease liabilities.

(c) lnterest in joint arrangements

Judgement is required to determine the Group’s rights and obligations for lease contracts within joint operations, to assess whether lease liabilities are recognised gross (100%) or in proportion to the Group’s participating interest in the joint operation. This includes an evaluation of whether the lease arrangement contains a sublease with the joint operation.

(d) Discount rates

Judgement is required to determine the discount rate, where the discount rate is the Group’s incremental borrowing rate if the rate implicit in the lease cannot be readily determined. The incremental borrowing rate is determined with reference to the Group’s borrowing portfolio at the inception of the arrangement or the time of the modification.

F-57

Notes to the financial statements E. Other items

for the year ended 31 December 2023

In this section

This section includes Group structure information and other disclosures.

E.	Other items
E.1	Contingent liabilities and assets	Page F-59
E.2	Employee benefits	Page F-59
E.3	Related party transactions	Page F-61
E.4	Auditor remuneration	Page F-61
E.5	Events after the end of the reporting period	Page F-61
E.6	Joint arrangements	Page F-61
E.7	Parent entity information	Page F-63
E.8	Subsidiaries	Page F-63
E.9	Other accounting policies	Page F-67

F-58

Notes to the financial statements E. Other items

for the year ended 31 December 2023

E.1 Contingent liabilities and assets

	2023 US$m		2022 US$m
Contingent liabilities at reporting date
Contingent liabilities		260		161
Guarantees		2		2
		262		163

Contingent liabilities relate predominantly to possible obligations whose existence will only be confirmed by the occurrence or non-occurrence of uncertain future events, and therefore the Group has not provided for such amounts in these financial statements. The Group operates in complex tax and legislative regimes. The amounts disclosed above include estimates made in relation to ongoing disputes with various tax and government authorities. Assessing a value of contingent liabilities requires a high degree of judgement. The contingent liabilities relating to tax matters are estimated based on notices received from authorities before interest and penalties. The possibility of further claims related to the same matters cannot be ruled out and the judicial processes may take extended periods to conclude. Additionally, there are a number of other claims and possible claims that have arisen in the course of business against entities in the Group, the outcome of which cannot be estimated at present and for which no amounts have been included in the table above.

The Group has contingent assets of $47 million as at 31 December 2023 (2022: $199 million).

E.2 Employee benefits

	2023 US$m		2022 US$m		2021 US$m
Employee benefits		494		415		217
Share-based payments		39		26		12
Defined contribution plan costs		53		41		26
Defined benefit plan expense		17		9		1
		603		491		256

(a) Employee benefits

Employee benefits for the reporting period are as follows:

Recognition and measurement

The Group’s accounting policy for employee benefits other than superannuation is set out in Note D.5. The policy relating to share-based payments is set out in Note E.2(c).

All employees of the Group are entitled to benefits on retirement, disability or death from the Group’s retirement plans. The Group operates a number of pension schemes throughout the world. Employees entitled to defined contribution schemes receive fixed contributions from Group companies and the Group’s legal or constructive obligation is limited to these contributions. Contributions to defined contribution funds are recognised as an expense as they become payable. Prepaid contributions are recognised as an asset to the extent that a cash refund or a reduction in the future payment is available.

(b) Compensation of key management personnel

Key management personnel (KMP) compensation for the financial year was as follows:

	2023 US$		2022 US$		2021 US$
Short-term employee benefits1		5,245,763		5,730,340		6,626,354
Post-employment benefits1		215,856		155,086		88,396
Share-based payments2		3,693,072		3,114,043		5,697,529
Long-term employee benefits		213,562		4,300		717,223
Termination benefits		-		152,531		2,447,525
		9,368,253		9,156,300		15,577,027

1. In the prior reporting period, the 2021 comparatives for short-term employee benefits and post-employment benefits were restated to include the superannuation component of the 2021 EIS cash and other cash bonuses for three key management personnel, increasing the short-term employee benefits expense by $26,676 to $6,626,354 and the post-employee benefits expense by $10,881 to $88,396.

2. In the prior reporting period, the 2021 comparative for share-based payments was restated to include amortisation of the fair value of 2021 performance rights for two key management personnel, increasing the expense by $88,507 to $5,697,529.

(c) Share plans

The Group provides benefits to its employees (including KMP) in the form of share-based payments (equity-settled transactions).

Woodside equity plan (WEP) and supplementary Woodside equity plan (SWEP)

The WEP is available to all permanent employees, but since 1 January 2018 has excluded Executive Incentive Scheme (EIS) participants. The number of Equity Rights (ERs) offered to each eligible employee is determined by the Board, and based on individual performance as assessed under the performance review process. The linking of performance to an allocation allows the Group to recognise and reward eligible employees for high performance. The ERs have no further ongoing performance conditions after allocation, and do not require participants to make any payment in respect of the ERs at grant or at vesting. Each ER entitles the participant to receive a Woodside share on the vesting date three years after the grant date.

F-59

Notes to the financial statements E. Other items

for the year ended 31 December 2023

For awards made in 2023 and 2022, participants are entitled to receive a Woodside share on the vesting date, three years after the grant date. Awards made in 2021 will vest under the terms of the plan at that time, which provided for 75% vesting of the ERs three years after the grant date and the remaining 25% of the ERs five years after the grant date.

In October 2011, the Board approved the establishment of the SWEP to enable the offering of targeted retention awards of ERs for key capability. The SWEP was updated in 2022 to broaden eligibility to all employees of a subsidiary of Woodside Energy Group Ltd and ensure compliance in all jurisdictions in which Woodside operates. This facilitated the offer of replacement unvested incentives, as required under transitional arrangements for eligible heritage BHP employees transitioning from BHP Group Long-Term Incentive (LTI) plans to VAR offered under Woodside’s VAR arrangements.

Each ER entitles the participant to receive a Woodside share on vesting date. Participants do not make any payment in respect of the ERs at grant or at vesting. 

Executive Incentive Scheme (EIS)

The EIS was introduced for the 2018 performance year for all Executives including Executive KMP. The EIS is delivered in the form of a cash incentive, Restricted Shares and Performance Rights. The grant date of the Restricted Shares and Performance Rights has been determined to be subsequent to the performance year, being the date of the Board of Directors’ approval. Accordingly, the 2022 Restricted Shares and Performance Rights were granted on 27 February 2023 for Executives and 28 April 2023 for the CEO and have been included in the table below. The expense estimated as at 31 December 2022 in relation to the 2022 performance year was updated to the fair value on grant date during the period.

The 2023 Restricted Shares and Performance Rights have not been included in the table below as they have not been approved as at 31 December 2023. An expense related to the 2023 performance year has been estimated for the Restricted Shares and Performance Rights, using fair value estimates based on inputs at 31 December 2023.

Performance Based Pay Plus (PBP Plus)

PBP Plus is available to senior, permanent employees who are not Executives. Participants receive an annual award of cash and Restricted Shares based on corporate and individual performance, recognising and rewarding eligible employees for high performance.

The grant date of the Restricted Shares has been determined to be subsequent to the performance year, being the date of the Board of Directors’ approval. Accordingly, the 2022 Restricted Shares were granted on 27 February 2023 and have been included in the table below. The expense estimated as at 31 December 2022 in relation to the 2022 performance year was updated to the fair value on grant date during the period.

The 2023 Restricted Shares have not been included in the table below as they have not been approved as at 31 December 2023. An expense related to the 2023 performance year has been estimated for the Restricted Shares, using fair value estimates based on inputs at 31 December 2023.

Recognition and measurement

All compensation under WEP, SWEP, PBP Plus and EIS Restricted Shares and Performance Rights is accounted for as share-based payments to employees for services provided. The cost of equity-settled transactions with employees is measured by reference to the fair values of the equity instruments at the date at which they are granted. The fair value of share-based payments is recognised, together with the corresponding increase in equity, over the period in which the vesting conditions are fulfilled, ending on the date on which the relevant employee becomes fully entitled to the shares. At each balance sheet date, the Group reassesses the number of awards that are expected to vest based on service conditions. The expense recognised each year takes into account the most recent estimate.

The fair value of the benefit provided for the WEP and SWEP is estimated using the Black-Scholes option pricing technique.

The fair value of the Restricted Shares is estimated as the closing share price at grant date. The fair value of the benefit provided for the relative total shareholder return Performance Rights is calculated using the Binomial or Black-Scholes option pricing technique combined with a Monte Carlo simulation methodology, where relevant, using historical volatility to estimate the volatility of the share price in the future.

The number of awards and movements for all share plans are summarised as follows:

	Number of performance awards
	Employee plans						Executive plans
	WEP			SWEP			STA4			LTA4
Year ended 31 December 2023
Opening balance		6,629,681			2,884,076			993,197			2,554,422
Granted during the year1,2,3		3,445,234			100,811			420,429			658,969
Vested during the year		(600,271	)		(1,071,291	)		(286,979	)		(106,430	)
Forfeited during the year		(349,204	)		(357,023	)		(60,410	)		(410,409	)
Awards at 31 December 2023		9,125,440			1,556,573			1,066,237			2,696,552
		US$m			US$m			US$m			US$m
Fair value of awards granted during the year		60			2			10			12

F-60

Notes to the financial statements E. Other items

for the year ended 31 December 2023

	Number of performance awards
	Employee plans						Executive plans
	WEP			SWEP			STA4			LTA4
Year ended 31 December 2022
Opening balance		5,649,783			-			994,436			2,379,220
Granted during the year1,2,3		3,017,366			3,046,963			495,800			764,171
Vested during the year		(1,498,065	)		(38,146	)		(450,609	)		(191,736	)
Forfeited during the year		(539,403	)		(124,741	)		(46,430	)		(397,233	)
Awards at 31 December 2022		6,629,681			2,884,076			993,197			2,554,422
		US$m			US$m			US$m			US$m
Fair value of awards granted during the year		49			60			9			13

1. For the purpose of valuation, the share price on grant date for the 2023 WEP allocations was $17.54 (2022: $16.30).

2. For the purpose of valuation, the share price on grant date for the 2023 SWEP allocations was $20.78 (2022: $19.74).

3. For the purpose of valuation, the share price on grant date for Restricted Shares was $23.48 and $23.33 (2022: $19.20 and $19.27) and Performance Rights was $15.96 (2022: $13.08 and $13.71).

4. Includes awards issued under Executive Incentive Plan (EIP), EIS and PBP Plus. 

For more detail on these share plans and Performance Rights issued to KMPs, refer to the Remuneration Report.

E.3 Related party transactions

The Group’s related party transactions are predominantly with associates of the Group. During the period, the transactions with related parties include purchases of goods/services of $71,407 thousand (2022: $60,730 thousand), sale of goods/services of $27,142 thousand (2022: $18,527 thousand) and dividend income of $15,296 thousand (2022: $8,294 thousand). As at 31 December 2023, the total amounts owing to related parties is $1,559 thousand (2022: $1,686 thousand) and amounts owing from related parties is $1,960 thousand (2022: $2,200 thousand). All transactions to/from related parties are made at arm’s length (normal market rates and on normal commercial terms).

There were no transactions with directors during the year. Key management personnel compensation is disclosed in Note E.2(b).

E.4 Auditor remuneration

Note not required for the purposes of US reporting.

E.5 Events after the end of the reporting period

On 23 February 2024, Woodside and JERA Scarborough Pty Ltd (JERA) entered into a Sale and Purchase agreement for JERA to acquire 15.1% participating interest in the Scarborough Joint Venture. The purchase price is $740 million. JERA will also reimburse Woodside for its share of expenditure for the Scarborough project from the effective date of 1 January 2022.

Subject to the satisfaction of conditions precedent, the transaction is expected to complete in the second half of 2024. The full financial effect of the transaction is still being assessed. The Scarborough Joint Venture is included in the Australia segment.

E.6 Joint arrangements

(a) Interest percentage in joint ventures

		Group Interest %
Entity	Principal activity	2023		2022
North West Shelf Gas Pty Ltd	Contract administration services for venturers for LNG sales to Japan. Marketing and administration services for venturers for gas processing.		33.3		33.3
North West Shelf Liaison Company Pty Ltd	Liaison for ventures in the sale of LNG to the Japanese market.		33.3		33.3
China Administration Company Pty Ltd	Contract administration services for venturers for LNG sales to China.		33.3		33.3
North West Shelf Shipping Service Company Pty Ltd	LNG vessel fleet advisor.		33.3		33.3
North West Shelf Lifting Coordinator Pty Ltd	Allocating, scheduling and administering the lifting of LNG and pipeline gas.		33.3		33.3

F-61

Notes to the financial statements E. Other items

for the year ended 31 December 2023

(b) Interest percentage in joint operations

	Group Interest %
	2023		2022
Producing and developing assets
Australia
North West Shelf		25.0 - 66.7		25.0 - 66.7
Greater Enfield and Vincent		60.0		60.0
Balnaves		65.0		65.0
Pluto		90.0		90.0
Wheatstone		13.0 - 65.0		13.0 - 65.0
Bass Strait		25.0 - 50.0		25.0 - 50.0
Macedon		71.4		71.4
Pyrenees		40.0 - 71.4		40.0 - 71.4
Griffin		45.0 - 71.0		45.0 - 71.0
Minerva		90.0		90.0
International
Sangomar		82.0		82.0
Atlantis		44.0		44.0
Mad Dog		23.9		23.9
Shenzi		72.0		72.0
Trion		60.0		60.0
Greater Angostura		45.0 - 68.5		45.0 - 68.5
Calypso		70.0		70.0
Exploration and evaluation assets
Oceania
Browse Basin		30.6		30.6
Carnarvon Basin		31.6 - 70.0		31.6 - 70.0
Bonaparte Basin		26.7 - 35.0		26.7 - 35.0
Africa
Congo		22.5		22.5
Senegal		90.0		90.0
Egypt		25.0 - 45.0		25.0 - 45.0
Americas
US Gulf of Mexico1		23.9 - 75.0		23.9 - 75.0
Kitimat		50.0		50.0
Asia
Republic of Korea2		-		50.0
Myanmar3		45.0		40.0 - 45.0
Caribbean
Barbados		60.0		60.0
Trinidad & Tobago4		70.0		65.0 - 70.0
Other joint operations
Angel		20.0		20.0
Bonaparte Basin		21.0		21.0

1. The Group relinquished permits GC 520, GC564, AC 39, AC 127 and AC170 in 2023

2. The Group relinquished permits 8 and 6-1N in 2023.

3. The Group relinquished permit A-6 in 2023.

4. The Group relinquished permit TTDA-5 in 2023.

The principal activities of the joint operations are exploration, development and production of hydrocarbons.

F-62

Notes to the financial statements E. Other items

for the year ended 31 December 2023

Key estimates and judgements

(a) Accounting for interests in other entities

Judgement is required in assessing the level of control obtained in a transaction to acquire an interest in another entity. Depending upon the facts and circumstances in each case, Woodside may obtain control, joint control or significant influence over the entity or arrangement. Judgement is applied when determining the relevant activities of a project and if joint control is held over it.

Relevant activities include, but are not limited to, work program and budget approval, investment decision approval, voting rights in joint operating committees, amendments to permits and changes to joint arrangement participant holdings. Transactions which give Woodside control of a business are business combinations. If Woodside obtains joint control of an arrangement, judgement is also required to assess whether the arrangement is a joint operation or a joint venture. If Woodside has neither control nor joint control, it may be in a position to exercise significant influence over the entity, which is then accounted for as an associate.

Recognition and measurement

Joint arrangements are arrangements in which two or more parties have joint control. Joint control is the contractual agreed sharing of control of the arrangement which exists only when decisions about the relevant activities require unanimous consent of the parties sharing control. Joint arrangements are classified as either a joint operation or joint venture, based on the rights and obligations arising from the contractual obligations between the parties to the arrangement.

To the extent the joint arrangement provides the Group with rights to the individual assets and obligations arising from the joint arrangement, the arrangement is classified as a joint operation, and as such the Group recognises its:

· assets, including its share of any assets held jointly;

· liabilities, including its share of any liabilities incurred jointly;

· revenue from the sale of its share of the output arising from the joint operation;

· share of revenue from the sale of the output by the joint operation; and expenses, including its share of any expenses incurred jointly.

To the extent the joint arrangement provides the Group with rights to the net assets of the arrangement, the investment is classified as a joint venture and accounted for using the equity method.

Joint arrangements acquired which are deemed to be carrying on a business are accounted for applying the principles of IFRS 3 Business Combinations. Joint arrangements which are not deemed to be carrying on a business are treated as asset acquisitions.

E.7 Parent entity information

Note not required for the purposes of US reporting.

E.8 Subsidiaries

(a) Subsidiaries

Name of entity	Country of incorporation19		Notes
Ultimate Parent Entity
Woodside Energy Group Ltd		Australia		(1,2,3	)
Subsidiaries
Company name
Woodside Energy Ltd		Australia		(2,3,4	)
Woodside Browse Pty Ltd		Australia		(2,4	)
Woodside Burrup Pty Ltd		Australia		(2,3,4	)
Burrup Facilities Company Pty Ltd		Australia		(5	)
Burrup Train 1 Pty Ltd		Australia		(5	)
Pluto LNG Pty Ltd		Australia		(5	)
Woodside Burrup Train 2 A Pty Ltd		Australia		(2,4	)
Woodside Burrup Train 2 B Pty Ltd		Australia		(2,4	)
Woodside Energy (LNG Fuels and Power) Pty Ltd		Australia		(2,4	)
Woodside Energy (Domestic Gas) Pty Ltd		Australia		(2,4	)

F-63

Notes to the financial statements E. Other items

for the year ended 31 December 2023

Name of entity	Country of incorporation19		Notes
Woodside Energy (Algeria) Pty Ltd		Australia		(2,4	)
Woodside Energy Australia Asia Holdings Pte Ltd		Singapore		(4	)
Woodside Energy Holdings International Pty Ltd		Australia		(2,4	)
Woodside Energy International (Canada) Limited		Canada		(4	)
Woodside Energy (Canada LNG) Limited		Canada		(4	)
Woodside Energy (Canada PTP) Limited		Canada		(4	)
KM LNG Operating General Partnership		Canada		(9	)
KM LNG Operating Ltd		Canada		(4	)
Woodside Energy Holdings Pty Ltd		Australia		(2,3,4	)
Woodside Energy Holdings (USA) Inc		United States		(4	)
Woodside Energy (USA) Inc		United States		(4	)
Gryphon Exploration Company		United States		(4	)
PT Woodside Energy Indonesia		Indonesia		(6	)
Woodside Energy (Cameroon) SARL		Cameroon		(4	)
Woodside Energy (Gabon) Pty Ltd		Australia		(2,4	)
Woodside Energy (Indonesia) Pty Ltd		Australia		(2,4	)
Woodside Energy (Indonesia II) Pty Ltd		Australia		(2,4	)
Woodside Energy (Malaysia) Pty Ltd		Australia		(2,4	)
Woodside Energy (Ireland) Pty Ltd		Australia		(2,4	)
Woodside Energy (Korea) Pte Ltd		Singapore		(4	)
Woodside Energy (Korea II) Pte Ltd		Singapore		(4	)
Woodside Energy (Myanmar) Pte Ltd		Singapore		(4	)
Woodside Energy (Morocco) Pty Ltd		Australia		(2,4	)
Woodside Energy (New Zealand) Limited		New Zealand		(4	)
Woodside Energy Holdings (New Zealand) Limited		New Zealand		(4	)
Woodside Energy (Peru) Pty Ltd		Australia		(2,4	)
Woodside Energy (Senegal) Pty Ltd		Australia		(2,4	)
Woodside Energy (Tanzania) Limited		Tanzania		(7	)
Woodside Energy Holdings II Pty Ltd		Australia		(2,4	)
Woodside Power Pty Ltd		Australia		(2,4	)
Woodside Power (Generation) Pty Ltd		Australia		(2,4	)
Woodside Energy Holdings (South America) Pty Ltd		Australia		(2,4	)
Woodside Energia (Brasil) Apoio Administrativo Ltda		Brazil		(8	)
Woodside Energy Holdings (UK) Pty Ltd		Australia		(2,4	)
Woodside Energy (UK) Limited		United Kingdom		(4	)
Woodside Energy Finance (UK) Limited		United Kingdom		(4	)
Woodside Energy (Congo) Limited		United Kingdom		(4	)
Woodside Energy (Bulgaria) Limited		United Kingdom		(4	)
Woodside Energy Holdings (Senegal) Limited		United Kingdom		(4	)
Woodside Energy (Senegal) B.V.		Netherlands		(4	)
Woodside Energy (France) SAS		France		(4	)
Woodside Energy Iberia S.A.		Spain		(4	)
Woodside Energy (N.A.) Limited		United Kingdom		(4	)
Woodside Energy Services (Qingdao) Co Ltd		China		(4	)
Woodside Energy Julimar Pty Ltd		Australia		(2,3,4	)
Woodside Energy (Norway) Pty Ltd		Australia		(2,4	)
Woodside Energy Technologies Pty Ltd		Australia		(2,4,14	)
Woodside Technology Solutions Pty Ltd		Australia		(2,4	)
Woodside Energy Scarborough Pty Ltd		Australia		(2,3,4	)
Woodside Energy Carbon Holdings Pty Ltd		Australia		(2,4	)
Woodside Energy Carbon (Assets) Pty Ltd		Australia		(2,4	)
Woodside Energy Carbon (Services) Pty Ltd		Australia		(2,4	)
Woodside Energy (Financial Advisory Services) Pty Ltd		Australia		(2,4	)
Woodside Energy Trading Singapore Pte Ltd		Singapore		(4	)
WelCap Insurance Pte Ltd		Singapore		(4	)
Woodside Energy Shipping Singapore Pte Ltd		Singapore		(4	)
Metasource Pty Ltd		Australia		(2,4	)
Mermaid Sound Port and Marine Services Pty Ltd		Australia		(2,4	)
Woodside Finance Limited		Australia		(2,4	)
Woodside Petroleum (Timor Sea 19) Pty Ltd		Australia		(2,4	)

F-64

Notes to the financial statements E. Other items

for the year ended 31 December 2023

Name of entity	Country of incorporation19		Notes
Woodside Petroleum (Timor Sea 20) Pty Ltd		Australia		(2,4	)
Woodside Petroleum Holdings Pty Ltd		Australia		(2,4,15	)
Woodside Energy Global Holdings Pty Ltd		Australia		(2,3,4	)
Woodside Energy Global Pty Ltd		Australia		(2,3,4	)
Perdido Mexico Pipeline Holdings, S.A. de C.V.		Mexico		(10	)
Perdido Mexico Pipeline, S. de R.L. de C.V.		Mexico		(10	)
Woodside Energy Investments Pty Ltd		Australia		(2,4	)
Woodside Energia Brasil Investimentos Ltda.		Brazil		(11	)
Woodside Energia Brasil Exploração e Produção Ltda.		Brazil		(11	)
Woodside Energy (Great Britain) Limited		United Kingdom		(4	)
Woodside Energy (North West Shelf) Pty Ltd		Australia		(2,3,4	)
Woodside Energy (Trinidad) Holdings Ltd		Saint Lucia		(4	)
Woodside Energy (Trinidad-3A) Ltd		R. of Trinidad and Tobago		(4	)
Woodside Energy USA Operations Inc		United States		(12	)
Hamilton Brothers Petroleum Corporation		United States		(4	)
Hamilton Oil Company LLC		United States		(4	)
Woodside Energy Boliviana Inc.		United States		(4	)
Woodside Energy (North America) LLC		United States		(4	)
Woodside Energy (Americas) Inc.		United States		(4	)
Woodside Energy (GOM) Inc.		United States		(4	)
Woodside Energy Hawaii Inc.		United States		(4,16	)
Woodside Energy Resources Inc.		United States		(4	)
Woodside Energy Holdings (Resources) Inc.		United States		(4	)
Woodside Energy USA Services Inc.		United States		(4	)
Woodside Energy Marketing Inc.		United States		(4	)
Woodside Energy (Deepwater) Inc.		United States		(4,17	)
Woodside Energy (USA New Energy Holdings) LLC		United States		(4,18	)
Woodside Energy (H2 Oklahoma) LLC		United States		(4,18	)
Woodside Energy (Foreign Exploration Holdings) LLC		United States		(4	)
Woodside Energy (Trinidad Block 3) Limited		United Kingdom		(4	)
Woodside Energy (Trinidad Block 5) Limited		United Kingdom		(4	)
Woodside Energy (Trinidad Block 6) Limited		United Kingdom		(4	)
Woodside Energy (Trinidad Block 7) Limited		United Kingdom		(4	)
Woodside Energy (Trinidad Block 14) Limited		United Kingdom		(4	)
Woodside Energy (Trinidad Block 23A) Limited		United Kingdom		(4	)
Woodside Energy (Trinidad Block 23B) Limited		United Kingdom		(4	)
Woodside Energy (Trinidad Block 28) Limited		United Kingdom		(4	)
Woodside Energy (Trinidad Block 29) Limited		United Kingdom		(4	)
Woodside Energy (Bimshire) Limited		United Kingdom		(4	)
Woodside Energy (South Africa 3B/4B) Limited		United Kingdom		(4	)
Woodside Energy (Egypt) Limited		United Kingdom		(4	)
Woodside Energy (Carlisle Bay) Limited		United Kingdom		(4	)
Woodside Energy (Mexico) Limited		United Kingdom		(4	)
Woodside Energía Servicios Administrativos,S. de R.L. de C.V.		Mexico		(13	)
Woodside Energía Servicios de México, S. de R.L. de C.V.		Mexico		(13	)
Woodside Energy (Mexico Holdings) LLC		United States		(4	)
Operaciones Conjuntas, S. de R.L. de C.V.		Mexico		(13	)
Woodside Energía Holdings de México, S. de R.L. de C.V.		Mexico		(13	)
Woodside Petróleo Operaciones de México, S. de R.L. de C.V.		Mexico		(13	)
Woodside Energy (Australia) Pty Ltd		Australia		(2,3,4	)
Woodside Energy (International Exploration) Pty Ltd		Australia		(2,4	)
Woodside Energy (Bass Strait) Pty Ltd		Australia		(2,3,4	)
Woodside Energy (Victoria) Pty Ltd		Australia		(2,4	)
Woodside Energy Holdings LLC		United States		(2,4,19	)
Woodside Energy (Trinidad-2C) Ltd		Canada		(4	)
Woodside Energy (Canada) Corporation		Canada		(4	)

1. Woodside Energy Group Ltd is the ultimate holding company and the head entity within the tax consolidated group.

2. These companies were members of the Australian tax consolidated group at 31 December 2023.

F-65

Notes to the financial statements E. Other items

for the year ended 31 December 2023

3. For the year ended 31 December 2022, Woodside Energy Group Ltd and Woodside Energy Ltd were parties to a Deed of Cross Guarantee. In November 2023, Revocations Deeds were entered into with respect to the previous Deed of Cross Guarantee (with the revocation to take effect in May 2024). In December 2023, a new Deed of Cross Guarantee was entered into between Woodside Energy Group Ltd, Woodside Energy Ltd, Woodside Energy Global Holdings Pty Ltd, Woodside Burrup Pty Ltd, Woodside Energy Julimar Pty Ltd, Woodside Energy Scarborough Pty Ltd, Woodside Energy Holdings Pty Ltd, Woodside Energy Global Pty Ltd, Woodside Energy (Australia) Pty Ltd, Woodside Energy (Bass Strait) Pty Ltd and Woodside Energy (North West Shelf) Pty Ltd.

