ANNUAL REPORTINCORPORATING APPENDIX 4E Annual Report 2021 This Annual Report 2021 is a summary of Woodside’s operations and activities for the 12-month period ended 31 December 2021 and financial position as at 31 December 2021. Woodside Petroleum 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 Petroleum Ltd and 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. In this report, references to a year are to the calendar and financial year ended 31 December 2021 unless otherwise stated. All dollar figures are expressed in US currency, Woodside share, unless otherwise stated. On the cover Liquefied natural gas (LNG) storage tank, Karratha Gas Plant. Forward-looking statements This report contains forward-looking statements. Please refer to page 153 which contains a notice in respect of these statements. Sustainable Development Report 2021 and Climate Report 2021 A summary of Woodside’s sustainability approach, health and safety performance and other material information for the 12-month period ended 31 December 2021 is included in our Sustainable Development Report 2021. A summary of Woodside's climate change approach for the 12-month period ended 31 December 2021 is included in our Climate Report 2021. The Annual Report, Sustainable Development Report and Climate Report together provide a complementary review of Woodside’s business. ii Annual Report 2021 Acknowledging Country Woodside recognises Aboriginal and Torres Strait Islander peoples as Australia’s first peoples. We acknowledge the unique connection that Indigenous people have to land, waters and the environment. We extend this recognition and respect to Indigenous peoples and communities around the world. We are working with Green Reports™ on an initiative ensuring that communications minimise environmental impact and create a more sustainable future for the community. APPENDIX 4E Results for announcement to the market 2021 2020 Revenue from ordinary activities Increased 93% to US$6,962 million US$3,600 million Profit/(loss) from ordinary activities after tax attributable to members Increased 149% to US$1,983 million (US$4,028) million Net profit/(loss) for the period attributable to members Increased 149% to US$1,983 million (US$4,028) million Dividends Amount Franked amount per security Final dividend (US cents per share) Interim dividend (US cents per share) None of the dividends are foreign sourced Previous corresponding period: Final dividend (US cents per share) Interim dividend (US cents per share) Ordinary 105¢ Ordinary 30¢ Ordinary 105¢ Ordinary 30¢ Ordinary 12¢ Ordinary 26¢ Ordinary 12¢ Ordinary 26¢ Ex-dividend date Record date for determining entitlements to the final dividend Payment date for the final dividend 24 February 2022 25 February 2022 23 March 2022 Net tangible asset per security1 31 December 2021 31 December 2020 $13.86 $12.55 1 Includes lease assets of $1,080 million and lease liabilities of $1,367 million (2020: $984 million and $1,278 million) as a result of AASB 16 Leases. Woodside Petroleum Ltd iii We provide the energy the world needs iv Annual Report 2021 CONTENTS Overview About Woodside 202I achievements 202I summary Chairman's report Chief Executive Officer's report Executive management Focus areas Merger with BHP Petroleum Financial Performance and Strategy Financial summary Strategy and capital management Energy markets Business model and value chain Operations Development Corporate Climate change New energy Carbon Risk Reserves and resources Governance Woodside Board of Directors Corporate governance Directors' report Remuneration Report Financial Statements Shareholder Information Shareholder statistics Key announcements 2021 Events calendar 2022 Business directory Asset facts Glossary, units of measure and conversion factors Ten-year comparative data summary 6 6 7 8 10 12 14 16 18 19 20 25 28 29 31 41 47 48 49 50 51 55 60 61 65 66 69 93 149 150 152 152 154 155 156 159 Woodside’s Operating and Financial Review is contained on pages 6-59. Woodside Petroleum Ltd v OVERVIEW ABOUT WOODSIDE We provide energy which Australia and the world needs to heat homes, keep lights on and enable industry. We have a reputation for safe and reliable operations. Our LNG in particular supports the decarbonisation goals of our customers, and we are progressing opportunities to commercialise new energy products and lower-carbon services as part of our broader product mix. Our proven capabilities as a reliable, low-cost energy provider combined with a focus on technology to enable efficiency will drive our long-term success. We have a portfolio of quality oil and gas assets and more than 30 years of operating experience. Through our North West Shelf and Pluto LNG projects we operated 5% of global LNG supply in 2021. Offshore Australia we operate two floating production storage and offloading (FPSO) facilities, the Okha FPSO and Ngujima-Yin FPSO. Our operations are focused on safety, reliability, efficiency and environmental performance. We also have a non-operated participating interest in the Wheatstone project, which started production in 2017. In November 2021, we reached agreement with BHP Group (BHP) for the merger of BHP's petroleum business with Woodside. The merger will deliver increased scale, diversity and resilience. Completion of the merger is targeted for the second quarter of 2022, following receipt of approvals. The Scarborough and Pluto Train 2 projects have been approved, with first LNG cargo expected in 2026. In Senegal, the Sangomar Field Development Phase 1 remains on track targeting first oil in 2023. Our marketing, trading and shipping activities enable us to supply a growing base of customers primarily in the Asia-Pacific region. We are evolving our business to develop a low-cost, lower- carbon, profitable, resilient and diversified portfolio to help us thrive through the global energy transition. Our climate strategy is to reduce our net equity Scope 1 and 2 greenhouse gas emissions, while investing in the products and services that our customers need as they reduce their emissions. We have set targets to reduce our net equity Scope 1 and 2 greenhouse gas emissions, including a 15% reduction by 2025 and 30% by 2030, towards our aspiration to achieve net zero by 2050 or sooner.1 Our hydrocarbon business is complemented by a growing portfolio of hydrogen, ammonia and solar opportunities in Australia and internationally. Our new energy opportunities include the proposed hydrogen and ammonia projects H2Perth and H2TAS in Australia and the proposed hydrogen project H2OK in North America. We take a disciplined and prudent approach to investment through our capital management framework, ensuring we manage financial risks and maintain a resilient financial position. This allows us to optimise the value delivered from our portfolio of opportunities. Environmental, social and governance performance is integral to our success. Our approach to sustainability is outlined in our Sustainable Development Report. Enduring, meaningful relationships with communities are fundamental to our social performance. Woodside is committed to managing our activities in a sustainable way that is fundamental to the wellbeing of our workforce, our communities and our environment. We recognise that our success is driven by our people and our culture. We are committed to upholding our values of respect, ownership, sustainability, working together, integrity and courage, and we aim to attract, develop and retain a diverse, high performing workforce. 1 Target is for net equity Scope 1 and 2 greenhouse gas emissions, relative to a starting base 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. Post-completion of the Woodside and BHP petroleum merger (which remains subject to conditions including regulatory approvals), the starting base will be adjusted for the then combined Woodside and BHP petroleum portfolio. 6 Annual Report 2021 2021 ACHIEVEMENTS Net profit after tax Underlying net profit after tax million $1,983 $3,792 Operating cash flow million 149% I05% million $1,620 135 Full-year dividend US CPS 262% 255% STRATEGIC ACHIEVEMENTS 1 2 3 4 Merger agreed with BHP's petroleum business Final investment decisions approved for Scarborough and Pluto Train 2 Sell-down agreed for Pluto Train 2 $5 billion investment target to support the energy transition1 1 Targeted investment in new energy products and lower-carbon services by 2030. Investment target assumes completion of the proposed merger with BHP’s petroleum business. Individual investment decisions are subject to Woodside’s investment hurdles. Not guidance. Woodside Petroleum Ltd 7 2021 SUMMARY Achieved strong operational performance, delivered highest profit since 2014 and maintained balance sheet strength. CREATING VALUE We delivered a reported NPAT of $1,983 million, the highest since 2014. Our strong NPAT performance was underpinned by increased oil and gas prices, consistent operational performance and proactive decisions to manage our sales portfolio. Earnings per share increased by 149% to 206 US cps and our full-year fully franked total dividend increased by 255% to 135 US cps. FINANCIAL STRENGTH We continued to prudently manage our debt portfolio with net debt of $3,772 million and gearing of 21.9%, within our target range of 15-35%. We maintained our investment grade credit rating and ended the period with more than $6 billion of liquidity. CONSISTENT OPERATIONS Our operations maintained strong LNG reliability. Total recordable injury rate (TRIR) increased to 1.74 per million work hours. Reported net profit after tax (NPAT) 1,983 1,364 1,069 343 n o i l l i m $ Production 100.3 91.4 89.6 91.1 84.4 e o b M M (4,028) 2017 2018 2019 2020 2021 2017 2018 2019 2020 2021 Gearing Liquidity 23.9 24.4 21.9 % 12.1 14.4 3,918 n o i l l i m $ 2,942 6,952 6,704 6,125 2017 2018 2019 2020 2021 2017 2018 2019 2020 2021 LNG reliability Safety 93.5 97.3 93.7 97.6 97.7 s e i r u n j i l e b a d r o c e r l a t o T 1.32 1.29 12 5 21 2 1.74 TRIR 0.90 0.88 19 Contractors 11 3 8 3 8 Employees 2017 2018 2019 2020 2021 2017 2018 2019 2020 2021 TRIR is the total recordable injury rate per million work hours. Woodside continues to be recognised for strong sustainability performance. % 8 Annual Report 2021 Operating revenue Sales volume 5,240 4,873 3,600 3,975 n o i l l i m $ 6,962 106.8 111.6 89.2 84.1 97.4 e o b M M 2017 2018 2019 2020 2021 2017 2018 2019 2020 2021 Net debt 4,747 n o i l l i m $ 3,888 3,772 2,791 2,397 2017 2018 2019 2020 2021 Credit ratings S&P Global BBB+ Moody'sBaa1 Production cost 5.7 505 5.2 5.1 465 443 4.8 5.3 Unit production cost ($/boe) 478 481 Morgan Stanley Capital International1 Total production cost ($ million) Sustainalytics2 SHAREHOLDER OUTCOMES Full-year dividend 135US CPS 255% Earnings per share 206.0 US CPS 149% Return on equity 14.8% 144% Return on average capital employed 15.6% 174% 2017 2018 2019 2020 2021 1 2 As of 2021, Woodside received an Morgan Stanley Capital International ESG Rating of AAA. Refer to the disclaimer on page 11 of the Sustainable Development Report 2021. In December 2021, Woodside Petroleum Ltd received an ESG Risk Rating of 26.7 and was assessed by Sustainalytics to be at medium risk of experiencing material financial impacts from ESG factors. In 2021, Woodside was recognised by Sustainalytics as an ESG Industry Top Rated company. Copyright ©2021Sustainalytics. All rights reserved. This section contains information developed by Sustainalytics (www.sustainalytics.com). Such information and data are proprietary of Sustainalytics and/or its third party suppliers (Third Party Data) and are provided for informational purposes only. They do not constitute an endorsement of any product or project, nor an investment advice and are not warranted to be complete, timely, accurate or suitable for a particular purpose. Their use is subject to conditions available at https://www.sustainalytics.com/legal-disclaimers. Woodside Petroleum Ltd 9 CHAIRMAN'S REPORT On behalf of the Board, I am pleased to report that 2021 has delivered improved financial performance and significant decisions which we think will set Woodside up to deliver value to all our stakeholders in the years ahead. With the global economy rebounding during the year, we were able to capitalise on high oil and gas prices to report a 2021 net profit after tax of $1,983 million. Strong operating revenue and prudent management of capital and expenditure have us very well positioned to deliver our growth ambitions while returning value to shareholders. We will pay a full-year total dividend of 135 US cents per share. As the COVID-19 pandemic continued to evolve around the world and in Australia, we maintained rigorous controls and response measures to protect the health of our workforce and community, and maintain production at our operations. Our safety performance was disappointing. Our total recordable injury rate increased, in contrast with a downward trend in previous years. Improving this performance is a priority in the year ahead, both in operations and as we embark on new major projects requiring thousands of additional workers. Our announcement of a proposed merger with BHP’s petroleum business in August, followed by execution of a binding share sale agreement in November, is a momentous decision for Woodside’s long-term future. The case for the proposed merger is compelling, bringing together the best of both organisations to create a larger global independent energy company with the scale, diversity, and resilience to provide value to shareholders and navigate the energy transition. We are expecting to deliver significant synergies as we bring both businesses together. I look forward to seeking our shareholders’ approval for the merger, with the vote targeted for 19 May 2022. Announcing final investment decisions on our Scarborough and Pluto Train 2 projects and the sell-down of 49% of Pluto Train 2 to Global Infrastructure Partners which completed in January 2022, were further significant achievements for Woodside in 2021. Scarborough is a world-class reservoir containing only 0.1% carbon dioxide that will be processed through the expanded Pluto LNG facility. It is targeted to deliver first cargo in 2026 into a market with anticipated robust demand for LNG. It will 10 Annual Report 2021 also deliver significant benefits to Western Australia and the nation in the form of thousands of jobs during development, tax revenues and domestic gas supply. The COP-26 global climate summit in October-November 2021 saw renewed focus on global efforts to address climate change. Woodside aims to thrive in the energy transition as a low-cost, lower-carbon energy provider and our approach to climate strategy is simple. First, like all firms and consumers, we must reduce our own greenhouse gas emissions. Secondly, as an energy producer, we must ensure that we invest in the products and services that our customers want, as they too reduce their emissions. Natural gas, when used to generate electricity, emits around half the life cycle emissions of coal. It can also play an important role in ‘firming up’ intermittent renewable generation and be used in ‘hard to abate’ industrial sectors. Major customer countries for Woodside’s LNG, including Japan, the Republic of Korea and China, have set net zero targets and identified ongoing use of natural gas in their energy mix. Global demand for oil is forecast to continue for decades, particularly given the challenges in substituting other energy sources in certain applications. Oil production, as part of Woodside’s broader diversified portfolio, will help meet this global demand, contributing margins and cash flow as Woodside navigates the energy transition. We are making solid progress against our net equity Scope 1 and 2 greenhouse gas emissions reduction targets. Our 2021 net equity Scope 1 and 2 greenhouse gas emissions were 10% below the 2016 – 2020 gross annual average. These reductions were achieved by a range of design, operations and offsetting actions and we are on course to achieve Woodside’s near-term 2025 target of a 15% reduction. From there, we have a mid-term target of a 30% reduction by 2030, with a net zero aspiration by 2050.1 We are also pursuing opportunities to commercialise new energy products and lower-carbon services as part of our broader product mix. In December 2021 we set ourselves a new target to invest $5 billion in profitable new energy products and lower-carbon services by 2030, assuming the proposed merger with BHP’s petroleum business is completed.2 These products include hydrogen and ammonia which produce lower greenhouse gas emissions at the point of use and can help our customers decarbonise. We announced new hydrogen and ammonia producing opportunities including H2Perth near the Kwinana industrial hub south of Perth, H2TAS located in the Bell Bay area of northern Tasmania, and H2OK in Oklahoma. Following the State of Emergency declared on 1 February 2021 in Myanmar, we placed all business decisions under review and expressed our concern at the deteriorating human rights situation. Subsequent to the reporting period, we announced our intention to withdraw from our interests in Myanmar. In the second quarter, we also announced a decision to exit Kitimat LNG in Canada, allowing us to focus on higher value opportunities in Australia and Senegal, where we are on track to deliver first oil from the Sangomar development in 2023. Continued capital discipline is central to our strategy to thrive through the energy transition by building a low-cost, lower- carbon, profitable, resilient and diversified portfolio. On behalf of the Board, I would like to thank the entire Woodside team, who delivered excellent results in 2021 while continuing to pivot and adapt in a dynamic external environment. Peter Coleman retired as Chief Executive Officer and Managing Director in the second quarter after 10 years in the role. Peter’s focus on safety and operational excellence, and his leadership on sustainability, are very valuable legacies. We thank Peter and Meg O’Neill, who acted as Chief Executive Officer from April until August, when the Board formally appointed her to the role. — Richard Goyder, AO Meg has taken on the role with great leadership and energy, overseeing an incredible second half in which we announced the proposed merger with BHP’s petroleum business, Scarborough and Pluto Train 2 final investment decisions, a number of new energy opportunities, and now an impressive profit result. My thanks also go to my Board colleagues who have put in many hours and enthusiastically participated in all the transformational decisions taken in 2021. To all our shareholders, we appreciate your ongoing support. We are pleased that the significant efforts of the Woodside team in 2021 have delivered increased financial returns to you. Rest assured that we remain focused on delivering value to all of our stakeholders and building a stronger, more resilient and diversified company. Richard Goyder, AO Chairman 17 February 2022 1 Target is for net equity Scope 1 and 2 greenhouse gas emissions, relative to a starting base 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. Post-completion of the Woodside and BHP petroleum merger (which remains subject to conditions including regulatory approvals), the starting base will be adjusted for the then combined Woodside and BHP petroleum portfolio. 2 Investment target assumes completion of the proposed merger with BHP’s petroleum business. Individual investment decisions are subject to Woodside’s investment hurdles. Not guidance. Woodside Petroleum Ltd 11 CHIEF EXECUTIVE OFFICER'S REPORT 2021 has been a transformative year for Woodside in which we delivered strong financial results driven by our low-cost, reliable operations, and announced key investment decisions and strategies to ensure that Woodside is a resilient and diversified company in the future. We achieved a reported net profit after tax of $1,983 million, underpinned by strengthened oil and LNG pricing, increased trading activity and the reversal of non-cash impairments related to Pluto-Scarborough and NWS Gas. We generated an operating cash flow of $3.8 billion, a 105% increase from 2020, strengthening our balance sheet and financial position. We announced the proposed merger with BHP’s petroleum business in August and signed a binding share sale agreement in November. The merger is transformative and will deliver increased scale, diversity, and resilience to better navigate the energy transition. It will provide the financial strength to fund planned developments in the near term, investment in future energy opportunities and return value to shareholders through the cycle. Completion of the merger is targeted for early June 2022 subject to a shareholder vote on the transaction which is targeted for 19 May 2022. Unfortunately, and contrary to the importance we place on keeping our colleagues safe, our total recordable injury rate increased to 1.74 per million work hours. The safety of our employees and contractors is our number one priority. A focus area for 2022 is to address common root causes for the 2021 incidents to deliver improvements in overall safety performance. We continued to deliver reliable and lower-cost operations, all while completing our largest ever program of planned maintenance which included work scopes deferred from 2020 due to the impact of the COVID-19 pandemic. We established the Operations Transformation program to support the long-term cost competitiveness of our assets and business. As part of this program we are streamlining processes, utilising technology to enable more informed decision making and automating routine tasks. A key focus for our team has been improving the efficiency and effectiveness of maintenance planning and execution. We had a reserves downgrade on Julimar-Brunello and a reserves revision on the Greater Pluto region following the completion of integrated subsurface studies incorporating 4D seismic and well performance data. We approved final investment decisions on our Scarborough and Pluto Train 2 projects. These decisions are as significant for us as the North West Shelf was in the 1980s, and Pluto in the 2000s. Scarborough is a world-class reservoir containing only 0.1% carbon dioxide and will be processed through the expanded Pluto LNG facility. The Scarborough and Pluto Train 2 projects leverage existing infrastructure at Pluto LNG and site works for Pluto Train 2 were previously completed when the original LNG train was built. Processing Scarborough gas through the efficient and expanded Pluto LNG facility makes it an attractive option for major LNG customers seeking reliable, affordable, and lower-carbon energy to meet demand and support their decarbonisation goals. The approved FID decisions have also resulted in an increase to Woodside's overall corporate Proved plus Probable (2P) Total Reserves by 1,432.7 MMboe. In addition to achieving FID, we also completed the sell- down of a 49% non-operated participating interest in Pluto Train 2 to Global Infrastructure Partners (GIP). This transaction completed in January 2022. Construction of our Sangomar project in Senegal continued on schedule with the first well drilled and completed and FPSO conversion activities continuing. First oil is targeted for 2023. Construction of the Pluto-KGP Interconnector pipeline between Pluto LNG and the Karratha Gas Plant was completed and commissioning activities commenced ahead of ready for start-up (RFSU) targeted for the first quarter of 2022. The Interconnector will provide opportunities to take advantage of future excess capacity at KGP. It will also provide potential 12 Annual Report 2021 to accelerate future developments of other offshore Pluto gas reserves, as well as third-party resources. In October, the first phase of the Pyxis Hub achieved RFSU, which will tie-back the Pyxis and Pluto North fields to existing Pluto infrastructure and support the Pluto-KGP Interconnector. We also achieved RFSU of Julimar-Brunello Phase 2, which involves the tie-back of the Julimar field to the Wheatstone offshore platform. Both Pyxis Hub and Julimar-Brunello Phase 2 were delivered ahead of schedule and under budget. Woodside recognises that a decarbonising world requires low-cost and lower-carbon energy. As well as managing our net equity Scope 1 and 2 greenhouse gas emissions, our approach includes growing our portfolio of new energy opportunities and building capability as we develop the market for lower-carbon products and services. In December, we built on our net equity Scope 1 and 2 greenhouse gas emissions reduction targets of 15% by 2025 and 30% by 2030, with a net zero aspiration by 2050, by setting ourselves a new target to invest $5 billion in new energy products and lower-carbon services by 2030.1,2 Our focus is on hydrogen and ammonia, which produce lower greenhouse gas emissions at the point of use and will help our customers decarbonise. We are also looking at lower-carbon services such as carbon capture and storage, which Woodside could offer as a service to third parties to sequester their emissions. — Meg O'Neill In parallel with this Annual Report we have also released our Climate Report, which articulates how our business will thrive in the energy transition. The report will be put to a non- binding advisory vote at our 2022 Annual General Meeting on 19 May 2022. Environmental, social and governance performance is integral to our success. Our Sustainable Development Report outlines our approach to sustainability which covers inclusion and diversity. I am both humbled and honoured to be leading Woodside during this transformational period for our company. Our story is already remarkable because of the challenges we have overcome and the opportunities we have grasped. I believe we will only emerge stronger as we continue to create a future in which Woodside provides reliable, affordable and lower-carbon energy for decades to come. Meg O'Neill Chief Executive Officer and Managing Director 17 February 2022 1 Target is for net equity Scope 1 and 2 greenhouse gas emissions, relative to a starting base 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. Post-completion of the Woodside and BHP petroleum merger (which remains subject to conditions including regulatory approvals), the starting base will be adjusted for the then combined Woodside and BHP petroleum portfolio. 2 Investment target assumes completion of the proposed merger with BHP’s petroleum business. Individual investment decisions are subject to Woodside’s investment hurdles. Not guidance. Woodside Petroleum Ltd 13 EXECUTIVE MANAGEMENT Meg O’Neill BSc (Ocean Engineering), BSc (Chemical Engineering), MSc (Ocean Systems Management) Chief Executive Officer and Managing Director Mark Abbotsford BEcon (Hons), MBA, MPhil (Finance) Jacky Connolly BCom, MOHS Vice President Marketing, Trading and Shipping Vice President People and Global Capability » Marketing » Trading » Shipping » People and Global Capability » Organisational Development » Remuneration Fiona Hick BEng (Materials Engineering), BAppSci (Energy and Carbon Studies), FIEAust Daniel Kalms BEng (Chemical Engineering), GradCertProjMgt, MBA Senior Vice President Merger Integration Planning » Integration Planning Executive Vice President Operations » Producing Business Units » Production Support » Maintenance » Logistics » Health, Safety and Environment » Subsea and Pipelines » Reservoir Management » Decomissioning 14 Annual Report 2021 Julie Fallon BEng (Hons) (Chemical Engineering), FIChemE Acting Senior Vice President Corporate and Legal » Internal Audit » Business Climate and Energy Outlook » Corporate Affairs » Legal and Secretariat » Governance, Risk and Compliance » Property, Security and Resilience Shaun Gregory BSc (Hons), MBT Executive Vice President Sustainability and Chief Technology Officer » Exploration » Digital » Geoscience » Technology » New Energy and Carbon Abatement opportunities Dr Tom Ridsdill-Smith BSc (Hons), PhD (Mathematical Geophysics) Graham Tiver1 BBus, FCPA Menno Weustink MSc (Offshore Technology) Senior Vice President Climate » Climate Solutions » Climate Engagement Executive Vice President and Chief Financial Officer » Finance, Tax, Treasury and Insurance Acting Vice President Development » Engineering » Projects » Commercial » Development Planning » Business Development and Growth » Drilling and Completions » Contracting and Procurement » Investor Relations » Quality » Browse » Strategy, Planning and Analysis » Sangomar Field Development » Kitimat » Sunrise 1 Mr Tiver commenced with Woodside on 1 February 2022 after the resignation of Sherry Duhe as Executive Vice President and Chief Financial Officer. Woodside Petroleum Ltd 15 FOCUS AREAS Senegal Canada Beijing2 Seoul2 Tokyo2 Houston Myanmar3 H2OK Heliogen Singapore1 Perth Carbon origination projects H2Perth H2TAS Australia Timor-Leste/Australia Product type Phase Gas Oil Producing assets Developments Gas or oil Appraisal and exploration New energies Carbon origination projects Refer to the Asset Facts section on page 155 for full details of Woodside's global interests. 1 Denotes marketing office. 2 Denotes representative and liaison offices. 3 Woodside announced its decision to withdraw from its interests in Myanmar on 27 January 2022. 