4. All subsidiaries are wholly owned except those referred to in Notes 5 to 13.

5. Kansai Electric Power Australia Pty Ltd and Tokyo Gas Pluto Pty Ltd each hold a 5% interest in the shares of these subsidiaries. These subsidiaries are controlled.

6. As at 31 December 2023, Woodside Energy Holdings Pty Ltd held a 99% interest in the shares of PT Woodside Energy Indonesia. Woodside Energy Ltd held the remaining 1% interest.

7. As at 31 December 2023, Woodside Energy Holdings Pty Ltd held >99.99% interest in the shares of Woodside Energy (Tanzania) Limited and Woodside Energy Ltd held the remaining interest.

8. As at 31 December 2023, Woodside Energy Holdings (South America) Pty Ltd held >99.99% interest in the shares of Woodside Energia (Brasil) Apoio Administrativo Ltda and Woodside Energy Ltd held the remaining interest.

9. As at 31 December 2023, Woodside Energy International (Canada) Limited and Woodside Energy (Canada LNG) Limited were the general partners of the KM LNG Operating General Partnership holding a 99.99% and 0.01% partnership interest, respectively.

10. As at 31 December 2023, Woodside Energy Global Holdings Pty Ltd held a 99.99% interest in shares of Perdido Mexico Pipeline Holdings, S.A. de C.V. and Perdido Mexico Pipeline, S. de R.L. de C.V. Woodside Energy Investments Pty Ltd held the remaining 0.01% interest.

11. As at 31 December 2023, Woodside Energy Investments Pty Ltd held a 99.97% interest in shares of Woodside Energia Brasil Investimentos Ltda. Woodside Energy Global Holdings Pty Ltd held the remaining 0.03% interest. As at 31 December 2023, Woodside Energia Brasil Investimentos Ltda. held >99.99% interest in shares of Woodside Energia Brasil Exploração e Produção Ltda. Woodside Energy Global Holdings Pty Ltd held the remaining interest.

12. As at 31 December 2023, Woodside Energy Global Holdings Pty Ltd held 90% voting interest and 37.67% interest in shares of Woodside Energy USA Operations Inc. Woodside Energy Holdings LLC held the remaining 10% voting interest and 62.33% interest in shares.

13. As at 31 December 2023, Woodside Energy (Mexico) Limited held a 99% interest in shares of Woodside Energía Servicios Administrativos, S. de R.L. de C.V., Woodside Energía Servicios de México, S. de R.L. de C.V., Operaciones Conjuntas, S. de R.L. de C.V. and Woodside Petróleo Operaciones de México, S. de R.L. de C.V. and 99.99% interest in shares of Woodside Energía Holdings de México, S. de R.L. de C.V. Woodside Energy (Mexico Holdings) LLC held the remaining 0.01%-1% interest.

14. As at 31 December 2023, Woodside Energy Technologies Pty Ltd held 28.5% of the shares in Blue Ocean Seismic Services Limited which is accounted for as an investment in associate.

15. As at 31 December 2023, Woodside Energy (North West Shelf) Pty Ltd and Woodside Petroleum Holdings Pty Ltd each held 16.67% of the shares in International Gas Transportation Company Limited. This investment has been accounted for as an investment in associate.

16. As at 31 December 2023, Woodside Energy Hawaii Inc held 14.96% of the shares in Iwilei District Participating Parties LLC which is accounted for as an investment in associate.

17. As at 31 December 2023, Woodside Energy (Deepwater) Inc held 25% of the shares in Caesar Oil Pipeline Company LLC, 22% of the shares in Cleopatra Gas Gathering Company LLC and 10% of the shares in Marine Well Containment Company LLC. These are accounted for as investments in associates.

18. Woodside Energy (USA New Energy Holdings) LLC and Woodside Energy (H2 Oklahoma) LLC were incorporated on 1 August 2023.

19. All subsidiaries are tax residents in their place of incorporation.

Classification

Subsidiaries are all the entities over which the Group has the power over the investee such that the Group is able to direct the relevant activities, has exposure, or rights, to variable returns from its involvement with the investee and has the ability to use its power over the investee to affect the amount of the investor’s returns.

(b) Subsidiaries with material non-controlling interests

The Group has two Australian subsidiaries with material non-controlling interests (NCI).

Name of entity	Principal place of business	% held by NCI
Burrup Facilities Company Pty Ltd	Australia		10%
Burrup Train 1 Pty Ltd	Australia		10%

The NCI in both subsidiaries is 10% held by the same parties (refer to Note E.8(a) footnote 5 for details).

The summarised financial information (including consolidation adjustments but before intercompany eliminations) of subsidiaries with material NCI is as follows:

	2023		2022		2021
	US$m		US$m		US$m
Burrup Facilities Company Pty Ltd
Current assets		513		567		518
Non-current assets		5,020		5,047		5,038
Current liabilities		(58)		(68)		(71)
Non-current liabilities		(568)		(528)		(528)
Net assets		4,907		5,018		4,957
Accumulated balance of NCI		491		502		496
Revenue		839		889		858
Profit		400		489		328
Profit allocated to NCI		40		49		33
Dividends paid to NCI		(51)		(43)		(40)
Operating		570		601		633
Investing		(58)		(45)		(111)
Financing		(512)		(556)		(522)
Net increase/(decrease) in cash and cash equivalents		-		-		-
Burrup Train 1 Pty Ltd
Current assets		453		429		435
Non-current assets		2,806		2,900		2,915
Current liabilities		(121)		(119)		(110)
Non-current liabilities		(341)		(325)		(345)
Net assets		2,797		2,885		2,895
Accumulated balance of NCI		280		289		290
Revenue		1,393		1,471		1,421
Profit		222		282		200
Profit allocated to NCI		22		28		20
Dividends paid to NCI		(31)		(29)		(27)
Operating		321		391		393
Investing		(80)		(55)		(4)
Financing		(241)		(336)		(389)
Net increase/(decrease) in cash and cash equivalents		-		-		-

F-66

Notes to the financial statements E. Other items

for the year ended 31 December 2023

(c) Deed of Cross Guarantee and Closed Group

Note not required for the purposes of US reporting.

E.9 Other accounting policies

(a) Summary of other material accounting policies 

Australia tax consolidation

The parent and its wholly owned Australian controlled entities have elected to enter a tax consolidation, with Woodside Energy Group Ltd as the head entity of the tax consolidated group. The members of the Australian tax consolidated group are identified in Note E.8(a).

The tax expense/benefit, deferred tax liabilities and deferred tax assets arising from temporary differences of the members of the tax consolidated group are recognised in the separate financial statements of the members of the tax consolidated group, using the stand-alone approach.

Entities within the tax consolidated group have entered into a tax funding arrangement and a tax sharing agreement with the head entity. Under the tax funding agreement, Woodside Energy Group Ltd and each of the entities in the tax consolidated group have agreed to pay or receive a tax equivalent payment to or from the head entity, based on the current tax liability or current tax asset of the entity.

The tax sharing agreement entered into between members of the tax consolidated group provides for the determination of the allocation of income tax liabilities between the entities, should the head entity default on its tax payment obligations. No amounts have been recognised in the financial statements in respect of this agreement as payment of any amounts under the tax sharing agreement is considered remote.

US tax consolidation

Woodside Energy USA Operations Inc and its wholly owned USA controlled entities have elected to file a consolidated tax return, with Woodside Energy USA Operations Inc as the parent of the tax consolidated group.

The tax expense/benefit, deferred tax liabilities and deferred tax assets arising from temporary differences of the members of the tax consolidated group are computed on a separate company basis.

Entities within the tax consolidated group have entered into a tax sharing agreement. Under the tax sharing agreement, the tax liability for the consolidated group or the utilisation of tax attributes are settled periodically between the members of the group. No amounts have been recognised in the financial statements in respect of this agreement as payment of any amounts under the tax sharing agreement is considered remote.

(b) New standards and interpretations

New and amended accounting standards adopted

A number of amended standards became applicable for the current reporting period. The Group did not make any significant changes to its accounting policies and did not make retrospective adjustments as a result of adopting these amended standards. These amendments did not materially impact the accounting policies or amounts disclosed in the year end financial statements of the Group.

New and amended accounting standards not yet adopted

Certain new accounting standards, amendments to accounting standards and interpretations have been published that are not mandatory for the 31 December 2023 reporting period and have not been early adopted by the Group. These standards, amendments or interpretations are not expected to have a material impact to the Group in the current or future reporting periods and on foreseeable future transactions with the exception of the amendments to IAS 12 Income Taxes where the impact is under assessment.

Pillar Two reforms

In December 2021, the Organisation for Economic Co-operation and Development (OECD) published its Pillar Two model rules. The Pillar Two model rules:

· aim to ensure that large multinational groups pay a minimum amount of tax on income arising in each jurisdiction in which they operate; and

· would achieve a minimum effective tax rate in each jurisdiction of 15% from the reporting period commencing 1 January 2024.

For the year ended 31 December 2023, the Group paid $2,916 million of income tax and PRRT and reported a global effective income tax rate of 27.5%.

The Group’s impact assessment will depend on the extent to which the Pillar Two legislation has been enacted in the various jurisdictions the Group operates in and when it comes into effect. The Group will continue to monitor and assess the expected impact of the Pillar Two reform.

F-67

Directors’ declaration

Directors’ declaration

Not required for the purposes of US reporting.

F-68

PwC - Report of Independent Registered Public Accounting Firm

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of Woodside Energy Group Ltd

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated statement of financial position of Woodside Energy Group Ltd and its subsidiaries (the “Company”) as of December 31, 2023 and 2022, and the related statements of consolidated income, consolidated comprehensive income, consolidated changes in equity and consolidated cash flows for each of the two years in the period ended December 31, 2023, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company’s internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2023 in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board (“IFRS”). Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.

We also have audited the adjustments to the 2021 consolidated financial statements to reflect the change in the composition of reportable segments, as described in Note A.1. In our opinion, such adjustments are appropriate and have been properly applied. We were not engaged to audit, review, or apply any procedures to the 2021 consolidated financial statements of the Company other than with respect to the adjustments and, accordingly, we do not express an opinion or any other form of assurance on the 2021 consolidated financial statements taken as a whole.

Basis for Opinions

The Company’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in management’s annual report on internal control over financial reporting within section 4.1.8 Other governance disclosures. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

F-69

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Carrying value of cash generating units (CGUs) with goodwill and oil and gas properties – Shenzi and Wheatstone

As described in Note B.4 to the consolidated financial statements, the Company conducted its annual goodwill impairment testing for CGUs with goodwill and estimated the recoverable amount of CGUs with an impairment indicator at December 31, 2023. This resulted in the recognition of pre-tax impairment charges of $1,383 million for the Shenzi CGU and $466 million for the Wheatstone CGU. The recoverable amounts for the Shenzi and Wheatstone CGUs were estimated using the fair value less costs of disposal approach utilizing cash flow models. The Company’s cash flow models included significant judgments and assumptions relating to oil and gas reserves and resources, estimates of future production and commodity prices, forecast expenditures incorporating expected inflation and foreign exchange rates, discount rate assumptions, and estimates of carbon costs.

The principal considerations for our determination that performing procedures relating to the assessment of the carrying value of the Shenzi and Wheatstone CGUs is a critical audit matter are (i) there is a significant level of judgment applied by the Company, including the use of the Company’s specialists, in the determination of the significant estimates and assumptions included in the impairment models; (ii) this in turn led to a high degree of auditor judgment, effort and subjectivity in performing procedures and evaluating the Company’s significant assumptions and estimates; and (iii) the nature and extent of audit effort required to perform the procedures and evaluate the Company’s significant assumptions and estimates required the use of professionals with specialized skill and knowledge.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included, among others, (i) testing the effectiveness of controls relating to management’s assessment of the significant estimates and assumptions included within the impairment models; (ii) assessing the reasonableness of significant estimates and assumptions applied by the Company; (iii) evaluating the work of the Company’s specialists involved in the determination of significant estimates and assumptions; (iv) evaluating the disclosures made regarding the impairment of goodwill and oil and gas properties in the consolidated financial statements against the requirements of IFRS; and (v) professionals with specialized skill and knowledge were used to assist in evaluating the appropriateness of the Company’s recoverable amount estimates.

Valuation of the Petroleum Resource Rent Tax (PRRT) deferred tax assets (DTAs) - Pluto

As described in Note A.5 to the consolidated financial statements, the Company has recognized deferred tax assets of $1,717 million as of December 31, 2023, of which $1,101 million relates to PRRT, including the Pluto PRRT DTA which reduced by $637 million during the year on the basis of future taxable profits not being available to utilize the deductible expenditure. PRRT is considered, for accounting purposes, to be an income tax. PRRT DTAs are based on estimates of future taxable profits available to recover incurred general and exploration expenditure. The Company’s estimation of the PRRT DTAs involves significant judgments and assumptions including assessing the forecast future taxable profits (which are risk-adjusted where appropriate by a market premium risk rate to reflect uncertainty inherent in long-term forecasts) generated from the Australian assets, which have regard to the future commodity price assumptions, and forecast assessable revenues, exploration and general expenditure.

F-70

The principal considerations for our determination that performing procedures relating to valuation of the Pluto PRRT DTAs is a critical audit matter are (i) there is a significant level of judgment applied by the Company in determining the recoverability of the PRRT DTAs, including having regard to the judgments and assumptions mentioned above, and considering the specialized knowledge and input of the Company’s specialists informing significant estimates and assumptions; (ii) this in turn led to a high degree of auditor judgment, effort and subjectivity in performing procedures and evaluating the Company’s methodology, significant assumptions and estimates; and (iii) the nature and extent of audit effort required to perform the procedures and evaluate the Company’s methodology, significant assumptions and estimates required the use of professionals with specialized skill and knowledge.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included, among others, (i) testing the effectiveness of controls relating to management’s assessment of the significant judgments and assumptions included within the PRRT modelling and recoverability assessment; (ii) assessing the reasonableness of significant judgments and assumptions applied by the Company to estimate the recoverable amount of DTAs; (iii) evaluating the work of the Company’s specialists involved in the determination of significant judgments and estimates; (iv) evaluating the disclosures made regarding the PRRT DTAs recognized in the consolidated financial statements against the requirements of IFRS; and (v) professionals with specialized skill and knowledge were used to assist in evaluating the appropriateness of the Company’s assessment of recoverability of the PRRT DTAs including certain significant assumptions.

/s/ PricewaterhouseCoopers

Perth, Australia

February 27, 2024

We have served as the Company’s auditor since 2022.

F-71

EY - Report of Independent Registered Public Accounting Firm

Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Directors of Woodside Energy Group Ltd (formerly known as Woodside Petroleum Ltd)

Opinion on the Financial Statements

We have audited, before the effects of the adjustments to retrospectively reflect the change in the composition of reportable segments described in Note A.1, the accompanying statements of comprehensive income, changes in equity, and cash flows of Woodside Energy Group Limited (the “Group”) for the year ended 31 December 2021, and the related notes (collectively referred to as the “consolidated financial statements”). The 2021 consolidated financial statements before the effects of the adjustments to retrospectively reflect the change in the composition of reportable segments discussed in Note A.1, are not presented herein.

In our opinion, the 2021 consolidated financial statements, before the effects of the adjustments to retrospectively reflect the change in the composition of reportable segments described in Note A.1, present fairly, in all material respects, the results of the Group’s operations and the Group’s cash flows for the year ending 31 December 2021, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.

We were not engaged to audit, review, or apply any procedures to the adjustments to retrospectively reflect the change in the composition of reportable segments described in Note A.1, and, accordingly, we do not express an opinion or any other form of assurance about whether such adjustments are appropriate and have been properly applied. Those adjustments were audited by PricewaterhouseCoopers.

Basis for Opinion

The 2021 consolidated financial statements are the responsibility of the Group’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Group in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Group is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Group’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Ernst & Young

We served as the Group’s auditor from 1954 to 2022.

Perth, Australia

8 March 2022

F-72

 

 SECTION 6: ADDITIONAL INFORMATION

 

SECTION 6.1

Supplementary information on oil and gas - unaudited

In accordance with the requirements of the Financial Accounting Standards Board (FASB) Accounting Standard Codification ‘Extractive Activities-Oil and Gas’ (Topic 932) and SEC requirements set out in Subpart 1200 of Regulation S-K, the Group is presenting certain disclosures about its oil and gas activities. These disclosures are presented below as supplementary oil and gas information, in addition to information relating to the reserves and production disclosed in section 3.10 of this report.

The information set out in this section is referred to as unaudited as it is not included in the scope of the audit opinion of the independent auditor on Woodside’s Financial Statements.

Reserves

Proved oil and gas reserves information is included in section 3.10 - Reserves Statement.

Capitalised costs relating to oil and gas production activities

The following table shows the aggregate capitalised costs related to oil and gas exploration and production activities, and the related accumulated depreciation, depletion, amortisation and valuation provisions.

	Australia US$m		International US$m		Total US$m
2023
Unproved properties		1,193		1,109		2,302
Proved properties1		52,563		18,039		70,602
Total costs		53,756		19,148		72,904
Less: Accumulated depreciation, depletion, amortisation and valuation provisions		(27,548)		(3,994)		(31,542)
Net capitalised costs		26,208		15,154		41,362
2022
Unproved properties		1,154		1,834		2,988
Proved properties1		49,190		15,546		64,736
Total costs		50,344		17,380		67,724
Less: Accumulated depreciation, depletion, amortisation and valuation provisions		(24,353)		(2,491)		(26,844)
Net capitalised costs		25,991		14,889		40,880
2021
Unproved properties		1,172		1,703		2,875
Proved properties1		38,352		2,517		40,869
Total costs		39,524		4,220		43,744
Less: Accumulated depreciation, depletion, amortisation and valuation provisions		(22,738)		(1,958)		(24,696)
Net capitalised costs		16,786		2,262		19,048

  1. Proved properties include the fair value ascribed to future phases of certain projects acquired through business combinations.

A-1

Costs incurred relating to oil and gas property acquisition, exploration and development activities

The following table shows the costs incurred related to oil and gas property acquisition, exploration and development activities (expensed and capitalised). Amounts shown include interest capitalised.

	Australia US$m		International US$m		Total US$m
2023
Acquisitions of proved property		-		-		-
Acquisitions of unproved property		-		-		-
Exploration1		103		420		523
Development2		3,315		2,124		5,439
Total costs3		3,418		2,544		5,962
2022
Acquisitions of proved property		8,488		11,098		19,586
Acquisitions of unproved property		-		180		180
Exploration1		39		541		580
Development2		2,365		1,740		4,105
Total costs3		10,892		13,559		24,451
2021
Acquisitions of proved property		-		205		205
Acquisitions of unproved property		-		7		7
Exploration1		459		84		543
Development2		1,141		935		2,076
Total costs3		1,600		1,231		2,831

  1. Represents gross exploration expenditure, including capitalised exploration expenditure, geological and geophysical expenditure and development evaluation costs charged to income as incurred.

  2. Total development costs includes $5,128 million of expenditure and $311 million of capitalised interest in 2023.

  3. Total costs include $5,683 million (2022: $23,991 million, 2021: $2,777 million) capitalised during the year.

A-2

Results of operations from oil and gas production activities

	Australia US$m			International US$m			Total US$m
2023
Oil and gas revenue		9,699			2,564			12,263
Production costs		(1,396	)		(402	)		(1,798	)
Exploration expenses		(55	)		(299	)		(354	)
Depreciation, depletion, amortisation and valuation provision1		(3,288	)		(2,555	)		(5,843	)
Production taxes2		(363	)		(29	)		(392	)
Accretion expense3		(179	)		(58	)		(237	)
Income taxes		(1,449	)		-			(1,449	)
Royalty-related taxes4		(367	)		-			(367	)
Results of oil and gas producing activities5		2,602			(779	)		1,823
2022
Oil and gas revenue		12,453			1,575			14,028
Production costs		(1,277	)		(353	)		(1,630	)
Exploration expenses		(20	)		(440	)		(460	)
Depreciation, depletion, amortisation and valuation provision1		(1,476	)		(460	)		(1,936	)
Production taxes2		(429	)		(16	)		(445	)
Accretion expense3		(85	)		(23	)		(108	)
Income taxes		(2,707	)		(151	)		(2,858	)
Royalty-related taxes4		(501	)		-			(501	)
Results of oil and gas producing activities5		5,958			132			6,090
2021
Oil and gas revenue		5,624			-			5,624
Production costs		(504	)		-			(504	)
Exploration expenses		(6	)		(48	)		(54	)
Depreciation, depletion, amortisation and valuation provision1		(501	)		(268	)		(769	)
Production taxes2		(218	)		-			(218	)
Accretion expense3		(23	)		(1	)		(24	)
Income taxes		(1,312	)		-			(1,312	)
Royalty-related taxes4		-			-			-
Results of oil and gas producing activities5		3,060			(317	)		2,743

1. Includes valuation provision recognition of $1,917 million (2022: reversal of $900 million; 2021: reversal of $1,048 million).

2. Includes royalties and excise duty.

3. Represents the unwinding of the discount on the closure and rehabilitation provision.

4. Includes petroleum resource rent tax and petroleum revenue tax where applicable. Excludes deferred tax expense/(benefit) of $531 million (2022: $(814) million; 2021: $297 million).

5. This table reflects the results of our oil and gas activities as reported in note A.1 ‘Segment revenue and expenses’ in Section 5 – Financial Statements. Other income, other expenses, general and administrative costs and amounts relating to the marketing and corporate/other segments within the note are excluded.

A-3

Standardised measure of discounted future net cash flows relating to prove oil and gas reserves (standardised measure)

The following tables set out the standardised measure of discounted future net cash flows, and changes therein, related to the Group’s estimated proved reserves as presented in Reserves, and should be read in conjunction with that disclosure.

The analysis is prepared in compliance with FASB Oil and Gas Disclosure requirements, applying certain prescribed assumptions under Topic 932 including the use of unweighted average first-day-of-the-month market prices for the previous 12-months, year-end cost factors, currently enacted tax rates and an annual discount factor of 10% to year-end quantities of net proved reserves.

Certain key assumptions prescribed under Topic 932 are arbitrary in nature and may not prove to be accurate. The reserve estimates on which the Standard measure is based are subject to revision as further technical information becomes available or economic conditions change.

Discounted future net cash flows like those shown below are not intended to represent estimates of fair value. An estimate of fair value would also take into account, among other things, the expected recovery of reserves in excess of proved reserves, anticipated future changes in commodity prices, exchange rates, development and production costs as well as alternative discount factors representing the time value of money and adjustments for risk inherent in producing oil and gas.

Woodside standardised measure year ended 31 December

	Australia US$m		International US$m		Total US$m
2023
Future cash inflows		114,168		41,307		155,475
Future production costs		(31,945)		(11,344)		(43,289)
Future development costs1		(10,758)		(8,216)		(18,974)
Future income taxes		(27,527)		(5,375)		(32,902)
Future net cash flows		43,938		16,372		60,310
Discount at 10% per annum		(20,024)		(8,133)		(28,157)
Standardised measure		23,914		8,239		32,153
2022
Future cash inflows		197,194		38,256		235,450
Future production costs		(31,157)		(9,698)		(40,855)
Future development costs1		(12,259)		(4,487)		(16,746)
Future income taxes		(62,182)		(4,823)		(67,005)
Future net cash flows		91,596		19,248		110,844
Discount at 10% per annum		(48,924)		(7,777)		(56,701)
Standardised measure		42,672		11,471		54,143
2021
Future cash inflows		76,202		5,695		81,897
Future production costs		(22,193)		(899)		(23,092)
Future development costs1		(8,296)		(2,481)		(10,777)
Future income taxes		(16,266)		(90)		(16,356)
Future net cash flows		29,447		2,225		31,672
Discount at 10% per annum		(14,793)		(1,142)		(15,935)
Standardised measure		14,654		1,083		15,737

1. Future development costs include decommissioning.

A-4

Changes in the standardised measure are presented in the following table:

	2023    US$m		2022    US$m		2021    US$m
Changes in the standardised measure
Standardised measure at the beginning of the year		54,143		15,737		5,084
Revisions:
Prices, net of production costs		(41,132)		22,558		7,741
Changes in future development costs		(2,288)		(873)		20
Revisions of reserves quantity estimates		3,156		5,898		2,109
Accretion of discount		8,039		4,051		430
Changes in production timing and other		(707)		2,371		3,485
Sales of oil and gas, net of production costs		(10,500)		(10,202)		(5,698)
Acquisitions of reserves-in-place		-		28,309		-
Sales of reserves-in-place		-		-		-
Previously estimated development costs incurred		5,276		3,339		565
Extensions, discoveries, and improved recoveries, net of future costs		1,174		-		8,346
Changes in future income taxes		14,992		(17,045)		(6,345)
Standardised measure at the end of the year		32,153		54,143		15,737

Changes in reserves quantities are shown in section 3.10 - Reserves Statement.

Accounting for suspended exploratory well costs

Expenditure on exploration and evaluation is accounted for in accordance with the area of interest method. Areas of interest are based on a geographical area for which the rights of tenure are current. All exploration and evaluation expenditure, including general permit activity, geological and geophysical costs and new venture activity costs, is expensed as incurred except for the following:

• where the expenditure relates to an exploration discovery for which the assessment of the existence or otherwise of economically recoverable hydrocarbons is not yet complete; or

• where the expenditure is expected to be recouped through successful exploitation of the area of interest, or alternatively, by its sale.

The costs of acquiring interests in new exploration and evaluation licences are capitalised. The costs of drilling exploration wells are initially capitalised pending the results of the well. Costs are expensed where the well does not result in the successful discovery of economically recoverable hydrocarbons and the recognition of an area of interest. Subsequent to the recognition of an area of interest, all further evaluation costs relating to that area of interest are capitalised.

Upon approval for the commercial development of an area of interest, accumulated expenditure for the area of interest is transferred to oil and gas properties.

In the consolidated statement of cash flows, those cash flows associated with capitalised exploration and evaluation expenditure, including unsuccessful wells, are classified as cash flows used in investing activities.

A-5

The following table provides the changes to the capitalised exploratory well costs that were pending the determination of proved reserves for the three years ended 31 December 2023, 31 December 2022 and 31 December 2021.

	2023 US$m		2022 US$m		2021 US$m
Movement in capitalised exploratory well costs1
At the beginning of the year		807		614		2,045
Acquisitions to the capitalised exploratory well costs pending the determination of proved reserves		-		180		-
Additions to the capitalised exploratory well costs pending the determination of proved reserves		169		111		501
Capitalised exploratory well costs expensed2		(4)		(62)		(268)
Capitalised exploratory well costs reclassified to wells, equipment and facilities based on the determination of proved reserves		(304)		(36)		(1,664)
Sale of suspended wells		-		-		-
At the end of the year		668		807		614

1. Suspended exploratory well costs represent capitalised exploration, evaluation and permit acquisition costs.

2. Includes amortisation of licence acquisition costs.

The following table provides an ageing of capitalised exploratory well costs, based on the date the drilling was completed, and the number of projects for which exploratory well costs has been capitalised for a period greater than one year since the completion of drilling.

Exploration activity typically involves drilling multiple wells, over a number of years, to fully evaluate and appraise a project. The term ‘project’ as used in this disclosure refers primarily to individual wells and associated exploratory activities.

	2023 US$m		2022 US$m		2021 US$m
Ageing of capitalised exploratory well costs
Exploratory well costs capitalised for a period of one year or less		71		124		19
Exploratory well costs capitalised for a period greater than one year		597		683		595
At the end of the year		668		807		614
	2023 US$m		2022 US$m		2021 US$m
Number of projects that have been capitalised for a period greater than one year		17		21		25

A-6

6.2 Additional Information

Three-year financial analysis

THREE-YEAR PRICING OVERVIEW

Woodside’s results from operations are significantly influenced by global energy market conditions. Over the last three years, oil and gas prices have experienced significant volatility. In 2021, prices began recovering from the COVID-19 pandemic as economic activity increased. In 2022 gas prices hit record highs driven by years of underinvestment and the supply shock caused by Russia’s invasion of Ukraine. In 2022 there was a significant increase in the scale of Woodside’s production portfolio, with the completion of the merger with BHP’s petroleum business on 1 June 2022. In 2023, prices declined below summer 2021 levels, however remained above historic averages with the decline triggered by milder weather conditions and higher stock levels across Europe. After three years of volatility global energy markets have returned to a degree of stability reflecting normalising levels of demand and price, though uncertainty remains, particularly in light of the ongoing conflict in Ukraine and geopolitical events in the Middle East.

SEASONALITY

Woodside’s revenue is exposed to commodity price fluctuations through the sale of hydrocarbons. Commodity pricing can be affected by seasonal energy demand movements in different markets.

Financial results	2023     US$m			2022     US$m			2021     US$m
Operating revenue		13,994			16,817			6,962
Cost of sales		(7,519	)		(6,540	)		(3,845	)
Gross profit		6,475			10,277			3,117
Other income		322			735			139
Other expenses		(1,573	)		(2,726	)		(811	)
Impairment losses		(1,917	)		-			(10	)
Impairment reversals		-			900			1,058
Profit before tax and net finance costs		3,307			9,186			3,493
Net finance costs		(34	)		(12	)		(203	)
Total tax expense		(1,551	)		(2,599	)		(1,254	)
Profit after tax		1,722			6,575			2,036
Attributable to equity holders of the parent		1,660			6,498			1,983
Attributable to non-controlling interests		62			77			53
Profit for the period		1,722			6,575			2,036

Woodside’s profit after tax attributable to equity holders of the parent decreased to $1,660 million in 2023 from $6,498 million in 2022 and $1,983 million in 2021.

Operating revenue of $13,994 million decreased by $2,823 million, or -17%, from 2022. The decrease was driven by lower average Brent, TTF and JKM price markers and planned turnaround activities at Ngujima-Yin, North West Shelf and Pluto, designed to support future asset reliability. This decrease was partly offset by an additional five months of production from BHP’s petroleum business acquired on 1 June 2022. Operating revenue increased by $9,855 million, or 142% from 2021 to 2022, driven primarily by the merger with BHP’s petroleum business which completed on 1 June 2022, the Pluto-KGP interconnector, strong operational performance and higher realised prices across all products.

Cost of sales increased by $979 million, or 15%, to $7,519 million compared to 2022. The increase was driven by planned turnaround activity at Pluto, Ngujima-Yin and North West Shelf, which is intended to form a solid base for increased future asset reliability, combined with additional five months activity from the assets acquired as part of the merger with BHP’s petroleum business. Cost of sales increased by $2,695 million from 2021 to 2022 primarily due to an additional seven months of volumes as a result of the merger with BHP Petroleum and the Pluto-KGP Interconnector, as well as higher costs related to Corpus Christi and Pluto cargoes.

Other income decreased by $413 million, or 56%, to $322 million from 2022, primarily due to profit on the sell-down of Pluto Train 2 in 2022, which was also the primary reason for the increase of $596 million, or 429% from 2021 to 2022.

Other expenses decreased by $1,153 million, or 42%, to $1,573 million from 2022, primarily due to lower losses on hedging activities and the incurrence of merger transaction costs in 2022. Other expenses increased $1,915 million, or 236% from 2021

A-7

to 2022, driven by higher losses on hedging activities and repurchase agreements and transaction and integration costs relating to the merger with BHP Petroleum. The increased activity that comes with a larger, more diverse portfolio of assets also led to an increase in expenses associated with exploration activity and restoration movements from 2021 to 2022.

In 2023, an impairment loss totalling $1,917 million was recognised for the Shenzi, Wheatstone and Pyrenees assets, compared to an impairment reversal of $900 million for the Wheatstone asset in 2022. For more information on impairment refer to Note B.4 Impairment of exploration and evaluation, oil and gas properties and goodwill in section 5 - Financial Statements.

Net finance costs increased by $22 million, or 183%, from 2022, to $34 million. This was primarily due to higher restoration accretion, driven by an additional five months activity from the assets acquired as part of the merger with BHP’s petroleum business, offset by higher interest rates on cash deposits. Net finance costs decreased $191 million, or 94% from 2021 to 2022 as a result of higher interest income generated from higher interest rates and cash balances and a reduction in finance costs due to higher capitalised borrowing costs.

Total tax expense comprises income tax and petroleum resource rent tax (PRRT). Income tax expense decreased in 2023 primarily due to lower assessable income and the recognition of a DTA on the Trion FID. PRRT expense increased from 2022 to 2023 due to the partial de-recognition of the Pluto PRRT DTA. Both income tax expense and PRRT expense increased from 2021 to 2022 before recognising additional PRRT deferred tax assets. Higher realised prices in 2022 led to additional PRRT payments but also supported the recognition of additional Pluto deferred tax assets ($1,362 million) which resulted in a 2022 net PRRT tax benefit. PRRT expense therefore decreased from 2021 by $610 million due to the Pluto deferred tax asset recognition and the impairment reversal in 2021 not present in 2022.

Income tax decreased by $2,259 million, or 78%, to $653 million. The decrease is primarily related to lower profits driven by lower prices. Income tax expense increased $1,955 million, or 204% from 2021 to 2022, primarily due to higher profits driven by higher prices and additional production.

A-8

VOLUMES, REALISED PRICES AND OPERATING REVENUES BY PRODUCT

The following describes movements in Woodside’s operating revenues including a discussion of production volumes, sales volumes and realised prices for the years ended 31 December 2023, 2022 and 2021.

	Units	2023		2022		2021
Production volumes
LNG	MMboe		88.6		85.1		70.8
Pipeline gas	MMboe		39.7		28.6		2.5
Crude oil and condensate	MMboe		51.8		38.7		17.3
NGLs	MMboe		7.1		5.3		0.5
Total production volumes	MMboe		187.2		157.7		91.1
Sales volumes
LNG	MMboe		104.5		96.6		91.2
Pipeline gas	MMboe		39.6		28.4		2.5
Crude oil and condensate	MMboe		50.3		39.3		17.2
NGLs	MMboe		7.1		4.6		0.7
Total sales volumes	MMboe		201.5		168.9		111.6
	Units	2023		2022		2021
Average realised prices
LNG	$/boe		78.2		116.9		58.8
Pipeline gas	$/boe		34.7		47.8		17.0
Crude oil and condensate	$/boe		79.0		95.8		76.4
NGLs	$/boe		39.5		44.4		82.4
Volume – weighted average	$/boe		68.6		98.4		60.7
Operating revenue
LNG	$m		8,165		11,289		5,359
Pipeline gas	$m		1,374		1,362		43
Crude oil and condensate	$m		3,981		3,758		1,316
NGLs	$m		281		206		60
Other revenue	$m		193		202		184
Operating revenue	$m		13,994		16,817		6,962

A-9

LNG

Revenue from the sale of LNG in 2023 decreased by $3,124 million, or 28%, to $8,165 million for 2023 from 2022, primarily due to gas prices which decreased in the second half of 2022 which continued in the first half of 2023 before stabilising in the second half of 2023 (TTF price markers decreased by 62% from 31 December 2022 to 31 December 2023). Lower prices were partially offset by five additional months of increased volumes following the merger with BHP Petroleum.

Revenue from the sale of LNG in 2022 increased by $5,930 million, or 111%, to $11,289 million from 2021, primarily due to seven months of increased volumes following the merger with BHP Petroleum and the contribution of the Pluto-KGP interconnector during a period of higher average realised prices.

Pipeline gas

Revenue from the sale of pipeline gas in 2023 increased by $12 million, or 1%, to $1,374 million for 2023 from 2022, primarily due to five months of increased pipeline gas volumes as a result of the merger with BHP Petroleum offset by lower average prices.

Revenue from the sale of pipeline gas in 2022 increased by $1,319 million, or 3,067%, to $1,362 million from 2021, primarily due to seven months of increased pipeline gas volumes as a result of the merger with BHP Petroleum and higher average realised prices.

Crude oil and condensate

Revenue from the sale of crude oil and condensate in 2023 increased by $223 million, or 6%, to $3,981 million for 2023 from 2022, due to five months of increased crude oil and condensate volumes as a result of the merger with BHP Petroleum, however was offset by lower average realised prices.

Revenue from the sale of crude oil and condensate in 2022 increased by $2,442 million, or 186%, to $3,758 million for 2022 from 2021, due to increased crude oil and condensate volumes primarily as a result of the merger with BHP Petroleum as well as higher average realised prices.

NGLs

Revenue from the sale of NGLs in 2023 increased by $75 million, or 36%, to $281 million for 2023 from 2022, due to five months of increased NGLs volumes as a result of the merger with BHP Petroleum.

Revenue from the sale of NGLs in 2022 increased by $146 million, or 243%, to $206 million for 2022 from 2021, due to increased NGLs volumes as a result of the merger with BHP Petroleum, offset by a decreased average realised price.

Other Revenue

Other revenue comprises of processing and services tariff revenue received from non-controlling interests and plant processing fees.

PERFORMANCE BY SEGMENT

Woodside has identified its operating segments based on the internal reports that are reviewed and used by the Chief Executive Officer in assessing performance and are based on the nature and geographical location of the related activity. For more information on our reportable segments, please refer to Note A.1 Segment revenue and expenses in section 5 - Financial Statements.

The disclosed operating segments in 2023 remain consistent to 2022. The 2021 amounts have been restated to be presented on the same basis.

The performance of operating segments is evaluated based on profit before tax and net finance costs and is measured in accordance with Woodside’s accounting policies. Financing requirements, including cash and debt balances, finance income, finance costs and taxes for Woodside and its subsidiaries are managed at a Group level.

A-10

Australia

Detailed below is the financial and operating information for our Australian operations comparing 2023, 2022 and 2021.

Key metric	Units	2023		2022		2021
Operating revenue	$m		9,802		12,299		5,240
Profit before tax and net finance costs	$m		4,487		9,415		3,711
Total production	MMboe		145.1		136.6		91.1
Average realised prices
LNG	$/boe		76.4		108.5		56.3
Pipeline gas	$/boe		38.9		47.6		17.0
Crude oil and condensate	$/boe		80.0		99.9		76.4
Natural gas liquids	$/boe		39.1		47.2		82.4

Financial results

Operating revenue of $9,802 million decreased by $2,497 million, or 20%, from 2022 primarily due to lower realised prices and planned turnaround activities, partially offset by five additional months of increased volumes following the merger with BHP Petroleum. Refer to the section entitled ‘Three-year pricing overview’ for more information.

Profit before tax and net finance costs of $4,487 million decreased by $4,928 million, or 52%, from 2022 primarily due to lower prices and the pre-tax impairment of Wheatstone and Pyrenees assets of $534 million.

Operating revenue increased by $7,059 million in 2022 from 2021 underpinned by strong operational reliability, increased volumes and higher realised prices across all products. The increase in volumes was primarily as a result of the merger with BHP Petroleum and the contribution of the Pluto-KGP interconnector.

Profit before tax and net finance costs in 2022 increased by $5,704 million, or 154%, from 2021 primarily due to increased operating revenue and the profit on the sell-down of Pluto Train 2 ($427 million) and an impairment reversal recognised on Wheatstone ($900 million), partially offset by increased cost of sales ($1,693 million) and increased restoration provisions ($154 million). The increased cost of sales was driven by production and price-linked costs ($808 million) and increased depreciation ($777 million) primarily relating to the assets acquired as a result of the merger with BHP’s petroleum business.

Production

The Australia segment achieved an increase in production volumes of 8.5 MMboe in 2023 compared to 2022, primarily due to strong reliability of Pluto, additional interconnector cargoes and five additional months of increased volumes following the merger with BHP Petroleum.

Production volumes for the Australia segment increased by 45.5 MMboe in 2022 compared to 2021 primarily due to the merger with BHP Petroleum and the Pluto-KGP Interconnector along with strong operational performance.

International

Financial and operating information for our international operations comparing 2023, 2022 and 2021 is detailed below.

Key metric	Units	2023		2022		2021
Operating revenue	$m		2,549		1,570		-
(Loss) before tax and net finance costs	$m		(808)		125		(317	)
Total production	MMboe		42.1		21.1		-
Average realised prices
Pipeline gas	$/boe		24.7		49.0		-
Crude oil and condensate	$/boe		76.8		88.7		-
Natural gas liquids	$/boe		21.1		31.3		-

Financial results

Operating revenue of $2,549 million in 2023 increased by $979 million in 2023 from 2022 primarily due to five additional months of increased volumes following the merger with BHP Petroleum and the start of production at Argos in the Gulf of Mexico. For more information refer to Note A.1 Segment revenue and expenses in section 5 - Financial Statements.

Loss before tax and net finance costs of $808 million primarily due to the pre-tax impairment of the Shenzi asset $1,383 million.

Operating revenue increased by $1,570 million in 2022 from 2021 primarily due to the introduction of sales volumes as a result of the merger with BHP Petroleum. There was no operating revenue reported in this segment for 2021.

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Profit before tax and net finance costs increased by $442 million, or 139%, in 2022 from 2021 primarily due to increased operating revenue, offset by increased cost of sales ($837 million) and other expenses ($297 million). Increased cost of sales is driven primarily by production and price-linked costs ($352 million) and depreciation ($439 million) as a result of the merger with BHP Petroleum. The increased other expenses primarily relate to increased exploration and evaluation expenditure ($250 million) and increased restoration provision movements ($58 million), offset by Myanmar write-offs in 2021 not present in 2022 ($265 million).

Production

The International segment achieved an increase in production volumes of 21 MMboe in 2023 compared to 2022, primarily due to five additional months of increased volumes following the merger with BHP Petroleum and the Argos asset starting production in April 2023.

The International segment achieved production of 21.1 MMboe in 2022 due to the introduction of volume as a result of the merger with BHP Petroleum. There was no production recorded within this segment in 2021.

Marketing

Financial and operating information for our marketing operations comparing 2023, 2022 and 2021 is detailed below.

Key metric	Units	2023		2022		2021
Operating revenue	$m		1,643		2,948		1,722
Profit before tax and net finance costs	$m		375		848		354
Average realised prices
LNG	$/boe		76.2		165.6		66.6
Liquids	$/boe		78.9		165.6		66.6

Financial results

Operating revenue of $1,643 million, decreased by $1,305 million, or 44%, from 2022 primarily due to lower average realised price and fewer third-party trades.

Profit before tax and net finance costs of $375 million, decreased by $473 million, or 56%, from 2022 primarily due to lower average realised price.

Operating revenue increased by $1,226 million, or 71%, in 2022 from 2021 primarily due to higher trading revenue driven by higher realised prices and optimisation of scheduling and shipping, offset by fewer third-party trades as a result of tight market conditions.

Profit before tax and net finance costs increased by $494 million, or 140%, in 2022 from 2021 primarily due to increased operating revenue and movements in onerous contract provisions ($76 million), offset by higher shipping and trading costs ($299 million) and increased other expenses predominantly due to attributable hedging losses and movement on repurchase agreements ($503 million).

Corporate/Other Items

Financial information for our Corporate/Other Items comparing 2023, 2022 and 2021 is detailed below.

Key metric	Units	2023			2022			2021
Loss before tax and net finance costs	$m		(747	)		(1,202	)		(255	)

Loss before tax and net finance costs of $747 million decreased by $455 million, or 38%, from 2022 primarily due to the absence of merger cost in 2023.

Loss before tax and net finance costs increased by $947 million in 2022 from 2021 due to an increase in other expenses ($966 million) driven by increased general, administrative and other costs primarily as a result of transaction and other costs associated with the merger with BHP Petroleum ($595 million) and increased losses on hedging activities ($422 million).

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Capital and exploration expenditure

Woodside’s capital expenditures vary from year to year depending on the projects that it is undertaking, their stage of development and Woodside’s participating share in these projects. Woodside’s business does not generally require significant sustaining capital in order to maintain production.

Woodside’s exploration expenditures vary from year to year depending on its strategic priorities and the exploration projects which it undertakes.

For more information, refer to notes B.1 Segment production and growth assets, B.2 Exploration and evaluation and B.3 Oil and gas properties in section 5—Financial Statements.

Capital and exploration expenditure is an alternative performance measure (APM) which is a non-IFRS measure that is unaudited. Woodside believes this non-IFRS measure provides useful performance information, however it should not be considered as an indication of, or as a substitute for, statutory measures as an indicator of actual operating performance (such as net profit after tax or net cash from operating activities) or any other measure of financial performance or position presented in accordance with IFRS. For more information on non-IFRS measures, including reconciliations to Woodside’s Financial Statements, refer to section 6.6 - Alternative performance measures.

Capital and exploration expenditure geographical split¹

	2023 $m		2022 $m		2021 $m
Australia2		3,515		2,440		1,607
International3		2,588		2,093		1,121
		6,103		4,533		2,728

1 Includes capital additions on other corporate spend. The 2022 amounts have been restated to be presented on the same basis. The 2021 capital expenditure information has not been restated to include other corporate spend.

2 Capital and exploration expenditure incurred in Australia.

3 Capital and exploration expenditure incurred in all other locations excluding Australia.

Australian capital and exploration expenditure increased by $1,075 million, or 44%, to $3,515 million from 2022 to 2023 and $833 million from 2021 to 2022 primarily due to continued investment into the Scarborough and Pluto Train 2 assets.

International capital and exploration expenditure increased by $495 million, or 24%, to $2,588 million from 2022, primarily due to continued investment into the Sangomar and Trion assets.

The increased expenditure of $972 million from 2021 to 2022 was primarily due to continued investment into Sangomar and the introduction of spending in the Gulf of Mexico as a result of the merger with BHP Petroleum.

Cash flow analysis

The following section describes movements in Woodside’s cash flows for the years ending 31 December 2023, 2022 and 2021.

	2023 $m			2022 $m			2021 $m
Net cash from operating activities		6,145			8,811			3,792
Net cash used in investing activities		(5,585	)		(2,265	)		(2,941	)
Net cash used in financing activities		(5,000	)		(3,364	)		(1,424	)
Net increase/(decrease) in cash		(4,440	)		3,182			(573	)

Net cash from operating activities

Net cash from operating activities in 2023 decreased $2,666 million, or 30%, to $6,145 million from 2022, primarily due to lower EBITDA as a result of lower revenue driven by lower realised price; higher income tax and PRRT paid for record 2022 profits ($1,698 million); higher payments for restoration ($184 million); offset in part by return of collateral on Brent hedges vs payment in 2022 ($1,012 million); and higher receipts from interest ($156 million) due to higher interest rates from 2022 to 2023, despite reduction in deposits.

Net cash from operating activities in 2022 increased $5,019 million, or 132%, to $8,811 million from 2022, primarily due to increased cash generated from operations ($6,515 million) offset in part by higher taxes paid due to the higher profits ($947 million), additional restoration payments made as a result of increased decommissioning activities ($225 million) and increased collateral payments made relating to the Brent hedges ($506 million).

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Net cash used in investing activities

Net cash used in investing activities in 2023 increased $3,320 million, or 147%, to $5,585 million from 2022, primarily due to investments in major projects Scarborough, Sangomar and Trion. These new investments are intended to generate future operating cash flows and returns across the price cycle.

Net cash used in investing activities in 2022 decreased $676 million, or 23%, to $2,265 million from 2021, primarily due to cash receipts from the merger with BHP Petroleum ($1,082 million), payments made to acquire joint arrangements in 2021 not present in 2022 ($212 million), higher proceeds from the disposal of property, plant and equipment ($123 million) and lower payments made to Petrosen under a loan facility ($158 million) offset in part by higher capital expenditure predominantly related to Scarborough and Pluto Train 2, excluding the effect of GIP additional contribution to Pluto Train 2.

Net cash used in financing activities

Net cash used in financing activities in 2023 increased $1,636 million, or 49%, to $5,000 million from 2022, primarily due to higher final prior year dividend paid to shareholders ($1,695 million) due to the higher 2022 NPAT; and higher repayment of the principal portion of lease liabilities ($92 million) predominantly due to Sangomar.

Net cash used in financing activities increased $1,940 million, or 136%, to $3,364 million from 2021 to 2022, primarily due to higher dividends paid to shareholders as a result of the increased NPAT in the current year ($2,269 million), higher repayments for the purchase of shares under the dividend reinvestment plan ($144 million) and lower repayments of borrowings predominantly due to the repayment of the 2021 US bond in 2021 ($501 million).

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6.3 Additional Information

Additional disclosures

DRILLING AND OTHER EXPLORATORY AND DEVELOPMENT ACTIVITIES

The number of crude oil and natural gas wells drilled and completed for each of the last three years was as follows:

	Net exploratory wells			Net development wells
	Productive	Dry	Total	Productive	Dry	Total	Total
Year ended 31 December 2023
Australia	-	0.7	0.7	0.7	-	0.7	1.4
International1	0.2	0.4	0.7	6.3	0.4	6.7	7.4
Total	0.2	1.1	1.3	7.0	0.4	7.4	8.8
Year ended 31 December 20222
Australia	-	-	-	0.9	-	0.9	0.9
International3	0.9	2.0	2.9	1.2	-	1.2	4.0
Total	0.9	2.0	2.9	2.1	-	2.1	4.9
Year ended 31 December 2021
Australia	-	-	-	0.6	-	0.6	0.6
International4	-	1.5	1.5	-	-	-	1.5
Total	-	1.5	1.5	0.6	-	0.6	2.1

1 International is primarily US, and Trinidad and Tobago.

2 Includes BHP Petroleum from 1 June to 31 December 2022.

3 International is primarily US and Sangomar.

4 International is primarily Myanmar.

As set out in this section, the number of wells drilled refers to the number of wells completed at any time during the respective year, regardless of when drilling was initiated. Completion refers to the installation of permanent equipment for production of oil or gas, or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned.