16 Annual Report 2021 Okha FPSO North West Shelf Project Pluto Scarborough Wheatstone Ngujima-Yin FPSO Browse Karratha Pluto LNG North West Shelf Project Onslow Wheatstone Western Australia Product share of 2021 annual production Carbon origination projects Perth Woodside headquarters H2Perth LNG 78% Liquids 19% LPG and domestic gas 3% Woodside Petroleum Ltd 17 MERGER WITH BHP PETROLEUM Woodside and BHP signed a binding share sale agreement in November 2021 for the merger of Woodside and BHP’s petroleum business. TARGETED KEY DATES » Early April 2022 – Issue of notice of meeting, explanatory memorandum and independent expert’s report » 19 May 2022 – Shareholder meeting to vote on the merger » Early June 2022 – Completion of the merger The combination of Woodside and BHP’s petroleum business is expected to deliver: 1 2 3 4 5 6 A long-life, conventional asset portfolio of scale and diversity of geography, product and end markets. The recent final investment decisions for Scarborough and Pluto Train 2 crystallise a sustained LNG production profile A stronger balance sheet and resilient operating cash flows to fund shareholder returns and business evolution to support the energy transition Superior returns through continued capital discipline An enhanced development portfolio of high-return growth options Increased capacity to deliver on the energy transition Opportunities to deliver ongoing attractive synergies N O B R WER C A LO T S O C W O L P R OFITABLE OPTIMISE VALUE AND SHAREHOLDER RETURNS R E S I L I E N T D I V E R S I F I E D On completion, Woodside will be the largest energy company listed on the ASX and a global top 10 independent energy company by production.1 The merger supports Woodside’s strategy to build a low-cost, lower-carbon, profitable, resilient and diversified portfolio. Completion of the merger is subject to satisfaction (or waiver where permitted) of relevant conditions precedent, which include: • Approval by regulatory and competition authorities • Approval by Woodside shareholders at a general meeting • KPMG, in its capacity as Woodside's independent expert issuing a report concluding that the merger is in the best interests of Woodside shareholders • Registration statements relating to Woodside shares being declared effective by the United States Securities and Exchange Commission • Other conditions customary for a transaction of this nature. 1 Source: Wood Mackenzie Corporate Benchmarking Tool production forecasts as at 31 July 2021. Woodside analysis. 18 Annual Report 2021 FINANCIAL PERFORMANCE AND STRATEGY FINANCIAL SUMMARY In 2021 we achieved a reported net profit after tax of $1,983 million and an underlying net profit after tax of $1,620 million, the highest since 2014. Strong sales revenue resulting from increased market pricing in 2021 was a key contributor to this. The favourable market conditions also supported a significant increase in third-party trading activity. FINANCIAL SUMMARY $ million Operating revenue EBITDA1 EBIT1 NPAT Underlying NPAT1,2 Net cash from operating activities Investing expenditure Capital investment expenditure1,3 Exploration expenditure1,4 Free cashflow1 Dividends distributed Key ratios Return on equity ROACE Effective income tax rate5 Earnings Gearing Sales volumes Gas Liquids Total % % % US cps % MMboe MMboe 2021 6,962 4,135 3,493 1,983 1,620 3,792 2,727 2,631 96 851 404 14.8 15.6 32.0 206.0 21.9 93.7 17.9 111.6 2020 3,600 1,922 (5,171) (4,028) 447 1,849 2,013 1,901 112 (263) 766 (33.4) (21.0) 20.5 (423.5) 24.4 86.5 20.3 106.8 1 These are non-IFRS measures that are unaudited but derived from audited Financial Statements. These measures are presented to provide further insight into Woodside's performance. Refer to footnote 4 on page 159 for the calculation methodology on EBITDA. 2 2021 NPAT was adjusted for Myanmar exploration and evaluation write-offs ($209 million), various costs relating to Woodside's exit from the Kitimat LNG development ($33 million), one-off reconciliation of joint venture costs from prior years ($4 million); offset by the impact of impairment reversals of oil and gas properties ($582 million) and prior period impacts of price reviews ($27 million). 2020 NPAT was adjusted for the impact of impairment of oil and gas properties and exploration and evaluation assets ($3,923 million), recognition of provisions for the Corpus Christi onerous contract ($447 million), a one-off reconciliation of joint operating costs relating to prior years ($41 million), an adjustment to revenue recognised in prior periods relating to price reviews currently under negotiation ($27 million), redundancy costs ($20 million) and additional costs incurred as a result of COVID-19 ($17 million). 3 Excludes exploration capitalised. 4 Excludes prior period expenditure written off and permit amortisation; includes evaluation expense. 5 Global effective income tax rate. 2020 effective income tax rate was impacted by one-off items including the impairment of foreign assets and onerous contract provision. 20 Annual Report 2021 NPAT reconciliation ($ million) 3,161 165 (2,719) 1,058 (1,284) 5,716 d n a t n e m r i a p m I 0 2 0 2 t c a r t n o c s u o r e n o i t s i r h C s u p r o C ) x a t - e r p ( n o i t i n g o c e r n o i s i v o r p (4,028) T A P N 0 2 0 2 (86) 1,983 (363) 1,620 e c i r p - e u n e v e r l s e a S e m u o v l - e u n e v e r l s e a S ) x a t - e r p ( l a s r e v e r t n e m r i a p m i 1 2 0 2 r e h t O T A P N 1 2 0 2 s t s o c g n d a r T i T R R P d n a x a t e m o c n I s t n e m t s u d a T A P N j 1 2 0 2 i T A P N g n y l r e d n u 1 2 0 2 Key movements Sales revenue: price The recovery in oil and gas prices continued in 2021, leading to increased sales revenue due to higher realised prices. Sales revenue: volume There was an approximately ten-fold increase in the number of traded LNG cargoes in 2021 in response to favourable market conditions. There was also an approximately three- fold increase in the number of Corpus Christi cargoes lifted. This was partially offset by fewer condensate cargoes sold, lower facility reliability on Ngujima-Yin as well as weather events in the first half of 2021. The corresponding trading costs for the purchase of third-party traded LNG cargoes and Corpus Christi cargoes are shown in the "trading costs" line item within "other costs of sales" in note A.1 to the Financial Statements. Impairment reversals Final investment decisions for the Scarborough and Pluto Train 2 projects supported the reversal of a non-cash impairment for Pluto, previously recognised in 2020. The non-cash impairment for NWS Gas recognised in 2020 was also reversed, supported by updated cost and production profiles and an improved price environment. Trading costs Trading costs increased due to a higher number of traded cargoes in 2021. The trading revenue is recognised in LNG revenue, and the corresponding higher trading costs are shown in the "trading costs" line item within "other costs of sales" in note A.1 to the Financial Statements. Income tax and PRRT Income tax and PRRT expense increased primarily due to the effect of higher operating revenue in 2021. Other Oil and gas properties depreciation expense decreased primarily due to a reduction in asset bases following the asset impairments announced in July 2020. It was also impacted by lower oil production volumes as a result of lower facility reliability on Ngujima-Yin and weather events in 2021. Exploration wells in Myanmar were written-off during the period as a result of the decision to relinquish the blocks and withdraw from Myanmar. Other items decreasing NPAT included higher royalties, exercise and levies due to higher pricing and revenue, higher repurchase and cancellation costs for revenue optimisations and net loss on hedging activities. Average annual dated Brent ($/boe) 71 135 Dividend per share 71 144 54 98 64 91 42 38 2017 2018 2019 2020 2021 Full-year dividend (US cps) Woodside Petroleum Ltd 21 Capital management Capital allocation Capital expenditure increased in 2021 due to activity ramp up on Sangomar and other expenditure on projects such as Pyxis Hub and Julimar-Brunello Phase 2. Contingent payments were made to ExxonMobil and BHP following the final investment decisions taken on Scarborough and Pluto Train 2. Dividend payments A 2021 final dividend of US 105 cents per share (cps) has been declared. The final dividend is based on the 2021 underlying NPAT of $1,620 million and reflects the performance of our high-reliability and low-cost operations. The value of the final dividend payment is $1,018 million, representing a payout ratio of approximately 80% of underlying NPAT. Woodside's dividend policy remains unchanged following a review in 2021. Dividends will continue to be based on NPAT excluding non-recurring items, with a minimum 50% payout ratio, and a targeted payout ratio between 50% and 80%. The dividend reinvestment plan remains active, allowing eligible shareholders to reinvest their dividends directly into shares at a 1.5% discount. Unit production cost Unit production cost increased by 10% to $5.3/boe. Total production cost remained stable despite increased planned turnaround activity but produced volumes decreased, impacted by the expiry of NWS joint domestic gas contract obligations, cessation of production from the Angel field in 2020, turnaround activity on NWS Project and Wheatstone and the impact of weather events in the first half of 2021. Liquidity 3,792 (2,491) Cash Undrawn debt n o i l l i m $ 6,704 0 0 1 , 3 4 0 6 3 , y t i d u q i i l 0 2 0 2 w o fl h s a c g n i t a r e p O (450) (289) (700) (435) (6) 6,125 0 0 1 , 3 5 2 0 3 , y t i d u q i i l 1 2 0 2 s t n e m e v o m e g n a h c x e n g e r o F i d n o b f o t n e m y a p e R 1 s e i t i v i t c a g n d n u f i r e h t O i l g n d u c x e ( w o fl h s a c g n i t s e v n I I ) D F n o s t n e m y a p t n e g n i t n o c I D F n o s t n e m y a p t n e g n i t n o C ) P R D i f o t e n ( d a p s d n e d v D i i Production cost Debt maturity profile 5.2 443 5.1 465 5.7 505 4.8 478 5.3 481 n o i l l i m $ 1,500 1,000 500 0 7 1 0 2 8 1 0 2 9 1 0 2 0 2 0 2 1 2 0 2 2 2 0 2 3 2 0 2 4 2 0 2 5 2 0 2 6 2 0 2 7 2 0 2 8 2 0 2 9 2 0 2 0 3 0 2 1 3 0 2 Total production cost ($ million) Unit production cost ($/boe) Drawn debt Undrawn debt facilities 1 Other funding activities includes repayment of borrowings and lease liabilities, borrowing costs and contributions to NCI. 22 Annual Report 2021 Balance sheet, liquidity, and debt service During 2021 we generated $3,792 million of cash flow from operating activities. We ended the period with liquidity of $6,125 million. Our credit ratings of Baa1 and BBB+ were both reaffirmed during 2021 by Moody’s and S&P Global respectively. We prudently and strategically manage our debt near-term maturities and maintain a low cost of debt. During the first half of 2021 we repaid a $700 million bond and during the year we refinanced $400 million of committed undrawn facilities. Our gearing ratio decreased from 24.4% at the end of 2020 to 21.9% primarily due to a stronger equity position of the Group as a result of 2021 profit and our gearing remains within our target range of 15-35%. Our weighted average term to maturity decreased from 4.4 to 4.0 years, and our portfolio cost of debt decreased from 2.9% to 2.7%. Our drawn debt at the end of the period was $5,446 million. We will continue to actively manage our debt portfolio throughout 2022. Hedging The Board regularly reviews the appropriate level of hedging to protect against downside pricing risk. In December 2021, in anticipation of the merger, the Board approved hedging of up to 50% of oil-linked exposure from produced hydrocarbons in any one year. As at 14 February 2022, Woodside has oil hedges in place for approximately 17.5 MMboe of 2022 production at an average price of $74.57 per barrel and approximately 21.9 MMboe of 2023 production at an average price of $74.50 per barrel.1 Hedges were also placed to lock in Title Transfer Facility (TTF) priced volumes of approximately 0.5 MMboe for the first quarter of 2022.2 In addition, Woodside has taken hedges on Corpus Christi volumes to protect against downside pricing risk for 2022 and 2023. As a result of hedging and term sales, approximately 97% of Corpus Christi volumes in 2022 and 73% in 2023 have reduced pricing risk as at 14 February 2022.3 2022 outlook Our investment expenditure guidance for 2022 is $3,800 to $4,200 million. The guidance excludes the impact of any subsequent sell-downs which we are progressing on Sangomar and Scarborough upstream, and excludes the benefit of GIP's additional contribution of approximately $822 million for Pluto Train 2. We will increase expenditure on Scarborough and Pluto Train 2 following the final investment decisions in 2021 and will also continue to safely execute Sangomar, which is on track for first oil in 2023. 2022 guidance excludes the impact from the proposed merger with BHP’s petroleum business. 2022 Investment expenditure guidance 4,000 3,000 n o i l l i m $ 2,000 1,000 0 Sangomar4 Scarborough5 Pluto Train 26 Other growth7 Exploration Base business8 2022E 1 As at 31 December 2021, Woodside had oil hedges in place for approximately 13.9 MMboe of 2022 production at an average price of $73.60 per barrel and approximately 15.8 MMboe of 2023 production at an average price of $73.48 per barrel. 2 In place as at 31 December 2021. 3 As a result of hedging and term sales approximately 97% of Corpus Christi volumes in 2022 and 70% in 2023 had reduced pricing risk as at 31 December 2021. 4 Sangomar represents 82% participating interest. Excludes the impact of any subsequent sell-down. 5 Scarborough represents 73.5% participating interest. Excludes the impact of any subsequent sell-down. 6 Pluto Train 2 represents 51% participating interest. Excludes the benefit of GIP's additional contribution of approximately $822 million. 7 Other growth includes New Energy, Pluto-KGP Interconnector, Browse and other spend. 8 Base business includes Pyxis, Pluto LNG, NWS Project, Wheatstone, Australia Oil and Corporate. Woodside Petroleum Ltd 23 24 Annual Report 2021 STRATEGY AND CAPITAL MANAGEMENT We have a strategy to thrive through the energy transition by building a low-cost, lower-carbon, profitable, resilient and diversified portfolio. This will enable us to continue to optimise value and shareholder returns. Woodside has a history of low-cost, high margin operations. Our customers, investors and other stakeholders are increasingly demanding low-cost, lower-carbon energy and Woodside is working on opportunities to develop a resilient and diversified portfolio. Strategic framework Woodside has a portfolio of Tier 1 assets which provides the foundation to deliver new growth opportunities. Our disciplined capital allocation approach includes robust assessment of opportunities, portfolio outcomes and shareholder returns, while maintaining focus on safe and reliable operations. Our investment decisions are informed by energy market analysis including supply, demand and price outlooks and we test the robustness of potential investments against a wide range of climate scenarios to ensure we make the right investment decisions to remain profitable and resilient through various commodity cycles and climate outcomes. Our high performing culture, which includes an engaged, accountable and diverse workforce with a responsible environmental, social and governance (ESG) mindset, is critical to ensuring our effectiveness in delivering our vision and strategy. Our strategic framework is underpinned by our safe and reliable operations, a strong balance sheet and technology to enhance efficiency and deliver low-cost and improved decision making across the value chain. COMPETITIVE ADVANTAGE Highly valued products World-class Tier 1 assets Diversification within known value chains HIGH PERFORMING CULTURE Responsible environmental, social and governance (ESG) mindset Engaged, accountable and diverse workforce ENABLERS Safe and reliable operations Strong balance sheet Technology DISCIPLINED CAPITAL ALLOCATION Robust assessment of opportunities, portfolio outcomes and shareholder returns Disciplined capital spend bound by defined targets MARKET ANALYSIS Energy markets supply, demand and price outlook Scenarios inform new energy trajectory and existing business Woodside Petroleum Ltd 25 Capital allocation framework 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 is responsive to changes in demand and supply for our products. OIL GAS NEW ENERGY OFFSHORE PIPELINE LNG DIVERSIFIED Focus Generate high returns to fund diversified growth, focusing on high quality resources Leveraging infrastructure to monetise undeveloped gas, including optionality for hydrogen New energy products and lower-carbon services to reduce customers’ emissions; hydrogen, ammonia, CCUS1 High cash generation Characteristics Shorter payback period Quick to market Stable long-term cash flow profile Resilient to commodity pricing Long-term cash flow Strong forecast demand Upside potential Developing market Lower capital requirement Lower risk profile Opportunity targets Emissions reduction IRR > 15% IRR > 12% IRR > 10% Payback within 5 years2 Payback within 7 years2 Payback within 10 years2 30% net emissions reduction by 2030, net zero aspiration by 2050 or sooner3 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. Portfolio and opportunity optimisation Portfolio evaluation considerations4 Opportunity evaluation considerations4 EPS Free cash flow Funding capacity Emissions profile Strategic fit IRR/NPV Payback period Risk Breakeven Growth opportunities are screened against portfolio metrics using price, scenario and climate analysis 1 CCUS refers to carbon capture utilisation and storage. 2 Payback refers to RFSU + X years. 3 Target is for net equity Scope 1 and 2 greenhouse gas emissions, relative to a starting base 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. Post-completion of the Woodside and BHP petroleum merger (which remains subject to conditions including regulatory approvals), the starting base will be adjusted for the then combined Woodside and BHP petroleum portfolio. 4 Illustrative of the considerations. Not an exhaustive list. 26 Annual Report 2021 Capital management Our capital management framework provides us with the flexibility to maximise the value delivered from our portfolio of opportunities. We consider a range of climate and macroeconomic scenarios to inform our decision making and ensure we maintain a resilient financial position. Our capital investment requirements are primarily funded by our resilient and stable operating cash flows, which we augment or distribute with a number of capital management levers: • Participating interest management, ensuring we balance capital investment requirements, project execution risk and long-term value. In 2021 we announced the sell- down of a 49% non-operating participating interest in the Pluto Train 2 Joint Venture. This transaction completed in January 2022. In 2022, we will continue the targeted sell-down processes for Sangomar and the Scarborough offshore resource. • Hedging, to protect the balance sheet against the commodity cycle. • Debt management, to ensure that we continue to have access to premium debt markets at a competitive cost to support our growth activities. We seek to manage average debt maturity on our debt portfolio. Our gearing target is 15-35%. We continue to target maintaining an investment-grade credit rating. Optimise value and shareholder returns 2022 PRIORITIES » Maintain a strong balance sheet through liquidity and debt portfolio management » Active balance sheet management including commodity and foreign exchange hedging » Sell-down Sangomar and the Scarborough offshore resource • Shareholder returns, to ensure we reward our shareholders appropriately. Our dividend policy is to aim to pay a minimum of 50% of net profit after tax excluding non-recurring items. The net profit after tax basis helps preserve cash and protect the balance sheet in periods of low commodity pricing. We will target a payout ratio between 50 and 80% and our dividend reinvestment plan remains active. We will maintain the flexibility to consider opportunities to provide additional returns to shareholders through special dividends and share buy- backs in periods of excess cash generation. • Focused expenditure management, to ensure prudent and efficient deployment of capital to support delivery of base business and growth opportunities. Safe, reliable and low-cost operations Investment expenditure Strong balance sheet Dividend policy (minimum 50% payout ratio) Special dividends Share buy-backs Future investment Excess cash Investment grade credit rating Maintain dividend based on NPAT excluding non-recurring items, targeting 50-80% payout ratio Targeted 15-35% gearing Woodside Petroleum Ltd 27 ENERGY MARKETS The global economy grew strongly in 2021, continuing its recovery from the COVID-induced lows of 2020, supported by rising vaccination rates and fiscal and monetary stimulus measures. Oil and gas prices recovered, as demand rebounded in line with the global economic recovery. In 2021, north Asian LNG prices reached all-time highs in January and again in October, supported by various factors including colder winter weather in many key gas-consuming countries and disruptions experienced by a number of suppliers. Global LNG demand grew by 6% in 2021, supported by continued strong demand growth in Asia.1 The World Bank estimates in its Global Economic Prospects report released in January 2022 that global GDP growth will continue in 2022 but at a slower rate, expected to be 4.1% in 2022, down from 5.5% estimated for 2021. Global commitment to take decisive action to address climate change continues to strengthen. In the lead-up to the 26th UN Climate Change Conference of the Parties (COP-26) held in Glasgow during November 2021, many countries, including Japan, South Korea and China, pledged to achieve net zero carbon emissions by around the middle of this century. The International Energy Agency (IEA) estimated in November 2021 that if all of the climate pledges announced to date were met in full and on time, global warming could be limited to below 2 degrees Celsius by 2100.2 The global energy transition is creating uncertainty over how global energy markets will evolve, but there is broad consensus that lower-carbon power sources, such as solar, wind and lower-carbon hydrogen, will play an increasingly important role in global energy systems. LNG demand by region - AET-24 Natural gas, which on a lifecycle basis emits half the carbon dioxide of coal to generate power, is expected to play a critical role in the energy transition. Gas-fired power generation is expected to be an important source of grid stability and flexibility as power systems become renewables-rich.3 Natural gas can also be used in conjunction with carbon capture and storage to create lower-carbon hydrogen, which is likely to become an increasingly significant source of energy over time. It also has the potential to displace higher- carbon fuel sources in many applications. There is a significant opportunity for natural gas to assist with the decarbonisation goals of developing countries in Asia, which typically are fast-growing and often coal-dependent. Wood Mackenzie analysis indicates that growth in global gas demand is expected to at least 2035 under all of their scenarios, including their AET-2 scenario, with most growth coming from developing Asian nations.4 Under Wood Mackenzie’s AET-2 scenario, global LNG demand grows by 62% between 2021 and 2040. Asian LNG demand growth over this period is even stronger, at 90%. Under Energy Transition Outlook, their base case, global LNG demand increases by 90% between 2021 and 2040.4 In addition to our own Scarborough project, 2021 saw Qatar’s North Field East (NFE) project, the Darwin LNG backfill (Barossa) project in Australia, and Russia’s Baltic LNG (Ust-Luga) project take FID. Scarborough’s competitive cost of supply, low reservoir carbon content and proximity to key Asian demand centres makes it ideally placed to supply the world’s growing LNG needs. m c B 1,200 1,000 800 600 400 200 0 Energy Transition Outlook (base case) AET-2 Total global LNG demand Rest of world Europe South-Eastern Asia Southern Asia Eastern Asia 2021 2025 2030 2035 2040 1 Wood Mackenzie Short Term Demand Tracker, January 2022, pg 2. 2 IEA Commentary: COP26 climate pledges could help limit global warming to 1.8 degrees C, but implementing them will be key, Dr Fatih Birol, 4 November 2021. 3 Grattan Institute 2021: “Go for net zero – a practical plan for reliable, affordable, low-emissions electricity” page 30. 4 AET-2 is Wood Mackenzie's accelerated energy transition 2 degrees Celsius scenario. Wood Mackenzie Commodity Report, Global Gas Demand, October 2021, pg 2. 28 Annual Report 2021 BUSINESS MODEL AND VALUE CHAIN Woodside’s business model seeks to optimise returns across the value chain. We achieve this by prioritising competitive growth opportunities; by utilising our operational, development and technological capabilities; and by deepening relationships in energy markets with strong demand growth. We do this with the objective of delivering superior outcomes for stakeholders. Acquire and explore We grow our portfolio through acquisitions 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 assess acquisition opportunities that complement our discovered and undiscovered resource base. We target exploration opportunities close to existing infrastructure and with a clear path to commercialisation. 2021 EXAMPLES Executed binding share sale agreement for the merger of Woodside and BHP's petroleum business. Develop We are building on more than 30 years of development expertise from our assets in Western Australia by investing in opportunities in Australia and internationally. During the development phase, we maximise value by selecting the most competitive concept for extracting, processing and delivering energy to our customers. We are investing in new energy and lower-carbon solutions to meet the needs of our customers and support the resilience of our business. Achieved FID for the Scarborough and Pluto Train 2 projects, and secured land for two proposed hydrogen and ammonia projects in Australia and the proposed hydrogen project, H2OK in North America. Operate Our operations are characterised by strong safety, reliability, and environmental performance in remote and challenging locations. Our operated assets include the NWS Project and Pluto LNG. We also operate two FPSO facilities and have a non-operated interest in Wheatstone. By adopting technology and a continuous improvement mindset we are able to support operational performance and optimise the value of our assets. Completed major turnarounds at NWS Project’s Karratha Gas Plant, North Rankin Complex and Goodwyn-A platform. Woodside Petroleum Ltd 29 — Working at Pluto LNG onshore processing facility Market Our marketing and trading strategy is to build a diverse customer portfolio and pursue additional sales agreements, underpinned by reliable domestic gas, LNG and liquids production, and supplemented by globally sourced volumes. Our relationships with customers in Australian and international energy markets have been maintained through a track record of reliable delivery and expertise across contracting, marketing and trading. In addition to long-term LNG sales, we pursue near-term value-accretive arrangements through short- and mid-term sales and LNG shipping transactions. Our marketing of crude, condensate and LPG is based on short-term sales, and may be supplemented by term arrangements to maximise value. We are collaborating with our customers on innovative lower-carbon energy solutions, including carbon offset LNG and liquids cargoes. 2021 EXAMPLES Marketed domestic gas on a mid- and short-term basis from Woodside's portfolio. Decommission Decommissioning is integrated into project planning, from the earliest stages of development through to the end of field life. Through working together with our partners and technical experts, we are able to identity the most sustainable and beneficial post-closure options that minimise financial, social and environmental impacts. Completed plug and abandonment activities for the Capella well and two Yodel wells. 30 Annual Report 2021 OPERATIONS PLUTO LNG 2021 HIGHLIGHTS 2022 PLANNED ACTIVITIES » Delivered strong production performance » Achieve Pluto-KGP Interconnector ready » Achieved start-up of Pyxis Hub ahead of schedule for start-up and under budget » Achieve Pluto water handling ready for start-up » Agreed new targets for Pluto LNG greenhouse gas emissions under the Pluto Greenhouse Gas Abatement Program » Commence Xena 2 project execution Enabling growth The first phase of the Pyxis Hub project, comprising wells in the Pyxis and Pluto North fields, achieved ready for start-up (RFSU) in October 2021, four months ahead of the planned schedule and under budget. Pyxis Hub ties back the Pyxis and Pluto fields to existing Pluto infrastructure and will support the Pluto-KGP Interconnector expected to start-up in Q1 2022. The second phase of the project targets drilling, completion and subsea tie-back of the Xena 2 well. Hook-up and commissioning activities for the Pluto water handling project continued during the year. Schedule impacts related to COVID-19 were managed and the project is on track to achieve RFSU in 2022. Once operational the water handling unit will enable wet gas production. Woodside’s Pluto Greenhouse Gas Abatement Program (GGAP) was approved by the Western Australian Minister for Environment. The GGAP includes interim and long-term targets to achieve a 30% emissions reduction from approved levels by 2030 and net zero by 2050 across the entire project.2 The targets incorporate emissions associated with Pluto Train 2 (see Scarborough and Pluto Train 2 on pages 42-43). Woodside interest: 90%, operator Operational performance Woodside achieved strong production performance at Pluto LNG in 2021, delivering 44.3 MMboe of production (Woodside share). This was a decrease of 1% compared to 2020 due to a minor turnaround at Pluto LNG delivered in August 2021. High reliability of 97.2% at Pluto LNG was maintained during the year as a result of our focus on safe, reliable and efficient operations. We had no Tier 1 or 2 process safety events at Pluto LNG in 2021. We continue to focus on efficiency and emissions reduction opportunities. In 2021 new controls and piping were installed at Pluto LNG, enabling low pressure methane vapour to be captured, and compressed to recycle back into the LNG train. The estimated emissions savings compared to venting the uncombusted methane was approximately 2.4 kt CO2-e per annum.1 Woodside commenced construction of the Pluto Operations Centre at our head office in Perth to remotely operate the foundation Pluto offshore and onshore assets. The centre will be known as Moorditj Danjoo, which means 'strong together' in the local Nyoongar language. Moorditj Danjoo is expected to commence a phased transition to full operations from the second quarter of 2022 leveraging Woodside's capability to integrate innovation and technology to support operational performance. Woodside completed a review of the reserves and resource estimates for the Greater Pluto region in November 2021. The review followed completion of integrated subsurface studies incorporating 4D seismic and well performance data. Further detail is in the Reserves and resource statement on page 55. 