An exploratory well is a well drilled to find oil or gas in a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. A development well is a well drilled within the limits of a known oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

A productive well is an exploratory, development or extension well that is not a dry well. Productive wells include wells in which hydrocarbons were encountered and the drilling or completion of which, in the case of exploratory wells, has been suspended pending further drilling or evaluation. A dry well (hole) is an exploratory, development, or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

During 2023, productive development wells included a sidetrack and dual lateral at Pyrenees in Australia, the Mad Dog Phase 2 development wells in the US Gulf of Mexico (GOM), an Atlantis infill well, the Shenzi North development wells, and the conversion of injection wells to production wells in Trinidad and Tobago. A successful appraisal well was drilled at Mad Dog Southwest. Dry exploratory wells included the Spinel well in the GOM and Gemtree in Australia and a dry infill well was drilled at Atlantis.

PRESENT DEVELOPMENT ACTIVITIES CONTINUING AS OF 31 DECEMBER 2023

The number of wells in the process of drilling and/or completion as of 31 December 2023 was as follows:

	Exploratory wells		Development wells		Total
	Gross	Net	Gross	Net	Gross	Net
Australia	-	-	-	-	-	-
International1	-	-	19	12.1	19	12.1
Total	-	-	19	12.1	19	12.1

1 International is primarily US and Senegal.

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Development wells in progress include Sangomar wells in Senegal, Mad Dog Phase 2 wells, Atlantis wells, and a Mad Dog A spar well in the GOM. The Sangomar development is installing a waterflood recovery scheme as part of the ongoing project, and in the Gulf of Mexico a waterflood recovery scheme is included in the Mad Dog Phase 2 project.

OIL AND GAS PROPERTIES, WELLS, OPERATIONS AND ACREAGE

The following tables show the number of gross and net productive crude oil and natural gas wells and total gross and net developed and undeveloped oil and natural gas acreage as at 31 December 2023. A gross well or acre is one in which a working interest is owned, while a net well or acre exists when the sum of fractional working interests owned in gross wells or acres equals one.

Productive wells are producing wells and wells mechanically capable of production. Developed acreage is comprised of leased acres that are within an area by or assignable to a productive well. Undeveloped acreage is comprised of leased acres on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil and gas, regardless of whether such acres contain proved reserves.

The number of productive crude oil and natural gas wells in which Woodside held an interest at 31 December 2023 was as follows:

	Crude oil wells		Natural gas wells		Total
	Gross	Net	Gross	Net	Gross	Net
Australia	223	116.2	198	93.0	421	209.2
International1	87	41.7	16	7.7	103	49.4
Total	310	157.9	214	100.7	524	258.6

1 International is primarily US and Trinidad and Tobago.

Of the productive crude oil and natural gas wells, 156 (net: 75) wells had multiple completions. The number of wells with multiple completions refers to wells that have downhole equipment installed that allows zonal insolation or controlled commingling of production as permitted and approved by the applicable regulator.

Developed and undeveloped acreage (including both leases and concessions) held at 31 December 2023 was as follows:

	Developed acreage		Undeveloped acreage
Thousands of acres	Gross	Net	Gross	Net
Australia	2,441	1,217	3,767	3,192
International1,2	141	68	17,215	7,077
Total	2,582	1,285	20,982	10,269

1 Developed acreage in International primarily comprises US and Trinidad and Tobago.

2 Undeveloped acreage in International primarily comprises Barbados, Canada, Congo, Egypt, Ireland, Mexico, Myanmar, Senegal, Timor-Leste and Trinidad and Tobago.

Woodside has initiated exits from our Myanmar, Peru and Ireland positions, totalling approximately 8,426 thousand acres gross (3,670 thousand acres net). Approximately 248 thousand acres gross (200 thousand acres net), 1,333 thousand acres gross (615 thousand acres net) and 784 thousand acres gross (452 thousand acres net) of undeveloped acreage will expire in the years ending 31 December 2024, 2025 and 2026 respectively if Woodside does not establish production or take any other action to extend the terms of the licences and concessions.

DELIVERY COMMITMENTS

Woodside has contracts that require delivery of fixed volumes of crude oil, condensate, natural gas and NGL. Woodside intends to fulfill its short-term and long-term obligations with its production or from purchases of third-party volumes.

As at 31 December 2023, delivery commitments were as follows:

	Natural gas (MMboe)	Crude oil (MMbbl)	Condensate (MMbbl)	NGLs (MMbbl)
Year ended 31 December
2024 to 2028	336.5	7.2	2.2	3.8
Thereafter	327.6	-	-	-
Total oil and gas delivery commitments	664.1	7.2	2.2	3.8

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PRODUCTION

The following table details production by product and geographic location for each of the three years ended 31 December 2023, 2022 and 2021. The volumes are marketable production after deduction of applicable royalties, fuel and flare. Average production costs per unit of production and average sales prices per unit of production has also been included for each of these periods.

	20231			20221		20212
Production volumes (MMboe)
LNG
Australia		87.6			84.4		70.8
International		-			-		-
Total LNG		87.6			84.4		70.8
Pipeline gas
Australia		28.0			22.9		2.5
International		11.5			5.6		-
Total pipeline gas		39.5			28.5		2.5
Crude oil and condensate
Australia		22.7			24.0		17.3
International		29.1			14.7		-
Total crude oil and condensate		51.8			38.7		17.3
Natural gas liquids (NGLs)
Australia		5.7			4.4		0.5
International		1.4			0.8		-
Total NGLs		7.1			5.2		0.5
Total petroleum products
Australia		144.0			135.7		91.1
International		42.1			21.1		-
Total production		186.1			156.8		91.1
Average sales price per produced boe (US$/boe)
LNG
Australia		76.3			104.0		55.4
International		-			-		-
Total LNG		76.3			104.0		55.4
Pipeline gas
Australia		38.6			47.3		18.0
International		24.8			48.9		-
Total pipeline gas		34.6			47.6		18.0
Crude oil and condensate
Australia		70.8			103.3		75.8
International		77.0			86.7		-
Total crude oil and condensate		74.3			97.0		75.8
Natural gas liquids (NGLs)
Australia		38.3			40.6		121.2
International		22.9			34.5		-
Total NGLs		35.2			39.7		121.2
Total average production cost per produced boe (US$/boe)
Australia		(11.2	)		10.4		7.9
International		(8.5	)		16.9		-
Total average production cost per produced boe3		(10.6	)		11.2		7.9

1 Includes production of 186.1 MMboe from Woodside reserves and excludes 1.1 MMboe from feed gas purchased from Pluto non-operating participants processed through the Pluto-KGP Interconnector.

2 Production volumes for 2021 has been restated to present marketable production after deduction of applicable royalties, fuel and flare.

3 Average production costs per produced boe includes direct and indirect costs relating to production of total hydrocarbons and the foreign exchange effect of translating local currency denominated costs into US dollars but excludes cost to transport produced hydrocarbons to the point of sale, ad valorem and severance taxes.

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NPAT RECONCILIATION

The following table summarises the variance between the 2022 and 2023 results for the contribution of each line item to NPAT.

	Million			Primary reasons for variance
2022 reported NPAT		6,498
Revenue from sale of hydrocarbons
Price		(4,442	)	Lower average prices across all products.
Volume		1,628		Primarily due to the additional contribution from the BHP Petroleum assets, partially offset by the turnaround activities on Ngujima-Yin, NWS and Pluto.
Other operating revenue		(9	)	Primarily due to a decrease in shipping and other revenue.
Cost of sales		(979	)	Primarily due to higher depreciation expense, partially offset by lower trading costs driven by lower commodity prices.
Other income		(413	)	Primarily the profit on sale of 49% of the Pluto Train 2 Joint Venture recognised in 2022.
General administrative costs		338		Primarily due to merger transaction and integration costs recognised in 2022.
Other		808		Primarily driven by lower commodity hedge losses.
Income tax and PRRT		1,048		Primarily due to lower revenues and recognition of the Trion deferred tax asset (DTA), offset by derecognition of the Pluto PRRT DTA.
Impairment and impairment reversals		(2,817	)	Due to impairments recognised on Shenzi, Wheatstone and Pyrenees.
2023 reported NPAT		1,660
2023 NPAT adjustments		1,660		Adjustments for Shenzi, Wheatstone and Pyrenees impairment, net of tax ($1,533 million) and derecognition of Pluto PRRT DTA offset by the recognition of the Trion DTA.
2023 underlying NPAT		3,320

EMPLOYEES

As at 31 December 2023, Woodside had approximately 4,667 employees, the majority of whom are located in Australia and the United States of America (USA). The increase in the number of employees from 2022 was due to general workforce growth to support Woodside’s operations and projects.

Woodside regularly engages with our workforce and supports freedom of association. Our employees are free to join or not to join a labour union. Woodside strives to maintain a positive relationship with employees and labour unions. Woodside believes that the relationship between its management and labour unions is generally positive.

Employment region (number of staff by region)^1,2

	2023		2022		2021
Australia		3,563		3,338		3,660
Africa and Middle East		57		50		35
Asia		77		71		48
Caribbean3		105		108		NPR
Europe		24		11		8
Americas4		841		849		13
Total		4,667		4,427		3,764
Total number of contractors (TPCs)		474		394		267

1 Vacation students, cadets and scholarship students are included in relevant metrics where appropriate.

2 ‘Secondees in’ are excluded from these metrics; ‘secondees out’ are included.

3 NPR stands for ‘not previously reported’.

4 The United States and Canada region has been renamed to Americas. This region captures employees in Mexico.

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QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

In the normal course of business, Woodside is exposed to commodity price, foreign currency exchange rate and interest rate risks that could impact Woodside’s financial position and results of operations. Woodside’s risk management strategy with respect to these market risks may include the use of derivative financial instruments. Woodside uses derivative contracts to manage commodity price volatility, foreign exchange rate volatility on capital expenditure plans and interest rate exposure on financing activities.

Actual gains and losses in the future may differ materially from the sensitivity analyses based on changes in the timing and amount of commodity price, foreign currency exchange rate and interest rate movements and Woodside’s actual exposures and derivatives in place at the time of the change, as well as the effectiveness of the derivative to hedge the related exposure.

Commodity price risk management

Woodside’s revenues are primarily derived from sales of LNG, crude oil, condensate, pipeline gas and NGLs. Consequently, Woodside’s results of operations are strongly influenced by the prices it receives for these products, which in the case of oil and condensate are primarily determined by prevailing crude oil prices and in the case of pipeline gas, NGLs and LNG are primarily determined by prevailing crude oil prices as well as some fixed pricing and other price indexes (such as Henry Hub and the Japan Korea Marker). For the year ended 31 December 2023, the majority (approximately 72%) of Woodside’s production was attributed to natural gas, comprising LNG, NGLs and pipeline gas and the remaining portion (approximately 28%) of Woodside’s production was attributed to oil and condensate.

LNG market conditions including, but not limited to, supply and demand, are unpredictable and are beyond Woodside’s control. In particular, supply and demand for and pricing of LNG, remain sensitive to energy prices, external economic and political factors, weather, climate conditions, natural disasters (including pandemics), timing of FIDs for new operations, construction and start up and operating costs for new LNG supply, buyer preferences for LNG, coal or crude oil and evolving buyer preferences for different LNG price regimes, and the energy transition. Buyers and sellers of LNG are increasingly more flexible with the way they transact, and contracts may involve hybrid pricing that is linked to other indices such as the Intercontinental Exchange (ICE) Brent Crude deliverable futures contract (oil price) or the Japanese Crude Cocktail, which is the average price of customs- cleared crude oil imports into Japan as reported in customs statistics. Typically, only LNG supplied from the US was based on a component linked to movements in the US Henry Hub plus certain fixed and variable components. This type of pricing structure may become a component of the weighted average price into Asia and other markets. This is since LNG supply and trade has globalised and increasingly the lowest cost supply is setting the floor for long-term average global natural gas prices with transportation costs accounting for regional differences. This marginal supply is predominantly from the United States, indirectly pegging global gas prices and Asian spot LNG prices to the Henry Hub marker which could adversely affect the pricing of new LNG contracts and potential future price reviews of existing LNG contracts. Tenders may also be used by suppliers and buyers, typically for shorter-term contracts. In addition, long-term LNG contracts typically contain price review mechanisms which sometimes need to be resolved by expert determination or arbitration. The use of these independent resolution mechanisms is likely to be more prevalent in volatile commodity markets. Alternatives to fossil fuel-based products for the generation of electricity, for example nuclear power and renewable energy sources, are continually under development and, if these alternatives continue to gain market share, they could also have a material impact on demand for LNG, which in turn may negatively impact Woodside’s business, results of operations and financial condition in the longer-term.

Oil prices can be very volatile, and periods of sustained low prices could result in changes to Woodside’s carrying value assumptions and may also reduce the reported net profit for the relevant period. The price of crude oil may be affected by factors beyond Woodside’s control. These include worldwide oil supply and demand, the level of economic activity in the markets Woodside serves, regional political developments and military conflicts (including the ongoing Russia-Ukraine conflict), weather conditions and natural disasters, conservation and environmental protection efforts, the level of crude oil inventories, the ability of OPEC and other major oil-producing or oil-consuming nations to influence global production levels and prices, sanctions on the production or export of oil, governmental regulations and actions, including the imposition of taxes, trade restrictions, market uncertainty and speculative activities by those who buy and sell oil and gas on the world markets, commodity futures trading, availability and capacity of infrastructure, supply chain disruptions, processing facilities and necessary transportation, the price and availability of new technology, the availability and cost of alternative sources of energy, and the impact of climate change considerations and actions towards energy transition on the demand for key commodities which Woodside produces.

The transition to lower carbon sources of energy in many parts of the world (driven by ESG and climate change concerns) may affect demand for Woodside’s products including crude oil, natural gas and LNG. In turn, this may affect the price received (or expected to be received) for these products. Material adverse price impacts (including as a result of the energy transition) may affect the economic performance (including as to margins and cash flows) of, and longevity of production from, Woodside’s existing and future production assets, and ultimately the financial performance of Woodside.

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It is impossible to predict future crude oil, LNG and natural gas price movements with certainty. A low crude oil price environment or declines in the price of crude oil, LNG and natural gas prices, could adversely affect Woodside’s business, results of operations and financial condition and liquidity. They could also negatively impact its ability to access sources of capital, including equity and debt markets. Those circumstances may also adversely impact Woodside’s ability to finance planned capital expenditures, including development projects, and may change the economics of operating certain wells, which could result in a reduction in the volume of Woodside’s reserves. Declines in crude oil, LNG and natural gas prices, especially sustained declines, may also reduce the amount of oil and gas that it can produce economically, reduce the economic viability of planned projects or assets that it plans to acquire or has acquired, and may reduce the expected value and the potential commerciality of exploration and appraisal assets. Those reductions may result in substantial downward adjustments to Woodside’s estimated proved reserves and require additional write-downs of the value of its oil and gas properties.

Sales contracts with the National Gas Company of Trinidad and Tobago relating to production from Woodside’s Trinidad and Tobago operations are partially linked to ammonia pricing. In addition there is a Western Australian domestic gas sales contract linked to urea pricing. Similar to crude oil, LNG and natural gas, it is impossible to predict future ammonia and urea prices with certainty.

There can be no assurance that Woodside will successfully manage its exposure to commodity prices. There is also counterparty risk associated with derivative contracts. If any counterparty to Woodside’s derivative instruments were to default or seek bankruptcy protection, it could subject a larger percentage of Woodside’s future oil and gas production to price changes and could have a negative effect on Woodside’s financial performance, including its ability to fund future projects. Whether Woodside engages in hedging and other oil and gas derivative contracts on a limited basis or otherwise, Woodside will remain exposed to fluctuations in crude oil prices.

Foreign exchange and interest rate risk management

Refer to sections A and C in Section 5 - Financial Statements for further information on foreign exchange and interest rate risks.

CYBERSECURITY

Our Cyber Resilience Process and Risk Management

Woodside’s approach to managing material risks from cybersecurity threats is integrated into our overall risk management processes as disclosed in this section 4.1.6 - Risk management and internal control.

Woodside’s cybersecurity resilience and risk management strategy and process are based on the National Institute of Standards and Technology (NIST) Cybersecurity Framework.

Woodside’s Cyber Resilience Process consists of various Group-wide policies, procedures and guidelines concerning cybersecurity matters. These documents are published within the Woodside Management System (WMS) and aim to:

1. Design, build and maintain Woodside’s Information Technology (IT), Operational Technology (OT) and Industrial Internet of Things systems with the right cybersecurity controls to support confidentiality, integrity and availability.

2. Monitor and strengthen Woodside’s cybersecurity posture while preventing, detecting, analysing and responding to cybersecurity incidents.

3. Embed a cyber-safe culture across Woodside, and foster industry collaboration.

4. Enable compliance with all applicable legislation.

The process involves five key activities: identify, protect, detect, respond, and recover.

In addition to the Cyber Resilience Process, the Data, Information and Systems Management process documented within the WMS, includes the Woodside Information Technology Systems - Conditions of Use Procedure. This procedure sets out Woodside’s mandatory conditions applicable to the use of Woodside’s IT, OT and digital Systems.

Woodside manages cybersecurity risks utilising the same Woodside risk management process as described in section 3.9 - Risk factors of the Annual Report.

Our Cyber Resilience Process Assurance

Woodside’s Cybersecurity team engages third-party vendors as part of our Cyber Resilience Process to perform a variety of technical assessments such as penetration testing. As part of these assessments, the third parties test our internal and external defenses, and help us with identifying any weaknesses and vulnerabilities within our environment. These assessment findings are risk ranked and prioritised for remediation.

Woodside internal audit team conducts audits on cybersecurity on a biennial basis. The internal audit function engages external expertise to conduct the audits. The most recent cybersecurity audit concluded in 2023.

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Third Party Cybersecurity Risk Management

Woodside identifies and manages risks from cybersecurity threats associated with third parties accessing, storing and processing Woodside data, through up-front cybersecurity assessment processes that leverage independently verified security programs including ISO 27001 certification and SOC 2 compliance, and through contractual terms and conditions.

Woodside manages risk of third-party access to Woodside systems through on-boarding and induction processes for personnel including mandatory training. Third-party personnel accessing Woodside systems are subject to the same cyber security controls as Woodside staff. This includes the requirement to complete annual cybersecurity training. Higher risk scenarios such as direct network connectivity from third-party networks are not permitted.

Material Impact from cybersecurity risks, threats or previous cybersecurity incidents

Risk from cybersecurity threats have the potential to materially affect Woodside’s business strategy, results of operations and financial conditions. This risk is described in section 3.9 - Risk factors.

Woodside continuously monitors its digital information landscape and has various threat detection measures in place. Woodside is not aware of any cybersecurity incidents or threats that have materially affected or are reasonably likely to materially affect our business strategy, results of operations or financial conditions.

GOVERNMENT REGULATIONS

Woodside’s assets and exploration, development, extraction and production operations are subject to a wide range of laws and regulations imposed by governments and regulatory bodies. These regulations touch all aspects of our assets, including how we extract, process and explore for oil and natural gas and how we conduct our business, including regulations governing matters such as environmental protection, land rehabilitation and facilities decommissioning, occupational health and safety, human rights, the rights and interests of First Nations peoples, competition, foreign investment, export, marketing of oil and natural gas, royalties and taxes.

The ability to extract and process oil and natural gas is fundamental to our business. In most jurisdictions, the rights to explore for and extract petroleum deposits are owned by the government. We obtain the right to access the land and extract the product by entering into licences or leases with the government that owns the oil or natural gas deposit. Usually, the right to explore for oil and natural gas carries with it the obligation to spend a defined amount of money on the exploration, or to undertake particular exploration activities.

We also rely on governments to grant the rights necessary to transport and treat the extracted petroleum to prepare it for sale. The terms of the right, including the time period of the right, vary depending on the laws of the relevant government or terms negotiated with the relevant government.

In certain jurisdictions where we have assets, such as Trinidad and Tobago and Senegal, a production sharing contract (PSC) governs the relationship between the government and companies (typically referred to as ‘Contractor’) concerning, among other things, how much of the oil and gas extracted from the country each party will receive. Under PSCs, the government awards exclusive rights for the execution of exploration, development and production activities to the Contractor in accordance with the PSC’s terms. Generally speaking, the Contractor bears the financial risk of the initiative to explore, develop and ultimately produce the field. When successful, the Contractor is permitted to use a certain set percentage of produced oil and gas to recover its capital and operational expenditures, often called ‘cost oil.’ The remaining production is split between the government and the Contractor at a rate determined by the government and set out in the PSC.

The PSC may also include additional fiscal terms such as royalties, production bonuses and tax treatment, and other contractual terms addressing domestic supply obligations, local content, measurement and valuation. PSCs are bilateral contracts negotiated between the Contractor and the government and so each is necessarily on different terms.

Applicable laws and regulations, and any permits that Woodside is required to obtain under these laws, may obligate Woodside to identify, avoid, mitigate and disclose environmental risks in various operational practices, including, among others, through pursuing and obtaining permits before commencing activities, restricting air and water emissions and waste discharges, limiting the type, quantity and concentration of various substances that can be utilised or released into the environment, addressing potential or actual impacts to protected species or cultural resources, monitoring or remediating contamination under certain circumstances, establishing and following certain inspection, testing, maintenance and decommissioning protocols, and disclosing certain operational practices. Moreover, environmental permits required for our operations may be subject to legal challenges by third parties, and such challenges can materially and adversely affect our operations to the extent they delay or prevent obtaining approvals or permits required for our operations, or otherwise require incurring increased costs in order to obtain such approvals or permits. Applicable environmental laws and regulations may also dictate worker health and safety and community notification procedures.

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In addition, from time to time, certain trade sanctions are adopted by the United Nations (UN) Security Council and/or various governments, including in the United Kingdom, the United States, the European Union (EU), China and Australia against certain countries, entities or individuals, that may restrict our ability to sell extracted minerals, oil or natural gas to, and/or our ability to purchase goods or services from, these countries, entities or individuals.

This summary focuses on the Australian and United States regulatory regimes, as well as certain regulations in Senegal. It is not a full summary of the regulatory regimes in those jurisdictions nor is it a complete list of the legislation and regulation that applies to Woodside. Woodside is also subject to environmental and other regulations to varying degrees in each of the jurisdictions in which it has assets and operations.

Australia

In Australia, petroleum exploration and development takes place within a legal framework characterised by a division of responsibilities between the federal and the state or territory governments. Exploration and production activities conducted onshore and within three nautical miles of the territorial sea baseline of the relevant state or territory are the responsibility of the individual state or territory governments. The Australian Federal Government has legislative responsibility for Australian offshore petroleum exploration and production beyond the three nautical mile territorial sea, which encompasses the area of most relevance to Woodside’s offshore activities. In addition, Woodside has certain onshore operations in Victoria and Western Australia which are subject to various state legislation.

Environmental regulation

Woodside’s Australian operations are subject to federal, state and local environmental laws and regulations. For offshore petroleum activities, these laws and regulations generally require the acquisition of an approval before an activity commences, and require that for an activity, environmental risks are identified and controls put in place to reduce or eliminate the risks.

For exploration drilling and seismic activities in the federal jurisdiction, this is outlined in an Environment Plan accepted by the National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA), an independent statutory authority; as an operation goes into construction, commissioning and production, a whole offshore project proposal and new or revised environment plan is required as the initial document to be submitted for approval. Subsequent environment plans for each activity are required to be submitted after the offshore project proposal has been approved. These laws and regulations also restrict the type, quantity and concentration of various substances that can be utilised or released into the environment in connection with marine and land-based activities; limit or prohibit drilling and seismic or production activities in and near certain environmentally sensitive or protected areas; and impose criminal and civil liabilities for pollution or other unauthorised impacts to the environment resulting from oil, natural gas and petrochemical operations.

The National Greenhouse and Energy Reporting Act 2007 (Cth) requires corporations that meet certain reporting thresholds to report company information about greenhouse gas (GHG) emissions and energy production and consumption as part of a single, national reporting scheme and establishes the Safeguard Mechanism which aims to keep certain GHG emissions at or below legislated limits, known as baselines, for Australia’s largest industrial facilities. In March 2023, the Safeguard Mechanism (Crediting) Amendment Bill 2023 was passed, which applied reforms to the Safeguard Mechanism from 1 July 2023 intended to reduce Scope 1 GHG emissions from Australia’s largest industrial facilities on a trajectory consistent with achieving Australia’s GHG emission reduction targets of 43% below 2005 levels by 2030 and net zero by 2050. There is ongoing public pressure in Australia on the government to accelerate its carbon emissions reduction program. As such, there remains significant uncertainty regarding the future of climate change regulation in Australia and the effect it may have on Woodside’s business.

In addition, Australian environmental laws and regulations also include restrictions on air emissions and water discharges resulting from the operation of drilling equipment, processing facilities, pipelines and transport vessels. These laws also regulate the use, management and disposal of hazardous materials and general waste; prohibit the clearing of native vegetation without approval; manage biodiversity and manage and authorise impacts to Aboriginal heritage; and require Woodside to prepare and implement safety and environmental management plans.

Woodside is required to provide bonds or maintain other forms of financial assurance for rehabilitation, clean-up or pollution prevention work that may be necessary as a result of the construction, operation, decommissioning or removal of a pipeline or other infrastructure and to report, monitor or remediate contamination under certain circumstances. Woodside is subject to ‘strict liability’ for oil spills, rendering it liable without regard to potential negligence or fault and may be subject to fines and other penalties for breaches of laws, regulations, licences or other approvals.