1 The estimated GHG savings quoted in each example are based on operated emissions using engineering judgment by appropriately skilled and experienced Woodside engineers. 2 Pluto LNG Development Public Environmental Review (2006) emissions estimate of 4.1 Mtpa CO2-e for two LNG trains. 32 Annual Report 2021 Production 44.3 MMboe LNG reliability 97.2% Sales revenue $2,649 million Unit production cost $4.3 per boe — Pluto LNG onshore processing facility Woodside Petroleum Ltd 33 NWS PROJECT 2021 HIGHLIGHTS 2022 PLANNED ACTIVITIES » Successfully delivered major turnaround activities » Commence processing other resource owner » Delivered 14% reduction in underlying operating costs » Established a marketing entity to engage with other resource owners for processing gas through the Karratha Gas Plant » Re-engaged with the Browse Joint Venture on potential supply of gas to KGP gas through Karratha Gas Plant » Commence production from Greater Western Flank Phase 3 » Target further improvement in underlying operating cost performance Operational performance The NWS Project delivered full-year production of 24.7 MMboe in 2021 (Woodside share). This was a decrease of 20% compared to 2020, due to significant planned turnaround activity in 2021 and offshore gas supply constraints. We achieved high reliability of 98.3% during the year and we had no Tier 1 or 2 process safety events at NWS in 2021. We continue to focus on efficiency and emissions reduction opportunities to support Woodside's corporate targets. In 2021, KGP used advanced process controls to prioritise in real time the most modern and efficient gas turbines. This resulted in increased energy efficiency compared to a non-prioritised approach. Estimated savings are approximately 55-150 kt CO2-e per annum.1 The NWS Project successfully executed its largest scope of planned shutdown maintenance in 2021 and included work deferred from 2020 due to the impact of the COVID-19 pandemic. The turnarounds were completed at Karratha Gas Plant (KGP), North Rankin Complex and Goodwyn A platform. Our people demonstrated resilience to maintain safe, reliable production at NWS, despite constraints presented by COVID-19 border restrictions. This required careful workforce management to ensure compliance with government requirements. Enabling growth With emerging processing capacity, the NWS Project is preparing to process third-party gas from 2022 and has created a marketing entity to market available processing capacity at KGP. Arrangements were finalised with the Western Australian Government for the processing of gas from Pluto from 2022 and the Waitsia Joint Venture from 2023. Woodside also agreed with the Western Australian Government to market and make available from 2025 an additional 45.6 PJ of domestic gas from its existing NWS equity production. The four-well development drilling campaign for Greater Western Flank Phase 3 (GWF-3) completed in January 2022. GWF-3 (including Lambert Deep) is a subsea tie-back opportunity to further commercialise NWS reserves. The NWS Project re-engaged with the Browse Joint Venture on a commercial proposal and joint technical studies to support processing Browse gas at KGP. A revised Greenhouse Gas Management Plan was submitted to the Environmental Protection Authority in December 2021 by the NWS Project participants to support long-term operations and processing of future third-party gas resources. Woodside interest: 16.67%, operator 1 The estimated GHG savings quoted in each example are based on operated emissions using engineering judgment by appropriately skilled and experienced Woodside engineers. 34 Annual Report 2021 Production 24.7 MMboe LNG reliability 98.3% Sales revenue $I,530 million Unit production cost $4.7 per boe — Working at Karratha Gas Plant Woodside Petroleum Ltd 35 WHEATSTONE AND JULIMAR-BRUNELLO 202I HIGHLIGHTS 2022 PLANNED ACTIVITIES » Achieved start-up of Julimar-Brunello Phase 2 » Safely execute Phase 2 of the Wheatstone major ahead of schedule and under budget turnaround » Completed Phase 1 of the Wheatstone major turnaround Operational performance Woodside's share of annual production in 2021 was 13.5 MMboe, a decrease from 15.2 MMboe in 2020 due to the Wheatstone major turnaround and Brunello reservoir performance. Wheatstone executed the first phase of a multi-year major turnaround throughout September and October 2021 and will complete the second phase during 2022.1 Woodside completed a review of the reserves and resource estimates for Julimar-Brunello in October 2021. The review followed completion of integrated subsurface studies incorporating 4D seismic, well performance and well drilling results. Further detail is in the Reserves and resource statement on page 55. Julimar-Brunello Phase 2 Julimar-Brunello Phase 2 involves the tie-back of the Julimar field to the Wheatstone offshore platform. Strong progress was made on the development throughout 2021, with installation of subsea equipment completed. Completion of cold commissioning activities and RFSU was achieved in December 2021. Woodside interest: 13%, non-operator (Wheatstone); 65%, operator (Julimar-Brunello) — Subsea 7 vessel, Seven Oceans installing 18" flow line for Julimar-Brunello Phase 2 Production Sales revenue I3.5 MMboe $772 million 1 Wheatstone LNG processes gas from two separate developments, the Wheatstone Iago Project (80%) and the Julimar-Brunello Project (20%). Woodside is the operator of the Julimar-Brunello project with 65% equity. Woodside’s 13% non-operated interest in the Wheatstone facilities includes the offshore platform, the pipeline to shore and the onshore plant, but excludes the Wheatstone Iago fields and infrastructure. 36 Annual Report 2021 AUSTRALIA OIL 202I HIGHLIGHTS 2022 PLANNED ACTIVITIES » Successful execution of Okha FPSO major » Commencement of Enfield subsea wells turnaround plug and abandonment » Delivered revenue optimisation activities » Start-up of Cimatti production and water injection wells to Ngujima-Yin FPSO » Preparation for Ngujima-Yin major turnaround in 2023 Ngujima-Yin FPSO The Ngujima-Yin FPSO produces oil from the Vincent and Greater Enfield resources. The facility delivered full-year production of 7.1 MMboe in 2021 (Woodside share), down from 8.3 MMboe in 2020 due to weather impacts and lower facility reliability, including the FPSO disconnection during Tropical Cyclone Seroja in April 2021. In addition, Woodside temporarily shut-in production from the Cimatti field to capitalise on the continued increased price premium for low sulphur fuel oil. Woodside completed engineering studies to enable additional production through increased water injection without the need for large capital expenditure. Woodside interest: 60%, operator Okha FPSO The Okha FPSO produces oil from the Cossack, Wanaea, Lambert and Hermes fields. Woodside successfully completed a series of significant maintenance activities including a major turnaround and a five-yearly survey to establish the technical condition of the facility. Woodside's share of annual production in 2021 was 1.5 MMboe, an increase from 1.4 MMboe in 2020 due to the installation of a replacement subsea flowline increasing production rates at the Okha FPSO by approximately 1,000 bbl/d. Woodside interest: 33.33%, operator — Okha FPSO Woodside Petroleum Ltd 37 EXPLORATION 2021 HIGHLIGHTS 2022 PLANNED ACTIVITIES » Completed three offshore exploration wells in » Continue to prioritise infrastructure-led activities Myanmar in Q1 2021 » Completed ‘Ojingeo’ 3D marine seismic offshore Republic of Korea in May 2021 » Senegal SNE North-2 appraisal well planning and PSC licence extension » Drill SNE North-2 well in Senegal » Evaluate 3D seismic data from offshore Republic of Korea to identify prospectivity close to the Korean market » Relinquish remaining interests in Myanmar Woodside is focused on maturing exploration activities near existing infrastructure, exiting low value licences and planning for future exploration wells. Australia Interpretation of datasets focused primarily on exploration opportunities in Western Australia close to existing infrastructure. An infrastructure-led portfolio approach during 2021 identified opportunities which are notionally planned for the 2023-2024 period. The Gemtree exploration prospect in permit WA-49-L has received Environment Plan approval and is planned to be drilled in 2023 for tie-back to Wheatstone infrastructure. Additional subsurface studies facilitated Woodside’s bid and award of WA-550-P gazettal permit, which provides highly prospective tie-back options for Woodside’s Pluto infrastructure. A 2D seismic survey acquisition in NT-P86 offshore the Northern Territory is targeted for 2022. Global activities A 3D seismic survey covering approximately 2,575km² was successfully acquired in H1 2021 for Blocks 8 and 6-1N in offshore the Republic of Korea. This data will support the continued subsurface assessment and identification of prospects. Woodside progressed and approved the Senegal SNE North-2 well location. This well targets both appraisal and exploration oil intervals to enable tie-back into the under construction Sangomar FPSO. The well is planned to be drilled in the second half of 2022, in conjunction with the ongoing Sangomar Field Development Phase 1 drilling campaign. An extension to the RSSD Exploration Licence was supported. 38 Annual Report 2021 In March 2021 Woodside completed a three well exploration campaign in Myanmar blocks A-7, AD-1 and AD-8. All three wells were safely drilled, evaluated, and abandoned, and while AD-8 and A-7 found hydrocarbons, none of the wells were considered a commercial discovery. Notice to terminate the Production Sharing Contract for Myanmar Block A-7 was accepted by Myanma Oil and Gas Enterprise on 23 November 2021. The effective date is 30 September 2021 with the formal relinquishment process on-going. On 27 January 2022 Woodside announced its decision to withdraw from its interests in Myanmar. Location of SNE North-2 offshore Senegal. MARKETING, TRADING AND SHIPPING LNG portfolio Woodside supplies LNG to major gas and electricity utilities, trading houses and industrial buyers around the world. We manage our LNG portfolio through a mix of short-, mid- and long-term contracts, supplied by Woodside and cargoes purchased from third parties. This combination of different arrangements within our LNG portfolio enables operational flexibility to capitalise on changing market conditions as they occur. In 2021 Woodside supplied 8.6 million tonnes of LNG from both produced volumes and purchased Corpus Christi volumes. Our trading and optimisation activity significantly increased in 2021 reaching its highest level, driven by favourable commodity price levels and volatile market conditions. Our LNG portfolio approach enables sales commitments to be met from produced and purchased offtake, allowing optimisation of both our portfolio offtake and our shipping fleet to maximise value. Portfolio optimisation activities include the purchase and on-sale of third-party cargoes to extract additional value, which has enabled Woodside to increase exposure to gas hub indices at higher price levels. Gas hub exposure is the proportion of produced equity LNG volumes expected to be sold on gas hub indices such as JKM, TTF and UK National Balancing Point. Henry Hub is excluded from the calculation. In 2021 our produced LNG sold on gas hub indices was approximately 16% and we expect approximately 20-25% of our produced LNG to be sold on gas hub indices in 2022. Liquids marketing Woodside has built its liquids marketing capability to optimise value from its oil portfolio. The marketing of crude, condensate and LPG is based on short-term sales, and may be supplemented by term arrangements. Woodside achieved record premiums to Dated Brent for three cargoes in 2021; a Vincent crude cargo produced from the Ngujima-Yin FPSO, which targeted low sulphur fuel oil blenders as opposed to traditional refineries, and two Wheatstone condensate cargoes resulting from strengthening regional condensate demand. — Karratha Gas Plant Woodside Petroleum Ltd 39 Growth The long-term sale and purchase agreement executed in January 2021 with Uniper Global Commodities included an approved Scarborough FID condition which was satisfied in November 2021. The Scarborough FID also provides a strong foundation to undertake future mid-term and long-term LNG sales, targeting traditional and growth markets principally in the Asia region. Woodside signed a memorandum of understanding with Viva Energy to progress discussions on capacity usage at Viva Energy’s proposed LNG regasification terminal in Geelong, Australia, potentially enabling Woodside to supply LNG to the east coast Australia market. Woodside signed a non-binding heads of agreement with Commonwealth LNG, to negotiate a sale and purchase agreement for the supply of LNG from the proposed Commonwealth LNG development in Cameron, Louisiana. Woodside executed joint venture agreements with the RSSD joint venture participants to enable the lifting and marketing of oil production from the Sangomar Field Development Phase 1. Domestic gas Woodside continues to meet customer requirements for domestic gas through a mix of short-, mid- and long- term contracts. Our domestic gas sources include the NWS Project, Pluto LNG and Wheatstone. Our portfolio sales approach enables us to develop our base of customers and trading capabilities. Woodside and joint venture participant EDL LNG Fuel to Power executed three sale and purchase agreements (SPA) for the supply of domestic LNG from the Pluto LNG truck loading facility for a period of five to ten years. Woodside is continuing discussions with various mining companies for the potential delivery of LNG to their mine sites. Integrated shipping and operations Woodside has a proven track record across integrated shipping, operations, marketing and trading which delivered 308 LNG, condensate, crude and LPG cargoes with Woodside equity interest in 2021. Woodside maintains an LNG shipping fleet of six vessels under long-term contracts, and one vessel on short-term charter. Control of shipping capacity protects value from producing assets, ensures reliable cargo delivery to meet contractual sales arrangements and enables portfolio and shipping optimisation. Woodside actively engaged with customers on inclusion of carbon offsets as part of structuring sales transactions, building its carbon offset marketing capability and supporting the decarbonisation goals of our customers. In March 2021, Woodside and the Pluto LNG joint venture participants sold their first carbon offset condensate cargo to Trafigura Pte Ltd. In November 2021, Woodside sold its first carbon offset LNG cargo to Uniper Global Commodities SE, and its first carbon offset LPG cargo to Vitol Asia Pte Ltd.1 1 The term “carbon offset” indicates that the seller and the buyer have committed to reduce or offset the amount of carbon dioxide equivalent associated with their respective operated emissions (including the extraction, processing, storage, and shipping) through a combination of demonstrated emissions reductions and carbon offsets certified by Verra or Gold Standard. — LNG jetty, Karratha Gas Plant. 40 Annual Report 2021 DEVELOPMENT SCARBOROUGH AND PLUTO TRAIN 2 2021 HIGHLIGHTS 2022 PLANNED ACTIVITIES » Approved final investment decisions in » Commence site civil works and module November 2021 fabrication for Pluto Train 2 » Executed commercial agreements to enable processing of Scarborough gas at the Pluto LNG site » Progress Scarborough engineering, procurement and manufacturing activities across all major contracts » Agreed sell-down of a 49% non-operating » Commence fabrication yard activities for the interest in Pluto Train 2 to Global Infrastructure Partners (GIP)1 floating production unit » Complete front-end engineering design (FEED) » Issued full notice to proceed to Scarborough for Pluto Train 1 modifications contractors » Target sell-down of Scarborough offshore resource Final investment decisions were approved for the Scarborough and Pluto Train 2 projects, including the construction of new domestic gas facilities. The Scarborough field is located approximately 375 km off the coast of Western Australia and is estimated to contain 11.1 trillion cubic feet (100%) of dry gas. Development of Scarborough will include the installation of a floating production unit with eight wells drilled in the initial phase and thirteen wells drilled over the life of the Scarborough field. The gas will be transported to the existing Pluto LNG facility through a new approximately 430 km trunkline. Expansion of Pluto LNG will include the construction of a second LNG train, associated domestic gas processing facilities, supporting infrastructure and modifications to Pluto Train 1 to allow it to process Scarborough gas. The composition of gas from the Scarborough field is well suited to Pluto LNG which is designed for lean gas and nitrogen removal. An area for a second train was pre-prepared when the foundation project was built, with minimal earthworks required for Pluto Train 2. During 2021, Woodside completed key activities to support the final investment decisions. This included entering 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. The transaction included a number of other related agreements between Woodside and GIP, including a project commitment agreement. The transaction completed on 18 January 2022. Woodside is continuing the sell-down process for Scarborough, targeting an operating equity interest of 51% or greater in the Scarborough Joint Venture. Woodside continues to work with Traditional Custodians to identify, manage and protect heritage. In 2021 an independent ethnographic assessment found no ethnographic sites within the proposed Scarborough development area. This, coupled with an archaeological assessment that did not find any prospective submerged archaeological locations likely to be impacted by the project, supports there being a nil to low likelihood of submerged heritage in the development area. All key primary environmental approvals to support the final investment decisions are in place, with secondary environmental approvals progressing to support project execution activities. Woodside’s Pluto Greenhouse Gas Abatement Program (GGAP) was approved by the Western Australian Minister for Environment. The GGAP includes interim and long-term 1 This transaction completed in January 2022. 42 Annual Report 2021 — Illustration of the approved Scarborough and Pluto Train 2 projects at the existing Pluto LNG onshore facility targets to achieve a 30% emissions reduction from approved levels by 2030 and net zero by 2050 across the entire project.1 The targets incorporate emissions associated with Pluto Train 2. Woodside was also granted environmental approval of the State waters (nearshore) component for the Scarborough project by the Western Australian Minister for Environment. This is the primary environmental approval required for activities in State waters. It authorises the installation of an approximately 32 km section of the Scarborough trunkline within State waters, together with associated activities required to construct the trunkline. Bechtel has proven Australian LNG project experience and has been selected as the EPC contractor for Pluto Train 2 and integration into the existing Pluto LNG facilities. Woodside issued a limited notice to proceed to Bechtel in October 2021, enabling Bechtel to progress engineering, and order materials and equipment for Pluto Train 2 and commence early works for construction of the accommodation village in Karratha. Bechtel was issued full notice to proceed in January 2022. Concept definition studies were completed in Q4 2021 for modifications to Pluto Train 1 to enable processing of up to 3 Mtpa of Scarborough gas. Front-end engineering design commenced in Q1 2022 and is expected to be completed in the second half of 2022. Woodside has engaged a range of specialist contractors in the offshore, subsea and pipelines sectors to deliver the Scarborough project and has secured access to the Valaris DPS-1 mobile offshore drilling unit to undertake drilling of the initial eight wells. The detailed design activities are well progressed and in Q4 2021 the project took delivery of five subsea production trees which will be stored and preserved in readiness for drilling operations in 2023. Woodside has commitments in place with our contractors to deliver skills development and training, employment, contracting and Indigenous participation during the four- year construction phase. The Scarborough Field Development Plan and pipeline licence applications were submitted to regulators and are currently under assessment. Retention lease renewals in respect of the WA-61-R and WA-63-R titles for the Jupiter and Thebe fields respectively were granted by the Commonwealth and Western Australian Joint Authority. Woodside is targeting the first LNG cargo in 2026. Woodside interest: 73.5%, operator (Scarborough); 51%, operator (Pluto Train 2)2 1 Pluto LNG Development Public Environmental Review (2006) emissions estimate of 4.1 Mtpa CO2-e for two LNG trains. 2 Following sell-down of a 49% non-operating participating interest to GIP which completed on 18 January 2022. Woodside Petroleum Ltd 43 PLUTO-KGP INTERCONNECTOR The Pluto-KGP Interconnector will allow the transfer of gas between Pluto LNG and the NWS Project’s Karratha Gas Plant to optimise production across both facilities, enabling accelerated production of Pluto gas reserves as well as third-party resources. Gas from Pluto will be processed using new equipment at Pluto LNG before being transported by the 3.2 km, 30-inch pipeline to Karratha Gas Plant (KGP). The pipeline has been constructed within the existing Dampier to Bunbury Natural Gas Pipeline corridor. In January 2021, domestic gas arrangements with the Western Australian Government were finalised to allow Woodside to supply Pluto gas through the Interconnector pipeline, for processing at KGP. Throughout the year, construction activities progressed for the processing facilities and piping at Pluto LNG and KGP. The primary module of the Interconnector project, fabricated and supplied by a Western Australian based contractor was installed at Pluto LNG in Q3 2021. The pipeline construction between Pluto LNG and KGP was completed in Q4 2021. Traditional Custodians were consulted and engaged during clearing and other key activities to ensure culturally significant areas were clearly demarcated and avoided, and pipeline construction activities were undertaken in a culturally appropriate manner. Commissioning activities are underway and Woodside is targeting ready for start-up in Q1 2022. Woodside interest: 100% — Pluto-KGP Interconnector under construction 44 Annual Report 2021 SANGOMAR FIELD DEVELOPMENT 2021 HIGHLIGHTS 2022 PLANNED ACTIVITIES » Drilled and completed the first development well » Commence subsea installation » Commenced FPSO conversion activities » Arrival of second drillship in Senegal » Progressed subsea infrastructure fabrication » Progress FPSO conversion activities The Sangomar Field Development Phase 1 is Senegal’s first oil project and is on track for first oil in 2023. Phase 1 is developing the less complex reservoirs in the Sangomar field and testing other reservoirs to support potential future phases. This phase of the development targets production of an estimated 231 million barrels of oil resources (100%) with 2P Reserves of 149 MMbbl Woodside economic share. Oil will be produced through a stand-alone floating production storage and offloading (FPSO) facility with supporting subsea infrastructure. It is designed to allow the tie-in of subsequent phases. In February 2021, the VLCC oil tanker arrived at a shipyard in China and FPSO conversion activities commenced. The FPSO will be named FPSO Léopold Sédar Senghor, after the first President of the Republic of Senegal. The FPSO conversion activities continued throughout the year, with construction work scopes for the turret, mooring system and topside modules progressing. The conversion remains on schedule. In July 2021, the Ocean BlackRhino drillship arrived in Senegal and subsequently the first development well was drilled and completed, including installation of the xmas tree. It was the first horizontal production well to be drilled in Senegal. Overall, the drilling campaign will include up to 23 production, gas and water injections wells and will be undertaken using two drill ships using a batch drilling approach. Subsea equipment fabrication is on schedule across multiple international locations and equipment continues to arrive in Senegal, including wellhead systems and xmas trees. Preparation activities are ongoing for the subsea installation campaign, expected to commence in 2022. Woodside is working with the Government of Senegal to develop local capabilities, support training initiatives, offer employment opportunities and organise capacity building sessions with Senegalese administrations. Woodside has local content commitments with our key contractors to ensure opportunities are maximised for Senegalese people and suppliers. In 2021, Woodside awarded contracts to Senegalese local businesses for major services to support in-country development activities. In 2021 Woodside Energy (Senegal) B.V. completed the acquisition of the entire participating interest of FAR Senegal RSSD S.A. in the Rufisque Offshore, Sangomar Offshore and Sangomar Deep Offshore (RSSD) joint venture. Woodside’s participating interest increased to 82% for the Sangomar exploitation area (with Petrosen's participating interest 18%) and 90% for the remaining RSSD evaluation area (with Petrosen's participating interest 10%). Woodside commenced engagement with interested parties to sell down its participating interest in the RSSD joint venture to a targeted 40-50%. Woodside interest: 82%, operator Woodside Petroleum Ltd 45 BROWSE SUNRISE The Sunrise development comprises the Sunrise and Troubadour gas and condensate fields. The fields contain an estimated contingent resource (2C) of 1.7 Tcf of dry gas and 76 MMbbl of condensate Woodside share (5.1 Tcf of dry gas and 226 MMbbl of condensate, 100%). The Sunrise Joint Venture participants continue to engage the Australian and Timor-Leste Governments on a new Greater Sunrise Production Sharing Contract (PSC), which is required under the 2019 Maritime Boundary Treaty. Woodside is meeting its relevant title commitments (JPDA 03-19 and JPDA 03-20 and Retention Lease NT/ RL2 and NT/ RL4) and maintains a social investment program. Woodside interest: 33.44%, operator CANADA In 2021 Woodside announced its decision to exit its 50% non- operated participating interest in the proposed Kitimat LNG (KLNG) development, located in British Columbia, Canada. Exit activities progressed as planned with commercial agreement terminations, lease relinquishments and remediation planning well underway. The sale of the Pacific Trail Pipeline route to Enbridge Inc. was completed in December 2021. Woodside is retaining an upstream position in the Liard Basin by assuming full equity in 28 non-infrastructure related Liard Basin leases from Chevron Canada, to study low-cost natural gas, ammonia and hydrogen opportunities in Canada. More information is available in the Reserves and resources statement on page 55. The Browse Joint Venture (BJV) is proposing to develop the Brecknock, Calliance and Torosa fields located approximately 425 km north of Broome in the offshore Browse basin. The Browse resource contains an estimated contingent resource (2C) of 4.3 Tcf of dry gas and 119 MMbbl of condensate Woodside share (13.9 Tcf of dry gas and 390 MMbbl of condensate, 100%). Activities during 2021 focused on key commercial, regulatory and technical work streams to enable greater certainty for the development to progress towards FEED entry. This included recommencing commercial discussions and joint technical studies with the North West Shelf Project regarding an agreement to process Browse gas at KGP. Woodside continues to work with both Commonwealth and State regulators and engage relevant stakeholders to finalise the supplement to the proposed Browse to NWS Project Draft Environmental Impact Statement (EIS) and Response to Submissions on the Environmental Review Document (ERD). The BJV is evaluating a range of options to manage greenhouse gas emissions and is progressing a feasibility assessment for a carbon capture and storage solution and opportunities to improve energy efficiency. Applications for production licences for the Calliance and Torosa Fields and a retention lease renewal in relation to Brecknock were submitted in April 2020. Commonwealth and State title regulators are continuing their assessment of these applications. Woodside interest: 30.6%, operator MYANMAR Following the State of Emergency declared on 1 February 2021, Woodside placed all business decisions under continuous review. Woodside announced its decision to withdraw from its interests in Myanmar on 27 January 2022. 46 Annual Report 2021 CORPORATE CLIMATE CHANGE Woodside aims to thrive through the energy transition by building a low-cost, lower-carbon, profitable, resilient and diversified portfolio. Our climate strategy is an integral part of our company strategy. It has two key elements: reducing our net equity Scope 1 and 2 greenhouse gas emissions, and investing in the products and services that our customers need as they reduce their emissions. Our Climate Report includes a detailed description of Woodside's approach to climate change. This Annual Report should be read in conjunction with Woodside's Climate Report 2021 and the Sustainable Development Report 2021. In 2021, Woodside’s net equity Scope 1 and 2 greenhouse gas emissions were 3,235 kt CO2-e, 10% below the 2016-2020 gross annual average and is on track to achieve Woodside’s target of a 15% reduction by 2025. We plan to achieve this by avoiding emissions in the way we design our facilities, reducing emissions in the way we operate our facilities and offsetting the remainder. Woodside is focused on reducing methane emissions and is a signatory to the Methane Guiding Principles. Woodside has also published its approach to Scope 3 greenhouse gas emissions. This includes a new investment target of $5 billion by 2030 in new energy products and lower-carbon services which are expected to support customer and supplier emissions reduction, together with promoting global emissions measurement and reporting.1 Woodside's climate reporting has been structured to align with the Task Force on Climate-related Financial Disclosures (TCFD) recommendations framework, and is a supporter of TCFD. This year we have issued a separate Climate Report and will put it to a non-binding, advisory shareholder vote at our 2022 Annual General Meeting. THE CLIMATE REPORT DESCRIBES OUR: STRATEGY including emissions reduction plans and portfolio scenario analysis TARGETS AND METRICS including our progress against emissions reduction objectives GOVERNANCE RISK MANAGEMENT including the respective roles of Board and Management including short-, medium- and long-term risks and opportunities 1 Investment target assumes completion of the proposed merger with BHP’s petroleum business. Individual investment decisions are subject to Woodside’s investment hurdles. Not guidance. 48 Annual Report 2021 NEW ENERGY Woodside's strategy is to invest in the new energy products and the lower- carbon services our customers need as they decarbonise. We are progressing opportunities for producing products such as hydrogen and ammonia. In 2021, we made significant progress by securing land for three proposed projects: • H2Perth, a world-scale liquid hydrogen and ammonia production facility to be located on 130 hectares of industrial land in southern metropolitan Perth • H2TAS, a 100% renewable ammonia project to be located in Tasmania’s Bell Bay region, allowing expansion of the previous concept to export scale while also providing local supply • H2OK, a 290 MW liquid hydrogen project in the Westport Industrial Park, Ardmore, Oklahoma. Front-end engineering design has commenced. A key component of this strategy is to work with potential customers to develop demand for new sources of energy. Customer collaboration highlights in 2021 include: • A new export project consortium with Japan’s IHI Corporation and Marubeni Corporation in connection with H2TAS • A joint feasibility study to establish a clean fuel ammonia supply chain from Australia to Japan with Japan Oil, Gas and Metals National Corporation, Marubeni Corporation, Hokuriku Electric Power Company and The Kansai Electric Power Co., Inc. • Forming the HyStation company alongside five other parties in September 2021 to drive hydrogen bus adoption in the Republic of Korea • Agreeing a memorandum of understanding (MOU) with Hyzon Motor Company to explore collaboration opportunities in the US and Australia • Agreeing a MOU with Keppel Data Centres, City Energy, Osaka Gas Singapore and City-OG Gas Energy Services to study the feasibility of a liquid hydrogen supply chain to Singapore and potentially Japan from Woodside’s proposed H2Perth project. Our new energy technology focus is on hydrogen production, renewables and carbon management. In October 2021 we announced a collaboration with Heliogen, Inc. including a proposed commercial-scale pilot facility in California. Heliogen is a leading provider of artificial intelligence enabled concentrated solar technology. Woodside is also progressing the Woodside Solar Project, a proposed solar facility that could supply 100 MW of solar energy to Pluto LNG and other customers located near Karratha in Western Australia, with potential expansion to a maximum of 500 MW. Woodside announced plans in November 2021 to target $5 billion investment by 2030 in new energy products and lower-carbon services.1 Refer to the capital allocation framework on page 26 for investment criteria. 1 Investment target assumes completion of the proposed merger with BHP’s petroleum business. Individual investment decisions are subject to Woodside’s investment hurdles. Not guidance. Illustration of the proposed hydrogen project H2OK in Oklahoma, North America. Woodside Petroleum Ltd 49 CARBON Woodside has built a portfolio of offsets and carbon origination projects sufficient to meet our net equity Scope 1 and 2 greenhouse gas emissions reduction target of 15% by 2025.1 Woodside established a carbon business in 2018 to develop a sustainable offset portfolio in support of our base business and new energy projects. We acquire offsets on carbon markets and also originate our own, managing them on a portfolio basis to optimise the cost of meeting both regulatory and corporate targets.2 This approach is intended to manage the risk of future changes in the costs, availability and regulatory framework for offsets, by developing a diverse portfolio differentiated by vintage, methodology and geography. We retire offsets annually to meet our emissions reduction targets. Further details can be found in our Climate Report 2021. Woodside has a program aimed at utilising land in Western Australia for biodiverse carbon plantings. The Woodside Native Reforestation Project planted 3,000 hectares in Western Australia across 2020 and 2021, which is estimated to sequester about 700,000 tonnes of CO2-e over 25 years. In 2021, we purchased two properties in the Wheatbelt region of Western Australia, with planting targeted for 2022. Woodside entered into an agreement with the Northern Territory Government, Commonwealth Scientific and Industrial Research Organisation and industry to develop a business case assessing the viability of a large-scale, low emission carbon capture utilisation and storage hub based in the Northern Territory. The hub has the potential to reduce emissions, acting as a catalyst to new net zero industries that can continue throughout the energy transition. In November, Woodside, bp and Japan Australia LNG (MIMI) Pty Ltd agreed to form a consortium to progress feasibility studies for a large-scale, multi-user carbon capture and storage (CCS) project near Karratha in Western Australia. The consortium will assess the technical, regulatory and commercial feasibility of capturing carbon emitted by multiple industries located near Karratha and storing it in offshore reservoirs in the Northern Carnarvon Basin. The study represents an important step towards the development of one of Australia’s first multi-user CCS projects, ideally located to aggregate emissions from various existing sources. 1 Target is for net equity Scope 1 and 2 greenhouse gas emissions, relative to a starting base 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. Post-completion of the Woodside and BHP petroleum merger (which remains subject to conditions including regulatory approvals), the starting base will be adjusted for the then combined Woodside and BHP petroleum portfolio. Assumes equity Scope 1 and 2 greenhouse gas emissions are as currently forecast in Woodside's business plan. 2 Further information on the cost of offsets is available in our Climate Report 2021. 50 Annual Report 2021 — Tree planting site at near Cranbrook, Great Southern region, Western Australia RISK Our approach to risk management enables us to take risk for reward, protects against negative impacts and improves our resilience to emerging risks. Woodside recognises that risk is inherent in our business and the effective management of risk is vital to deliver our strategic objectives, continued growth and success. We are committed to managing risks in a proactive and effective manner as a source of competitive advantage. We apply a structured and comprehensive approach to the identification, assessment and treatment of current risks and in response to emerging risks. Our risk management framework provides a single consolidated view of risks across the company to quantify our full risk exposure and prioritise risk management and governance. The framework is aligned with the intent of the International Standard ISO31000 for risk management, providing line of sight of risk at appropriate levels of the organisation, including the executive team and the Board, based on defined materiality thresholds. Our assessment of risk considers both financial and non-financial exposures, including health and safety, environment, finance, reputation and brand, legal and compliance, social and culture. A twice yearly review by the executive team and the Board evaluates the strategic risk profile, and the effectiveness of material current risks being managed across the business. Uncertainty in the external environment has increased in 2021 such as growing geopolitical concerns and nationalism, increasing sophistication and frequency of cyber and digital related attacks, continuing global and domestic impacts of the COVID-19 pandemic, and higher and evolving societal and stakeholder expectations (notably on environmental, social and governance (ESG) topics). We continually monitor external signals to ensure we are able to adapt our strategies, or review and improve the controls we rely on, to effectively and efficiently manage our exposure to risk. Refer to Woodside’s Corporate Governance Statement for more information (woodside.com.au/about-us/ corporate-governance). The Board reviewed and confirmed in 2021 that the risk management framework is sound, and that Woodside is operating with due regard to the risk appetite endorsed by the Board. Social Licence to Operate Stakeholders have higher and evolving expectations of Woodside’s social responsibility, with a focus on transparency and ethical decision making. In 2021 the release of ‘Our Risk and Compliance Behaviours’ framework helped our leaders at all levels of the organisation, by reinforcing the positive behaviours and actions to influence decision making, realise opportunity and support sustainable long-term performance consistent with our Vision and Compass values. Refer to our Sustainable Development Report 2021 for more information on ESG. Climate Change Climate change and the transition to a lower-carbon economy influences Woodside’s strategy, presenting both risk and opportunity in the operation of our existing assets or commercialisation of our growth portfolio. We leverage our risk management framework to ensure an integrated and coordinated approach to the management of climate change across the business. The risks posed by the transition to a lower-carbon economy are recognised given changes in policy, regulation or social expectations in current or future markets. Refer to our Climate Report 2021 for more information. Woodside Petroleum Ltd 51 Overview of our strategic and material risks TITLE CONTEXT RISK MITIGATION Climate change Climate change is impacting the way that the world produces and consumes energy, and this is expected to accelerate over time. Climate change also requires adaptation to physical change. Social licence to operate Our business performance is underpinned by our social licence to operate, which requires compliance with legislation and the maintenance of a high level of ethical behaviour and social responsibility. Our business activities are subject to extensive regulation and government policy in each of the countries where we do business. Failure to comply may impact our licence to operate. Stakeholders have evolving expectations of social responsibility and ethical decision making. These are changing at a rate faster than governments can introduce or amend regulation. This will impact the transition to a lower-carbon economy and may impact demand (and pricing) for oil, gas and its substitutes, the policy and legal environment for its production, our reputation, and our operating environment. Further, the availability and cost of emission allowances or carbon offsets could adversely impact costs of operations. Woodside contributes to solving climate change challenges by supplying LNG, improving our energy efficiency, focusing on reducing our emissions (and potentially those of our customers or value chain participants), and developing innovative new energy technologies and markets for the efficient delivery of lower-carbon energy to grow a longer-term resilient portfolio. We have near- and mid-term emissions reduction targets with plans to meet them.1 We engage and advocate with key industry and governance stakeholders. Further information is in our Climate Report 2021. Failure to meet stakeholder expectations can lead to opposition and a decline in support for both our base business and future growth opportunities. Woodside proactively maintains and builds our social licence to operate through the application of our Compass values, effective stakeholder engagement strategies, our regulatory compliance framework and our anti-fraud and corruption program. A significant or continuous departure from national or local laws, regulations or approvals may result in negative social and cultural impacts, reputation and brand, and loss of licence to operate. Violation of international anti- bribery and corruption laws may expose Woodside to fines, criminal sanctions and civil suits, and negatively impact our international reputation. Our regulatory compliance framework assists Woodside to proactively maintain relationships with governments and regulators within countries that support base business and future growth opportunities. Woodside maintains meaningful relationships with stakeholders, seeking proactive engagement to inform decisions and gain support for changes. Our fraud and corruption framework aims to prevent, detect and respond to unethical behaviour. It incorporates policies, standards, guidelines and training to ensure activities are conducted ethically and to a high standard. Scarborough Scarborough extends the economic life of Pluto LNG, enables future tiebacks from adjacent resources, and will generate significant long- term cashflow to underpin Woodside’s future growth strategy Failure to commercialise and deliver Scarborough could result in a loss of shareholder value and impact our growth strategy. Growth Growth opportunities can be captured through exploration, mergers, acquisitions or expansions. Each may incur risks that impact our ability to realise the expected value. The inability to identify and commercialise growth opportunities, or realise their full value, may result in a loss of shareholder value. Failure to complete the merger with BHP's petroleum business may also result in a loss of shareholder value. We employ a number of measures to ensure Scarborough is delivered to the approved business case including: • Effectively managing execution contractors ensuring they deliver to or better than promised • Securing execution-related environmental and regulatory approvals and ensuring compliance through execution and operations • Continue to pursue funding opportunities such as the equity sell down of Scarborough • Delivering safe and reliable operations that meet production commitments. See pages 42-43 for more information on the Scarborough project. Our opportunity management framework is flexible and adaptable with the primary objective to realise the value of an opportunity while mitigating the risk of a sub- optimal outcome. We aim to identify and progress a suite of commercially attractive and sustainable opportunities that complement our existing assets, enable portfolio diversity and optimise our commercial position. We continue to monitor and assess growth opportunities through mergers and acquisitions on a case-by-case basis. 1 Target is for net equity Scope 1 and 2 greenhouse gas emissions, relative to a starting base 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. Post-completion of the Woodside and BHP petroleum merger (which remains subject to conditions including regulatory approvals), the starting base will be adjusted for the then combined Woodside and BHP petroleum portfolio. 52 Annual Report 2021 TITLE CONTEXT RISK MITIGATION Operations Maintaining the technical integrity and operational performance of our assets is essential to protecting our people, the environment, our licence to operate and the financial capacity to support existing business and growth opportunities. Finance Woodside’s financial performance and resilience may be impacted by key factors such as: • Disruption in market dynamics • Ability to maintain competitive advantage • Access to capital • Management of financial risks Safe operation is fundamentally embedded through an extensive framework of controls that deliver strong operational performance in our base business. We have a track record of operating discipline and excellence. The framework includes production processes, drilling and completions and well integrity management processes, inspection and maintenance procedures and performance standards. The framework is supported and inspected on an ongoing basis by our regulators. Decommissioning is integrated into project planning. We work with our partners and technical experts to identify sustainable and beneficial post-closure options that minimise financial, social and environmental impacts. The framework is adaptable to ensure we are able to maintain and improve our operating model and performance, target reliability, cost discipline, emissions reductions and strong safety and environmental performance for both our existing business and future growth opportunities. The delivery of our strategic portfolio objectives requires significant capital expenditure, supported by strong underlying cashflows. • Uncertainty associated with product demand is mitigated by selling LNG in a portfolio manner and under long-term ‘take or pay’ sale agreements, in addition to the spot market. Our low-cost of production and prudent approach to balance sheet risk management further mitigates this exposure. • A flexible approach to capital management enables this overall level of investment in the different areas of our business and the mix to be adjusted to reflect the external environment. Our capital management strategy focuses on capital allocation, capital discipline and efficiency, and active balance sheet management including commodity and foreign exchange hedging. • We maintain insurance in line with industry practice and sufficient to cover normal operational risks. However, Woodside is not insured against all potential risks because not all risks can be insured and because of constraints on the availability of commercial insurance in global markets. Insurance coverage is determined by the availability of commercial options and cost/benefit analysis, taking into account Woodside’s risk management program. Losses that are not insured could impact Woodside’s financial performance. For example, Woodside does not purchase insurance for the loss of revenue arising from an operational interruption. Our extensive framework of financial controls, including monitoring of counterparties, enables the management of these risks. • The US dollar reflects the majority of Woodside’s underlying cashflows and is used in our financial reporting, reducing our exposure to currency fluctuations. Failure to deliver safe, reliable and efficient operations could result in a sustained, unplanned interruption to production, and a failure to meet production forecasts, deliver base business and provide revenue to support growth. Our operating assets are subject to operating hazards associated with major accident events, cyber attacks, extreme weather events and disruptions within global supply chains that may ultimately lead to a loss of hydrocarbon containment or additional costs. An inability to fund the delivery of strategic portfolio objectives could prevent Woodside from unlocking value, weaken financial resilience and result in a loss of shareholder value. Risk factors include: • Commodity prices are variable and are impacted by global economic factors beyond Woodside’s control. • Demand for and pricing of our products remain sensitive to external economic and political factors, weather, natural disasters, introduction of new and competing supply, changes in buyer preferences for differing products and price regimes. • We are exposed to treasury and financial risks, including liquidity, changes in interest rates, fluctuations in foreign exchange rates and credit risk. • Insufficient liquidity to meet financial commitments and fund growth opportunities could have a material adverse effect on our operations and financial performance. • Our financing costs could be affected by interest rate fluctuations or deterioration in our long-term investment grade credit rating. • We are exposed to credit risk; our counterparties could fail or could be unable to meet their payment or performance obligations under contractual arrangements. Woodside Petroleum Ltd 53 TITLE CONTEXT RISK MITIGATION People and culture Innovation Digital and cybersecurity Woodside must maintain sufficient talent, capability and capacity and a strong organisational culture. An engaged and enabled workforce underpins our ability to deliver base business, future growth and new energy opportunities. This may impact our operating model and create the need for a new or co- existing culture at Woodside. We focus on maintaining our competitive advantage by delivering value through new ideas, technologies or diversified products. The practical application of innovation delivers near-term value to our base business and in the longer term, transforms and creates opportunities to thrive in a lower-carbon economy. Woodside continues to invest in and rely on sustainable and secure digital technologies to deliver a cost competitive base business, to enhance our growth opportunities and pace of innovation. Cyber risks continue to evolve with greater levels of sophistication. Regulatory and compliance obligations are increasing for data protection and security of critical infrastructure. Failure to establish and maintain sufficient workforce capability and capacity may impact achievement of our base business or future growth objectives and inhibit new energy opportunities An ineffective operating model could inhibit the energy transition of our base business and new energy opportunities. Woodside has a set of resourcing frameworks to attract, retain and develop our workforce to support both base business and growth opportunities. We recognise and value the benefits of creating an inclusive and diverse working environment. We employ a direct engagement model to maintain effective employee and industrial relations. We proactively engage our major contractors and suppliers to strengthen alignment with expectations, securing capability and pricing to meet future business needs. Inability to deliver an organisational model may undermine value following completion of the merger with BHP's petroleum business. Failure to build, embed, leverage and support innovation may result in a significant threat to the competitive advantage of our base business and our longer-term sustainability. In anticipation of the merger with BHP's petroleum business we are reviewing our current and future operating models to support both base business and growth opportunities. We drive the practical application of innovation through an entrepreneurial, opportunity-focused, agile approach. We seek and leverage world-class knowledge and innovation communities, platforms and tools to reduce unit costs for both our base business and future growth opportunities. We are creating a portfolio of new energy opportunities to form new strategic relationships or capture market in response to emerging trends, and disruptive and complementary technologies. Failure to safeguard the confidentiality, integrity and availability of digital data and information. Woodside’s technology systems may be subject to both unintentional and intentional disruption, for example cybersecurity attack. We are committed to the protection of our people, assets, reputation and brand through securely enabled digital technologies. Digital risks are identified, assessed and managed based on the business criticality of our people and systems, and may be required to be segregated and isolated. Digital risks include third parties, including suppliers and service providers, within our supply chain. Our operating model aims to continuously assess and determine access permissions to critical information or data, while consolidating, simplifying and automating security controls. Our exposure to cyber risk is managed by a control framework that ensures cyber events are identified, contained and recovered in a timely manner, and embeds a cyber-safe culture across the company, with our joint venture participants and in our supply chain. 54 Annual Report 2021 RESERVES AND RESOURCES Woodside delivered Reserves production of 93 MMboe in 2021.18 Approval of the Scarborough development contributed 1,433 MMboe of Proved plus Probable (2P) Undeveloped Reserves. Start-up of the Pyxis, Pluto North and Julimar-Brunello Phase 2 wells contributed Proved plus Probable (2P) Developed Reserves of 45 MMboe, 25 MMboe and 62 MMboe, respectively. Increased equity interest in the Sangomar Field Development resulted in a net increase of 16 MMboe Proved (1P) Undeveloped Reserves, 25 MMboe Proved plus Probable (2P) Undeveloped Reserves and 46 MMboe Best Estimate (2C) Contingent Resources. Increased equity interest in the upstream Liard Basin contributed a net increase of 2,106 MMboe Best Estimate (2C) Contingent Resources. Completion of the Greater Pluto and Julimar-Brunello integrated subsurface studies resulted in updated reserves positions for these regions. The Greater Pluto Proved (1P) Developed and Undeveloped Reserves and Proved plus Probable (2P) Developed and Undeveloped Reserves decreased by 17 MMboe and 92 MMboe, respectively.34 Julimar-Brunello Proved (1P) Developed and Undeveloped Reserves and Proved plus Probable (2P) Developed and Undeveloped Reserves decreased by 45 MMboe and 65 MMboe, respectively.34 These changes include 2021 net Reserves production of 46 MMboe for Greater Pluto and 13 MMboe for Julimar-Brunello.18 Following Woodside’s decision to withdraw from its interests in Myanmar announced on 27 January 2022, the Best Estimate Contingent Resources (2C) will no longer include 109.5 MMboe for the Myanmar region. Table 1: Woodside's Reserves1,3,4,5 and Contingent Resources2 overview* (Woodside share, as at 31 December 2021) Proved11 Developed13 and Undeveloped14 Proved Developed Proved Undeveloped Proved plus Probable12 Developed and Undeveloped Proved plus Probable Developed Proved plus Probable Undeveloped Contingent Resources * Small differences are due to rounding. Table 2: Key Metrics 2021 reserves replacement ratio15 Organic 2021 reserves replacement ratio16 Three-year reserves replacement ratio Organic three-year reserves replacement ratio Reserves life17 Annual production18 Net acquisitions and divestments Dry Gas6 Bcf8 Condensate7 MMbbl9 Oil MMbbl Total MMboe10 8,090.7 1,952.9 6,137.8 11,669.4 2,634.9 9,034.6 34,768.0 44.8 33.5 11.3 60.2 45.4 14.8 230.1 128.1 30.0 98.0 184.2 35.5 148.7 269.7 1,592.3 406.1 1,186.2 2,291.7 543.1 1,748.5 6,599.4 Units Proved Proved plus Probable % % % % Years MMboe MMboe 1,044 1,027 336 314 17.1 92.9 16.0 1,446 1,419 467 434 24.7 92.9 24.9 Woodside Petroleum Ltd 55 1P Reserves 2P Reserves 2C Contingent Resources 2 9 5 , 1 2 9 2 2 , 5 1 9 1 7 8 4 1 7 8 0 5 , 1 2 4 4 , 1 4 3 3 , 1 e o b M M 8 3 2 , 1 3 1 2 , 1 1 4 0 , 1 e o b M M 9 9 5 6 , 9 7 9 5 , 5 2 9 5 , 7 1 5 2 5 1 0 5 , , 4 1 0 8 5 9 3 4 , , 1 1 0 , 1 0 5 1 , 1 0 8 0 , 1 e o b M M 2015 2016 2017 2018 2019 2020 2021 2015 2016 2017 2018 2019 2020 2021 2015 2016 2017 2018 2019 2020 2021 Table 3: Proved (1P) and Proved plus Probable (2P) Developed and Undeveloped Reserves annual reconciliation by product* (Woodside share, as at 31 December 2021) Dry Gas Bcf Condensate MMbbl Oil MMbbl Total MMboe ) P 1 ( d e v o r P ) P 2 ( e l b a b o r P l s u p d e v o r P Reserves at 31 December 2020 3,118.3 4,502.6 Revision of Previous Estimates19 -26.8 -520.2 Transfer to/from Reserves20 5,425.0 8,111.3 Extensions and Discoveries21 Acquisitions and Divestments22 9.8 - 11.3 - Annual Production -435.5 -435.5 ) P 1 ( d e v o r P 51.1 1.6 -0.3 0.3 - -7.9 ) P 2 ( e l b a b o r P l s u p d e v o r P ) P 1 ( d e v o r P ) P 2 ( e l b a b o r P l s u p d e v o r P ) P 1 ( d e v o r P ) P 2 ( e l b a b o r P l s u p d e v o r P 72.9 116.3 177.8 714.5 1,040.6 -4.5 -0.7 0.4 - -7.9 4.4 -9.9 1.3 -105.6 - - 16.0 -8.6 - - 24.9 -8.6 951.4 1,422.4 2.0 16.0 2.3 24.9 -92.9 -92.9 Reserves at 31 December 2021 8,090.7 11,669.4 44.8 60.2 128.1 184.2 1,592.3 2,291.7 * Small differences are due to rounding. Table 4: Best Estimate Contingent Resources (2C) annual reconciliation by product* (Woodside share, as at 31 December 2021) Contingent Resources at 31 December 2020 Revision of Previous Estimates Transfer to/from Reserves Extensions and Discoveries Acquisitions and Divestments Dry Gas Bcf Condensate MMbbl 31,113.5 -160.1 -8,230.1 - 12,044.6 231.4 -0.6 -0.7 - - Oil MMbbl 234.9 -4.7 - - Total MMboe 5,924.8 -33.4 -1,444.6 - 39.4 2,152.5 Contingent Resources at 31 December 2021 34,768.0 230.1 269.7 6,599.4 * Small differences are due to rounding. 