The requirements imposed by environmental laws and regulations are subject to change and have tended to become increasingly restrictive over time. The modification of existing foreign or domestic laws or regulations or the adoption of new laws or regulations curtailing exploratory or development drilling for oil and gas for economic, political, social, environmental or other reasons could have a material adverse effect on Woodside’s business, financial condition or results of operations.

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Fair Work Act and other related amendments

A significant number of changes to the Fair Work Act 2009 (Cth) (FW Act) and other related laws have been introduced over the past year.

In December 2022, the Australian Federal Government passed the Fair Work Legislation Amendment (Secure Jobs, Better Pay) Act 2022 (Cth) (SJBP Act) which introduced a raft of amendments into the FW Act with phased commencement dates over the course of 2023. All key provisions of the SJBP Act have now become effective.

Key material employment changes to the FW Act arising from the SJBP Act included expanded rights for employees to enforce flexible working arrangements, new restrictions on the use of fixed term (including ’maximum term’) employment contracts, prohibitions against pay secrecy, expanding the protected attributes (namely gender identity, intersex status and breastfeeding) against which discriminatory and other conduct are prohibited, broadening the ability of employees to extend and enforce unpaid parental leave, and providing additional avenues for workers to seek recourse against sexual harassment. The sexual harassment-related amendments in particular complement the commencement in December 2022 of a new positive duty to prevent sexual harassment in the Sex Discrimination Act 1984 (Cth) which the Australian Human Rights Commission can enforce from 12 December 2023. Additionally, the Australian Human Rights Commission Amendment (Costs Protection) Bill 2023 (Cth) is currently before Parliament and, if passed, will reduce the financial barriers for sexual harassment complainants to bring claims.

The SJBP Act also introduced a series of significant industrial relations changes to enterprise bargaining, including expanding the ability of employees and unions to seek multi-employer enterprise agreements, broadening the power of the Fair Work Commission to resolve (through mediation or conciliation) bargaining disputes before industrial action is taken and to intervene and make workplace determinations where bargaining becomes ‘intractable’. Other changes to bargaining introduced by the SJBP Act included amendments making it easier for employee bargaining representatives to commence bargaining to renew existing single-enterprise agreements, changes to the Fair Work Commission’s enterprise agreement approval-related requirements (including consideration of whether a proposed agreement has been genuinely agreed to and passes the ‘better- off-overall’ test) and substantially restricting the ability of employers to terminate nominally-expired enterprise agreements.

In June 2023, the Fair Work Legislation Amendment (Protecting Worker Entitlements) Act 2023 (Cth) was introduced, bringing further changes to the FW Act. Key changes arising from this Act include the expansion of unpaid parental leave rights (from 1 July 2023) and enshrining superannuation payments as an enforceable National Employment Standard under the FW Act (from 1 January 2024).

A further package of significant reforms is contained in the Australian Federal Government’s Fair Work Legislation Amendment (Closing Loopholes) Act 2023 (Cth) (Closing Loopholes Act). While various key aspects of the Closing Loopholes Act are the subject of a Senate Committee Inquiry (to be concluded from February 2024 onwards), numerous reforms contained in this reform package passed both houses of Parliament on 7 December 2023. Key provisions that have passed include new ‘same job, same pay’ provisions which give the Fair Work Commission the ability to make orders upon application requiring employers (excluding service contractors) to pay their employees who perform work for a ‘regulated host’ the same rate of pay as employees of that host (provided that the host’s employees perform work of the same kind). Among other provisions, new rights for workplace delegates to paid time off to attend training as well as reasonable time and access to employer facilities to communicate with eligible union members have also passed, as has a new criminal wage theft offence in respect of intentional underpayments.

The Closing Loopholes Act received Royal Assent on 14 December 2023. As such, many of the amendments from the Closing Loopholes Act - excluding the provisions relating to wage theft – commenced on 15 December 2023 (although same job, same pay-related regulated labour hire arrangement orders can only take effect on and after 1 November 2024). Proposed outstanding amendments that are the subject of the Senate Committee Inquiry, include changes to the definition of employment (including casual employment), increased civil penalties for underpayment contraventions, new right of entry rights relating to suspected underpayments and further limitations to the Fair Work Commission’s powers to reduce employee entitlements in the context of intractable bargaining disputes.

Woodside believes that it is well placed to confirm its compliance with the numerous new employment and industrial relations obligations that have been introduced over the past year. Moving forward, increased compliance-related demands are expected, especially given the further reforms that are anticipated in 2024.

Decommissioning liability amendments

On 2 September 2021, the Australian Federal parliament passed the Offshore Petroleum and Greenhouse Gas Storage Amendment (Titles Administration and Other Measures) Act 2021 (Cth) which, among other changes, amends the Offshore Petroleum and Greenhouse Gas Storage Act (Cth) (OPGGSA) to expand the trailing liability provisions. The amendments took effect from 2 March 2022. The expanded trailing liability regime gives NOPSEMA and the responsible Commonwealth Minister the ability to recall any titleholders, former titleholders and their respective related bodies corporate and ‘related persons’ to undertake decommissioning activities on a title area. These powers are retrospective in their application and apply to titles that are currently in force as well as to titles that ceased to be in force on or after 1 January 2021.

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Santos Barossa decision and Environment Plans

In December 2022, the Full Court of the Federal Court of Australia handed down its decision in Santos NA Barossa Pty Ltd v Tipakalippa [2002] FCAFC 193 (Appeal Decision). The Appeal Decision decided certain aspects of the requirements for consultation associated with the acceptance of environment plans for offshore petroleum activities by NOPSEMA, as required under the OPGGSA. Subsequently, NOPSEMA published a guideline for industry entitled “Consultation in the course of preparing an environment plan”. As a consequence of these events, Woodside has experienced delays in obtaining Environment Plans for petroleum activities in Commonwealth waters.

In September 2023, the Federal Court of Australia, in Cooper v National Offshore Petroleum Safety and Environmental Management Authority (No. 2) [2023] FCA 1158, found that NOPSEMA’s decision to accept, with conditions, Woodside’s environment plan for seismic surveys associated with the Scarborough project was invalid. Woodside was a party to this matter. Woodside submitted a revised environment plan for this activity in October 2023. Woodside’s revised environment plan was accepted by NOPSEMA in December 2023 and work was completed under the accepted environment plan in December 2023.

Refer to section 3.9 – Risk factors for further information on risks related to government regulations and other legal developments.

Domestic gas reservation policy

Under a Western Australian State Government policy (WA Domestic Gas Policy), introduced in 2006, gas equivalent to 15% of LNG production from LNG export projects is required to be reserved for domestic use as a condition of State approvals required for LNG projects. The policy is typically implemented through domestic gas commitment agreements entered into between project proponents and the State, allowing negotiations to occur on a case-by-case basis regarding the method by which the LNG project proponents fulfil their domestic gas commitments, including from alternative sources.

Woodside and (where applicable) its joint venture participants have domestic gas contractual commitments in place with the Western Australian State Government in respect to the North West Shelf (NWS), Pluto LNG, Scarborough and Wheatstone projects. In 2015, the NWS State Agreement (North West Gas Development (Woodside) Agreement 1979) was amended to include a new domestic gas commitment of 15% (or lesser approved amount) of total LNG quantity approved for use, supply or sale overseas to bring the NWS Project in line with the WA Domestic Gas Policy. In 2006, in connection with the final investment decision taken in respect of the Pluto LNG project, Woodside entered into an arrangement with the Western Australian State Government to market and make available for supply a quantity of domestic gas from Pluto, provided that Woodside was not required to supply domestic gas if it is not commercially viable to do so. In January 2021, Woodside signed a further agreement with the Western Australian State Government in which Woodside agreed to market and make available 45.6 PJ of additional domestic gas from its share of NWS Project gas, separate and in addition to the 2015 commitment from the NWS Joint Venture. In November 2021, Woodside signed a further domestic gas commitment agreement with the Western Australian State Government with respect to the Scarborough project pursuant to which, consistent with the WA Domestic Gas Policy, the Scarborough Joint Venture will make gas equivalent to 15% of its LNG exports available to the domestic market. In January 2021, Woodside signed a further domestic gas commitment agreement with the Western Australian State Government with respect to the Pluto acceleration project pursuant to which, consistent with the WA Domestic Gas Policy, Woodside will make gas equivalent to 15% of its LNG exports processed at the NWS Project as part of the Pluto acceleration project available to the domestic market. Woodside also has domestic gas commitments in respect to its interest in the Wheatstone LNG Project under a 2011 agreement with the Western Australian State Government.

Additional major legislation and regulations

Woodside’s Australian offshore operations beyond coastal waters are primarily governed by the OPGGSA and related legislation, which establishes a joint authority (Joint Authority) whereby relevant Australian state, territory and federal governments cooperate in the administration and supervision of petroleum activities in offshore areas beyond coastal waters. The OPGGSA provides for the grant of exploration permits, retention leases, production licences, pipeline licences and facilities licences within the areas of the OPGGSA’s jurisdictional operation. Within the coastal waters, petroleum operations are covered by the relevant state or Northern Territory legislation that is substantively similar to the OPGGSA.

The Offshore Petroleum and Greenhouse Gas Storage (Resource Management and Administration) Regulations 2011 (Cth) contain resource management provisions, including a requirement for the holder of a production licence to have in place a Field Development Plan approved by the Joint Authority before petroleum production can commence.

Many of Woodside’s operations rely on pipeline licences to transport oil and gas from the point of production to processing facilities and relevant markets. As mentioned above, the OPGGSA also provides for the grant of pipeline licences within the areas of the OPGGSA’s jurisdictional operation. Pipelines within the coastal waters of Western Australia are licensed under the Petroleum (Submerged Lands) Act 1982 (WA) and pipelines within the coastal waters of Victoria are licensed under the Offshore Petroleum and Greenhouse Gas Storage Act 2010 (Vic). Onshore pipelines in Western Australia are licensed under the Petroleum Pipelines Act 1969 (WA) and onshore pipelines in Victoria are licensed under the Pipelines Act 2005 (Vic).

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Woodside is also subject to the following laws, among others:

• Various petroleum taxes, including royalties, excise taxes, temporary levies, and the Petroleum Resource Rent Tax (PRRT). In May 2023, the Australian Government announced rules aimed at ensuring offshore LNG projects make minimum PRRT payments once 7 years from first production have elapsed. The rules are intended to be effective from 1 July 2023. The related amendments to PRRT legislation were introduced into the Federal parliament on 16 November 2023. It is not yet clear when these amendments will receive Royal Assent. Subject to becoming law, these rules are expected to apply to the Pluto LNG Project from 1 July 2023 and the Wheatstone LNG Project from 1 July 2024. The announcement also included a commitment to remake the Petroleum Resource Rent Tax Assessment Regulation 2015 (Cth) (GTP Regulation). The price of sales gas, which is processed into LNG, and the treatment of tolling arrangements are determined under the GTP Regulation. On 22 December 2023, the Australian Government released an Exposure Draft of a remade GTP Regulation for consultation.

• Australia’s competition laws contained in the Competition and Consumer Act 2010 (Cth), which prohibit, among other things, engaging in conduct with the purpose or effect of substantially lessening competition, price fixing, cartel conduct, market sharing, concerted practices or bid rigging. The Act was also recently amended by the Competition and Consumer (Gas Market Code) Regulations 2023 (Cth) (Gas Code), which became effective on 11 July 2023, to allow for the imposition of gas price controls in the eastern Australian gas market. Currently, the price of gas produced by Woodside and supplied into the eastern Australian gas market is capped at $12/ GJ until 1 July 2025. The price cap may be updated by the Australian Competition and Consumer Commission every two years. The Gas Code also introduces a mandatory code of conduct that establishes minimum conduct and process standards for commercial negotiations for wholesale gas contracts, including good faith obligations and a ‘reasonable pricing’ provision.

• The Australian Domestic Gas Security Mechanism (ADGSM), established pursuant to the Customs (Prohibited Exports) Regulations 1958 (Cth) and the Customs (Prohibited Exports) (Operation of the Australian Domestic Gas Security Mechanism) Guidelines 2023 (Cth), by which the Australian Government can require LNG projects to prohibit exports or find offsetting sources of gas, to ensure that there are sufficient supplies of natural gas for domestic use. The ADGSM is intended to be a measure of last resort where market based solutions and other regulatory interventions have failed.

• Laws protecting the rights and interests of First Nations Australians and their cultural heritage. Since 1992, Australian common law has recognised that, in certain circumstances, First Nations Australians may have rights and interests over land and waters in accordance with their traditional laws and customs. The Native Title Act 1993 (Cth) (NTA) and complimentary state legislation recognise and protect the native title rights and interests of native title holders and registered native title claimants. Multiple pieces of Australian state and federal government legislation protect Aboriginal cultural heritage, rights and access to land in Australia and many of these laws are subject to review and change to ensure a greater level of involvement of First Nations Australians in decisions that may impact cultural heritage and other rights and interests.

• The Greater Sunrise Special Regime (GSSR), established pursuant to the Maritime Boundaries Treaty which came into force on 30 August 2019. Woodside holds production sharing contracts and retention leases covering its petroleum interests within GSSR under joint Australian/Timor-Leste administrative control.

• The Foreign Acquisitions and Takeovers Act 1975 (Cth) (FATA), regulations under the FATA and Australia’s Foreign Investment Policy, which are intended to encourage foreign investment in Australia that is not contrary to the Australian national interest. As Woodside is a reporting entity of a critical gas asset within the meaning of the Security of Critical Infrastructure Act 2018 (Cth), it is considered a ‘national security business’ under the FATA, meaning that certain investments by foreign investors (including foreign government investors) must be notified to the Australian Government and require prior approval from the Australian Treasurer in accordance with the FATA.

• There is legislation covering work health and safety (WHS) in both state and federal jurisdictions, with separate onshore and offshore regulation. WHS laws aim to protect workers’ health and safety by imposing obligations on all parties who are in a position to contribute to the management of workplace risks, including manufacturers and suppliers of equipment and substances, as well as employers and workers (including employees and contractors). Among other things, Woodside, as operator of both onshore and offshore facilities, is required to develop and comply with a comprehensive ‘safety case’ which describes the facility and provides details on the hazards and risks associated with the facility, the risk controls and the safety management system that will be used to minimise relevant risks.

• State legislation regulates matters such as long service leave, workers’ compensation, as well as anti-discrimination and equal opportunity.

• The OPGGSA also provides the legislative framework for CCS and CCUS projects in offshore areas beyond coastal waters and the grant of assessment permits, holding leases and injection licences. Within Western Australian coast waters, on 29 November 2023, the Western Australian Government recently introduced the Petroleum Legislation Amendment Bill 2023 (WA) to enable the transportation and geological storage of GHG in Western Australia.

United States

In the United States, numerous federal agencies regulate specific portions of the industry and Woodside’s US operations. The US Federal Government directly regulates the development of hydrocarbon interests on federal lands, including those in the US Gulf of Mexico (GOM) and elsewhere in the Outer Continental Shelf (OCS). Federal leasing activities in recent years have been subject to political scrutiny and motivations, material uncertainties, delays, and legal challenges relating to potential impacts from climate change related to new offshore exploration and production or the adequacy of federal environmental reviews performed in connection with GOM lease auctions. Woodside is also subject to the following laws and regulatory agencies, among others.

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OCS regulation

The Outer Continental Shelf Lands Act (OCSLA) governs Woodside’s hydrocarbon activities on federal offshore oil and natural gas leases in the GOM. The OCSLA empowers the Department of the Interior (DOI), through its agencies the Bureau of Safety and Environmental Enforcement (BSEE), the Bureau of Ocean Energy Management (BOEM) and the Office of Natural Resources Revenue (ONRR), to administer and create regulations concerning the exploration and development of minerals in the OCS.

Leases on the OCS, which contain relatively standardised terms, are awarded under OSCLA authority through scheduled lease sales by BOEM based on competitive bidding and require compliance with detailed BSEE and BOEM regulations and orders issued pursuant to various federal laws, including the National Environmental Policy Act (NEPA) and the Coastal Zone Management Act (CZMA). For certain exploration and development activities, lessees are also required to obtain environmental permits from agencies such as the US Environmental Protection Agency (EPA).

Certain OCS activities are also subject to regulation under US Maritime Law by the US Coast Guard. In addition, offshore pipelines, including those located in the GOM, are subject to federal regulation including under the jurisdiction of the Federal Energy Regulatory Commission (FERC) and the Pipeline and Hazardous Materials Safety Administration (PHMSA), under the US Department of Transportation. BSEE has also adopted regulations for offshore pipelines under its jurisdiction covering similar matters.

Moreover, our US operations in the GOM are subject to extensive requirements related to the plugging and abandonment of wells and decommissioning of offshore structures and equipment. We may be required to post substantial financial assurance, such as surety bonds, or to otherwise demonstrate financial capability to support these decommissioning obligations, such as through access to insurance, the costs of which could be material. Further, BOEM is currently considering, through proposed updated financial assurance regulations, increasing its supplemental bonding requirements. Any such increase could generally drive up our operating costs by increasing the amount of security we are required to post and, in turn, stress the capacity of the surety bond market to provide sufficient bonds to meet resulting demands from the offshore oil and gas industry.

Environmental regulation

The Clean Air Act and comparable state laws and regulations govern emissions of various air pollutants through the issuance of permits and other authorization requirements. Since 2009, the EPA has been monitoring and regulating GHG emissions, including carbon dioxide and methane, from certain sources in the oil and gas sector due to their association with climate change. In addition, international climate efforts, including the 2015 Paris Agreement and the 2021 and 2022 Conferences of the Parties of the UN Framework Convention on Climate Change have resulted in commitments from many countries to reduce GHG emissions and have called for parties to eliminate certain fossil fuel subsidies and pursue further action on non-carbon dioxide GHGs.

In August 2022, President Biden signed into law the Inflation Reduction Act of 2022 (IRA), which expands policy support and incentives for deployment of CCUS, hydrogen and other low-carbon projects, including several enhancements to federal tax credits. The IRA also establishes a charge on methane emissions above a certain methane intensity threshold for facilities that report their GHG emissions under the EPA’s GHG Emissions Reporting Program Part 98 regulations. The methane emissions charge will be imposed beginning with respect to emissions reported for calendar year 2024. The methane emissions charge could increase our operating costs, which could adversely impact our business, financial condition and cash flows.

In December 2023, the EPA published a final rule to reduce methane and other pollution from oil and natural gas operations. Among other things, the final rule will phase out routine flaring of natural gas from new oil wells, require all well sites and compressor stations to be routinely monitored for leaks and provide companies greater flexibility to use innovative and cost- effective methane detection technologies. The IRA and the final rule will impact Woodside’s Shenzi asset and any future acquired GOM-operated assets.

The exploration, production, and transportation of crude oil and natural gas involves risk that hazardous liquids or flammable gases may be released into the environment and may cause substantial harm to the environment, natural resources, or human health and safety. Such incidents, as well as failure to comply with applicable environmental laws and regulations, may result in material expenditures for response actions, significant government civil or criminal fines and penalties, liability to government agencies for natural resources damages, and significant business interruption. In addition, a spill on or related to our properties and operations could expose us to joint and several and strict liability, without regard to fault. Existing and new laws and regulations could require us to evaluate and upgrade existing infrastructure and operational practices on an accelerated basis or pursue additional capital projects, any or all of which could result in increased operating costs, which in turn could have a material adverse effect on our business, financial condition or results of operations.

Laws and regulations are frequently subject to change, and the general trend in the United States has been for these governmental agencies to continue to evaluate and, as necessary, develop and implement new, more restrictive permitting, performance and disclosure requirements, particularly with respect to the protection of the environment, GHG emissions, natural resources, and worker health and safety. The 2024 US election cycle (including a presidential election) contributes to uncertainty on the future direction of regulatory change. In addition, offshore wind and carbon sequestration have the potential to increase competing uses of the OCS, which may limit future opportunities for offshore oil and gas operations. The modification of existing laws or regulations or the adoption of new laws or regulations curtailing or imposing greater restrictions on exploratory or development drilling for oil and gas for economic, political, social, environmental or other reasons could have a material adverse effect on our business, financial condition or results of operations.

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Senegal

In Senegal, Woodside’s PSC and the prospecting, exploration, exploitation and transportation of hydrocarbons, as well as the tax rules for such activities, are primarily governed by Law no. 98-05 dated 8 January 1998 (Petroleum Code) and its implementing decree no. 98-810 dated 6 October 1998. The Petroleum Code determines that the Senegalese Ministry of Petroleum and Energy is the competent authority for its implementation and is responsible for authorising activities for oil and gas prospecting, exploration, exploitation and transportation. While a revised Petroleum Code was introduced in 2019, the terms of that legislation state that any PSC issued prior to the introduction of the 2019 Petroleum Code retain their legal regime, and as such, the 1998 Petroleum Code continues to apply to Woodside’s PSC. There is also other legislation and regulation that applies to Woodside’s activities in Senegal including, without limitation, in respect of the environment and local content requirements.

MATERIAL LIMITATIONS

Woodside has certain obligations as part of its operations in Western Australia to provide natural gas into the Western Australian domestic market. Please refer to ‘Government regulations - Domestic gas reservation policy’ in this section for further information.

Woodside is subject to ordinary course production sharing contract limitations in Senegal. Refer to ‘Government regulations - Other jurisdictions’ in this section for further information.

SUMMARY OF MATERIAL LEGAL PROCEEDINGS

Woodside is involved from time to time in legal proceedings and governmental investigations of a character normally incidental to its business, including claims and pending actions against it seeking damages, or clarification or prosecution of legal rights and regulatory inquiries regarding business practices. Insurance or other indemnification protection may offset the financial impact on Woodside of a successful claim.

Except as set forth below, there are no governmental, legal or arbitral proceedings (including any such proceedings which are pending or threatened and of which Woodside is aware) which may have, or have had during the 12 months prior to the date of this report a significant effect on Woodside’s financial position or profitability:

• In June 2022, the Australian Conservation Foundation Incorporated (ACF) (represented by the Environmental Defenders Office Ltd) commenced Federal Court of Australia proceedings in relation to the environmental assessment of the Scarborough project. The ACF is seeking a final injunction to restrain Woodside from carrying out offshore project activities for the Scarborough project. The trial has been set down for an estimate of three weeks, commencing on 2 September 2024.

• In addition, the proceedings arising from the application filed by the Conservation Council of Western Australia (CCWA) seeking judicial review of a decision by the CEO of the Western Australian Department of Water and Environmental Regulation to grant Woodside a works approval for the Pluto Train 2 project were settled in 2023.

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6.4 Additional Information

Shareholder statistics

Information in this section is current as at 13 February 2024, unless otherwise stated. References to ‘the company’ or ‘Woodside’ are to Woodside Energy Group Ltd and references to shareholdings and other equity on those pages are to equity in Woodside Energy Group Ltd.

NUMBER OF SHAREHOLDINGS

There were 620,891 shareholders.

DISTRIBUTION OF SHAREHOLDINGS

The following table shows the distribution of Woodside Energy Group Ltd shareholders by size of shareholding and number of shareholders and shares as of 13 February 2024.

Size of shareholding	Number of holders	Number     of shares1	% of issued capital
1–1,000	503,618	118,595,289	6.25
1,001–5,000	100,451	211,804,045	11.15
5,001–10,000	11,202	77,790,076	4.10
10,001–100,000	5,462	110,913,590	5.84
Greater than 100,000	158	1,379,646,771	72.66
Total	620,891	1,898,749,771	100.00

1 All issued shares carry voting rights on a one-for-one basis.

UNMARKETABLE PARCELS

There were 62,107 members holding less than a marketable parcel of shares in the company (based on the closing market price of $31.13 on 13 February 2024).

 Geographical distribution of shareholders and shareholding

Registered address	Number of holders	Number     of shares	% of issued capital
Australia	602,134	1,886,776,367	99.37
New Zealand	7,530	6,333,881	0.33
United Kingdom	3,225	2,130,124	0.11
United States of America	1,885	1,122,322	0.06
Other	6,117	2,387,077	0.13
Total	620,891	1,898,749,771	100.00

US shareholdings

Classification of holder	Number of holders	Number     of shares	% of issued capital
Registered holders of voting securities	1,885	1,122,322	0.06
ADR holders	2,338	47,844,455	2.52

Distribution of rights holdings

The following table shows the distribution of Woodside Energy Group Ltd rights by size of holding and number of holders and rights as of 13 February 2024.

Size of holding	Number of holders		Number     of rights		% of rights on issue
1–1,000		705		414,060		2.87
1,001–5,000		3,275		7,512,825		52.01
5,001–10,000		243		1,589,691		11.00
10,001–100,000		142		3,475,465		24.06
Greater than 100,000		7		1,452,761		10.06
Total		4,372		14,444,802		100.00

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 TWENTY LARGEST SHAREHOLDERS

The following table sets out the 20 largest shareholders of ordinary shares listed on the Woodside Energy Group Ltd share register and the details of their shareholding as of 13 February 2024.