56 Annual Report 2021 Table 5: Best Estimate Contingent Resources (2C) summary by region* (Woodside share, as at 31 December 2021) Greater Browse29 Greater Sunrise31 Greater Pluto24 Greater Exmouth26 North West Shelf25 Julimar-Brunello27 Canada33 Senegal28 Greater Scarborough30 Myanmar32 Total * Small differences are due to rounding. Dry Gas Bcf Condensate MMbbl Oil MMbbl Total MMboe 4,257.8 1,716.8 1,116.5 307.4 282.4 37.4 25,373.3 232.2 820.2 624.0 119.4 75.6 22.5 2.2 9.7 0.7 - - - - - - - 26.7 11.7 - - 231.2 - - 866.4 376.7 218.3 82.9 71.0 7.3 4,451.5 271.9 143.9 109.5 34,768.0 230.1 269.7 6,599.4 1P Reserves by region (Developed and Undeveloped) 2P Reserves by region (Developed and Undeveloped) 2C Contingent Resource by region I,592 MMboe 2,292 MMboe 6,599 MMboe Greater Pluto North West Shelf Greater Exmouth Julimar-Brunello Senegal % 17% 9% 1% 7% 6% Greater Pluto North West Shelf Greater Exmouth Julimar-Brunello Senegal Greater Scarborough 60% Greater Scarborough % 15% 7% 1% 7% 6% 63% Greater Pluto North West Shelf Greater Exmouth Julimar-Brunello* Senegal Greater Scarborough Greater Browse Greater Sunrise Canada Myanmar % 3% 1% 1% 0.1% 4% 2% 13% 6% 67% 2% * Small differences are due to rounding. Woodside Petroleum Ltd 57 Table 6: Proved (1P) Developed and Undeveloped23 Reserves by region* Dry Gas Bcf Condensate MMbbl Oil MMbbl Total MMboe d e p o e v e D l l d e p o e v e d n U l a t o T Greater Pluto24 1,123.1 309.2 1,432.3 North West Shelf25 550.5 Greater Exmouth26 - 91.1 - 641.6 - Julimar-Brunello27 279.3 284.7 564.0 Senegal28 Greater Scarborough30 - - - - 5,452.8 5,452.8 d e p o e v e D l 15.8 12.3 - 5.4 - - l d e p o e v e d n U 4.0 2.1 - 5.3 - - d e p o e v e D l - 8.4 21.6 - - - l d e p o e v e d n U - - - - l a t o T - 8.4 21.6 - 98.0 98.0 - - d e p o e v e D l 212.8 117.3 21.6 54.4 - - l d e p o e v e d n U 58.2 18.1 - 55.2 98.0 l a t o T 271.0 135.4 21.6 109.6 98.0 956.6 956.6 l a t o T 19.7 14.4 - 10.6 - - Reserves 1,952.9 6,137.8 8,090.7 33.5 11.3 44.8 30.0 98.0 128.1 406.1 1,186.2 1,592.3 * Small differences are due to rounding. Table 7: Proved plus Probable (2P) Developed and Undeveloped23 Reserves by region* Dry Gas Bcf Condensate MMbbl Oil MMbbl Total MMboe d e p o e v e D l l d e p o e v e d n U l a t o T Greater Pluto 1,511.6 333.6 1,845.2 North West Shelf 689.0 118.6 807.6 Greater Exmouth - - - Julimar-Brunello 434.3 415.7 849.9 Senegal Greater Scarborough - - - - 8,166.6 8,166.6 d e p o e v e D l 20.7 15.8 - 8.9 - - l d e p o e v e d n U 4.3 2.8 - 7.7 - - l a t o T 25.0 18.5 - 16.7 - - d e p o e v e D l - 10.1 25.3 - - - l d e p o e v e d n U - - - - l a t o T - 10.1 25.3 - 148.7 148.7 - - d e p o e v e D l 285.9 146.7 25.3 85.1 - - l d e p o e v e d n U 62.8 23.6 - 80.6 148.7 l a t o T 348.7 170.3 25.3 165.8 148.7 1,432.7 1,432.7 Reserves 2,634.9 9,034.6 11,669.4 45.4 14.8 60.2 35.5 148.7 184.2 543.1 1,748.5 2,291.7 Qualified Petroleum Reserves and Resource Evaluator Statement The estimates of petroleum resources are based on and fairly represent information and supporting documentation prepared under the supervision of and approved by Mr Jason Greenwald, Woodside’s Vice President Reservoir Management, who is a full-time employee of the company and a member of the Society of Petroleum Engineers. Mr Greenwald’s qualifications include a Bachelor of Science (Chemical Engineering) from Rice University, Houston, Texas, and more than 20 years of relevant experience. * Small differences are due to rounding. Governance and Assurance Woodside as an Australian company listed on the Australian Securities Exchange, reports its petroleum resource estimates using definitions and guidelines consistent with the 2018 Society of Petroleum Engineers (SPE)/World Petroleum Council (WPC)/American Association of Petroleum Geologists (AAPG)/Society of Petroleum Evaluation Engineers (SPEE) Petroleum Resources Management System (PRMS). Woodside has several processes to provide assurance for reserves reporting, including the Woodside Reserves Policy, Petroleum Resources Management Procedure, Petroleum Resource Management Guideline, staff training and minimum competency levels and external reserves audits. On average, 99% of Woodside’s Proved Reserves have been externally verified by independent review over the past four years. Unless otherwise stated, all petroleum resource estimates are quoted as net Woodside share at standard oilfield conditions of 14.696 pounds per square inch (psi) (101.325 kPa) and sixty degrees Fahrenheit (15.56 degrees Celsius). 58 Annual Report 2021 Notes to the Reserves and Resource Statement 1. 2. ‘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. ‘Contingent resources’ are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations, but the applied project(s) are not yet considered mature enough for commercial development due to one or more contingencies. Contingent resources may include, for example, projects for which there are currently no viable markets, or where commercial recovery is dependent on technology under development, or where evaluation of the accumulation is insufficient to clearly assess commerciality. Woodside reports contingent resources net of the fuel and flare required for production, processing and transportation up to a reference point and non-hydrocarbons not present in sales products. Contingent resources estimates may not always mature to reserves and do not necessarily represent future reserves bookings. Contingent resource volumes are reported at the ‘Best Estimate’ (P50) confidence level. Assessment of the economic value of the project, in support of a reserves classification, uses Woodside Portfolio Economic Assumptions (PEAs). The PEAs are reviewed on an annual basis or more often if required. The review is based on historical data and forecast estimates for economic variables such as product prices and exchange rates. The PEAs are approved by the Woodside Board. Specific contractual arrangements for individual projects are also taken into account. 4. Woodside uses both deterministic and probabilistic methods for 3. estimation of petroleum resources at the field and project levels. Unless otherwise stated, all petroleum estimates reported at the company or region level are aggregated by arithmetic summation by category. Note that the aggregated Proved level may be a very conservative estimate due to the portfolio effects of arithmetic summation. Probabilistic aggregation at field and project level is more appropriate than arithmetic summation as inter-field dependencies reflecting different reservoir characteristics between fields are incorporated. 5. Woodside reports reserves net of the fuel and flare required for production, processing and transportation up to a reference point. For offshore oil projects, the reference point is defined as the outlet of the floating production storage and offloading facility (FPSO), while for the onshore gas projects the reference point is defined as the inlet to the downstream (onshore) processing facility. Downstream fuel and flare represent 10.0% of Woodside’s Proved (Developed and Undeveloped) reserves, and 9.9% of Proved plus Probable (Developed and Undeveloped) reserves. ’Dry gas’ is defined as ‘C4 minus’ petroleum components including non-hydrocarbons. These volumes include LPG (propane and butane) resources. Dry gas reserves and contingent resources include ‘C4 minus’ hydrocarbon components and non-hydrocarbon volumes that are present in sales product. ‘Condensate’ is defined as ‘C5 plus’ petroleum components. ‘Bcf’ means Billions (109) of cubic feet of gas at standard oilfield conditions of 14.696 psi (101.325 kPa) and sixty degrees Fahrenheit (15.56 degrees Celsius). ‘MMbbl’ means millions (106) of barrels of oil and condensate at standard oilfield conditions of 14.696 psi (101.325 kPa) and sixty degrees Fahrenheit (15.56 degrees Celsius). ‘MMboe’ means millions (106) of barrels of oil equivalent. Dry gas volumes, defined as ‘C4 minus’ hydrocarbon components and non- hydrocarbon volumes that are present in sales product, 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 oil and condensate, defined as ‘C5 plus’ petroleum components, are converted from MMbbl to MMboe on a 1:1 ratio. ‘Proved reserves’ are those reserves which analysis of geological and engineering data suggests, to a high degree of confidence that the quantities are recoverable. Where probabilistic methods are used, there is at least a 90% probability that the quantities actually recovered will equal or exceed the sum of estimated Proved (1P) reserves. ‘Probable reserves’ are those reserves which analysis of geological and engineering data suggests are more likely than not to be recoverable. Proved plus Probable reserves represent the best estimate of recoverable quantities. Where probabilistic methods are used, there is at least a 50% probability that the quantities actually recovered will equal or exceed the sum of estimated Proved plus Probable (2P) reserves. ‘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. 6. 7. 8. 9. 10. 11. 12. 13. 15. 14. ‘Undeveloped reserves’ are those reserves for which wells and facilities have not been installed or executed but are expected to be recovered through future investments. The ‘reserves replacement ratio’ is the reserves (Developed and Undeveloped) change during the year, before the deduction of production, divided by production during the year. The ‘three-year reserves replacement ratio’ is the reserves (Developed and Undeveloped) change over three years, before the deduction of production for that period, divided by production during the same period. 16. The ‘organic annual reserves replacement ratio’ is the reserves (Developed and Undeveloped) change during the year, before the deduction of production and adjustment for acquisition and divestments, divided by production during the year. The ‘reserves life’ is the reserves (Developed and Undeveloped) divided by production during the year. ‘Annual production’ is the volume of dry gas, condensate and oil produced during the year and converted to ’MMboe’ for the specific purpose of reserves reconciliation and the calculation of reserves replacement ratios. The ‘Reserves and Resources Statement’ annual production differs from production volumes reported in the company's annual and quarterly reports due to differences between the sales and reserves product definitions, differences between the Woodside equity share of NWS domestic gas production and independently marketed pipeline gas sales, reserves being reported gross of downstream fuel and flare and the ‘MMboe’ conversion factors applied. ‘Revision of Previous Estimates’ are revisions (either upward or downward) in previous estimates of reserves or contingent resources, which are a result from new information normally obtained from development drilling, field re-interpretation, production performance, or are the result of a change in economic factors including any change in Woodside net revenue interest not arising from acquisition or divestment. This change category is associated with absolute changes to the resource estimates associated with the affected reference projects but excludes re-classification changes. ‘Transfer to/from Reserves’ are revisions that represent changes (either upward or downward) in previous estimates of reserves or contingent resources, which are a result of re-classification of resource estimates (i.e. from reserves to contingent resources or vice versa) associated with one or more reference project(s). ‘Extensions and discoveries’ represent additions to reserves or contingent resources that result from increased areal extensions of previously discovered fields demonstrated to exist subsequent to the original discovery and/or discovery of reserves or contingent resource in new fields or new reservoirs in old fields. ‘Acquisitions and Divestments’ represent changes to resource entitlement (either upward or downward) that result from either purchase or sale of interests and/or execution of contracts conveying entitlement. 17. 18. 19. 20. 21. 22. 23. Material concentrations of undeveloped reserves in the North West Shelf, Greater Pluto and Julimar-Brunello region(s) have remained undeveloped for longer than 5 years from the dates they were initially reported as the incremental reserves are expected to be recovered through future developments to meet long-term contractual commitments. The incremental projects are included in the company business plan, demonstrating the intent to proceed with the developments. 24. The ‘Greater Pluto’ region comprises the Pluto-Xena, Pyxis, Larsen, Martell, Martin, Noblige and Remy fields. 25. The ‘North West Shelf’ (NWS) region includes all oil and gas fields within the North West Shelf Project Area. 26. The ‘Greater Exmouth’ region comprises Vincent, Enfield, Greater Enfield, Greater Laverda, Ragnar and Toro fields. 27. The ‘Julimar-Brunello’ region comprises the Julimar and Brunello fields. 28. The ‘Senegal’ region comprises the Sangomar field. The Developed and Undeveloped reserves comprise of oil estimates. The Best Estimate (2C) Contingent resources include gas and oil estimates. 29. The ‘Greater Browse’ region comprises the Brecknock, Calliance and Torosa fields. 30. The ‘Greater Scarborough’ region comprises the Jupiter, Scarborough and Thebe fields. The ‘Greater Sunrise’ region comprises the Sunrise and Troubadour fields. 31. 32. The ‘Myanmar’ region comprises the fields within the A-6 development. The Myanmar Best Estimate Contingent Resource (2C) of 109.5 MMboe is referenced at 31 December 2021. Woodside announced its decision to withdraw from its interests in Myanmar on 27 January 2022. 33. The ‘Canada’ region comprises unconventional resources in the Liard Basin. The increase in Liard Best Estimate (2C) Contingent Resources at 31 December 2021 is due to Woodside assuming full equity in 28 non- infrastructure related Liard Basin leases from Chevron Canada. 34. The Julimar-Brunello and Greater Pluto reserves estimates in this statement differ from the estimates reported in the 21 October 2021 and 5 November 2021 reserves updates, due to the impact of full year production. Woodside Petroleum Ltd 59 GOVERNANCE WOODSIDE BOARD OF DIRECTORS Richard Goyder, AO Meg O’Neill Larry Archibald Frank Cooper, AO Swee Chen Goh Christopher Haynes, OBE Ian Macfarlane Ann Pickard Sarah Ryan Gene Tilbrook Ben Wyatt Woodside Petroleum Ltd 61 Richard Goyder, AO BCom, FAICD Larry Archibald BSc (Geosciences), BA (Geology), MBA Chairman: Chairman since April 2018 Term of office: Director since February 2017 Term of office: Director since August 2017 Independent: Yes Independent: Yes Experience: 24 years with Wesfarmers Limited, including Managing Director and CEO from 2005 to late 2017. Chairman 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. Experience: Former ConocoPhillips company executive (2008 to 2015), spending eight years in senior positions including Senior Vice President, Business Development and Exploration, and Senior Vice President, Exploration. Prior to this, spent 29 years at Amoco (1980 to 1998) and BP (1998 to 2008) in various positions including leadership of exploration programs covering many world regions. Committee membership: Audit & Risk, Sustainability and Nominations & Governance Committees. Current directorships/other interests: Current directorships/other interests: Chair: University of Arizona Geosciences Advisory Board. Directorships of other listed entities within the past three years: Nil. Frank Cooper, AO BCom, FCA, FAICD Term of office: Director since February 2013 Independent: Yes Experience: More than 35 years’ experience in corporate tax, specialising in the mining, energy and utilities sector, including senior leadership roles at three of the largest accounting firms and director of a leading Australian utility company. Committee membership: Chair of the Audit & Risk Committee. Member of the Human Resources & Compensation and Nominations & Governance Committees. Current directorships/other interests: Chair: Insurance Commission of Western Australia. Director: St John of God Australia Limited (since 2015) and South32 Limited (since 2015). Pro Chancellor: Senate of the University of Western Australia. Trustee: St John of God Health Care (since 2015). Directorships of other listed entities within the past three years: Nil. Chairman: Qantas Airways Limited, Australian Football League Commission, Channel 7 Telethon Trust and West Australian Symphony Orchestra. Member: Evans and Partners Investment Committee. Directorships of other 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: Joined Woodside as Chief Operations Officer in May 2018. Previously held senior roles with ExxonMobil, including regional production and development leadership positions, and country leadership positions in Norway and Canada. Committee membership: Attends Board committee meetings. Current directorships/other interests: Vice Chair: Australian Petroleum Production & Exploration Association (APPEA) Director: Reconciliation WA, WA Venues & Events Pty Ltd (WAVE), West Australian Symphony Orchestra (WASO) Vice President: Australian Resources and Energy Group (AMMA) Member: Chief Executive Women, UWA Business School Advisory Board Directorships of other listed entities within the past three years: Nil. 62 Annual Report 2021 Swee Chen Goh BSc (Information Science), MBA Term of office: Director since January 2020 Independent: Yes Experience: Joined Shell in 2003 and retired as Chairperson of the Shell companies in Singapore in January 2019. Served on the boards of a number of Shell joint ventures in China, Korea and Saudi Arabia and has extensive board and governance experience. Prior to joining Shell, worked at Procter & Gamble and IBM. Gained significant experience in a diverse range of industries, including oil and gas, consumer goods and IT. Committee membership: Member of the Human Resources & Compensation, Sustainability and Nominations & Governance Committees. Current directorships/other interests: Chair: Nanyang Technological University (since 2021), National Arts Council Singapore (since 2019) and the Singapore Institute for Human Resource Professionals (since 2016). Director: CapitaLand Investment Ltd (since 2021), The Centre for Liveable Cities (since 2021), Singapore Airlines Ltd (since 2019) and Singapore Power Ltd (since 2019). Member: Singapore Legal Services Commission. President: Global Compact Network Singapore. Directorships of other listed entities within the past three years: Nil. Christopher Haynes, OBE BSc, DPhil, FREng, CEng, FIMechE, FIEAust Term of office: Director since June 2011 Independent: Yes Experience: A 38-year career with Shell including as Executive Vice President, Upstream Major Projects within Shell’s Projects and Technology business, General Manager of Shell’s operations in Syria and a secondment as Managing Director of Nigeria LNG Ltd. From 1999 to 2002, seconded to Woodside as General Manager of the North West Shelf Venture. Retired from Shell in 2011. Committee membership: Member of the Audit & Risk, Sustainability and Nominations & Governance Committees. Current directorships/other interests: Director: Worley Limited (since 2012). Directorships of other listed entities within the past three years: Nil. Ian Macfarlane Former Australian Federal Minister (Resources; Energy; Industry and Innovation), FAICD Term of office: Director since November 2016 Independent: Yes Experience: 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. Before entering politics, Mr Macfarlane’s experience included agriculture, and being President of the Queensland Graingrowers Association (1991 to 1998) and the Grains Council of Australia (1994 to 1996). Committee membership: Member of the Human Resources & Compensation, Sustainability and Nominations & Governance Committees. Current directorships/other interests: Chief Executive: Queensland Resources Council (since 2016). Chair: Innovative Manufacturing Co-operative Research Centre. Director: CSIRO (since 2021). Member: Toowoomba Community Advisory Committee of the University of Queensland Rural Clinical School. Directorships of other listed entities within the past three years: Nil. Ann Pickard BA, MA Term of office: Director since February 2016 Independent: Yes Experience: Retired from Shell in 2016 after a 15-year tenure holding numerous positions, including Executive Vice President Arctic, Executive Vice President Exploration and Production, Country Chair of Shell in Australia, and Executive Vice President Africa. Previously had an 11-year tenure with Mobil prior to its merger with Exxon. 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. Directorships of other listed entities within the past three years: Nil. Woodside Petroleum Ltd 63 Ben Wyatt LLB, MSc Term of office: Director since June 2021 Independent: Yes Experience: 15 years in the Western Australian Legislative Assembly, including as the Western Australian Treasurer, Minister for Finance, Energy, Aboriginal Affairs and Lands. The first Indigenous treasurer of any Australian government, and has held various shadow cabinet portfolios including responsibility for Native Title and the Pilbara. Committee membership: Member of the Human Resources & Compensation, Sustainability and Nominations & Governance Committees. Current directorships/other interests: Director: West Coast Eagles (since 2021), Telethon Kids Institute (since 2021), Rio Tinto Limited (since 2021) and Perth International Arts Festival (since 2021). Member: UWA Business School Advisory Board, APM Advisory Board and the Australian Institute of Company Directors. Directorships of other listed entities within the past three years: Nil. Peter Coleman BEng, MBA, FTSE, MAICD, D.Eng (Hon), D.Law (Hon) Mr Peter Coleman retired effective 19 April 2021 after 10 years of service as Woodside's CEO and Managing Director. Sarah Ryan BSc (Geology), BSc (Geophysics) (Hons 1), PhD (Petroleum and Geophysics), FTSE Term of office: Director since December 2012 Independent: Yes Experience: More than 30 years’ experience in the oil and gas industry in various technical, operational and senior management positions, including 15 years with Schlumberger Ltd. From 2007 to 2017 was an equity analyst, portfolio manager and energy advisor for Earnest Partners. Committee membership: Member of the Audit & Risk, Sustainability and Nominations & Governance Committees. Current directorships/other interests: Director: OZ Minerals (since 2021), Future Battery Industries Co-operative Research Centre (since 2020), Aurizon Holdings (since 2019), Viva Energy Group Ltd (since 2018) and MPC Kinetic Pty Ltd (since 2016). Member: ASIC Corporate Governance Consultative Panel (since 2019) and Chief Executive Women (since 2016). Directorships of other listed entities within the past three years: Nil. Gene Tilbrook BSc, MBA, FAICD Term of office: Director since December 2014 Independent: Yes Experience: Broad experience in corporate strategy, investment and finance. Senior executive of Wesfarmers Limited between 1985 and 2009, including roles as Executive Director Finance and Executive Director Business Development. Committee membership: Chair of the Human Resources & Compensation Committee. Member of the Audit & Risk and Nominations & Governance Committees. Current directorships/other interests: Director: Orica Limited (since 2013). Member: Western Australian division of the Australian Institute of Company Directors (since 2013). Directorships of other listed entities within the past three years: GPT Group Limited (2010-2021). 64 Annual Report 2021 CORPORATE GOVERNANCE We believe high standards of governance and transparency are essential. Corporate governance at Woodside Woodside is committed to a high level of corporate governance and fostering a culture that values ethical behaviour, integrity and respect. We believe that adopting and operating in accordance with high standards of corporate governance is essential for sustainable long-term performance and value creation. Woodside’s Compass is core to our governance framework. It sets out our core values of integrity, respect, sustainability, working together, ownership and courage. The Compass is the overarching guide for everyone who works for Woodside. Our values define what is important to us in the way we work. Refer to Woodside’s website for more information (woodside.com.au). Our corporate governance model is illustrated 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 our employees and contractors are expected to work. The WMS establishes a common approach to how we operate, wherever the location. These principles and practices are reviewed regularly and revised as appropriate to reflect changes in law and developments in corporate governance. The Corporate Governance Statement discusses arrangements in relation to our Board of Directors, committees of the Board, shareholders, risk management and internal control, the external auditor relationship, and inclusion and diversity. The Chairman of the Board, Mr Richard Goyder, is an independent, non-executive director and a resident Australian citizen. The Chairman of the Board is responsible for leadership and effective performance of the Board. The Chairman’s responsibilities are set out in more detail in the Board Charter. Mr Goyder is also Chairman of Qantas Airways Limited. The Board considers that neither his chairmanship of Qantas Airways Limited, nor any of his other commitments listed on page 62, interfere with the discharge of his duties to Woodside. 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 Woodside’s headquarters in Perth, Western Australia. The Board is satisfied that Mr Goyder commits the time necessary to discharge his role effectively. Woodside follows the ASX Corporate Governance Council’s Corporate Governance Principles and Recommendations (fourth edition) (ASXCGC Recommendations). Throughout the year, Woodside complied with all the ASXCGC Recommendations. Our website contains copies of Board and committee charters and copies of many of the policies and documents mentioned in the Corporate Governance Statement. The website is updated regularly to ensure that it reflects Woodside’s most current corporate governance information. Our Corporate Governance Statement reports on Woodside’s key governance principles and practices. Refer to Woodside’s Corporate Governance Statement for more information (woodside.com.au). STAKEHOLDERS BOARD AUDIT & RISK COMMITTEE HUMAN RESOURCES & COMPENSATION COMMITTEE CHIEF EXECUTIVE OFFICER NOMINATIONS & GOVERNANCE COMMITTEE SUSTAINABILITY COMMITTEE INDEPENDENT ASSURANCE MANAGEMENT GOVERNANCE AND ASSURANCE EXTERNAL AUDIT __________________________________ STRATEGY INTERNAL AUDIT RISK MANAGEMENT WOODSIDE MANAGEMENT SYSTEM INCLUDING WOODSIDE COMPASS AND POLICIES AUTHORITIES OPERATING STRUCTURE Woodside Petroleum Ltd 65 DIRECTORS' REPORT The directors of Woodside Petroleum Ltd present their report (including the Remuneration Report) together with the Financial Statements of the consolidated entity, being Woodside Petroleum Ltd and its controlled entities, for the year ended 31 December 2021. Directors The directors of Woodside Petroleum Ltd in office at any time during or since the end of the 2021 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 on pages 62-64. 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 Petroleum Ltd during the financial year are shown in Table 3 on page 19 of the Corporate Governance Statement. Details of director and senior executive remuneration are set out in the Remuneration Report. The particulars of directors’ interests in shares of the company as at the date of this report are set out on page 68. Principal activities The principal activities and operations of the Group during the financial year were hydrocarbon exploration, evaluation, development, production and marketing. Other than as previously referred to in the Annual Report, there were no other significant changes in the nature of the activities of the consolidated entity during the year. Consolidated results The consolidated operating profit attributable to the company’s shareholders after provision for income tax was $1,983 million (loss of $4,028 million in 2020). Review of operations A review of the operations of the Woodside Group during the financial year and the results of those operations are set out on pages 6-59. Significant changes in the state of affairs The review of operations (pages 6-59) 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 declared 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 declared or determined by the directors on or before the end of the financial year. Dividend The directors have declared a final dividend in respect of the year ended 31 December 2021 of 105 cents per ordinary share (fully franked) payable on 23 March 2022. Type 2021 final 2021 interim 2020 final Payment date 23 March 2022 24 September 2021 24 March 2021 Period ends 31 December 2021 30 June 2021 31 December 2020 Cents per share Value $ million Fully franked 105 1,018 30 289 12 115 The full-year 2021 dividend was 135 cents per share. Likely developments and expected results In general terms, the review of operations of the Group gives an indication of likely developments 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 the Group. 66 Annual Report 2021 Environmental compliance Woodside is subject to a range of environmental legislation in Australia and other countries in which it operates. Details of Woodside’s environmental performance are provided on pages 23-41 of the Sustainable Development Report 2021. Through its Health, Safety and Environment Policy and Quality Policy, Woodside plans and performs activities so that adverse effects on the environment are avoided or kept as low as reasonably practicable. Company Secretaries The following individuals have acted as Company Secretary during 2021: Andrew Cox BA (Hons), LLB, MA Vice President Legal and General Counsel, and Joint Company Secretary Mr Cox joined Woodside in 2004 and was appointed to the role of Vice President Legal in January 2015. He was appointed Vice President Legal and General Counsel and Joint Company Secretary on 1 June 2017. Warren Baillie LLB, BCom, Grad. Dip. CSP Company Secretary Mr Baillie joined Woodside in 2005 and was appointed 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. Indemnification and insurance of directors and officers The company’s constitution requires the company to indemnify each director, secretary, executive officer or employee of the company or its wholly owned subsidiaries against liabilities (to the extent the company is not precluded by law from doing so) incurred in or arising out of the conduct of the business of the company or the discharge of the duties of any such person. The company has entered into deeds of indemnity with each of its directors, secretaries, certain senior executives, and employees serving as officers on wholly owned or partly owned companies of Woodside in terms of the indemnity provided under the company’s constitution. From time to time, Woodside engages its external auditor, Ernst & Young, 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 Ernst & Young: • against all losses, claims, costs, expenses, actions, demands, damages, liabilities or any proceedings (liabilities) incurred by Ernst & Young in respect of third- party claims arising from a breach by the Group under the engagement terms; and • for all liabilities Ernst & Young has to the Group or any third-party as a result of reliance on information provided by the Group that is false, misleading or incomplete. The company has paid a premium under a contract insuring each director, officer, secretary and employee who is concerned with the management of the company or its subsidiaries against liability incurred in that capacity. 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. The company has not provided any insurance for the external auditor of the company or a body corporate related to the external auditor. Non-audit services and auditor independence declaration Details of the amounts paid or payable to the external auditor of the company, Ernst & Young, for audit and non- audit services provided during the year are disclosed in note E.4 to the Financial Statements. 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; and • 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. Further information on Woodside’s policy in relation to the provision of non-audit services by the auditor is set out in section 7 of the Corporate Governance Statement. The auditor’s independence declaration, as required under section 307C of the Corporations Act 2001, is set out on this page and forms part of this report. 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 The amounts contained in this report have been rounded to the nearest million dollars under the option available to the company under Australian Securities and Investments Commission Corporations (Rounding in Financial/Directors’ Reports) Instrument 2016/191 dated 24 March 2016. Woodside Petroleum Ltd 67 Directors’ relevant interests in Woodside shares as at the Auditor’s independence declaration to the Directors of date of this report Director L Archibald F Cooper S C Goh R Goyder C Haynes I Macfarlane M O'Neill1 A Pickard S Ryan G Tilbrook B Wyatt2 1 Ms O'Neill also holds Performance Rights under the Executive Incentive Scheme, Relevant interest in shares 11,977 13,450 12,786 23,634 14,598 10,329 229,652 14,206 11,910 7,949 Nil details of which are set out in the Remuneration Report in Table 12 on pages 89-90 and Table 14 on page 91. 2 Mr Wyatt is participating in the Non-Executive Directors' Share Plan and will acquire shares going forward under this plan. Signed in accordance with a resolution of the directors. Woodside Petroleum Ltd As lead auditor for the audit of the financial report of Woodside Petroleum Ltd for the financial year ended 31 December 2021, I declare to the best of my knowledge and belief, there have been: (a) no contraventions of the auditor independence requirements of the Corporations Act 2001 in relation to the audit; (b) no contraventions of any applicable code of professional conduct in relation to the audit; and (c) no non-audit services provided that contravene any applicable code of professional conduct in relation to the audit. This declaration is in respect of Woodside Petroleum Ltd and the entities it controlled during the financial year. R J Goyder, AO Chairman Perth, Western Australia 17 February 2022 M E O'Neill Chief Executive Officer and Managing Director Perth, Western Australia 17 February 2022 Ernst & Young R Kirkby Partner Perth, Western Australia 17 February 2022 Liability limited by a scheme approved under Professional Standards Legislation 68 Annual Report 2021 REMUNERATION REPORT CONTENTS Committee Chair's letter Remuneration Report (audited) KMP and summary of Woodside’s five-year performance Remuneration Policy 2021 remuneration changes Executive Incentive Scheme Executive KMP remuneration structure Executive KMP KPIs and outcomes for 2021 Other equity plans Contracts for Executive KMP Non-executive directors Human Resources & Compensation Committee Use of remuneration consultants Reporting notes Statutory tables Glossary 71 73 73 74 74 75 76 80 84 85 86 87 87 87 88 92 70 Annual Report 2021 Committee Chair's letter 17 February 2022 Dear Shareholders On behalf of the Board, I am pleased to present the Remuneration Report for the year ended 31 December 2021. In 2021 we maintained reliable operations, started up new projects and leveraged favourable market conditions to achieve strong earnings outcomes. We took significant steps to support long-term sustainable returns for shareholders, entering into a binding share sale agreement for the merger with BHP’s oil and gas portfolio and taking FIDs on Scarborough and Pluto Train 2. We progressed a portfolio of new energy opportunities and completed our largest ever planned maintenance campaign. 2021 was also a challenging year in which we saw disappointing safety performance compared to our strong results in 2019 and 2020. We fell short of our internal production targets, although results were in line with market guidance. These results are reflected in our 2021 Executive remuneration outcomes, as outlined below and in further detail in this report. Remuneration Policy 2021 marked the fourth year since the introduction of the EIS. Changes were made to the Corporate Scorecard for 2021 to strengthen the link between Executive reward and shareholder experience. The 2021 Corporate Scorecard was based on the following five equally weighted metrics, with two new financial metrics introduced in place of NPAT: • Operating Expenditure – 20% (New in 2021) • Earnings Before Interest, Taxes, Depreciation and Amortisation (EBITDA) – 20% (New in 2021) • Production – 20% • Material Sustainability Issues – 20% • Delivery against Business Priorities – 20% We describe Executive KMP performance and pay outcomes in this report (pages 81-82). This includes discussion of Executives’ performance against carbon-related measures which impact award outcomes. Woodside adopted a specific measure for net equity Scope 1 and 2 greenhouse gas emissions reduction for the first time in the 2021 Corporate Scorecard. We will continue to enhance reporting of remuneration outcomes linked to climate metrics as we progress lower carbon solutions and our new energy portfolio. The take home pay table is on page 83. The EIS continues to achieve remuneration outcomes which fairly reflect Woodside’s performance and are strongly linked to the creation of value for shareholders. There are no material changes to the EIS structure anticipated for 2022. Proposed Merger The merger with BHP’s oil and gas portfolio represents a substantial opportunity for Woodside and its shareholders and is expected to involve updates to our Remuneration Policy including how we benchmark Executive reward, reflecting changes to Executive roles and accountabilities. The international peer group used to measure RTSR performance for equity components of future Executive awards will be reviewed to maintain alignment with Woodside’s expanded global business activities. The Committee has reviewed preliminary plans for a new senior management structure and the transition of several BHP executives to the EIS on merger completion. The transition will be aimed at ensuring Woodside can continue to attract and retain executive capability in a globally competitive market. Business Performance 2021 has been a year of substantial progress for Woodside as it maintains safe and efficient operations in a COVID-19-challenged environment, progressing a binding share sale agreement for the merger with BHP’s oil and gas portfolio and the FIDs for Scarborough and Pluto Train 2. It is pleasing that the focus on delivering a successful merger has not diverted attention away from other business priorities, including progress on new energy opportunities. The company’s EBITDA for 2021 was above target at $4,135 million, primarily due to significantly improved market pricing for Woodside’s products and activities focussed on optimising value from this. Operating expenditure failed to meet the target of A$1,000 million, primarily due to costs associated with merger activities, partially offset by lower production costs. Production for 2021 was within the range but below target at 91.1 MMboe. Performance was lower largely due to weather impacts. Safety performance has been a disappointment, with a TRIR of 1.74 which exceeded the target of 1.0. Performance against the remaining Material Sustainability Issues was strong, with no Tier 1 or Tier 2 Process Safety Events occurring and year-end emissions abatement of 80.1kT CO2-e, more than double the annual baseline target. Our overall Corporate Scorecard was above target at 6 out of 10. Woodside Petroleum Ltd 71 Executive KMP Changes Peter Coleman retired as CEO and Managing Director effective 19 April 2021 after more than ten years in the role and departed Woodside on 3 June 2021. Details of the treatment of Mr Coleman’s unvested equity incentives and his pro-rata 2021 EIS award are on page 80 of this report. Meg O’Neill was appointed as Acting CEO on 20 April 2021, during the Board’s internal and external CEO search, and was subsequently appointed Woodside’s CEO and Managing Director on 17 August 2021. Ms O’Neill’s FAR on appointment was A$2,200,000 with a target value for VAR set at A$4,400,000. In a year of strong corporate and personal performance, Ms O’Neill achieved a 2021 EIS award of 75.6% of the maximum award. Details of the assessment of the CEO’s performance and 2021 award are set out in Table 4 on page 81 of this report. The equity components of Ms O’Neill’s 2021 VAR will be presented for shareholder approval at the 2022 AGM. Sherry Duhe resigned as Executive Vice President and Chief Financial Officer on 16 November 2021 and remained with the company until 4 February 2022 to ensure a smooth transition of her responsibilities. In accordance with the EIS, Ms Duhe’s unvested equity incentives lapsed following her resignation. She was not entitled to receive a 2021 EIS award. The Board appointed Mr Graham Tiver as Executive Vice President and Chief Financial Officer effective 1 February 2022. The Board is pleased to have appointed to the CEO and CFO positions two outstanding people who will work with a strong senior team to deliver value for shareholders and advance the organisation’s capability and culture to implement the significant opportunities ahead of the company. Executive Remuneration Outcomes The 2021 remuneration outcomes include: • No fixed remuneration increase for Senior Executives (other than in connection with changes to role scope and accountabilities). • CEO EIS award of 117% of target (75.6% of maximum opportunity). • Senior Executive awards ranging from 69.4% to 73.1% of maximum opportunity. • The 2015 and 2016 awards under the prior Executive Incentive Plan were tested against their respective RTSR hurdles. This was the second test for the 2015 award which resulted in 9.2% partial vesting. Overall, 47.5% of the 2015 award vested. This was the first test for the 2016 award and resulted in 63% vesting. • No fee increases for the non-executive directors. The Board has reviewed the 2021 EIS outcomes and considers that they align with overall corporate performance. 2021 Committee Activities Key activities undertaken by the Committee during the year included reviewing the company’s remuneration policies and practices and changes for Executives who report directly to the CEO and moved roles or reporting structures, including the appointment and remuneration packages of those Executives. The Committee considered activities to assess and monitor culture, including across all areas of our Integrated Culture Framework (values, safety, risk and compliance). This included ensuring a robust approach to bullying and harassment in the workplace and endorsing a new Working Respectfully Policy. The Committee oversaw implementation of the 2021-2025 inclusion and diversity strategy and reviewed progress against the key performance measures. Details of Woodside's performance against the inclusion and diversity strategy in 2021 are available on pages 53-64 of the Sustainable Development Report 2021. Summary The Board has been proud of the leadership and collaboration shown by our employees during this significant phase of growth, including progressing the merger with BHP’s oil and gas portfolio and transforming the way we work in response to the energy transition. Our employees continued to respond strongly to the ongoing challenges of the COVID-19 pandemic in ensuring the safety of our employees and the ongoing performance of our assets. We look forward to our ongoing engagement with Woodside’s shareholders and sharing in Woodside’s future success. Yours sincerely Gene Tilbrook Chair of Human Resources & Compensation Committee 72 Annual Report 2021 Remuneration Report (audited) KMP and summary of Woodside’s five-year performance This report outlines the remuneration arrangements in place and outcomes achieved for Woodside’s KMP during 2021. Woodside’s KMP are the people who have the authority to shape and influence 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). During 2021 the following changes to KMP occurred: • Meg O’Neill was appointed Acting CEO with effect from 20 April 2021 and CEO and Managing Director on 17 August 2021. Ms O’Neill was previously Executive Vice President Development and Marketing. • Peter Coleman retired as CEO and Managing Director and ceased to be an Executive KMP on 19 April 2021. He departed Woodside on 3 June 2021. The treatment of Mr Coleman’s unvested equity awards and his pro-rata 2021 award are detailed on page 80. • Sherry Duhe resigned as Executive Vice President and CFO on 16 November 2021. Ms Duhe remained with Woodside until 4 February 2022 to ensure a smooth transition of key responsibilities. • On 14 December 2021, Woodside announced that it had appointed Graham Tiver as Executive Vice President and CFO. Mr Tiver commenced with Woodside on 1 February 2022. • Ben Wyatt was appointed a non-executive director on 1 June 2021. The names and positions of the individuals who were KMP during 2021 are set out in Tables 1A and 1B. TABLE 1A - EXECUTIVE KMP TABLE 1B - NON-EXECUTIVE DIRECTORS KMP Executive Director Meg O’Neill (Chief Executive Officer and Managing Director (CEO))1 Peter Coleman (former Chief Executive Officer and Managing Director)2 Senior Executives Shaun Gregory (Executive Vice President Sustainability and Chief Technology Officer) Fiona Hick (Executive Vice President Operations)3 Sherry Duhe (former Executive Vice President and Chief Financial Officer)4 Richard Goyder, AO (Chairman) Larry Archibald Frank Cooper, AO Swee Chen Goh Christopher Haynes, OBE Ian Macfarlane Ann Pickard Sarah Ryan Gene Tilbrook Ben Wyatt5 1 Ms M O’Neill’s title changed from Executive Vice President Development and Marketing to Acting Chief Executive Officer on 20 April 2021. Ms O’Neill was appointed Chief Executive Officer and Managing Director on 17 August 2021. 2 Mr P Coleman ceased to be Chief Executive Officer, Managing Director and an Executive KMP on 19 April 2021. Mr Coleman departed Woodside on 3 June 2021. 3 Ms F Hick’s title changed from Senior Vice President Operations to Executive Vice President Operations on 1 April 2021. 4 Ms S Duhe ceased to be an Executive Vice President, Chief Financial Officer and Executive KMP on 4 February 2022. 5 Mr B Wyatt was appointed a non-executive director on 1 June 2021. TABLE 2 – FIVE-YEAR PERFORMANCE Earnings before interest, tax, depreciation and amortisation (EBITDA)1 Operating Expenditure2 Net profit after tax (NPAT)3 Basic earnings per share4 Dividends per share Share closing price (last trading day of the year) Production Average annual dated Brent (US$ million) (A$ million) (US$ million) (US cents) (US cents) (A$) (MMboe) (US$/boe) 2021 4,135 1,030 1,983 206 135 21.93 91.1 71 2020 1,922 2019 3,531 2018 3,814 20175 2,918 (4,028) (424) 38 22.74 100.3 42 343 37 91 34.38 89.6 64 1,364 1,069 148 144 123 98 31.32 33.08 91.4 71 84.4 54 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. Refer to footnote 4 on page 159 for the calculation methodology of EBIDTA. 2 Operating Expenditure was not disclosed prior to 2021. Operating Expenditure is defined in the Glossary on page 92. This is a non-IFRS measure that is unaudited. 3 Represents NPAT attributable to equity holders of the parent with further details presented in the Financial Statements on pages 93-148. 4 Basic earnings per share from total operations. 5 2017 NPAT has been restated for the retrospective application of AASB 15 Revenue from Contracts with Customers (AASB 15), and earnings per share has been restated for the retrospective application of AASB 15 and the Retail Entitlement Offer. Woodside Petroleum Ltd 73 Remuneration Policy Woodside aims to deliver affordable energy solutions and superior outcomes to stakeholders. We are managing our business by focusing on the energy transition through: the provision of natural gas; the decarbonisation of our business; and incremental investment in targeted new energy businesses with prospective exponential growth, such as hydrogen and the development of new, value- creating projects. 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 Compass, 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) at target is structured to reward the Executives for achieving challenging yet realistic targets set by the Board which deliver short-term and long- term returns for the company. VAR aligns shareholder and executive remuneration outcomes by ensuring a significant portion of executive remuneration is at risk, while rewarding performance. Executive remuneration is reviewed annually, having regard to the accountabilities, experience and performance of the 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. 2021 remuneration changes Following feedback from our investors, we implemented changes for 2021 to our Corporate Scorecard and the weighting of individual and corporate performance which determine executive VAR. The change strengthened the connection between corporate performance, executive reward and shareholder experience. An Executive’s award is based on their individual performance against KPIs and the company’s performance against the Corporate Scorecard. Individual performance measures are designed to ensure Executives focus on driving Woodside’s culture and the values and behaviours that underpin our success whilst executing Woodside’s strategic imperatives. Individual performance is weighted at 30% and corporate performance is weighted at 70% to determine an Executive’s final performance outcome and reward. CORPORATE SCORECARD 70% INDIVIDUAL PERFORMANCE FACTOR INDIVIDUAL KPIs 30% Corporate Scorecard In 2021, the overall weighting of the financial metrics increased from 25% (based on NPAT) to 40% (EBITDA and Operating Expenditure). Individual Performance Individual performance 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. The 2021 Corporate Scorecard for Executive KMP was based on five equally weighted measures that were chosen because they impact short-term and long-term shareholder value, with a score of 5 for an outcome at target and a maximum score of 10 on each measure. The Corporate Scorecard is the same for all employees to enable Executives to drive performance at all levels of the organisation. The 2022 Corporate Scorecard is expected to be based on the same five equally weighted measures. The Board has strong oversight and governance to ensure that appropriate and challenging targets are set to create a clear link between performance and reward. The Board has an overriding discretion which it can and does exercise to adjust outcomes in line with shareholder experience and company or management performance. 74 Annual Report 2021 EBITDA Production CORPORATE SCORECARD Operating Expenditure Controlling Operating Expenditure brings a focus on efficient operations; cost competitiveness; and shareholder returns. _____ 20% EBITDA is a key measure of annual profitability and is influenced by both management performance and commodity prices. _____ 20% Revenue is maximised and value generated from our assets when they are fully utilised in production. Material Sustainability Issues Material sustainability issues include personal and process safety, environment, emissions reductions, and our social licence to operate. Deliver Business Priorities Business priorities focus on progress and milestones of capital projects; business developments; and balance sheet management. _____ 20% _____ 20% _____ 20% Executive Incentive Scheme VAR is delivered under the Woodside Executive Incentive Scheme (EIS). The EIS remunerates Executives for delivering results against measurable criteria aimed at safe, efficient operations; delivery of new projects and an effective financial structure against the following three key objectives: 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 simple remuneration structure and clear line of sight to how performance is reflected in remuneration outcomes. 87.5% of the award is delivered as equity in a combination of Restricted Shares or Performance Rights. The Performance Rights are relative total shareholder return (RTSR) tested against comparator groups, after five years. 60% of the award has a five-year deferral period, which reflects Woodside’s strategic time horizons to drive Executives to deliver our strategic objectives with discipline and collaboration, in turn creating shareholder value. Woodside Petroleum Ltd 75 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 VAR • Executives are eligible to receive a single variable reward linked to challenging 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. 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 the performance year. • 12.5% of the variable reward is paid in cash. • 27.5% is allocated in Restricted Shares, subject to a three-year deferral period. • 30% is allocated in Restricted Shares, subject to a five-year deferral period. • 30% is allocated in Performance Rights which are subject to a RTSR test five years after the date of allocation, with one-third tested against a comparator group that comprises the ASX 50 and the remaining two-thirds against a group of international oil and gas companies determined by the Board. Performance Rights1 30% Restricted Shares1 30% Restricted Shares1 27.5% Cash 12.5% Performance tested Subject to a five-year deferral period with a RTSR test five years after the date of allocation; with one-third of performance rights tested against the ASX 50 companies and the remaining two-thirds against a group of international oil and gas companies Deferred Subject to a five-year deferral period Deferred Subject to a three-year deferral period Payable following the end of the performance year Year 12 Year 2 Year 3 Year 4 Year 5 1 Allocated using a face value methodology. 2 Award allocated after completion of 12-month performance period. 76 Annual Report 2021 TABLE 3 – KEY EIS FEATURES Allocation methodology Dividends Clawback provisions Control event 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) in December each year. 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 the period between allocation and vesting. The Board has the discretion to reduce 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; or the Board determines that circumstances have occurred that have resulted in an unfair benefit to the Executive. The Board has the discretion to determine the treatment of any EIS award on a change of control event. If a change of control occurs during the 12-month performance period, an Executive will receive at least a pro-rata cash payment in respect of the unallocated cash and Restricted Share components of the EIS award for that year, assessed at target. If a change of control occurs during the vesting period for equity awards, Restricted Shares will vest in full whilst Performance Rights may, at the discretion of the Board, vest on an at least pro-rata basis. Cessation of employment During a performance period, 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 period elapsed in determining the form of any EIS award. During a deferral 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. The Board will have discretion to accelerate the vesting of unvested equity awards, subject to termination benefits laws. 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. Calculation of award for 2021 Each Executive’s award is based upon two components: individual performance against challenging KPIs (30% weighting) and the company’s performance against the Corporate Scorecard (70% weighting). This results in an individual performance factor (IPF) which ranges from 0 to 1.6 for Executive KMP. The Corporate Scorecard targets and individual KPIs are designed to promote short-term and long-term shareholder value. Exceeding targets may result in an increased award, whereas 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. The decision to pay or allocate an EIS award is subject to the overriding discretion of the Board, which may adjust outcomes to better reflect shareholder outcomes and company or management performance. See pages 81-82 for details of the CEO’s and Senior Executives’ individual performance assessement. Woodside Petroleum Ltd 77 Target variable reward opportunity for 2021 Each Executive is given a target VAR opportunity and a maximum VAR opportunity which is a percentage of the Executive’s FAR. The opportunities for 2021 are outlined below. Position CEO Senior Executives Minimum opportunity (% of FAR) Target opportunity (% of FAR) Maximum opportunity (% of FAR) Zero 200 160 300 256 Cash The cash component represents 12.5% of the VAR and is payable following the end of the performance year. Restricted Shares The Restricted Shares are divided into two tranches. The first tranche is 27.5% of the award and subject to a three-year deferral period. The second tranche is 30% of the award and subject to a five-year deferral period. 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 ensures that awards remain subject to fluctuations in share price across the three and five-year periods, which is intended to reflect the sustainability of performance over the medium-term and long-term and support increased 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 2021. The remaining two-thirds are tested against an international group of oil and gas companies, set out in Table 11 on page 88. RTSR outcomes are calculated by an external adviser on or after the fifth anniversary of the allocation of the Performance Rights. 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. RTSR PERFORMANCE HURDLE VESTING Woodside RTSR percentile position within peer group Vesting of Performance Rights Less than 50th percentile Equal to 50th percentile No vesting 50% vest Vesting between the 50th and 75th percentile Vesting on a pro-rata basis Equal to or greater than 75th percentile 100% vest CEO target remuneration Senior Executive target remuneration FIXED REWARD 33% VARIABLE REWARD 67% FIXED REWARD 38% VARIABLE REWARD 62% 78 Annual Report 2021 CORPORATE SCORECARD OUTCOMES FOR 2021 Operating Expenditure (20%) MID-POINT MAX OUTCOME 5 Controlling Operating Expenditure brings a focus on efficient operations; cost competitiveness; and shareholder returns. 2021 Performance: Operating Expenditure was A$1,030 million, which did not meet the target of A$1,000 million primarily due to costs associated with the proposed merger with BHP's oil and gas portfolio, partially offset by lower production costs. EBITDA (20%) MID-POINT MAX OUTCOME 10 EBITDA is a key measure of 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 price and foreign exchange fluctuations, as are returns to shareholders. 