Shareholders		Shares Held		% of issued capital
HSBC CUSTODY NOMINEES (AUSTRALIA) LIMITED		565,630,320		29.79
J P MORGAN NOMINEES AUSTRALIA PTY LIMITED		341,304,362		17.98
CITICORP NOMINEES PTY LIMITED		173,343,239		9.13
CITICORP NOMINEES PTY LIMITED <CITIBANK NY ADR DEP A/C>		48,744,455		2.57
NATIONAL NOMINEES LIMITED		38,168,780		2.01
BNP PARIBAS NOMS PTY LTD		36,196,274		1.91
COMPUTERSHARE CLEARING PTY LTD <CCNL DI A/C>		31,200,312		1.64
BNP PARIBAS NOMINEES PTY LTD ACF CLEARSTREAM		19,941,977		1.05
BNP PARIBAS NOMINEES PTY LTD <AGENCY LENDING A/C>		13,561,156		0.71
HSBC CUSTODY NOMINEES (AUSTRALIA) LIMITED <NT-COMNWLTH SUPER CORP A/C>		13,363,475		0.70
CITICORP NOMINEES PTY LIMITED <COLONIAL FIRST STATE INV A/C>		9,617,598		0.51
BNPP NOMS PTY LTD HUB24 CUSTODIAL SERV LTD		8,617,134		0.45
NETWEALTH INVESTMENTS LIMITED <WRAP SERVICES A/C>		7,606,775		0.40
AUSTRALIAN FOUNDATION INVESTMENT COMPANY LIMITED		3,816,348		0.20
ARGO INVESTMENTS LIMITED		3,571,455		0.19
AUSTRALIAN FOUNDATION INVESTMENT COMPANY LIMITED		2,954,652		0.16
NETWEALTH INVESTMENTS LIMITED <SUPER SERVICES A/C>		2,837,416		0.15
MUTUAL TRUST PTY LTD		2,798,294		0.15
HSBC CUSTODY NOMINEES (AUSTRALIA) LIMITED		2,518,358		0.13
HSBC CUSTODY NOMINEES (AUSTRALIA) LIMITED - A/C 2		2,455,728		0.13
	1,328,248,108		69.95

SUBSTANTIAL SHAREHOLDERS

Substantial shareholders as disclosed in substantial shareholder notices given to the company are as follows:

		Date of last notice
Substantial shareholder	Title of class	Date received	Date of change	Shares held1	% of total voting rights1
BlackRock Group (BlackRock Inc. and subsidiaries)	Ordinary shares	8 February 2024	5 February 2024	133,581,277	7.03
BlackRock Group (BlackRock Inc. and subsidiaries)	ADR 1:1	8 February 2024	5 February 2024	1,992,368	0.11
Vanguard Group (The Vanguard Group, Inc. and its controlled entities)	Ordinary shares	23 June 2022	17 June 2022	95,642,3122	5.037
State Street Corporation and subsidiaries	Ordinary shares	6 September 2022	1 September 2022	95,780,835	5.04

1 These figures quoted are based on the number owned and voting rights provided in the latest applicable substantial shareholder notice.

2 As stated in its latest substantial shareholder notice, Vanguard Group also holds 42,270 shares of Woodside ADR.

BUY BACKS

There are currently no on-market buy backs.

ESCROWED AND RESTRICTED SECURITIES

Woodside Energy Group Ltd does not have any restricted securities or securities subject to voluntary escrow on issue.

ON-MARKET PURCHASES FOR WOODSIDE EMPLOYEE INCENTIVE PLANS^1,2

Period	Total shares purchased	Average price paid per share (A$)	Average price paid per share (US$)	Number of shares purchased for employee plans
February 2023	399,500	35.99	24.22	399,500
March 2023	399,500	36.57	24.67	399,500
August 2023	1,533,121	37.66	24.21	1,533,121
Total	2,332,121	37.33	24.42	2,332,121

1 These shares were purchased to satisfy employee incentive plan requirements.

2 The on-market purchases for Woodside employee incentive plans total 0.12% of total share capital.

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ANNUAL GENERAL MEETING

The 2024 Annual General Meeting (AGM) of Woodside Energy Group Ltd will be held on 24 April 2024. Details of the business of the meeting will be provided in the AGM notice. The AGM will be webcast live on the internet. An archived version of the webcast will be placed on the Woodside website to enable the proceedings to be viewed at a later time. The closing date for receipt of director nominations was 19 February 2024.

DOCUMENTS ON DISPLAY

Documents filed by Woodside on the ASX are available at asx.com.au and documents filed with the Financial Conduct Authority (FCA) in the UK, including copies of announcements made to the LSE, are available at data.fca.org.uk/#/nsm/nationalstoragemechanism. Woodside files Annual Reports and other reports and information with the US Securities and Exchange Commission (SEC). These filings are available on the SEC’s website at sec.gov.

Documents filed on the ASX or with the FCA or SEC are not incorporated by reference into this report. The documents referred to in this report as being available on our website, woodside.com, are not incorporated by reference and do not form part of this report.

WOODSIDE ENERGY GROUP LTD

Woodside was registered under Australian corporate law in 1971 and listed on the ASX on 18 November 1971. Woodside’s shares are currently listed on the ASX and LSE under the ticker symbol ‘WDS’ and its American Depositary Shares (ADS) are listed on the NYSE under the symbol ‘WDS’. Following the approval of Woodside shareholders at Woodside’s Annual General Meeting on 19 May 2022, Woodside changed its name from ‘Woodside Petroleum Ltd.’ to ‘Woodside Energy Group Ltd’ effective 20 May 2022.

Woodside’s registered office is Mia Yellagonga, 11 Mount Street, Perth, Western Australia 6000, Australia, telephone +61 8 9348 4000. Additional information about Woodside can be found on its website at woodside.com.

DIVIDEND PAYMENTS

Woodside determines its dividends in US dollars as this is our functional and presentation currency. Woodside pays its dividends in Australian dollars, unless a shareholder’s registered address is in the United Kingdom (UK), where they are paid in UK pounds sterling, or in the United States of America (USA), where they are paid in US dollars, or in New Zealand (NZ), where they are paid in NZ dollars.

Shareholders may have their dividends paid directly into any bank or building society account in Australia, the USA, the UK or NZ. Payments are electronically credited on the dividend payment date and confirmed by payment advice. To request direct crediting of dividend payments, please contact the share registry or visit the share registry website (investorcentre.com/wds).

Shareholders must make an election to alter their dividend currency by the business day after the record date for the dividend.

Shareholders who reside outside the USA, the UK, Australia and NZ may elect to receive their dividend electronically in their local currency using the share registry’s Global Wire Payment Service. For a list of currencies offered and how to subscribe to the service, please contact the share registry.

For more information on this topic, refer to Woodside’s website for the history of dividends paid by the company at woodside. com

CHANGE OF ADDRESS OR BANKING DETAILS

Shareholders should immediately notify the share registry of any change to their address or banking arrangements for dividends electronically credited to a bank account.

For more information on this topic, refer to the share registry website to change details at investorcentre.com/wds

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AUSTRALIAN SECURITIES EXCHANGE

Investors who hold Woodside shares listed on the ASX seeking information about their shareholdings should contact Woodside’s Australian share registry:

Computershare Investor Services Pty Limited

Address:	Level 17, 221 St Georges Terrace Perth WA 6000
Postal address:	GPO Box D182 Perth WA 6840
Telephone:	1300 558 507 (within Australia) +61 3 9415 4632 (outside Australia)
Email:	web.queries@computershare.com.au
Website:	investorcentre.com/wds

The share registry can assist with queries on share transfers, dividend payments, the dividend reinvestment plan, notification of tax file numbers and changes of name, address or bank account details.

For security reasons, you will need your Security Reference Number (SRN) or Holder Identification Number (HIN) when communicating with the share registry. The share registry website allows shareholders to make changes to address and banking details online.

For more information on this topic, refer to the share registry website to change details at investorcentre.com/wds

LONDON STOCK EXCHANGE

Woodside shares are traded on the Main Market for listed securities of the London Stock Exchange (with trades settled in the form of UK Depository Interests) under the symbol ‘WDS’. Woodside has appointed Computershare Investor Services PLC as its registrar.

If you have a query regarding your shareholding, please contact Computershare in the United Kingdom:

Computershare Investor Services Pty Limited

Postal address:	Computershare Investor Services PLC
	The Pavilions, Bridgwater Road Bristol BS99 6ZZ
Telephone:	+44 (0) 370 703 6075
Email:	WebCorres@computershare.co.uk
Website:	computershare.com/uk

AMERICAN DEPOSITARY RECEIPTS

We have an American Depositary Receipts (ADR) program. The ADR program has a 1:1 ordinary share to American Depositary Share (ADS) ratio.

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Depositary fees

Citibank serves as the depositary bank for our ADR program. ADR holders agree to the terms in the deposit agreement filed with the SEC for depositing ADSs or surrendering the ADSs for cancellation and for certain services as provided by Citibank. Holders are required to pay all fees for general depositary services provided by Citibank in each of our ADR programs, as set forth in the table below.

Service	Fees
Issuance of ADSs upon deposit of shares.	Up to $0.05 per ADS issued.
Cancellation of ADSs.	Up to $0.05 per ADS cancelled.
Distribution of cash dividends or other cash distributions.	Up to $0.05 per ADS held.
Distribution of securities other than ADSs or rights to purchase additional ADSs.	Up to $0.05 per ADS held.
ADS Services.	Up to $0.05 per ADS held on the applicable record date(s) established by the Depositary.
Registration of ADS transfers.	Up to $0.05 per ADS transferred.
Conversion of ADSs of one series for ADSs of another series.	Up to $0.05 per ADS converted.

FEES PAYABLE BY THE DEPOSITARY TO THE ISSUER

Citibank reimburses Woodside for certain expenses Woodside incurs in connection with its ADR program, subject to certain ceilings. These reimbursable expenses currently include, but are not limited to, legal, accounting and reserve engineer fees, listing fees, expenses related to investor relations in the United States, fees payable to service providers for the distribution of material to ADR holders and expenses to remain in compliance with applicable US laws and NYSE listing standards. Citibank has further agreed to waive certain fees in connection with Woodside’s ADR program. These waived expenses currently include, but are not limited to, standard costs associated with the administration of the ADR program and certain fees in connection with issuance of ADRs under Woodside’s equity compensatory plans. For the year ended 31 December 2023, direct reimbursements and waived fees totalled approximately US$1,633,000. Under certain circumstances, including termination of our ADS program or removal of our Depositary, we may be required to repay to the Depositary a portion of the amounts reimbursed in prior periods.

The ADSs issued under our ADR programs trade on the NYSE under the stock ticker WDS. As of 13 February 2024, there were 47,844,455 ADSs on issue and outstanding in the Woodside ADS program.

ADR holders should deal directly with Citibank on all matters related to their ADRs, using the details below. Enquiries should be directed to:

Citibank Shareholder Services

Address:	PO Box 43077 Providence Rhode Island 02940-3077
USA Toll Free:	1-877-CITI-ADR
International:	+1 781 575 4555
Email:	citibank@shareholders-online.com

Investor Relations enquiries

Address:	Woodside Energy Group Ltd Mia Yellagonga 11 Mount Street Perth WA 6000
Postal address:	GPO Box D188 Perth WA 6840
Telephone:	+61 8 9348 4000
Email:	investor@woodside.com
Website:	woodside.com

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For additional information regarding Woodside ADSs, please refer to Exhibit 2.1—Description of Securities to this report on Form 20-F.

EXCHANGE CONTROLS

Under Australian foreign exchange controls currently in effect, transfers of capital to and from Australia are not subject to prior government approval and, except as described below, Australia does not restrict the flow of currency into or out of the country. Regulations may be made under the Anti-Money Laundering and Counter-Terrorism Financing Act 2006 (Cth) of Australia (AML/ CTF Act) prohibiting the entering into of transactions involving prescribed foreign countries. As of the date of this report, no such regulations are in place. To control tax evasion and money laundering, the AML/CTF Act also requires certain transactions to be reported to the Australian Transaction Reports and Analysis Centre (AUSTRAC) and prohibits reporting entities from providing certain ‘designated services’ to customers without having complied with certain obligations under the AML/CTF Act (for example ‘know your customer’ checks). In addition, the Financial Transaction Reports Act 1988 (Cth) (FTR Act) imposes certain obligations on solicitors and ‘cash dealers’ to report ‘significant cash transactions’. The Autonomous Sanctions Regulations 2011 (Cth) promulgated under the Autonomous Sanctions Act 2011 (Cth) of Australia, the Charter of the United Nations Act 1945 (Cth) of Australia and other acts and regulations in Australia restrict or prohibit payments, transactions or other dealings with assets having a proscribed connection with certain countries or named individuals or entities subject to financial sanctions or identified with terrorism. The Australian Department of Foreign Affairs and Trade (DFAT) maintains a list of all persons and entities subject to financial sanctions or having a proscribed connection with terrorism which is available to the public at DFAT’s website. There are no specific restrictions regarding the remittance of profits, dividends or capital.

TAXATION

This section describes the material United States and Australian Federal income tax consequences to a US holder (as defined below) of owning shares or ADSs (together, ‘Woodside Securities’). It applies to you only if you acquire your shares or ADSs and you hold your shares or ADSs as capital assets for tax purposes. This discussion addresses only United States and Australian Federal income taxation and does not discuss all of the tax consequences that may be relevant to you in light of your individual circumstances, including foreign, state or local tax consequences, estate and gift tax consequences, and tax consequences arising under the Medicare contribution tax on net investment income or the alternative minimum tax. This section does not apply to you if you are a member of a special class of holders subject to special rules, including:

• a dealer in securities,

• a trader in securities that elects to use a mark-to-market method of accounting for securities holdings,

• a tax-exempt organisation,

• a life insurance company,

• a person that actually or constructively owns 10% or more of the combined voting power of our voting stock or of the total value of our stock,

• a person that holds shares or ADSs as part of a straddle or a hedging or conversion transaction,

• a person that purchases or sells shares or ADSs as part of a wash sale for tax purposes, or

• a person whose functional currency is not the US dollar.

This section is based on the Internal Revenue Code of 1986, as amended, its legislative history, existing and proposed regulations, published rulings and court decisions, all as currently in effect, as well as on the Convention Between the United States of America and Australia (the Treaty). These authorities are subject to change, possibly on a retroactive basis. In addition, this section is based in part upon the representations of the Depositary and the assumption that each obligation in the Deposit Agreement will be performed in accordance with its terms.

You are a US holder if you are a beneficial owner of shares or ADSs and you are, for United States Federal income tax purposes:

• a citizen or resident of the United States,

• a domestic corporation,

• an estate whose income is subject to United States Federal income tax regardless of its source, or

• a trust if a United States court can exercise primary supervision over the trust’s administration and one or more United States persons are authorised to control all substantial decisions of the trust.

If an entity or arrangement that is treated as a partnership for United States Federal income tax purposes holds the shares or ADSs, the United States Federal income tax treatment of a partner will generally depend on the status of the partner and the tax treatment of the partnership. A partner in a partnership holding the shares or ADSs should consult its tax advisor with regard to the United States Federal income tax treatment of an investment in the shares or ADSs.

You should consult your own tax advisor regarding the United States Federal, state and local and Australian Federal tax consequences of owning and disposing of shares and ADSs in your particular circumstances. In particular, you should confirm whether you qualify for the benefits of the Treaty and the consequences of failing to do so.

In general, and taking into account the earlier assumptions, for United States Federal income tax purposes, if you hold ADRs evidencing ADSs, you will be treated as the owner of the shares represented by those ADRs.

Exchanges of shares for ADRs, and ADRs for shares, generally will not be subject to United States Federal income tax.

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Material United States Federal Income Tax Consequences

The tax treatment of your shares or ADSs will depend in part on whether or not we are classified as a passive foreign investment company, or PFIC, for United States Federal income tax purposes. Except as discussed below under “PFIC Classification”, this discussion assumes that we are not classified as a PFIC for United States Federal income tax purposes.

Taxation of Distributions

Under the United States Federal income tax laws, the gross amount of any distribution we pay out of our current or accumulated earnings and profits (as determined for United States Federal income tax purposes), other than certain pro-rata distributions of our shares, will be treated as a dividend that is subject to United States Federal income taxation. If you are a noncorporate U.S. holder, dividends that constitute qualified dividend income will be taxable to you at the preferential rates applicable to long-term capital gains provided that you hold the shares or ADSs for more than 60 days during the 121-day period beginning 60 days before the ex-dividend date and meet other holding period requirements.

Dividends we pay with respect to the shares or ADSs generally will be qualified dividend income provided that, in the year that you receive the dividend, we are eligible for the benefits of the Treaty. We believe that we are currently eligible for the benefits of the Treaty and we therefore expect that dividends on the shares and ADS will be qualified dividend income, but there can be no assurance that we will continue to be eligible for the benefits of the Treaty.

You must include any Australian tax withheld from the dividend payment in this gross amount even though you do not in fact receive it. The dividend is taxable to you when you, in the case of shares, or the Depositary, in the case of ADSs, receive the dividend, actually or constructively. The dividend will not be eligible for the dividends-received deduction generally allowed to United States corporations in respect of dividends received from other United States corporations. The amount of the dividend distribution that you must include in your income will be the US dollar value of the Australian dollar payments made, determined at the spot Australian dollar/US dollar rate on the date the dividend is distributed, regardless of whether the payment is in fact converted into US dollars. Generally, any gain or loss resulting from currency exchange fluctuations during the period from the date the dividend is distributed to the date you convert the payment into US dollars will be treated as ordinary income or loss and will not be eligible for the special tax rate applicable to qualified dividend income. The gain or loss generally will be income or loss from sources within the United States for foreign tax credit limitation purposes. Distributions in excess of current and accumulated earnings and profits, as determined for United States Federal income tax purposes, will be treated as a non-taxable return of capital to the extent of your basis in the shares or ADSs and thereafter as capital gain. However, we do not expect to calculate earnings and profits in accordance with United States Federal income tax principles. Accordingly, you should expect to generally treat distributions we make as dividends.

Subject to certain limitations, the Australian tax withheld in accordance with the Treaty and paid over to Australia will generally be creditable against your United States Federal income tax liability. To the extent a reduction or refund of the tax withheld is available to you under Australian law or under the Treaty, the amount of tax withheld that could have been reduced or that is refundable will not be eligible for credit against your United States Federal income tax liability.

Dividends will generally be income from sources outside the United States and will generally be ‘passive’ income for purposes of computing the foreign tax credit allowable to you.

Taxation of Capital Gains

If you are a US holder and you sell or otherwise dispose of your shares or ADSs, you will recognise capital gain or loss for United States Federal income tax purposes equal to the difference between the US dollar value of the amount that you realise and your tax basis, determined in US dollars, in your shares or ADSs. Your tax basis would generally equal the cost of your shares or ADSs, or if you received the shares or ADSs pursuant to a taxable distribution, the fair market value of the shares or ADSs at the time of such distribution, reduced by any distributions on the shares or ADSs that were treated as a return of capital for United States Federal income tax purposes. Capital gain of a non-corporate US holder is generally taxed at preferential rates where the property is held for more than one year. The gain or loss will generally be income or loss from sources within the United States for foreign tax credit limitation purposes. Your ability to deduct capital losses is subject to limitations.

PFIC Classification

We believe that we should not be currently classified as a PFIC for United States Federal income tax purposes and we do not expect to become a PFIC in the foreseeable future. However, this conclusion is a factual determination that is made annually and thus may be subject to change. It is therefore possible that we could become a PFIC in a future taxable year.

In general, we will be a PFIC in a taxable year if:

• at least 75% of our gross income for the taxable year is passive income; or

• at least 50% of the value, determined on the basis of a quarterly average, of our assets in such taxable year is attributable to assets that produce or are held for the production of passive income.

If we were to be treated as a PFIC and you are a US holder, gain realised on the sale or other disposition of your shares or ADSs would in general not be treated as capital gain. Instead, you would generally be treated as if you had realised such gain and certain ‘excess distributions’ ratably over your holding period for the shares or ADSs and would be taxed at the highest tax rate in effect for each previous year to which the gain was allocated in which we were a PFIC with respect to you, together with an interest charge in respect of the tax attributable to each such year. With certain exceptions, your shares or ADSs will be treated as stock in a PFIC if we were a PFIC at any time during your holding period in your shares or ADSs. Dividends that you receive from us will not be eligible for the special tax rates applicable to qualified dividend income if we are a PFIC or are treated as a PFIC with respect to you either in the taxable year of the distribution or the preceding taxable year, but instead will be taxable at rates applicable to ordinary income. If you own shares or ADSs during any year that we are a PFIC with respect to you, you may be required to file Internal Revenue Service (IRS) Form 8621.

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Material Australian tax considerations

This section is based on the Income Tax Assessment Act 1936 (Cth) and the Income Tax Assessment Act 1997 (Cth), as amended, its legislative history, existing and proposed regulations, published rulings and court decisions, all as currently in effect, as well as on the Treaty. These authorities are subject to change, possibly on a retroactive basis.

Dividends (including other distributions treated as dividends for Australian tax purposes) paid by Woodside to a US Holder that is not an Australian resident for Australian tax purposes will generally not be subject to Australian withholding tax if they are fully franked (broadly, where a dividend is franked, tax paid by Woodside is imputed to the shareholders).

Dividends paid to such US Holders, which are not fully franked, will generally be subject to Australian withholding tax not exceeding 15% only to the extent (if any) that the dividend is neither:

• franked; nor

• declared by Woodside to be conduit foreign income. (Broadly, this means that the relevant part of the dividend is declared to have been paid out of foreign source amounts received by Woodside that are not subject to tax in Australia, such as dividends remitted to Australia by foreign subsidiaries).

The Australian withholding tax outcome described above applies to US Holders who are eligible for benefits under the Tax Convention between Australia and the US as to the Avoidance of Double Taxation (the Australian Tax Treaty). Otherwise, the rate of Australian withholding tax may be 30%.

In contrast, dividends (including other distributions treated as dividends for Australian tax purposes) paid by Woodside to a US Holder may instead by taxed by assessment in Australia if the US Holder:

• is an Australian resident for Australian tax purposes (although tax will generally not exceed 15% where the US Holder is eligible for benefits under the Australian Tax Treaty as a treaty resident of the US and any franking credits may be creditable against their Australian income tax liability); or

• carries on business in Australia through a permanent establishment as defined in the Australian Tax Treaty, or performs personal services from a fixed base in Australia, and the shareholding in respect of which the dividend is paid is effectively connected with that permanent establishment or fixed base, (however, in such a case any franking credits may be creditable against the Australian income tax liability).

The treatment of dividends outlined above may be modified where the shareholding in Woodside is held through a trust, limited partnership, limited liability company, pension fund, sovereign wealth fund or other investment vehicle. Affected US Holders should seek their own advice in relation to such arrangements.

Material Australian tax considerations—disposals of Woodside Securities

Gains made by US Holders on the sale of Woodside Securities will generally not be taxed in Australia.

However, the precise Australian tax treatment of gains made by US Holders on the sale of Woodside Securities generally depends on whether or not the gain is an Australian sourced gain of an income nature for Australian income tax purposes.

Where the gain is of an income nature, a US Holder will generally only be liable to Australian income tax on an assessment basis (whether or not they are also an Australian resident for Australian tax purposes) if:

• they are not eligible for benefits under the Australian Tax Treaty and the gain is sourced in Australia for Australian tax purposes; or

• they are eligible for benefits under the Australian Tax Treaty but the gain constitutes any of the following (in which case the gain will be deemed to have an Australian source):

• business profits of an enterprise attributable to a permanent establishment situated in Australia through which the enterprise carries on business in Australia; or

• income or gains from the alienation of property that form part of the business property of a permanent establishment of an enterprise that the US Holder has in Australia, or pertain to a fixed base available to the US Holder in Australia for the purpose of performing independent personal services; or

• income derived from the disposition of shares in a company, the assets of which consist wholly or principally of real property (which includes rights to exploit or to explore for nature resources) situated in Australia, whether such assets are held directly or indirectly through one or more interposed entities.

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Where the gain is not taxed as Australian sourced income, the US Holder will generally only be liable to Australian capital gains tax on an assessment basis if they acquired (or are deemed to have acquired) their Woodside Securities after 19 September 1985 and one or more of the following applies:

• the US Holder is an Australian resident for Australian tax purposes; or

• the Woodside Securities have been used by the US Holder in carrying on a business through permanent establishment in Australia; or

• the Woodside Securities constitute an ‘indirect Australian real properly interest’ for Australian CGT purposes – this will generally be the case if the US Holder (either alone or together with associates) directly or indirectly owns or owned 10% or more of the issued share capital of Woodside at the time of disposal or throughout a 12-month period during the two years prior to the time of disposal and, at the time of the disposal, the sum of market values of Woodside’s assets (held directly or through interposed entities) that are not taxable Australian real property at that time (which, for these purposes includes mining, quarrying or prospecting rights in respect of minerals, petroleum or quarry materials situated in Australia); or

• the US Holder is an individual who is not eligible for benefits under the Australian Tax Treaty as a treaty resident of the US and elected on becoming a non-resident of Australia to continue to have the Woodside Securities subject to Australian capital gains tax.

In certain circumstances, if the Woodside Securities constitute an ‘indirect Australian real property interest’ for Australian CGT purposes, the purchaser may be required to withhold under the non-resident CGT withholding regime an amount equal to 12.5% of the purchase price in situations including where the acquisition is undertaken by way of an off-market transfer. It has been announced this withholding rate will be increased to 15% in respect of sale contracts entered into on or after 1 January 2025.

Affected US Holders should seek their own advice in relation to how this withholding regime may apply to them.

The comments above on the sale of Woodside Securities do not apply:

• to temporary residents of Australia who should seek advice that is specific to their circumstances; or

• if the Investment Management Regime (IMR) applies to the US Holder, which exempts from the Australian income tax and capital gains tax gains made on disposal by certain categories of non-resident funds – called IMR entities – of (relevantly) portfolio interests in Australian public companies (subject to a number of conditions). The IMR exemptions broadly apply to widely held IMR entities in relation to their direct investments and indirect investments made through an independent

Australian fund manager. The exemptions apply to gains made by IMR entities that are treated as companies for Australian tax purposes as well as gains made by non-resident investors in IMR entities that are treated as trusts and partnerships for Australian tax purposes.

THE FOREGOING DISCUSSION IS NOT TAX ADVICE OR A COMPREHENSIVE DISCUSSION OF ALL US AND AUSTRALIAN FEDERAL INCOME TAX CONSEQUENCES TO US HOLDERS OF WOODSIDE SECURITIES. SUCH HOLDERS SHOULD CONSULT WITH, AND RELY SOLELY UPON, THEIR OWN TAX ADVISERS TO DETERMINE THE SPECIFIC TAX CONSEQUENCES TO THEM OF THE OWNERSHIP AND DISPOSITION OF WOODSIDE SECURITIES, INCLUDING THE EFFECT OF ANY US FEDERAL, STATE, LOCAL, NON-US, OR OTHER TAX LAWS.

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KEY ANNOUNCEMENTS 2023

January		Fourth quarter 2022 results
February		Annual General Meeting 2023
		Line-item guidance and other items
		Full-Year 2022 results
		US Annual Report 2022 (Form 20-F)
		Sustainable Development Report 2022
		Climate Report 2022
March		Changes to Woodside Board
April		First quarter 2023 results
		Appointment – Executive Vice President Australian Operations
June		Fatality at North Rankin Complex
		Woodside approves investment in Trion development
		Report on payments to governments 2022
July		Sangomar project update
		Second quarter 2023 results
August		Woodside to sell 10% Scarborough interest to LNG Japan
		Half-Year 2023 results
		Trion receives regulatory approval
October		Third quarter 2023 report
November		Investor Briefing Day 2023
December		Woodside and Mexico Pacific sign LNG supply agreement
		Response to media speculation
January 2024		Fourth quarter 2023 report
		Appointment of Director and changes to Committee Membership
February 2024		Woodside concludes discussions with Santos
		Woodside releases Reserves Statement and financial updates
		Woodside to sell 15.1% Scarborough interest to JERA
EVENTS CALENDAR 2024
Key calendar dates for Woodside shareholders in 2024. Please note dates are subject to review.
February	27	Full-Year 2023 results and briefing
	27	Annual Report 2023
	27	US Annual Report 2023 (Form 20-F)
	27	Climate Transition Action Plan and 2023 Progress Report
March	7	Ex-dividend date for dividend entitlement
	8	Record date for dividend entitlements
April	4	Payment date
	19	First quarter 2024 results
	24	Annual General Meeting
June	30	Half-Year end 2024
July	23	Second quarter 2024 results
August	27	Half-Year 2024 results
October	16	Third quarter 2024 results
November		Investor Briefing Day 2024
December	31	Year-end 2024

6.5 Additional Information

Asset facts

PRODUCING FACILITIES

Australia

Asset	Role	Equity	Infrastructure	Capacity (100% project)	Product
Pluto LNG	Operator	90%	Pluto LNG Plant (onshore gas plant)	LNG: 4.9 Mtpa Domestic gas: 25 TJ/d Condensate: 1,140 tonnes/d	LNG, pipeline gas and condensate
			Pluto Platform (steel jacket fixed platform)	Dry gas: 1,320 MMscf/d	Gas and condensate
North West Shelf1	Operator	33.33%	Karratha Gas Plant (onshore gas plant)	LNG: 16.9 Mtpa Domestic Gas: 630 TJ/d	LNG, pipeline gas, condensate and
				Condensate: 14,385 tonnes/d	NGLs
			North Rankin Complex (steel jacket fixed platform)	Dry gas: 60,000 tonnes/d Condensate: 6,200 tonnes/d	Gas and condensate
			Goodwyn A Platform (steel jacket fixed platform)	Dry gas: 38,000 tonnes/d Condensate: 18,000 tonnes/d	Gas and condensate
			Angel Platform (steel jacket fixed platform)	Dry gas: 21,500 tonnes/d Condensate: 8,600 sm3/d	Gas and condensate
Wheatstone2	Non-Operator	13%	Wheatstone LNG Plant (onshore gas plant)	LNG: 8.9 Mtpa Domestic gas: 215 TJ/d Condensate: 8,661 sm3/d	LNG, pipeline gas and condensate
			Wheatstone Platform (steel gravity structure platform)	Dry gas: 1,970 MMscf/d Condensate: 8,600 sm3/d	Gas and condensate
Okha FPSO	Operator	50%	FPSO	Oil: 60,000 bbl/d Gas: 82 MMscf/d	Crude oil
Ngujima-Yin FPSO	Operator	60%	FPSO	Oil: 120,000 bbl/d	Crude oil
Bass Strait	Non-Operator	50%	Longford (onshore gas plant)	Gas: 1,040 TJ/d Crude oil and condensate: 65,000 bbl/d Liquefied petroleum gas: 5,150 tonnes/d Ethane: 850 tonnes/d	Crude oil, pipeline gas, condensate and NGLs
			Long Island Point (onshore processing and storage plant)
			Barracouta (steel jacket platform and West Barracouta subsea tieback)
			Snapper (steel jacket platform)
			Marlin/Turrum (steel jacket platform)
			Tuna/West Tuna (steel jacket platform and concrete gravity structure)
			Oil Block (3 steel jacket platforms)
		32.5%	Kipper (subsea tieback to West Tuna)
Pyrenees FPSO	Operator	40-71.4%	FPSO	Oil: 96,000 bbl/d	Crude oil
Macedon	Operator	71.4%	Onshore single-train gas plant	Gas: 220 MMscf/d Condensate: 110 bbl/d	Pipeline gas

1 The North West Shelf consists of a number of active joint ventures. Woodside’s participating interest is 33.33% in all of these apart from the NWS joint ventures with CNOOC. Woodside’s participating interest in the CLNG JV is 25% and in the Extended Interest JVs is 31.567%.

2 The Wheatstone assets process gas from several offshore gas fields, including the Julimar and Brunello fields, for which Woodside has a 65% participating interest and is the operator.

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International

Asset	Role	Equity	Infrastructure	Capacity (100% project)	Product
Greater Angostura	Operator	45%	Angostura – Block 2(c) (central processing platform)	Oil: 100,000 bbl/d Gas: 340 MMscf/d	Crude oil and pipeline gas
		68.46%	Ruby – Block 3(a) (well protector platform)
Greater Shenzi	Operator	72%	Tension leg platform	Oil: 100,000 bbl/d Gas: 50 MMscf/d	Crude oil, pipeline gas, condensate and NGLs
Atlantis	Non-operator	44%	Semi-submersible FPU	Oil: 200,000 bbl/d Gas: 180 MMscf/d	Crude oil, pipeline gas, condensate and NGLs
Mad Dog	Non-operator	23.9%	Phase 1 (A-spar) Truss spar	Oil: 100,000 bbl/d Gas: 60 MMscf/d	Crude oil, pipeline gas, condensate and NGLs
			Phase 2 (Argos) semi-submersible FPU	Oil: 140,000 bbl/d Gas: 75 MMscf/d	Crude oil, pipeline gas, condensate and NGLs

PROJECTS

Post FID

Asset	Role	Equity	Infrastructure	Capacity (100% project)	Product
Scarborough	Operator	100%1	Semi-submersible FPU	Dry gas: 1,750 MMscf/d LNG: 5.0 Mtpa Domestic gas: 225 TJ/d	LNG, pipeline gas and condensate
		51%	Pluto Train 2 (onshore gas plant)
Sangomar	Operator	82%	FPSO	Oil: 100,000 bbl/d	Crude oil
Trion	Operator	60%	Semi-submersible FPU	Oil: 100,000 bbl/d	Crude oil

1 Following completion of the transactions with LNG Japan and JERA, Woodside will hold a 74.9% interest in the Scarborough Joint Venture and remain as operator. Completion is targeted for the first quarter of 2024 for the transaction with LNG Japan and the second half of 2024 for the transaction with JERA.

DEVELOPMENTS

Asset	Role	Equity	Product
Calypso	Operator	70%	Gas
Browse	Operator	30.6%	LNG, pipeline gas and condensate
Greater Scarborough1	Operator	100%	Gas
Liard	Non-operator	50%	Gas
Sunrise	Operator	33.44%	LNG, pipeline gas and condensate

1 Greater Scarborough includes the Jupiter and Thebe fields.

NEW ENERGY OPPORTUNITIES¹

Asset	Role	Equity	Product
H2OK	Operator	100%	Hydrogen
H2Perth	Operator	100%	Hydrogen and ammonia
Hydrogen Refueller @H2Perth	Operator	100%	Hydrogen
H2TAS	Operator	100%	Hydrogen and ammonia
Woodside Solar	Proponent2	100%	Solar energy
Southern Green Hydrogen3	Preferred partner	-	Hydrogen and ammonia
Capella project	Non-operating partner	N/A	Solar energy

1 Subject to FID and regulatory approvals.

2 Solar generation, battery services and transmission access and services will be supplied to Woodside under contracts with third parties.

3 Woodside’s equity in Southern Green Hydrogen is subject to finalising commercial agreements.

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GREENHOUSE GAS ASSESSMENT PERMITS

Asset	Permit	Role	Joint venture	Comment
Australia	G-7-AP	Non-operator	Bonaparte CCS Assessment Joint Venture	Located in the Bonaparte Basin off the north- western coast of the Northern Territory
	G-8-AP	Operator	Browse Joint Venture	For carbon capture and storage evaluation for Browse
	G-10-AP	Operator	Angel CCS Joint Venture	Located in the Northern Carnarvon Basin off the north west coast of Western Australia

EXPLORATION

Country	Permit	Role		Equity	Product
Asia-Pacific
Australia	WA-356-P		Operator	65%	Gas prone basin
	WA-536-P		Operator	65%	Gas prone basin
	WA-550-P		Operator	100%	Gas prone basin
	NT/P86		Operator	100%	Gas prone basin
	WA-404-P		Operator	100%	Gas prone basin
	WA-28-P		Operator	15.78%	Gas prone basin
	WA-93-R		Operator	70%	Gas prone basin
	WA-94-R		Operator	70%	Gas prone basin
Myanmar1	A-7		Operator	Relinquished, formalities pending	Gas prone basin
	AD-7		Non-operator	Relinquished, formalities pending	Gas prone basin
	AD-1		Joint operator	Relinquished, formalities pending	Gas prone basin
	AD-8		Joint operator	Relinquished, formalities pending	Gas prone basin
Europe
Ireland	FEL 5/13		Operator	Exit initiated	Oil or gas prone basin
Africa
Senegal	Rufisque, Sangomar and Sangomar Deep		Operator	90% - Exit initiated	Oil prone basin
Congo	Marine XX		Non-operator	22.5%	Oil or gas prone basin
Egypt	Red Sea Block 1		Non-operator	45%	Oil or gas prone basin
	Red Sea Block 3		Non-operator	30%	Oil and gas prone basin
	Red Sea Block 4		Non-operator	25%	Oil and gas prone basin
	Herodotus Block 2 – North Sidi Barani		Non-operator	27%	Oil and gas prone basin
	Herodotus Block 4 – North El Dabaa		Non-operator	27%	Oil and gas prone basin
Caribbean
Barbados	Carlisle Bay, Bimshire		Operator	60%	Oil or gas prone basin
Latin America
Peru	108		Non-operator	Exit initiated	Oil or gas prone basin

1 Woodside announced its decision to withdraw from its interests in Myanmar on 27 January 2022.

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North America
Country	Permit	Role	Equity	Product
US Gulf of Mexico	GB 640, GB 641, GB 685, GB 555, GB 726, GB 770, GB 771, GB 604, GB 605, GB 647, GB 648, GB 772, GB 728, GB 729, GB 773, GB 774, GB 421, GB 464, GB 465, GB 508, GB 509, GC 598	Non-operator	40%	Oil prone basin
	GB 574, GB 575, GB 619, GB 529, GB 530, GB 531	Operator	40%	Oil prone basin
	GB 630, GB 501, GB 502, GB 545, GB 676, GB 677, GB 719, GB 720, GB 721, GB 762, GB 753, GB 805, GB 806, GB 807, GB 851, GB 852, GB 895, GB 672, GB 716, GB 760	Operator	60%	Oil prone basin
	GC 282, GC 237	Non-operator	50%	Oil prone basin
	GC 210, GC 211, GB 663, GB 664, GB 678	Operator	100%	Oil prone basin
	EB 655, EB 656, EB 699, EB 700, EB 701, AC 34, AC 36, AC 78, AC 80, EB 566, EB 567, EB 610, EB 611, EB 914	Operator	70%	Oil prone basin
	AC 81, AC 82, AC 125, AC 126	Operator	45%	Oil prone basin
	MC 798, MC 842	Non-operator	45%	Oil prone basin
	GC 679, GC 768	Non-operator	45%	Oil prone basin
	GC 238	Non-operator	60%	Oil prone basin
	MC 368, MC 369, MC 411, MC 412, MC 455, MC 456	Non-operator	25%	Oil prone basin
	GC 80, GC 123, GC 124, GC 168	Operator	75%	Oil prone basin
	GC 738, GC 870	Non-operator	23.9%	Oil prone basin
	GC 480, GC 436	Non-operator	44%	Oil prone basin
	AT 228, AT 273, AT 274, AT 409, AT 452, AT 453, AT 454, AT 424, AT 425, AT 469, AT 470	Non-operator	30%	Oil prone basin

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6.6 Additional Information

Alternative performance measures

Certain parts of this report contain financial measures that are not defined in, and have not been prepared in accordance with, IFRS and are not recognised measures of financial performance or liquidity under IFRS. In addition to the financial information contained in this report presented in accordance with IFRS, certain ‘non-IFRS financial measures’ (which also constitute non- GAAP financial measures as defined in Item 10(e) of Regulation S-K under the US Securities Act on 1933, as amended) have been included in this report. These measures include EBIT, EBITDA, EBITDA excluding impairment, Gearing, Underlying NPAT, Net debt, Free cash flow, Operating cash flow, Capital expenditure, Exploration expenditure, Net tangible assets, Net tangible asset per ordinary security, Return on equity and Return on average capital employed. These non-IFRS financial measures are defined in section 6.7 - Glossary, units of measure and conversion factors. This section provides a reconciliation of these measures to the most directly comparable financial measure calculated and presented in accordance with IFRS in Woodside’s Financial Statements.

Woodside’s management uses these measures to monitor Woodside’s financial performance alongside IFRS measures to improve the comparability of information between reporting periods and business units and Woodside believes that the non- IFRS financial measures it presents provide a useful means through which to examine the underlying performance of its business. Undue reliance should not be placed on the non-IFRS financial measures contained in this report. The non-IFRS financial measures should be considered in addition to, and not as a substitute for or alternative to, or as superior to, measures of financial performance, financial position or cash flows reported in accordance with, or other figures determined in accordance with IFRS. Non-IFRS financial measures are not uniformly defined by all companies, including those in Woodside’s industry. Accordingly, such measures may not be comparable with similarly titled measures and disclosures by other companies.

Although certain non-IFRS data has been extracted or derived from Woodside’s Financial Statements, this data has not been audited or reviewed by Woodside’s independent auditors. You are urged to read carefully the audited Full-year Financial Statements and related notes thereto.

DEFINITION AND CALCULATION OF NON-IFRS FINANCIAL INFORMATION

Non-IFRS  financial  information	Why is the non-IFRS financial information useful	Calculation methodology
EBIT	Used to assess the Group’s operational profitability excluding net finance costs and taxation expense. This assists management in tracking the performance of the Group from its operations only.	Calculated as profit before income tax, PRRT and net finance costs.
EBITDA excluding  impairment	Used to assess the Group’s operational profitability excluding net finance costs, taxation expense, depreciation and amortization and impairment losses/ reversals. This measure assesses the performance of the Group’s segments and aids decision making of resource allocation.	Calculated as profit before income tax, PRRT, net finance costs, depreciation and amortization, impairment losses, impairment reversals.
Underlying NPAT	Used to assess the Group’s financial performance by excluding the impacts of exceptional items. This measure indicates the performance from the Group’s core operations only and is used by management to aid decision making of resource allocation.	Net profit after tax from the Group’s operations excluding any exceptional items (refer to the reconciliation in this section for the list of specific items for each financial year).
Capital and  exploration  expenditure	Used to assess efficient deployment of capital for oil and gas properties, evaluation capitalised and exploration and evaluation expenditure. Management uses this measure as support for decision making to maintain and improve productive capacity.	Includes capital additions on oil and gas properties, evaluation capitalised and exploration and evaluation expenditure land amortisation of licence acquisition costs and prior year exploration expense written off.
Capital expenditure	Used to assess efficient deployment of capital for oil and gas properties and evaluation capitalised. Management uses this measure as support for decision making to maintain and improve productive capacity.	Includes capital additions on oil and gas properties and evaluation capitalised.
Exploration  expenditure	Used to assess efficient deployment of capital for exploration and evaluation expenditure. Management uses this measure as support for decision making to maintain and improve productive capacity.	Includes exploration and evaluation expenditure and amortisation of licence acquisition costs and prior year exploration expense written off.
Free cash flow	Used to evaluate the cash available for financing activities, including shareholder distributions and debt servicing, after investment in maintaining and growing the Group’s operations. This measure is used as a key indicator of the level of cash the Group has at its disposal.	Cash flow from operating activities and cash flow from investing activities.
Net debt	Net debt measures how the Group manages our balance sheet and capital structure. Management uses this measure to track the level of debt of the Group.	Interest-bearing liabilities and lease liabilities less cash and cash equivalents.
Net tangible assets	Used to assess the Group’s net assets (excluding intangible) to assess how much risk the Group carries in liquidity, solvency and assets for financing purposes.	The Group’s net assets less goodwill, non-controlling interest and intangible assets.
Net tangible assets  per ordinary  security	Used by management to assess the Group’s investment strategy in comparison to the Group’s share price.	Net tangible assets divided by the number of issued and fully paid shares.
Gearing	Used to monitor the Group’s net debt relative to the Group’s total net debt and equity. This measure assists management in monitoring the Group’s leverage.	Net debt divided by the total of net debt and equity attributable to equity holders of the parent.
Return on equity	Used to measure the Group’s earnings as a percentage of shareholders’ investments.	Net profit after tax from the Group’s operations divided by equity attributable to equity holders of the parent.
Return on average  capital employed	Used to assess the efficiency of the Group’s utilisation of the capital employed.	Profit before tax and net finance costs dividend by the total average non-current liabilities and equity attributable to equity holders of the parent.

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APMs derived from Consolidated Income Statement

	2023     US$m		2022     US$m		2021     US$m
EBIT/EBITDA excluding impairment
Net profit after tax		1,722		6,575		2,036
Adjusted for:
Finance income		(273)		(155)		(27)
Finance costs		307		167		230
PRRT expense/(benefit)		898		(313)		297
Income tax expense		653		2,912		957
EBIT		3,307		9,186		3,493
Adjusted for:
Oil and gas properties depreciation and amortisation		3,956		2,798		1,549
Amortisation of licence acquisition costs		4		10		3
Depreciation of lease assets		179		140		108
Depreciation of other plant and equipment		-		-		30
Impairment losses		1,917		-		10
Impairment reversals		-		(900)		(1,058)
EBITDA excluding impairment		9,363		11,234		4,135
Underlying NPAT
Net profit/(loss) after tax attributable to equity holders of the parent		1,660		6,498		1,983
Adjusted for the following exceptional items:
Add: Impairment losses (post-tax)		1,533		-		-
Add: Reduction in Pluto PRRT (post-tax)		446		-		-
Add: Merger transaction costs		-		419		-
Add: Orphan Basin exit fee		-		142		-
Add: Myanmar exit		-		-		209
Add: Kitimat exit costs		-		-		33
Add: Joint venture recoveries		-		-		4
Less: Trion DTA recognition		(319)		-		-
Less: Derecognition of the Corpus Christi onerous contract provision		-		(245)		-
Less: Impairment reversal (post-tax)		-		(630)		(582)
Less: Pluto PRRT DTA recognition		-		(954)		-
Less: Pluto price adjustment		-		-		(27)
Underlying NPAT		3,320		5,230		1,620

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APMs derived from Consolidated Cash Flow Statement and Other Notes

	2023     US$m		2022     US$m		2021     US$m
Capital expenditure1
Capital additions on evaluation		163		119		453
Capital additions on oil and gas properties		5,317		3,904		2,178
Capital additions on other1		256		92		-
Capital expenditure		5,736		4,115		2,631
Exploration expenditure
Exploration and evaluation expenditure		360		470		322
Adjusted for:
Amortisation expense		(4)		(10)		(3)
Prior year expense written off		(77)		(164)		(265)
Exploration capitalised		88		122		42
Exploration expenditure		367		418		96
Capital and exploration expenditure		6,103		4,533		2,727
Free cash flow
Cash flow from operating activities		6,145		8,811		3,792
Cash flow used in investing activities		(5,585)		(2,265)		(2,941)
Free cash flow		560		6,546		851

1 Includes capital additions on other corporate spend. The 2022 amounts have been restated to be presented on the same basis. The 2021 capital expenditure information has not been restated to include other corporate spend.

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APMs derived from Consolidated Balance Sheet

	2023 US$m		2022 US$m		2021 US$m
Net tangible assets per ordinary security
Net assets		35,170		37,127		14,229
Adjusted for:
Goodwill		(3,995)		(4,614)		-
Non-controlling interest		(771)		(791)		(786)
Intangible assets		(187)		(55)		(2)
Net tangible assets		30,217		31,667		13,441
Number of issued and fully paid shares		1,898,749,771		1,898,749,771		969,631,826
Net tangible assets per ordinary security		15.91		16.68		13.86
Gearing
Interest-bearing liabilities (Current and non-current)1		4,874		5,138		5,430
Lease liabilities (Current and non-current)		1,615		1,634		1,367
Adjusted for:
Cash and cash equivalents		(1,740)		(6,201)		(3,025)
Add: restricted cash		-		12		-
Net debt		4,749		583		3,772
Equity attributable to equity holders of the parent		34,399		36,336		13,443
Total net debt and equity attributable to equity holders of the parent		39,148		36,919		17,215
Gearing		12.1		1.6		21.9

1 The 2023 balance agrees to Note C.2 which includes capitalised costs to be amortised within the next 12 months.

APMs derived from Consolidated Income Statement and Consolidated Balance Sheet

	2023 US$m		2022 US$m		2021 US$m
Return on equity
Net profit/(loss) after tax attributable to equity holders of the parent		1,660		6,498		1,983
Equity attributable to equity holders of the parent		34,399		36,336		13,443
Return on equity (%)		4.8		17.9		14.8
Return on average capital employed
Profit before tax and net finance costs		3,307		9,186		3,493
Opening non-current liabilities		15,586		9,623		9,654
Closing non-current liabilities		15,209		15,586		9,623
Average non-current liabilities		15,398		12,605		9,639
Opening equity attributable to equity holders of the parent		36,336		13,443		12,075
Closing equity attributable to equity holders of the parent		34,399		36,336		13,443
Average equity attributable to equity holders of the parent		35,368		24,890		12,759
Total average non-current liabilities and equity attributable to equity holders of the parent		50,766		37,495		22,398
Return on average capital employed (%)		6.5		24.5		15.6

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6.7 Additional Information

Glossary, units of measure and conversion factors

GLOSSARY

Term	Definition
$, $m	US dollars unless otherwise stated, millions of dollars
1P	Proved reserves
2C	Best Estimate of Contingent resources
2P	Proved plus Probable reserves
A$	Australian dollars
Abate/abatement	Avoidance, reduction or removal of an amount of carbon dioxide or equivalent.
ADR	American Depository Receipts
Aspiration	Woodside uses this term to describe an aspiration to seek the achievement of an outcome but where achievement of the outcome is subject to material uncertainties and contingencies such that Woodside considers there is not yet a suitable defined plan or pathway to achieve that outcome.
ASX	Australian Securities Exchange
Biodiversity	Biological diversity means the variability among living organisms from all sources including, inter alia, terrestrial, marine and other aquatic ecosystems and the ecological complexes of which they are a part; this includes diversity within species, between species and of ecosystems.1
Board	The Board of Directors of Woodside Energy Group Ltd
Brent	Intercontinental Exchange (ICE) Brent Crude deliverable futures contract (oil price)
Capital expenditure	Includes capital additions on oil and gas properties and evaluation capitalised.
Carbon credit	A tradable financial instrument that is issued by a carbon-crediting program. A carbon credit represents a greenhouse gas emission reduction to, or removal from, the atmosphere equivalent to 1 tCO2-e, calculated as the difference in emissions from a baseline scenario to a project scenario. Carbon credits are uniquely serialised, issued, tracked and retired or administratively cancelled by means of an electronic registry operated by an administrative body, such as a carbon-crediting program.
Carbon Credit Integrity	Woodside assesses Greenhouse gas integrity (abatement that is measurable, verifiable and has a low risk of being inaccurate, non-additional or impermanent) and Environmental, Social and Governance integrity (guided by positive (or no negative) impacts on people and the environment; and appropriate governance measures to prevent adverse consequences and impacts).
CCS	Carbon capture and storage
CCU	Carbon capture and utilisation, also referred to as carbon to products
CCUS	Carbon capture utilisation and storage
Cetaceans	Includes whales, dolphins, and porpoises
CHF	Swiss francs
CO2	Carbon dioxide
CO2-e	CO2 equivalent. The universal unit of measurement to indicate the global warming potential of each of the seven greenhouse gases, expressed in terms of the global warming potential of one unit of carbon dioxide. It is used to evaluate releasing (or avoiding releasing) any greenhouse gas against a common basis.2
COP28	The 28th Conference of the Parties to the United Nations Framework Convention on Climate Change, meeting in Dubai, UAE, November—December 2023.
Condensate	Hydrocarbons that are gaseous in a reservoir but that condense to form liquids as they rise to the surface.
cps	Cents per share
Decarbonisation	Woodside uses this term to describe activities or pathways that have the effect of moving towards a state that is lower carbon, as defined in this glossary.
DRP	Dividend reinvestment plan
EBIT	Calculated as profit before income tax, PRRT and net finance costs.
EBITDA excluding impairment	Calculated as profit before income tax, PRRT, net finance costs, depreciation and amortisation, impairment losses, impairment reversals.
Emissions	Emissions refers to emissions of greenhouse gases unless otherwise stated.