2021 Performance: EBITDA was $4,135 million, significantly above the target of $2,908 million due to strong operational performance and higher realised oil and gas pricing, through proactive decisions to manage our sales portfolio and successful completion of Pluto LNG price reviews. Production (20%) MID-POINT MAX OUTCOME 2 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 is set relative to the company’s annual budget and market guidance and is not revised through the year. 2021 Performance: 2021 production was 91.1 MMboe, lower than the 92.6 MMboe internal target, due to weather impacts and equipment reliability. Production performance was in line with market guidance of 90-95 MMboe. Material Sustainability Issues (20%) MID-POINT MAX OUTCOME 5 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. 2021 Performance: Safety performance was disappointing in 2021, with a TRIR of 1.74 significantly above the target of 1.0. No Tier 1 or 2 Process Safety Events were recorded and year-end emissions abatement of 80.1 kT CO2-e was more than double the target of 36 kT CO2-e. Delivery against Business Priorities (20%) MID-POINT MAX OUTCOME 8 In 2021, we focused on key business priorities supporting delivery of long-term shareholder value; safe and reliable base business; advancing our growth projects (Scarborough, Pluto Train 2 and Sangomar) and maturing future opportunities. 2021 Performance: Merger with BHP Petroleum • In addition to the key Business Priorities, merger announced with BHP’s oil and gas portfolio to deliver increased scale, diversity and resilience; provide financial strength to help fund planned developments in the near-term and invest in future energy opportunities and return value to shareholders through the cycle. Scarborough and Pluto Train 2 Final Investment Decisions • Final Investment Decisions (FIDs) for Scarborough and Pluto Train 2 developments approved • Sale and purchase agreement with Global Infrastructure Partners for 49% interest in the Pluto Train 2 Joint Venture • Fully termed processing and services agreement to process Scarborough gas through Pluto LNG facilities • Issued full notice to proceed to key Scarborough contractors for offshore project execution Sangomar • Sangomar Field Development Phase 1 48% complete and on track for targeted first oil in 2023 • Drilling commenced in July, first well completed • Subsea offshore construction campaign: Vessel mobilisation deferred to Q1 2022 for cost and schedule optimisation • Sales process launched and management presentations underway Future Opportunities • US H2OK 290MW FEED entry decision • Heliogen 5MW FID approved OVERALL CORPORATE PERFORMANCE OUTCOME TARGET MAX OUTCOME 6 Woodside Petroleum Ltd 79 Executive KMP KPIs and outcomes for 2021 CEO KPIs and outcomes In August 2021, Meg O’Neill was appointed CEO and Managing Director. Ms O’Neill had been Acting CEO since 20 April 2021 following Peter Coleman’s retirement. Ms O’Neill’s incentive arrangements are governed under the EIS. FAR Ms O’Neill’s FAR was increased to A$2,200,000 on appointment to CEO and Managing Director. The FAR for Ms O’Neill is 18.5 per cent less than the FAR paid to her predecessor, Mr Coleman. The Board considers that Ms O’Neill’s remuneration is competitive and benchmarks appropriately to peer companies. It is anticipated that the CEO’s remuneration will be reviewed following completion of the merger of Woodside and BHP’s oil and gas portfolios. Upon Ms O'Neill's appointment to CEO and Managing Director, the Board approved the accelerated vesting of 37,048 Restricted Shares as set out in Table 12 on page 89. Each vested Restricted Share entitled Ms O’Neill to receive one Woodside share. VAR For 2021, 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 successful performance in each area is 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 reviews the CEO’s performance for that year. The CEO is given an individual performance score of between 0 and 1.6, which together with the Corporate Scorecard outcome results in an IPF. The CEO’s overall IPF for 2021 resulted in an award of 75.6% of maximum opportunity. Ms O'Neill. Mr Coleman's EIS award earned as a percentage of maximum opportunity is 72%. The Board exercised its discretion to award Mr Coleman cash in lieu of the Restricted Shares component of his EIS award. The Performance Rights component of the award is subject to a three-year deferral period with a RTSR test three years after the date of allocation. No termination payments were made on cessation of Mr Coleman’s employment, other than a payment in lieu of a portion of his contractual notice period and his statutory leave entitlements. Amounts payable to Mr Coleman in 2021 are shown in Table 10 on page 88. Senior Executive FAR In August 2021, Woodside conducted a review of Senior Executive remuneration based on benchmarking data against a defined peer group alongside the consideration of executive performance and role accountabilities. The Committee approved the continued freeze on FAR and considers that Senior Executive remuneration remains competitive. Senior Executive remuneration will be reviewed following completion of the merger of Woodside and BHP’s oil and gas portfolios to ensure it remains competitive and appropriate given any changes in role scope and accountabilities. Senior Executive VAR and other incentives For 2021, the individual performance of each Senior Executive was evaluated against the same performance measures as the CEO, with individual KPIs set relevant to each Senior 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, resulting in an IPF between 0 and 1.6. The 2021 EIS award for the CEO is detailed in Table 7 on page 84. Information on the individual performance of the CEO is shown in Table 4 on page 81. Information on the individual performance of Executives who were KMP as at 31 December 2021 is shown in Table 4 on page 82. Details of the EIS award for each Senior Executive are set out in Table 7 on page 84. Former CEO and Managing Director Peter Coleman ceased to be CEO and Managing Director on 19 April 2021 and departed Woodside on 3 June 2021. In accordance with the terms of his contract, Mr Coleman is eligible for a 2021 EIS award for the period in which he remained in service. The 2021 award for Mr Coleman is detailed in Table 7 on page 84. Mr Coleman was key to the delivery of a number of achievements in 2021 including the approval of FIDs for the Scarborough and Pluto Train 2 developments. He facilitated a smooth transition of CEO and Managing Director to Ms Duhe was not eligible for a 2021 EIS award as she resigned during the period. No individual performance assessment has been included for Ms Duhe. For 2021, Woodside made one-off cash bonus payments to two Executive KMP, Shaun Gregory (A$170,700) and Ms Duhe (two payments totaling A$220,000), in connection with discretionary efforts related the merger with BHP's oil and gas portfolio and the Scarborough and Pluto Train 2 FIDs. These payments are detailed in Table 5 on page 83 and Table 10 on page 88. 80 Annual Report 2021 TABLE 4 – CEO AND SENIOR EXECUTIVE INDIVIDUAL PERFORMANCE FOR 2021 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. 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. Enterprise capability Assesses leadership development; workforce planning; executive succession; Indigenous participation and diversity; effective risk identification and management. Culture and reputation Assesses performance culture and emphasis on values; engagement and enablement; improved employee climate; Woodside’s brand as a partner of choice. 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. • Executed agreements to merge with BHP’s oil and gas portfolio • Achieved FIDs on Scarborough and Pluto Train 2 with compelling commercial outcomes • Advanced Woodside strategy to transform the way we work in response to the energy transition, including clear targets and metrics • Set financial return targets and $5 billion investment target by 2030 for new Above target energy investments • Growth agenda for energy transition materially progressed by four new energy opportunities and strategic partnerships established across value chain • Personal safety performance failed to meet the target, although process safety was strong • Abatement of greenhouse gas emissions was well above target • Production within range but below budget • Production operating costs were under budget. Total operating expenditure was over budget, primarily due to costs associated with the merger with BHP’s oil and gas portfolio On target • Executed LNG SPAs with Uniper and RWE • Sangomar execution on schedule and on budget • • • • Identified and took steps to address areas of cultural focus, including maturing commercial capability across the business and improving transparency Implemented value at risk framework to underpin growth of trading portfolio Implemented new ways of working including leadership development, refreshed Inclusion and Diversity strategy, enhanced approach to flexible working policy and endorsing Working Respectfully Policy Increased female and Indigenous representation across organisation • Provided a clear vision for Woodside’s desired culture, including to address the potential for bullying and harassment in the workplace whist encouraging an environment where people can speak up and debate • Led a cohesive and effective executive team during a significant phase of growth and in response to the ongoing challenges of the COVID-19 pandemic • Refreshed Woodside Compass with focus on trust, transparency and courage On target Above target • Executed selldown of 49% equity in Pluto Train 2 to Global Infrastructure Partners • Launched Woodside Transformation to drive cultural shift with increased accountability and streamlined decision-making to enhance cost focus whilst maintaining operational discipline On target • Exit from Kitimat LNG to focus on higher value opportunities EIS earned as percentage of maximum opportunity1 75.6%2 1 The award of Restricted Shares and Performance Rights is subject to shareholder approval at the 2022 Woodside Annual General Meeting. 2 Ms M O'Neill's EIS structure changed following her appointment as CEO and Managing Director on 17 August 2021, including her target and maximum award. Her 2021 EIS award was calculated on a pro-rata basis including target and maximum opportunity. Woodside Petroleum Ltd 81 SHAUN GREGORY – EXECUTIVE VICE PRESIDENT SUSTAINABILITY AND CHIEF TECHNOLOGY OFFICER KPI Performance Growth agenda Assesses the alignment of growth opportunities to shareholder return; portfolio balance; the achievement of challenging business objectives. 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. Enterprise capability Assesses leadership development; workforce planning; executive succession; Indigenous participation and diversity; effective risk identification and management. Culture and reputation Assesses performance culture and emphasis on values; engagement and enablement; improved employee climate; Woodside’s brand as a partner of choice. 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. • Commercial and technical progress across New Energy opportunity portfolio • Secured carbon offsets to meet 2025 net emissions reduction target • Safety and efficiency improvements delivered to business through robotics and technology • Safely completed Korea 3D seismic survey acquisition • High-performing system availability and cyber security systems • Matured data platforms to improve digital and cyber organisational capabilities On target and enable personnel • Advanced strategic partnerships covering technology and New Energy market development • Below budget exploration and operating expenditure for carbon, technology and digital • Focus on successful delivery of nearer-term, higher value opportunities • No commercial discovery from Myanmar exploration campaign EIS earned as percentage of maximum opportunity 73.1% FIONA HICK – EXECUTIVE VICE PRESIDENT OPERATIONS KPI Performance Growth agenda Assesses the alignment of growth opportunities to shareholder return; portfolio balance; the achievement of challenging business objectives. 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. Enterprise capability Assesses leadership development; workforce planning; executive succession; Indigenous participation and diversity; effective risk identification and management. Culture and reputation Assesses performance culture and emphasis on values; engagement and enablement; improved employee climate; Woodside’s brand as a partner of choice. 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. • Support to international growth projects, Scarborough and Pluto Train 2 FIDs and base business and projects Injury rate higher than target • Zero Tier 1 or Tier 2 process safety events • • Production within market guidance but below internal target • Reliability above target for gas facilities but below for oil facilities • Emissions reductions above target including due to strong reliability and delivery of emissions reduction projects • Seven turnaround maintenance campaigns (offshore and onshore), Woodside's largest ever planned maintenance campaign • Material progress on decommissioning obligations • Matured capability across operating assets to manage significant challenges including organisational change and the impacts of COVID-19 and border closures on personnel and supply chain Improved inclusion and diversity performance in Operations • • Key role in implementation of Woodside's new leadership development framework in Operations • Values focus demonstrated through significant challenges including impacts of COVID-19 and organisational change • Disciplined cost focus • Implemented transformation initiatives EIS earned as percentage of maximum opportunity 69.4% Outcome Above target Above target Above target On target Outcome On target Below target Above target On target Above target CEO actual remuneration FIXED REWARD 32.4% Senior Executive actual remuneration1 FIXED REWARD 35.4% VARIABLE REWARD 67.6% VARIABLE REWARD 64.6% 1 This represents an average of all Senior Executives’ actual and variable remuneration for 2021. It does not not include Ms S Duhe who was not eligible for a 2021 EIS award. 82 Annual Report 2021 The following table details the CEO and Senior Executives’ take home pay. This table has been included to provide greater transparency to shareholders of the take home pay received or receivable by the CEO and Senior Executives in 2020 and 2021. 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 on page 88. Amounts are shown in AUD (the currency in which the remuneration is paid), whereas Table 10 is expressed in USD which is Woodside’s reporting 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. TABLE 5 – CEO AND SENIOR EXECUTIVE TAKE HOME PAY TABLE (NON-IFRS INFORMATION) Salary, allowances and superannuation1 A$ EIS cash and other cash incentives2 A$ Restricted Shares vested3 A$ RTSR tested VPRs vested3 A$ Equity Rights vested3 A$ Total remuneration received A$ Previous years' awards forfeited or lapsed3 A$ 1,906,872 465,168 1,647,167 1,471,330 - 823,331 360,778 821,739 - 750,091 177,667 568,396 - - 122,257 222,183 52,486 65,632 - - 137,129 123,659 80,822 19,651 1,149,246 1,723,075 957,150 2,035,462 2,701,000 - 1,522,420 1,835,255 1,024,439 220,000 1,091,798 - 11,110 - - - - - - 4,019,207 1,471,330 - - 1,443,495 204,377 31,658 1,199,239 - 1,061,066 31,658 685,337 84,155 30,286 - 5,864,933 3,031,953 6,058,675 1,248,406 1,255,549 346,775 1,438,573 - - - - - Name M O’Neill S Gregory F Hick P Coleman5, 6 S Duhe7 Year 2021 20204 2021 20204 2021 20204 2021 20204 2021 20204 1 Represents the total fixed annual rewards earned in 2021 and 2020 including salaries, fees, allowances and company contributions to superannuation. This may differ from amounts disclosed in Table 10 which reflects pro-rated amounts for the period that Executives were in KMP roles, except for Mr P Coleman whose FAR is disclosed based on his contract end date. 2 Includes the EIS cash incentive earned in the respective year, which is actually paid in the following year. This is calculated on the same basis as amounts disclosed in Table 10. There was no EIS cash incentive earned in 2020. 3 The value of Restricted Shares, Variable Pay Rights and Equity Rights is calculated using the five-day VWAP leading up to but not including the vesting or forfeiture or lapsing date. 4 For the 2020 EIS Awards, the Board exercised its discretion to reduce VAR by 30%. 5 The 2020 EIS Award to Mr P Coleman (allocated in April 2021) was allocated in Performance Rights in lieu of cash and Restricted Shares. Mr P Coleman's 2021 EIS award was allocated in cash in lieu of Restricted Shares. 6 Mr P Coleman ceased being an Executive KMP on 19 April 2021. 7 Ms S Duhe ceased being an Executive KMP on 4 February 2022. TABLE 6 – 2021 VESTINGS1 2017 deferred short-term award Restricted Shares vested on 20 February 2021 2016 long-term award VPRs had a partial vesting of 63% on 9 March 2021 2015 long-term award VPRs had a partial vesting of 9.2% on 9 March 20212 2018 Restricted Shares sign on bonus vested on 1 May 2021 2018 Restricted Shares sign on bonus vested on 17 August 2021 1 Amounts that vested in 2021 (other than for Ms M O'Neill) relate to prior schemes as outlined on pages 89-90. 2 This was the second test for the 2015 award. Overall, 47.5% of the total 2015 award vested. Executive S Gregory F Hick P Coleman S Duhe S Gregory F Hick P Coleman S Gregory F Hick P Coleman M O’Neill M O’Neill Shares 4,831 2,074 37,822 439 4,502 3,010 66,822 963 211 14,297 37,048 37,048 Woodside Petroleum Ltd 83 TABLE 7 – VALUATION SUMMARY OF EXECUTIVE KMP EIS FOR 2021 AND 2020 Name M O’Neill S Gregory F Hick P Coleman4,5 S Duhe6 Year 20212 20203 20212 20203 20212 20203 20212 20203 2021 20203 Cash1 $ 337,421 - 137,878 - 128,875 - 1,249,873 - - - Restricted Shares 3-year vesting period $ Restricted Shares 5-year vesting period $ Performance Rights 3-year vesting period $ Performance Rights 5-year vesting period $ 745,559 309,344 304,645 177,107 284,757 146,255 - - - 813,351 309,344 332,344 177,107 310,643 146,255 - - - 225,387 225,387 - - - - - - 455,488 2,133,567 - - 688,613 426,616 281,375 244,243 263,002 201,700 - - - 310,849 Total EIS $ 2,584,944 1,045,304 1,056,242 598,457 987,277 494,210 1,705,361 2,133,567 - 761,623 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. There was no cash incentive earned in 2020. 2 The number of Restricted Shares and Performance Rights allocated for 2021 was calculated 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 of Restricted Shares and Performance Rights at their date of grant has been estimated by reference to the closing share price at 31 December 2021 and preliminary modelling respectively. Grant date for Senior Executives' awards has been determined to be the date of the Board of Directors' approval, being 16 February 2022 while grant date for Ms M O’Neill's award is the date of shareholder approval at the 2022 Woodside Annual General Meeting. Any differences between the estimated fair value at 31 December 2021 and the final fair value will be trued-up in the following 2022 financial year. The fair value is not related to or 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 2020 was calculated post year-end by dividing the amount of the Executive’s entitlement allocated to Performance Rights by the face value of Woodside’s shares. The USD fair value shown above was estimated at 31 December 2020 with reference to the closing share price and preliminary modelling. Grant date for all Executives apart from Mr P Coleman has been determined to be the date of the Board of Directors' approval, being 17 February 2021. The grant date for Mr P Coleman has been determined to be the date of shareholder approval at the 2021 Woodside Annual General Meeting. The final fair value was calculated at these dates and was trued-up in the 2021 financial year. The amount above is not related to or indicative of the benefit (if any) that an individual Executive may ultimately realise should these equity instruments vest. 4 Mr P Coleman's 2020 EIS Award was allocated in Performance Rights in lieu of cash and Restricted Shares. Mr P Coleman's 2021 EIS award was allocated in cash in lieu of Restricted Shares. 5 Mr P Coleman ceased being an Executive KMP on 19 April 2021. 6 Ms S Duhe ceased being an Executive KMP on 4 February 2022. 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, including the legacy Executive Incentive Plan. Details of prior year allocations are provided in Table 12 on pages 89-90. The terms applying to prior year grants are described in past Woodside Annual Reports. Executive Incentive Plan (EIP) The EIP operated as Woodside’s Executive incentive framework until the end of 2017, after which the Board introduced the EIS. The EIP was used to deliver short-term award (STA) and long-term award (LTA) to Senior Executives. Eligible Executives could only receive an STA award if their individual annual performance was assessed as acceptable. Participants were then divided into “Pool Groups”, with the size of the pool determined by each participant’s target STA, and then adjusted based on the Corporate Scorecard result. STA made up 30-33% of total target remuneration for Senior Executives with no individual maximum STA opportunity because the size of the STA pool varied from year to year depending on performance and other factors. LTA was granted in the form of Variable Pay Rights (VPRs) making up 20-22% of total target remuneration for Senior Executives. The LTA award was divided into two portions with each portion subject to a separate RTSR performance hurdle tested over a four-year period. One-third of the LTA is tested against a comparator group that comprises the entities within the ASX 50 index. The remaining two-thirds is tested against an international group of oil and gas companies. RTSR outcomes are calculated by an external adviser on the fourth anniversary of the allocation. For 2017 awards to Senior Executives, any VPRs that do not vest will lapse and are not retested. Awards made to other Executives are eligible for a retest in the following year. VPRs that do not vest following the re-test will lapse. 2017 is the last year of award to which a retest applies. Executives are entitled to receive dividends on Restricted Shares. There is no entitlement to dividends on VPRs. Details of prior year allocations are provided in Table 12 on pages 89-90. Peter Coleman’s STA and LTA The former CEO’s incentive arrangements are governed by his contract of employment. Prior to 2018, the former CEO’s STA award was determined by multiplying the former CEO’s FAR by the Corporate Scorecard result and the former CEO’s individual performance factor as determined by the Board. Two-thirds of the award was paid in cash with the remaining third delivered as a deferred equity award of Restricted Shares, subject to an overall cap of two times FAR. 84 Annual Report 2021 For 2017, the LTA opportunity was set at 133% of the former CEO’s FAR. The entitlement was allocated at face value and in the form of VPRs and divided into two portions with each subject to a separate RTSR performance hurdle tested over a four year period with no retest. One-third of the LTA will be tested against a comparator group that comprises the entities within the ASX 50 index. The remaining two-thirds will be tested against an international group of oil and gas companies. Details of prior year allocations are provided in Table 12 on pages 89-90. Woodside Equity Plan (WEP) The WEP is available to all permanent employees except EIS participants. The purpose of the WEP is to enable eligible employees to build up a holding of equity in the company as they progress through their career at Woodside. 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. There are no further ongoing performance conditions. The linking of performance to an allocation allows Woodside to recognise and reward eligible employees for high performance. Each ER entitles the participant to receive a Woodside share on the vesting date three or five years after the effective grant date. For offers prior to 2019, each ER entitled the participant to receive a Woodside share on the vesting date three years after the effective grant date. For subsequent awards, the Board amended the terms of the Plan to allow for 75% vesting of the ERs three years after the effective grant date and the remaining 25% of ERs five years after the effective grant date. Supplementary Woodside Equity Plan (SWEP) In October 2011, the Board approved a remuneration strategy which includes the use of equity to support a competitive base remuneration position. To this end, the Board approved the establishment of the SWEP to enable the offering of targeted retention awards of ERs for key capability. The SWEP was designed to be offered to a small number of employees identified as being retention critical. The SWEP awards have service conditions and no performance conditions. Each ER entitles the participant to receive a Woodside share on the vesting date three years after the effective grant date. There were no allocations under the SWEP in 2021. None of the Senior Executives have unvested SWEP ERs at the end of 2021. ERs under both the WEP and 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 of their ERs. 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 policy requires Senior Executives to have acquired and maintained Woodside shares for a minimum total purchase price of at least 100% of their fixed remuneration after a period of five years, and in the case of the CEO a minimum of 200% of fixed remuneration. Other equity awards In February 2018, the Board approved the Equity Award Rules which apply to EIS and discretionary executive allocations. This allows the Board and CEO to award discretionary allocations of Restricted Shares or Performance Rights. 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 M O’Neill3 S Gregory3 F Hick3 Employing company Contract duration Woodside Energy Ltd Woodside Energy Ltd Woodside Energy Ltd Unlimited Unlimited Unlimited Termination notice period company1, 2 Termination notice period executive 6 months 6 months 6 months 6 months 3 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 termination 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. Woodside Petroleum Ltd 85 Non-executive directors 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 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 Committee based on benchmarking from external remuneration consultants and determined by the Board. In 2021, 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$4.25 million per financial year, which was approved by shareholders at the 2019 AGM. NEDs are required to have acquired shares for a total purchase price of at least 100% of their pre-tax 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 with net fees, the shares in the NEDSP are not subject to any forfeiture conditions. NEDs remuneration structure NEDs remuneration consists of base Board fees and committee fees, plus statutory superannuation contributions or payments in lieu (currently 10%). 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 below shows the annual base Board and committee fees for NEDs. There has been no change to Board or committee fees since 2019. 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. In 2021, NEDs Frank Cooper, Ben Wyatt and Larry Archibald received an additional payment of A$20,000 each for services provided during the period outside the scope of Board and Committee duties, in connection with the proposed merger with BHP Group’s oil and gas portfolio, including membership of the Due Diligence Committee. Board fees are not paid to the CEO, as the time spent on Board work and the responsibilities of Board membership are considered in determining the remuneration package provided as part of the normal employment conditions. The total remuneration paid to, or in respect of, each NED in 2021 is set out in Table 13 on page 90. TABLE 9 – ANNUAL BASE BOARD AND COMMITTEE FEES FOR NEDS Position Chairman of the Board2 Non-executive directors3 Committee chair Committee member Board1 A$ 723,300 219,178 Audit & Risk Committee A$ Human Resources & Compensation Committee A$ Sustainability Committee A$ Nominations & Governance Committee A$ 59,360 31,964 52,000 26,500 47,400 23,700 Nil Nil 1 NEDs receive Board and committee fees plus statutory superannuation (or payments in lieu where statutory superannuation is not required to be paid). 2 Inclusive of committee work. 3 Board fees paid to NEDs other than the Chairman. 86 Annual Report 2021 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 section 3.4 of the Corporate Governance Statement, available on Woodside’s website. Use of remuneration consultants From time to time, the Committee may directly engage 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. 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. No executive remuneration advice was obtained from external independent remuneration consultants in 2021 and there were no fees payable to independent external remuneration consultants during the period. No loans 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. 