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Term	Definition
Environmental incident	Environmental incidents involving hydrocarbon and hazardous non hydrocarbon spills of greater than 1 bbl released to the environment.
EPS	Earnings per share
Equity greenhouse gas emissions	Woodside sets its Scope 1 and 2 greenhouse gas emissions reduction targets on an equity basis. This ensures that the scope of its emissions reduction targets is aligned with its economic interest in its investments. Equity emissions reflect the greenhouse gas emissions from operations according to Woodside’s share of equity in the operation. Its equity share of an operation reflects its economic interest in the operation, which is the extent of rights it has to the risks and rewards flowing from the operation.3
Exploration expenditure	Includes exploration and evaluation expenditure less amortisation of licence acquisition costs and prior year exploration expense written off.
FEED	Front-end engineering design
First Nations and Indigenous Peoples	First Nations people are the Indigenous people, or earliest known inhabitants, of a country. A First Nations person is a person of Indigenous decent, who identifies as a First Nations person and is accepted by their respective community. NOTE: We acknowledge the diversity of the First Nations communities in the areas where we are present. When communicating with a wide audience, Woodside uses the term Indigenous and First Nations interchangeably. On a local level, Woodside will be guided by the community as to the appropriate terms of reference.
FID	Final investment decision
Flaring	The controlled burning of gas found in oil and gas reservoirs.
FPIC	Free, Prior and Informed Consent. For further information, please see Woodside’s First Nations Communities Policy.
FPSO	Floating production storage and offloading
FPU	Floating production unit
Frequency rates	Frequency rates are calculated per million work hours.
Free cash flow	Cash flow from operating activities and cash flow from investing activities.
Gearing	Net debt divided by the total of net debt and equity attributable to equity holders of the parent.
GHG or greenhouse gas	The seven greenhouse gases listed in the Kyoto Protocol are: carbon dioxide (CO2); methane (CH4); nitrous oxide (N2O); hydrofluorocarbons (HFCs); nitrogen trifluoride (NF3); perfluorocarbons (PFCs); and sulphur hexafluoride (SF6).2
Goal	Woodside uses this term to broadly encompass its targets and aspirations.
Gross greenhouse gas emissions	Also referred to as ‘absolute’ emissions, gross emissions are a emissions before any eligible units and certificates have been accounted for.4
Gross margin	Gross profit divided by operating revenue. Gross profit excludes income tax, PRRT, net finance costs, other income and other expenses.
GWF	Greater Western Flank
H1, H2	Halves of the calendar year (H1 is 1 January to 30 June and H2 is 1 July to 31 December).
Hierarchy of controls	The hierarchy of controls is a method of identifying and ranking safeguards to protect workers from hazards. They are arranged from the most to least effective and include elimination (physically removing the hazard), substitution (replacing the hazard), engineering controls (isolating people from the hazard), administrative controls (changing the way people work) and personal protective equipment (to protect workers directly).
High-consequence work-related injury	Work-related injury that results in a fatality or in an injury from which the worker cannot, does not, or is not expected to recover fully to pre-injury health status within six months.
HSE	Health, safety and environment
IFRS	International Financial Reporting Standards
Incident	Is one, or more, of the following: an unplanned release of energy that actually resulted in injury, occupational illness, environmental harm or damage to assets, a near miss, damage or potential damage to company reputation, breach of regulatory compliance and/or legislation, security breach (including cybersecurity breach).
Capital and exploration expenditure	Includes capital expenditure and exploration expenditure
IRR	Internal rate of return
JCC	The Japan Customs-cleared Crude is the average price of customs-cleared crude oil imports into Japan as reported in customs statistics (also known as ‘Japanese Crude Cocktail’) and is used as a reference price for long-term supply LNG contracts.
JV	Joint venture
KGP	Karratha Gas Plant
Liquidity	Total cash and cash equivalents and available undrawn debt facilities.
LNG	Liquified natural gas
Loss of primary containment (LOPC)	An unplanned or uncontrolled release of any material from primary containment, including non-toxic and non-flammable materials (e.g. steam, hot condensate, nitrogen, compressed CO2 or compressed air).
Lower carbon	Woodside uses this term to describe the characteristic of having lower levels of associated potential GHG emissions when compared to historical and/or current conventions or analogues, for example relating to an otherwise similar resource, process, production facility, product or service, or activity. When applied to Woodside’s strategy, please see the definition of lower carbon portfolio.
Lower carbon economy	A lower carbon economy is an economy that produces lower levels of greenhouse gas emissions relative to today’s economy.

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Term	Definition
Lower carbon portfolio	For Woodside, a lower carbon portfolio is one from which the net equity Scope 1 and 2 greenhouse gas emissions, which includes the use of offsets, are being reduced towards targets, and into which new energy products and lower carbon services are planned to be introduced as a complement to existing and new investments in oil and gas. Our Climate Policy sets out the principles that we believe will assist us achieve this aim.
Lower carbon power	Lower carbon power comes from processes or technologies that produce electricity with a lower greenhouse gas emissions intensity relative to electricity produced from a higher emissions intensity source.
Lower carbon services	Woodside uses this term to describe technologies, such as CCUS or offsets, that may be capable of reducing the net greenhouse gas emissions of our customers.
LSE	London Stock Exchange
Major environmental incidents	Unplanned or undesired event resulting in a moderate, medium-term impact on ecosystems, species, habitat or physical or biological attributes.
Net debt	Interest-bearing liabilities and lease liabilities less cash and cash equivalents.
Net equity greenhouse gas emissions	Woodside’s equity share of net greenhouse gas emissions.
Net greenhouse gas emissions	Woodside has set its Scope 1 and 2 greenhouse gas emissions reduction targets on a net basis, allowing for both direct emissions reductions from its operations and emissions reduction achieved from the utilisation of carbon credits as offsets (including credits relating to avoidance, reduction and / or removal activities). Net greenhouse gas emissions are equal to an entity’s gross greenhouse gas emissions reduced by the number of retired carbon credits.4
Net profit attributable to equity holders of the parent	Net profit after tax excluding non-controlling interests from the Group’s operations.
Net tangible assets	The Group’s net assets less goodwill, non-controlling interest and intangible assets.
Net tangible assets per ordinary security	Net tangible assets divided by the number of issued and fully paid shares.
Net zero	Net zero emissions are achieved when anthropogenic emissions of greenhouse gases to the atmosphere are balanced by anthropogenic removals over a specified period. Where multiple greenhouse gases are involved, the quantification of net zero emissions depends on the climate metric chosen to compare emissions of different gases (such as global warming potential, global temperature change potential, and others, as well as the chosen time horizon).5
New energy	Woodside uses this term to describe energy technologies, such as hydrogen and ammonia, that are emerging in scale but which are expected to grow during the energy transition due to having lower greenhouse gas emissions at the point of use than conventional fossil fuels.
NGLs	Natural gas liquids
NPAT	Net profit after tax
NWS	North West Shelf
NYSE	New York Stock Exchange
Offsets	The compensation for an entity’s greenhouse gas emissions within its scope by achieving an equivalent amount of emission reductions or removals outside the boundary or value chain of that entity.
Offtake	Offtake refers to the agreement between a seller and a buyer for the purchase and delivery of a product, typically a commodity or energy resource.
Operator, Operated and non-operated	Oil and gas join venture participants will typically appoint one company as the operator, which will hold the contractual authority to manage joint venture activities on behalf of the joint venture participants. Where Woodside is the operator of a joint venture in which it holds an equity share, this report refers to that joint venture as being operated. Where another company is the operator of a joint venture in which Woodside holds an equity share, this report refers to that joint venture as being non- operated.
Paris aligned scenarios	Consistent with limiting global warming to below 2°C above pre-industrial levels and pursuing efforts to limit warming to 1.5°C.2
Potential risks	This is an environmental, social or governance related-risk, that if it occurs over the next 12 months, could cause an actual or a perceived negative impact on the business or on our activities.
PRRT	Petroleum resources rent tax
PSC	Production sharing contract
PSE	Process safety event
Residual levels of emissions	Residual levels of emissions denotes the goal of reducing emissions as much as possible, taking into account both technological capabilities and commercial feasibility, towards a level that approaches but does not reach zero.
Retire, Retirement	The transfer of a carbon credit to a registry account that permanently removes the carbon credit from circulation. The term retirement applies to the use of the carbon credit by an entity to meet voluntary commitments or compliance obligations.
Revenue from ordinary activities	Revenue from the sale of hydrocarbons, processing and services revenue and shipping and other revenue.
RFSU	Ready for start-up
RSSD	Rufisque Offshore, Sangomar Offshore and Sangomar Deep Offshore.
Scope 1 GHG emissions	Direct GHG emissions. These occur from sources that are owned or controlled by the company, for example, emissions from combustion in owned or controlled boilers, furnaces, vehicles, etc.; emissions from chemical production in owned or controlled process equipment. Woodside estimates greenhouse gas emissions, energy values and global warming potentials are estimated in accordance with the relevant reporting regulations in the jurisdiction where the emissions occur (e.g. Australian national Greenhouse and Energy Reporting (nGER), US EPA Greenhouse Gas Reporting Program (GHGRP)). Australian regulatory reporting principles have been used for emissions in jurisdictions where regulations do not yet exist.3

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Term	Definition
Scope 2 GHG emissions	Electricity indirect GHG emissions. Scope 2 accounts for GHG emissions from the generation of purchased electricity consumed by the company. Purchased electricity is defined as electricity that is purchased or otherwise brought into the organisational boundary of the company. Scope 2 emissions physically occur at the facility where electricity is generated. Woodside estimates greenhouse gas emissions, energy values and global warming potentials are estimated in accordance with the relevant reporting regulations in the jurisdiction where the emissions occur (e.g. Australian national Greenhouse and Energy Reporting (nGER), US EPA Greenhouse Gas Reporting Program (GHGRP)). Australian regulatory reporting principles have been used for emissions in jurisdictions where regulations do not yet exist.3
Scope 3 GHG emissions	Other indirect GHG emissions. Scope 3 is a reporting category that allows for the treatment of all other indirect emissions. Scope 3 emissions are a consequence of the activities of the company but occur from sources not owned or controlled by the company. Some examples of Scope 3 activities are extraction and production of purchased materials; transportation of purchased fuels; and use of sold products and services.3
Short- and long-term	This report refers to ranges of time as follows: short-term means from now until 2025, long-term means 2046 and beyond.
Starting base	Woodside uses a starting base of 6.32 Mt CClO2-e which is representative of the gross annual average equity Scope 1 and 2 greenhouse gas emissions over 2016-2020 and which may be adjusted (up or down) for potential equity changes in producing or sanctioned assets with a final investment decision prior to 2021. Net equity emissions include the utilisation of carbon credits as offsets.
Sustainably (including sustainable and sustainably)	References to sustainability (including sustainable and sustainably) are used with reference to Woodside’s Sustainability Committee and sustainability related Board policies, as well as in the context of Woodside’s aim to ensure its business is sustainable from a long-term perspective, considering a range of factors including economic (including being able to sustain our business in the long term by being low cost and profitable), environmental (including considering our environmental impact and striving for a lower carbon portfolio), social (including supporting our license to operate), and regulatory (including ongoing compliance with relevant legal obligations). Use of the terms ‘sustainability’, ‘sustainable’ and ‘sustainably’ is not intended to imply that Woodside will have no adverse impact on the economy, environment, or society, or that Woodside will achieve any particular economic, environmental, or social outcomes.
Target	Woodside uses this term to describe an intention to seek the achievement of an outcome, where Woodside considers that it has developed a suitably defined plan or pathway to achieve that outcome.
TCFD	Taskforce on Climate-related Financial Disclosures. For more information see www.fsb-tcfd.org/about
Tier 1 PSE	A typical Tier 1 process safety event is loss of containment of hydrocarbons greater than 500 kg (in any one-hour period).
Tier 2 PSE	A typical Tier 2 process safety event is loss of containment of hydrocarbons greater than 50 kg but less than 500 kg (in any one-hour period).
Total recordable injury rate (TRIR)	The number of recordable injuries (fatalities + lost work day cases + restricted workday cases + medical treatment cases + permanent partial disability) per million work hours.
Traditional Owners and Custodians	Members of the local Indigenous group with traditional rights and responsibilities in relation to the land and water in which we operate.
Transition case	Woodside uses this term to refer to the methodology Woodside applies to helps us manage risk by screening investment opportunities across a range of climate-related factors.
Underlying NPAT	Net profit after tax from the Group’s operations excluding any exceptional items
Unit production costs	Production costs ($ million) divided by production volume (MMboe)
US, USA	United States of America
USD, US$	US dollars
WA	Western Australia
USD, US$	US dollars
WA	Western Australia

1 UNEP, 1992. “Convention on Biological Diversity” https://www.cbd.int/doc/legal/cbd-en.pdf.

2 See IFRS Foundation 2021: Climate Related Disclosures Prototype. Appendix A. The IFRS published a further consultation document subsequent to the 2021 prototype. As it did not contain a updated definition of Paris-Aligned scenarios Woodside has retained use of the previous edition.

3 World Resources Institute and World Business Council for Sustainable Development 2004. “GHG Protocol: a corporate accounting and reporting standard”.

4 Definition as per the Australian Clean Energy Regulator https://www.cleanenergyregulator.gov.au/Infohub/Markets/cert-report/cert-report-2023/cert-2023-glossary

5 IPCC, 2018: Annex I: Glossary [Matthews, J.B.R. (ed.)]. In: Global Warming of 1.5°C. An IPCC Special Report on the impacts of global warming of 1.5°C above pre-industrial levels and related global greenhouse gas emission pathways, in the context of strengthening the global response to the threat of climate change, sustainable development, and efforts to eradicate poverty [Masson-Delmotte, V., P. Zhai, H.-O. Pörtner, D. Roberts, J. Skea, P.R. Shukla, A. Pirani, W. Moufouma-Okia, C. Péan, R. Pidcock, S. Connors, J.B.R. Matthews, Y. Chen, X. Zhou, M.I. Gomis, E. Lonnoy, T. Maycock, M. Tignor, and T. Waterfield (eds.)]. Cambridge University Press, Cambridge, UK and New York, NY, USA, pp. 541-562. https://doi.org/10.1017/9781009157940.008.

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UNITS OF MEASURE

Term	Definition
bbl	barrel
bcf	billion cubic feet of gas
boe	barrel of oil equivalent
boe/d	barrels of oil equivalent
CO2-e	carbon dioxide equivalent
GJ	gigajoule
GW	gigawatt
km	kilometre
m	metre
m3	cubic metre
Mbbl	thousand barrels
Mboe	thousand barrels of oil equivalent
MMboe	million barrels of oil equivalent
MMBtu	million British thermal units
MMscf	million standard cubic feet of gas
Mtpa	million tonnes per annum
MW	megawatt
scf	standard cubic feet of gas
Sm3	Standard cubic metre
TJ	terajoule
tpd	tonnes per day

CONVERSION FACTORS

Product	Unit	Conversion factor
Natural gas	5,700 SCF		1 boe
Condensate	1 bbl		1 boe
Oil	1 bbl		1 boe
Natural gas liquids (NGL)	1 bbl		1 boe
Unit	Facility	LNG conversion factor
1 tonne	Karratha Gas Plant		8.08 boe
1 tonne	Pluto Gas Plant		8.34 boe
1 tonne	Wheatstone		8.27 boe

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6.8 Additional Information

Information about this report

UNREASONABLE PREJUDICE

As permitted by sections 299(3) and 299A(3) of the Corporations Act 2001, we have omitted certain information from our operating and financial review and Directors’ report in relation to our business strategy, future prospects and likely developments in our operations and the expected results of those operations in future financial years. We have done this on the basis that such information, if disclosed, would be likely to result in unreasonable prejudice to Woodside (for example, because the information is premature, commercially sensitive, confidential or could give a third-party a commercial advantage). The omitted information relates to our internal budgets, forecasts and estimates, details of our business strategy, and LNG contractual pricing.

FORWARD-LOOKING STATEMENTS

This report contains forward-looking statements with respect to Woodside’s business and operations, market conditions, results of operations and financial condition, including, for example, but not limited to, outcomes of transactions, statements regarding long-term demand for Woodside’s products, development, completion and execution of Woodside’s projects, expectations regarding future capital expenditures, the payment of future dividends and the amount thereof, future results of projects, operating activities and new energy products, expectations and plans for renewables production capacity and investments in, and development of, renewables projects, expectations and guidance with respect to production, capital and exploration expenditure and gas hub exposure, and expectations regarding the achievement of Woodside’s net equity Scope 1 and 2 greenhouse gas emissions reduction and new energy investment targets and other climate and sustainability goals.

All statements, other than statements of historical or present facts, are forward-looking statements and generally may be identified by the use of forward-looking words such as ‘guidance’, ‘foresee’, ‘likely’, ‘potential’, ‘anticipate’, ‘believe’, ‘aim’, ‘aspire’, ‘estimate’, ‘expect’, ‘intend’, ‘may’, ‘target’, ‘plan’, ‘strategy’, ‘forecast’, ‘outlook’, ‘project’, ‘schedule’, ‘will’, ‘should’, ‘seek’ and other similar words or expressions. Similarly, statements that describe the objectives, plans, goals or expectations of Woodside are forward-looking statements.

Forward-looking statements in this report are not guidance, forecasts, guarantees or predictions of future events or performance, but are in the nature of future expectations that are based on management’s current expectations and assumptions.

Those statements and any assumptions on which they are based are subject to change without notice and are subject to inherent known and unknown risks, uncertainties, assumptions and other factors, many of which are beyond the control of Woodside, its related bodies corporate and their respective officers, directors, employees, advisers or representatives.

Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, fluctuations in commodity prices, actual demand for Woodside products, currency fluctuations, geotechnical factors, drilling and production results, gas commercialisation, development progress, operating results, engineering estimates, reserve and resource estimates, loss of market, industry competition, environmental risks, climate related risks, physical risks, legislative, fiscal and regulatory developments, changes in accounting standards, economic and financial markets conditions in various countries and regions, political risks, the actions of third parties, project delay or advancement, regulatory approvals, the impact of armed conflict and political instability (such as the ongoing conflict in Ukraine) on economic activity and oil and gas supply and demand, cost estimates, the effect of future regulatory or legislative actions on Woodside or the industries in which it operates, including potential changes to tax laws, the impact of general economic conditions, inflationary conditions, prevailing exchange rates and interest rates and conditions in financial markets, and risks associated with acquisitions, mergers and joint ventures, including difficulties integrating businesses, uncertainty associated with financial projections, restructuring, increased costs and adverse tax consequences, and uncertainties and liabilities associated with acquired and divested properties and businesses.

A more detailed summary of the key risks relating to Woodside and its business can be found in section 3.9 - Risk factors. You should review and have regard to these risks when considering the information contained in this report.

If any of the assumptions on which a forward-looking statement is based were to change or be found to be incorrect, this would likely cause outcomes to differ from the statements made in this report.

Investors are strongly cautioned not to place undue reliance on any forward-looking statements. Actual results or performance may vary materially from those expressed in, or implied by, any forward-looking statements. None of Woodside nor any of its related bodies corporate, nor any of their respective officers, directors, employees, advisers or representatives, nor any person named in this report or involved in the preparation of the information in this report, makes any representation, assurance, guarantee or warranty (either express or implied) as to the accuracy or likelihood of fulfilment of any forward-looking statement, or any outcomes, events or results expressed or implied in any forward-looking statement in this report.

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All forward-looking statements contained in this report reflect Woodside’s views held as at the date of this report and, except as required by applicable law, neither Woodside, its related bodies corporate, nor any of their respective officers, directors, employees, advisers or representatives intends to, undertakes to, or assumes any obligation to, provide any additional information or update or revise any of these statements after the date of this report, either to make them conform to actual results or as a result of new information, future events, changes in Woodside’s expectations or otherwise.

Past performance (including historical financial and operational information) is given for illustrative purposes only. It should not be relied on as, and is not necessarily, a reliable indicator of future performance, including future security prices.

CLIMATE STRATEGY AND EMISSIONS DATA

All greenhouse gas emissions data in this report are estimates, due to the inherent uncertainty and limitations in measuring or quantifying greenhouse gas emissions, and our methodologies for measuring or quantifying greenhouse gas emissions may evolve as best practices continue to develop and data quality and quantity continue to improve.

Woodside ‘greenhouse gas’ or ‘emissions’ information reported are net equity Scope 1 GHG emissions, Scope 2 GHG emissions, and/or Scope 3 GHG emissions, as the context requires.

The glossary and footnotes to this report provide further clarification of ‘lower carbon’ where applicable. Woodside uses the term ‘lower-carbon services’ to describe technologies, such as CCUS or offsets, that may be capable of reducing the net greenhouse gas emissions of our customers.

For more information on Woodside’s climate strategy, including references to ‘lower carbon’ as part of that strategy, and emissions data refer to Woodside’s Climate Transition Action Plan and 2023 Progress Report available at woodside.com.

INDUSTRY AND MARKET DATA

This report contains industry, market and competitive position data based on industry publications and studies conducted by third parties, as well as Woodside’s internal estimates and research. These industry publications and third-party studies generally state that the information they contain has been obtained from sources believed to be reliable, although they do not guarantee the accuracy or completeness of such information. While Woodside believes that each of these publications and third-party studies is reliable and has been prepared by a reputable source, Woodside has not independently verified the market and industry data obtained from these third-party sources and cannot guarantee the accuracy or completeness of such data. Accordingly, undue reliance should not be placed on any of the industry, market and competitive position data contained in this report.

Forecasts and other forward-looking information obtained from these sources are subject to the same qualifications and uncertainties as the other forward-looking statements contained in this report and may differ among third-party sources. These forecasts and forward-looking information are subject to uncertainty and risk due to a variety of factors, including those described in section 3.9 - Risk factors and in this section, section 6.8 - Information about this report. These and other factors could cause results to differ materially from those expressed in Woodside’s forecasts or estimates or those of independent third parties. While Woodside believes its internal research is reliable and its selection of industry publications and third-party studies and the description of its market and industry are appropriate, neither such research nor these descriptions have been verified by any independent source.

BASIS OF PRESENTATION

Woodside’s Financial Statements are prepared in accordance with the Australian Accounting Standards and other authoritative pronouncements of the Australian Accounting Standards Board (AASB) and comply with the International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB).

OTHER IMPORTANT INFORMATION

In this report, references to a year are to the calendar and financial year ended 31 December 2023 unless otherwise stated.

All references to dollars, cents of $ in this report are references to US currency and are stated in Woodside share, unless otherwise stated.

Unless otherwise stated, all Woodside results set out in this Annual Report 2023 include the performance of the interests acquired as part of the merger with BHP’s petroleum business from 1 June 2022.

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EXHIBITS

1.1	Constitution of Woodside Energy Group Ltd (incorporated by reference to Exhibit 99.4 to the Woodside’s Form 6-K (File No. 333-264268) filed on 20 May 2022).
2.1*	Description of Securities.
4.1	Indenture, dated as of 3 November 2003, by and among Woodside Finance Limited, Woodside Petroleum Ltd., Woodside Energy Ltd. And the Bank of New York (incorporated by reference to Exhibit 10.1 of Woodside’s registration statement on Form F-4 (File No. 333-264268) filed on 13 April 2022).
4.2*	Equity Award Rules.
4.3	Woodside Equity Plan (incorporated by reference to Exhibit 10.1 of Woodside’s registration statement on Form S-8 (File No. 333-267432) filed on 15 September 2022).
4.4	Supplementary Woodside Equity Plan (incorporated by reference to Exhibit 10.2 of Woodside’s registration statement on Form S-8 (File No. 333-267432) filed on 15 September 2022).
8.1*	List of subsidiaries of Woodside.
11.1*	Code of ethics
12.1*	Chief Executive Officer certification under Section 302 of the Sarbanes-Oxley Act of 2002.
12.2*	Chief Financial Officer certification under Section 302 of the Sarbanes-Oxley Act of 2002.
13.1#	Chief Executive Officer certification under Section 906 of the Sarbanes-Oxley Act of 2002.
13.2#	Chief Financial Officer certification under Section 906 of the Sarbanes-Oxley Act of 2002.
15.1*	Consent of Ernst & Young
15.2*	Consent of PricewaterhouseCoopers
97.1*	Compensation Recovery Policy of Woodside Energy Group Ltd
101.INS*	Inline XBRL Instance Document
101.SCH*	Inline XBRL Taxonomy Extension Schema Document
101.CAL*	Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*	Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*	Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE*	Inline XBRL Taxonomy Extension Presentation Linkbase Document
104*	Cover page Interactive Data File (embedded within the Inline XBRL document)

* Filed herewith.

# Furnished herewith

SIGNATURES

The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this annual report on its behalf.

Woodside Energy Group Ltd

/s/ Marguerite O’Neill

Marguerite O’Neill

Chief Executive Officer

Date: 27 February 2024