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 all KMP is paid in Australian dollars and, for reporting purposes, converted to US dollars based on the applicable exchange rate at the date of payment. Valuation of equity awards is converted at the spot rate applying when the equity award is granted. Woodside Petroleum Ltd 87 Statutory tables TABLE 10 - COMPENSATION OF CEO AND SENIOR EXECUTIVES FOR THE YEAR ENDED 31 DECEMBER 2021 AND 2020 FAR VAR and other incentives Short-term Post- employment Salaries, fees and allowances Non- monetary benefits1 Company contributions to superannuation $ 2021 1,431,531 52,614 2020 1,012,177 56,808 $ - - Share- based payments Share plans3 Long service leave Termination benefits Total remuneration4 Performance related5 $ $ $ $ A$ Cash Cash2 $ 337,421 1,515,992 129,123 - 3,466,681 4,633,501 - 1,066,937 40,928 2021 588,690 15,788 29,403 261,6999 557,279 18,260 2020 550,615 20,381 14,687 - 485,293 24,010 2021 540,368 29,989 22,742 128,875 390,418 11,742 2020 205,773 9,006 9,030 - 150,268 37,37110 - - - - - 2,176,850 3,164,334 1,471,119 1,971,787 1,094,986 1,591,702 1,124,134 1,503,402 411,448 569,568 2021 879,481 51,506 8,380 1,249,873 4,178,652 543,355 2,447,525 9,358,772 12,219,216 2020 1,843,422 38,301 14,686 - 4,022,663 75,827 - 5,994,899 8,714,358 2021 752,079 120,182 16,990 159,5829 (1,033,319) 14,743 2020 751,084 42,220 - - 597,006 31,213 - - 30,257 47,732 1,421,523 2,066,367 % 53 49 56 44 46 37 58 67 - 42 M O’Neill Chief Executive Officer and Managing Director6 S Gregory Executive Vice President Sustainability and Chief Technology Officer F Hick Executive Vice President Operations P Coleman8 S Duhe6, 7 1 Reflects the value of non-monetary benefits (including relocation, travel, 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. There was no cash incentive earned in 2020. 3 ‘Share plans’ incorporate all equity based plans. In accordance with the requirements of AASB 2 Share-based Payment, the fair value of rights as at their date of grant has been determined by applying the Black-Scholes option pricing technique or applying the binomial valuation method combined with a Monte Carlo simulation. The fair value of rights 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 2021 EIS has been measured using estimated fair values as disclosed in footnote 2 in Table 7. The amount included as remuneration is not related to or indicative of the benefit (if any) that individual Executives may ultimately realise should these equity instruments vest. 4 The total remuneration in AUD is converted from USD using the average exchange rate for the period. 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. 5 Performance related outcome percentage is calculated as total Variable Annual Reward divided by the total USD remuneration figure. 6 As a non-resident for Australian tax purposes 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. The cash payment is subject to (PAYG) income tax and paid as part of Ms M O’Neill’s normal monthly salary. The amount is included in salaries, fees and allowances. Ms S Duhe became a resident for Australian tax purposes effective 1 June 2021 and received superannuation contributions following this date. Prior to 1 June 2021, Ms S Duhe elected to receive a cash payment in lieu of superannuation contributions. 7 In accordance with the requirements of AASB 2 Share-based Payment, Ms S Duhe’s 2018, 2019, 2020 and 2021 share-based payment amortisation expenses have reversed following her notice of resignation on 16 November 2021. 8 Mr P Coleman ceased being an Executive KMP on 19 April 2021. In accordance with the requirements of AASB 2 Share-based Payment, his 2018, 2019, 2020 and 2021 share-based payment amortisation expenses have accelerated based on his contract end date of 3 June 2021. This is not reflective of any value received by Mr Coleman as the awards have not vested at 31 December 2021 and are subject to vesting conditions. Vesting details of these awards are disclosed in Table 12 on page 89. Mr P Coleman's FAR is disclosed to 3 June 2021. 9 Cash awards received by Mr S Gregory and Ms S Duhe include a cash bonus payment of $123,821 and $50,776 respectively upon signing of the merger commitment deed announced to ASX on 17 August 2021. Ms S Duhe received a further cash bonus payment of $108,806 in connection with efforts related to the merger share sale agreement and the Scarborough and Pluto Train 2 FIDs. 10 Ms F Hick's long service leave accrued in 2020 has been updated to reflect the period she was an Executive KMP from 1 July 2020 to 31 December 2020. TABLE 11 - PEER GROUP OF INTERNATIONAL OIL AND GAS COMPANIES1 APA Corporation (previously Apache Corporation) EOG Resources Beach Energy Canadian Natural Resources ConocoPhillips ENI S.p.A Equinor ASA Hess Corporation Inpex Corporation Marathon Oil Company Occidental Petroleum Origin Energy Limited Santos Ltd2 1 Peer group updated for 2021 EIS award to reflect recent changes including merger and acquisition activity in the prior year’s peer group. 2 Oil Search Limited and Santos Limited merged effective 17 December 2021. Oil Search Limited was removed from the Official List of ASX on 20 December 2021. 88 Annual Report 2021 Vested in 2021 % of total vested Lapsed in 2021 Fair value of equity4,5,6 TABLE 12 – SUMMARY OF CEO AND SENIOR EXECUTIVES’ ALLOCATED, VESTED OR LAPSED EQUITY Name Type of equity1 Grant date Allocation date Vesting date2,3 M O’Neill8 Restricted Shares 13 February 2019 19 February 2019 19 February 2022 Restricted Shares 13 February 2019 19 February 2019 19 February 2024 Restricted Shares 12 February 2020 18 February 2020 18 February 2023 Restricted Shares 12 February 2020 18 February 2020 18 February 2025 Restricted Shares 17 February 2021 24 February 2021 24 February 2024 Restricted Shares 17 February 2021 24 February 2021 24 February 2026 Restricted Shares 19 May 2022 Restricted Shares 19 May 2022 Restricted Shares 1 May 2018 Restricted Shares 1 May 2018 19 May 2022 19 May 2022 1 May 2018 1 May 2018 19 May 2025 19 May 2027 1 May 2021 17 August 2021 Awarded but not vested 14,097 15,379 15,025 16,391 17,697 17,697 46,861 51,122 - - - - - - - - - - 37,048 37,0488 Performance Rights 13 February 2019 19 February 2019 19 February 2024 Performance Rights 12 February 2020 18 February 2020 18 February 2025 Performance Rights 17 February 2021 24 February 2021 24 February 2026 Performance Rights 19 May 2022 19 May 2022 19 May 2027 15,379 16,391 23,596 51,122 - - - - S Gregory Restricted Shares 1 January 2017 20 February 2018 20 February 2021 - 4,831 100 Restricted Shares 13 February 2019 19 February 2019 19 February 2022 Restricted Shares 13 February 2019 19 February 2019 19 February 2024 Restricted Shares 12 February 2020 18 February 2020 18 February 2023 Restricted Shares 12 February 2020 18 February 2020 18 February 2025 Restricted Shares 17 February 2021 24 February 2021 24 February 2024 Restricted Shares 17 February 2021 24 February 2021 24 February 2026 Restricted Shares 16 February 2022 23 February 2022 23 February 2025 12,430 13,560 10,099 11,018 10,132 10,132 19,148 Restricted Shares 16 February 2022 23 February 2022 23 February 2027 20,889 - - - - - - - - - - - - - - - - - - - - - - - - 100 100 - - - - - - - - - - - - - - - - - - - - - - - - - - - RTSR Tested VPRs 1 January 2015 19 February 2016 9 March 2021 RTSR Tested VPRs 1 January 2016 27 February 2017 9 March 2021 - - 963 4,502 9.2 63.0 5,499 2,646 RTSR Tested VPRs 1 January 2017 20 February 2018 20 February 2022 Performance Rights 13 February 2019 19 February 2019 19 February 2024 Performance Rights 12 February 2020 18 February 2020 18 February 2025 Performance Rights 17 February 2021 24 February 2021 24 February 2026 Performance Rights 16 February 2022 23 February 2022 23 February 2027 7,1507 13,560 11,018 13,509 20,889 - - - - - - - - - - F Hick Restricted Shares 1 January 2017 20 February 2018 20 February 2021 - 2,074 100 Restricted Shares 13 February 2019 19 February 2019 19 February 2022 Restricted Shares 13 February 2019 19 February 2019 19 February 2024 Restricted Shares 12 February 2020 18 February 2020 18 February 2023 Restricted Shares 12 February 2020 18 February 2020 18 February 2025 Restricted Shares 17 February 2021 24 February 2021 24 February 2024 Restricted Shares 17 February 2021 24 February 2021 24 February 2026 Restricted Shares 16 February 2022 23 February 2022 23 February 2025 Restricted Shares 16 February 2022 23 February 2022 23 February 2027 RTSR Tested VPRs 1 January 2015 19 February 2016 9 March 2021 RTSR Tested VPRs 1 January 2016 27 February 2017 9 March 2021 RTSR Tested VPRs 1 January 2017 20 February 2018 20 February 2022 Performance Rights 13 February 2019 19 February 2019 19 February 2024 Performance Rights 12 February 2020 18 February 2020 18 February 2025 Performance Rights 17 February 2021 24 February 2021 24 February 2026 Performance Rights 16 February 2022 23 February 2022 23 February 2027 6,807 7,426 5,501 6,002 8,367 8,367 17,898 19,525 - 1,7697 4,9447 7,426 6,602 11,156 19,525 - - - - - - - - - - - - - - - - 211 3,010 9.2 63.0 - - - - - - - - - - P Coleman9 Restricted Shares Restricted Shares 1 January 2017 20 February 2018 20 February 2021 - 37,822 100 13 February 2019 19 February 2019 19 February 2022 Restricted Shares 13 February 2019 19 February 2019 19 February 2024 Restricted Shares 12 February 2020 18 February 2020 18 February 2023 Restricted Shares 12 February 2020 18 February 2020 18 February 2025 61,660 67,266 61,083 45,812 - - - - - - - - - - - - - - - - - - - - - - 1,207 - - - - - - - - - - - RTSR Tested VPRs 1 January 2015 19 February 2016 9 March 2021 RTSR Tested VPRs 1 January 2016 27 February 2017 9 March 2021 - - 14,297 66,822 9.2 63.0 81,587 39,245 RTSR Tested VPRs 1 January 2017 20 February 2018 20 February 2022 104,7977 Performance Rights 13 February 2019 19 February 2019 19 February 2024 Performance Rights 12 February 2020 18 February 2020 18 February 2025 Performance Rights 15 April 2021 15 April 20219 15 April 20249 Performance Rights 16 February 2022 23 February 2022 23 February 2025 67,266 45,812 118,007 33,815 - - - - - - - - - - - - - - - 24.71 24.71 22.76 22.76 20.18 20.18 15.91 15.91 24.45 24.45 16.87 15.81 14.44 13.47 22.49 24.71 24.71 22.76 22.76 20.18 20.18 15.91 15.91 17.39 12.05 12.06 16.87 15.81 14.44 13.47 22.49 24.71 24.71 22.76 22.76 20.18 20.18 15.91 15.91 17.39 12.05 12.06 16.87 15.81 14.44 13.47 22.49 24.71 24.71 22.76 22.76 17.39 12.05 12.06 16.87 15.81 11.66 13.47 Woodside Petroleum Ltd 89 Name S Duhe10 Type of equity1 Grant date Allocation date Vesting date2,3 Awarded but not vested Vested in 2021 % of total vested Lapsed in 2021 Fair value of equity4,5,6 Restricted Shares 1 January 2017 20 February 2018 20 February 2021 - 439 100 Restricted Shares 13 February 2019 19 February 2019 19 February 2022 Restricted Shares 13 February 2019 19 February 2019 19 February 2024 Restricted Shares 12 February 2020 18 February 2020 18 February 2023 Restricted Shares 12 February 2020 18 February 2020 18 February 2025 Restricted Shares 17 February 2021 24 February 2021 24 February 2024 Restricted Shares 17 February 2021 24 February 2021 24 February 2026 RTSR Tested VPRs 1 January 2017 20 February 2018 20 February 2022 Performance Rights 13 February 2019 19 February 2019 19 February 2024 Performance Rights 12 February 2020 18 February 2020 18 February 2025 Performance Rights 17 February 2021 24 February 2021 24 February 2026 14,604 15,931 11,816 12,890 12,894 12,894 8687 15,931 12,890 17,193 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 22.49 24.71 24.71 22.76 22.76 20.18 20.18 12.06 16.87 15.81 14.44 1 For valuation purposes all VPRs and performance rights are treated as if they will be equity settled. 2 Vesting date and exercise date are the same. Vesting is subject to the 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. The minimum total value of the grants for future financial years is nil if relevant vesting conditions are not satisfied. An estimate of the maximum possible total value in future financial years is the fair value at grant date multiplied by the number of equity instruments awarded. 3 Any RTSR-tested VPRs allocated to Senior Executives prior to 2017 that do not vest as a result of the first test will be re-tested over a five year performance period. RTSR-tested VPRs allocated in 2017 and performance rights will not be re-tested. The second test date for earlier VPR allocations is one year after the vesting date listed in the table. 4 In accordance with the requirements of AASB 2 Share-based Payment, the fair value of VPRs as at their date of grant has been determined by applying the Black-Scholes option pricing technique or binomial valuation method combined with a Monte Carlo simulation. The amount included as remuneration is not related to or indicative of the benefit (if any) that individual Executives may ultimately realise should these equity instruments vest. 5 The fair value of Rights and Restricted Shares as at their date of grant has been determined by reference to the share price at acquisition. The fair value is not related to or indicative of the benefit (if any) that individual Executives may ultimately realise should these equity instruments vest. 6 Fair values for the 2020 EIS with a grant date of 17 February 2021 have been estimated as disclosed in footnotes 2 and 3 of Table 7. Fair values for the 2021 EIS with a grant date of 16 February 2022 have been estimated as disclosed in footnote 2 of Table 7. 7 The RTSR-tested VPRs allocated for the 2015 and 2016 performance years have been updated to include any adjustments made as part of the Retail Entitlement Offer. 8 Ms M O'Neill was appointed CEO and Managing Director on 17 August 2021. The Board approved the accelerated vesting of 37,048 Restricted Shares upon her appointment as CEO and Managing Director. The grant of the Performance Rights and Restricted Shares components of Ms M O'Neill's 2021 EIS award is subject to shareholder approval at the 2022 Woodside Annual General Meeting. The grant date for Performance Rights and Restricted Shares is the date of shareholder approval. 9 Mr P Coleman ceased being an Executive KMP on 19 April 2021. Mr Coleman’s Restricted Shares, VPRs and Performance Rights remain on foot and will vest in the ordinary course subject to the satisfaction of applicable conditions. The grant date and allocation date for 118,007 Performance Rights awarded to Mr Coleman was the 2021 Annual General Meeting following shareholder approval. 10 Ms S Duhe resigned on 16 November 2021 and ceased to be an Executive KMP on 4 February 2022. Ms Duhe's Restricted Shares and Performance Rights lapsed on 7 February 2022. The following table provides a detailed breakdown of the components of remuneration for each of the company’s NEDs. TABLE 13 - TOTAL REMUNERATION PAID TO NEDS IN 2021 AND 2020 Short-term Post employment Cash salary and allowances Pension/Superannuation Board and Committee fees $ Other fees and allowances $ Company contributions to superannuation $ 542,997 497,582 206,330 189,073 228,999 209,846 202,228 185,314 206,330 189,073 202,228 185,314 220,020 201,618 206,330 189,073 227,575 208,542 114,868 - 35,953 32,584 35,132 24,841 15,014 - 21,452 19,154 20,117 24,841 15,294 10,381 21,452 26,033 - - - - 14,718 - 16,990 14,687 - - 22,327 19,935 - - - - 4,423 7,224 - - 20,117 17,962 22,189 19,811 16,082 - Non-executive director R Goyder L Archibald2 F Cooper S C Goh2 C Haynes2 I Macfarlane A Pickard2 S Ryan G Tilbrook B Wyatt 2021 2020 20211 2020 20211 2020 2021 2020 2021 2020 2021 2020 2021 2020 2021 2020 2021 2020 20211 2020 Total $ 595,940 544,853 241,462 213,914 266,340 229,781 223,680 204,468 226,447 213,914 221,945 202,919 241,472 227,651 226,447 207,035 249,764 228,353 145,668 - Total A$3 793,822 792,014 321,639 310,952 354,779 334,017 297,953 297,220 301,639 310,952 295,642 294,969 321,653 330,920 301,639 300,952 332,698 331,940 197,944 - 1 Includes an additional payment of A$20,000 each for services outside the scope of Board and Committee duties, in connection with the proposed merger with BHP Group’s oil and gas portfolio. 2 As non-residents for Australian tax purposes Mr L Archibald, Ms S C Goh, Dr C Haynes and Ms A Pickard 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 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. 90 Annual Report 2021 Details of shares held by KMP including their personally related entities1 for the 2021 financial year are as follows: TABLE 14 - KMP SHARE AND EQUITY HOLDINGS Name Type of equity Non-executive directors Opening holding at 1 January 2021² Rights allocated in 2021 Rights vested in 2021 Restricted Shares granted Net changes - other NEDSP³ Closing holding at 31 December 20214 R Goyder L Archibald F Cooper S C Goh C Haynes I Macfarlane A Pickard S Ryan G Tilbrook B Wyatt5 Executives M O’Neill S Gregory F Hick P Coleman6 S Duhe7 Shares Shares Shares Shares Shares Shares Shares Shares Shares Shares Rights Shares Rights Shares Rights Shares Rights Shares Rights Shares 23,634 8,249 11.541 5,089 12,734 7,841 10,196 10,247 7,949 - 31,770 194,258 45,338 67,228 24,569 29,557 419,826 530,985 29,689 70,833 - 3,728 1,909 7,697 1,864 2,488 4,010 1,663 - - - - - - - - - - - - - - - - - - - - - - 23,596 - - - - - - - - - - - - - - - - - - - - - - - - 35,394 - - - - - - - - - - - - 13,509 (5,465) - (8,145) - 11,156 - 118,007 - 17,193 - 5,465 (3,221) 3,221 (81,119) 81,119 - - 20,264 (6,633) - (1,207) 16,734 - - - - 25,788 (456,714) (612,104) - - 23,634 11,977 13,450 12,786 14,598 10,329 14,206 11,910 7,949 - 55,366 229,652 45,237 86,324 31,297 49,512 - - 46,882 96,621 1 Personally related entities include 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 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 2021. 5 Mr B Wyatt was appointed as a non-executive director on 1 June 2021. Mr Wyatt is participating in the NEDSP and will acquire shares under this plan going forward. 6 Mr P Coleman was granted 118,007 Performance Rights as approved at the 2021 Annual General Meeting under Listing Rule 10.14. As Mr Coleman ceased being an Executive KMP on 19 April 2021, the information disclosed in Table 14 is only in relation to the period he was an Executive KMP. 7 Ms S Duhe ceased to be an Executive KMP on 4 February 2022. Her Restricted Shares and Performance Rights lapsed on 7 February 2022. Woodside Petroleum Ltd 91 Glossary Key terms used in the Remuneration Report Term Committee Meaning The Human Resources & Compensation Committee Corporate Scorecard A corporate scorecard of key measures that aligns with Woodside’s overall business performance EIP EIS The Executive Incentive Plan The Executive Incentive Scheme Equity Award Rules The rules which govern offers of incentive securities to eligible employees ER 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 on page 73 FAR FID Fixed Annual Reward Final Investment Decision Former CEO Peter Coleman. Mr Coleman ceased to be an Executive KMP on 19 April 2021 IPF KMP KPI LTA MSR NED Individual Performance Factor Key management personnel Key performance indicator Long-term award Minimum shareholding requirements 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 Restricted Shares 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 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 Retail Entitlement Offer The pro-rata renounceable offer made to Eligible Retail Shareholders to subscribe for 1 new share for every 9 existing shares on 19 February 2018 Rights RTSR ERs, Performance Rights and VPRs Relative total shareholder return Senior Executive A Senior Executive listed as KMP in Table 1A on page 73, excluding the Executive Director STA SWEP VAR VPR Short-term award The Supplementary Woodside Equity Plan Variable Annual Reward Variable Pay Right. Each VPR 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 VPR WEP The Woodside Equity Plan 92 Annual Report 2021 FINANCIAL STATEMENTS CONTENTS Financial statements Consolidated income statement Consolidated statement of comprehensive income Consolidated statement of financial position Consolidated statement of cash flows Consolidated statement of changes in equity Notes to the financial statements About these statements A. Earnings for the year A.1 Segment revenue and expenses A.2 Finance costs A.3 Dividends paid and proposed A.4 Earnings/(losses) per share A.5 Taxes B. Production and growth assets B.1 Segment production and growth assets B.2 Exploration and evaluation B.3 Oil and gas properties B.4 Impairment of exploration and evaluation and oil and gas properties B.5 Significant production and growth asset acquisitions B.6 Non-current assets held for sale C. Debt and capital C.1 Cash and cash equivalents C.2 Interest-bearing liabilities and financing facilities C.3 Contributed equity C.4 Other reserves D. Other assets and liabilities D.1 Segment assets and liabilities D.2 Receivables D.3 Inventories D.4 Payables D.5 Provisions D.6 Other financial assets and liabilities D.7 Leases E. Other items E.1 Contingent liabilities and assets E.2 Employee benefits E.3 Related party transactions E.4 Auditor remuneration E.5 Events after the end of the reporting period E.6 Joint arrangements E.7 Parent entity information E.8 Subsidiaries E.9 Other accounting policies Directors' declaration Independent audit report 95 96 97 98 99 100 102 103 106 106 106 107 109 110 112 113 115 120 121 122 123 123 125 125 126 127 127 127 128 128 130 132 134 135 135 137 137 137 137 138 139 141 142 143 Significant changes in the current reporting period The financial performance and position of the Group were particularly affected by the following events and transactions during the reporting period: • On 10 February 2021, the Group redeemed the $700 million 2021 US bond (refer to Note C.2). • On 18 May 2021, the Group exited its 50% non-operated participating interest in the Kitimat LNG development. A net expense of $33 million, reflecting various exit costs, was recognised in the period (refer to Note A.1). • On 7 July 2021, the Group completed the acquisition of FAR Senegal RSSD SA’s interest in the Rufisque Offshore, Sangomar Offshore and Sangomar Deep Offshore (RSSD) Joint Venture (refer to Note B.5). • On 15 November 2021, the Group entered into a sale and purchase agreement with Global Infrastructure Partners for the sale of 49% of the Pluto Train 2 Joint Venture. As at 31 December 2021, the transaction has not been completed. Pluto Train 2 assets of $252 million have been reclassified to non-current assets held for sale as at 31 December 2021 (refer to Note B.6). • On 22 November 2021, the Group took unconditional FID on the Scarborough and Pluto Train 2 developments. Related exploration and evaluation assets were transferred to oil and gas properties (refer to Notes B.2 and B.3). In addition, FID triggered contingent payments of $300 million and $150 million to ExxonMobil and BHP Group respectively, which have been capitalised to oil and gas properties (refer to Note B.3). • The Group decided to withdraw from its interests in Myanmar and capitalised costs of $209 million were expensed (refer to Note B.2). • The Group recognised impairment reversals of $1,058 million (refer to Note B.4). • The Group hedged an increased percentage of its exposure to commodity price and foreign exchange risk through commodity swaps and foreign exchange forward derivatives (refer to Note D.6). 94 Annual Report 2021 CONSOLIDATED INCOME STATEMENT for the year ended 31 December 2021 Operating revenue Cost of sales Gross profit Other income Other expenses Impairment losses Impairment reversals Profit/(loss) before tax and net finance costs Finance income Finance costs Profit/(loss) before tax Petroleum resource rent tax (expense)/benefit Income tax (expense)/benefit Profit/(loss) after tax Profit/(loss) attributable to: Equity holders of the parent Non-controlling interest Profit/(loss) for the period Basic earnings/(losses) per share attributable to equity holders of the parent (US cents) Diluted earnings/(losses) per share attributable to equity holders of the parent (US cents) The accompanying notes form part of the Financial Statements. Notes A.1 A.1 A.1 A.1 A.1 A.1 A.2 A.5 A.5 E.8 A.4 A.4 2021 US$m 6,962 (3,845) 3,117 139 (811) (10) 1,058 3,493 27 (230) 3,290 (297) (957) 2,036 1,983 53 2,036 206.0 204.1 2020 US$m 3,600 (2,985) 615 (36) (481) (5,269) - (5,171) 58 (327) (5,440) 439 1,026 (3,975) (4,028) 53 (3,975) (423.5) (423.5) Woodside Petroleum Ltd 95 CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME for the year ended 31 December 2021 Profit/(loss) for the period Other comprehensive income/(loss) Items that may be reclassified to the income statement in subsequent periods: Loss on cash flow hedges (refer to Note D.6 for more details) Loss on cash flow hedges reclassified to the income statement Tax recognised within other comprehensive income Items that will not be reclassified to the income statement in subsequent periods: Remeasurement gains on defined benefit plan Other comprehensive income/(loss) for the period, net of tax Total comprehensive income/(loss) for the period Total comprehensive income/(loss) attributable to: Equity holders of the parent Non-controlling interest Total comprehensive income/(loss) for the period The accompanying notes form part of the Financial Statements. 2021 US$m 2,036 (390) 66 (5) 13 (316) 1,720 1,667 53 1,720 2020 US$m (3,975) (136) 52 25 2 (57) (4,032) (4,085) 53 (4,032) 96 Annual Report 2021 CONSOLIDATED STATEMENT OF FINANCIAL POSITION as at 31 December 2021 Current assets Cash and cash equivalents Receivables Inventories Other financial assets Other assets Non-current assets held for sale Total current assets Non-current assets Receivables Inventories Other financial assets Other assets Exploration and evaluation assets Oil and gas properties Other plant and equipment Deferred tax assets Lease assets Total non-current assets Total assets Current liabilities Payables Interest-bearing liabilities Other financial liabilities Other liabilities Provisions Tax payable Lease liabilities Total current liabilities Non-current liabilities Interest-bearing liabilities Deferred tax liabilities Other financial liabilities Other liabilities Provisions Lease liabilities Total non-current liabilities Total liabilities Net assets Equity Issued and fully paid shares Shares reserved for employee share plans Other reserves Retained earnings Equity attributable to equity holders of the parent Non-controlling interest Total equity The accompanying notes form part of the Financial Statements. Notes C.1 D.2 D.3 D.6 B.6 D.2 D.3 D.6 B.2 B.3 A.5 D.7 D.4 C.2 D.6 D.5 A.5 D.7 C.2 A.5 D.6 D.5 D.7 C.3 C.3 C.4 E.8 2021 US$m 3,025 368 202 320 109 254 4,278 686 19 107 34 614 18,434 215 1,007 1,080 22,196 26,474 639 277 411 86 605 413 191 2020 US$m 3,604 303 125 172 48 - 4,252 423 40 54 55 2,045 15,267 199 1,304 984 20,371 24,623 505 776 37 136 500 46 94 2,622 2,094 5,153 878 161 36 2,219 1,176 9,623 12,245 14,229 9,409 (30) 683 3,381 13,443 786 14,229 5,438 549 34 42 2,407 1,184 9,654 11,748 12,875 9,297 (23) 1,403 1,398 12,075 800 12,875 Woodside Petroleum Ltd 97 CONSOLIDATED STATEMENT OF CASH FLOWS for the year ended 31 December 2021 Cash flows from operating activities Profit/(loss) after tax for the period Adjustments for: Non-cash items Depreciation and amortisation Depreciation of lease assets Change in fair value of derivative financial instruments Net finance costs Tax expense/(benefit) Exploration and evaluation written off Impairment losses Impairment reversals Restoration Onerous contracts provision Other Changes in assets and liabilities (Increase)/decrease in trade and other receivables (Increase)/decrease in inventories Increase in lease assets (Decrease)/increase in provisions (Decrease)/increase in lease liabilities Increase in other assets and liabilities Increase/(decrease) in trade and other payables Cash generated from operations Purchases of shares and payments relating to employee share plans Interest received Dividends received Borrowing costs relating to operating activities Income tax paid Payments for restoration Net cash from operating activities Cash flows used in investing activities Payments for capital and exploration expenditure Borrowing costs relating to investing activities Advances to other external entities Proceeds from disposal of non-current assets Payments for acquisition of joint arrangements Net cash used in investing activities Cash flows used in financing activities Proceeds from borrowings Repayment of borrowings Borrowing costs relating to financing activities Repayment of lease liabilities Borrowing costs relating to lease liabilities Contributions to non-controlling interests Dividends paid (net of DRP) Net proceeds from share issuance Net cash used in financing activities Net decrease in cash held Cash and cash equivalents at the beginning of the period Effects of exchange rate changes Cash and cash equivalents at the end of the period The accompanying notes form part of the Financial Statements. 98 Annual Report 2021 Notes 2021 US$m 2020 US$m 2,036 (3,975) 1,582 108 31 203 1,254 265 10 (1,058) 68 (95) 30 (39) (4) (16) (75) (25) (128) 75 4,222 (47) 11 6 (91) (271) (38) 3,792 1,730 94 31 269 (1,465) 2 5,269 - 28 347 (12) 41 51 - 155 40 (137) (121) 2,347 (32) 64 4 (180) (331) (23) 1,849 (2,406) (1,418) (126) (206) 9 (212) (57) (110) - (527) (2,941) (2,112) - (784) (15) (155) (89) (92) (289) - (1,424) (573) 3,604 (6) 3,025 600 (83) (21) (71) (86) (111) (454) 23 (203) (466) 4,058 12 3,604 B.2 B.4 B.4 B.5 C.2 C.2 C.1 CONSOLIDATED STATEMENT OF CHANGES IN EQUITY for the year ended 31 December 2021 d i a p y l l u f d n a d e u s s I s e r a h s s n a l p e r a h s e e y o p m e l r o f d e v r e s e r s e r a h S s t fi e n e b e e y o p m E l e v r e s e r e v r e s e r n o i t a l s n a r t y c n e r r u c n g i e r o F s t fi o r p e l b a t u b i r t s i D e v r e s e r e v r e s e r g n g d e H i e h t l f o s r e d o h y t i u q E t n e r a p i s g n n r a e d e n i a t e R C.3 US$m C.3 US$m C.4 US$m C.4 US$m C.4 US$m C.4 US$m US$m US$m 9,297 - - - 112 - - - - 9,409 9,010 - - - - 264 23 - - - - 9,297 (23) - - - - (47) 40 - - (30) (39) - - - - - - (32) 48 - - (23) 219 - 13 13 - - (40) 40 - 232 211 - - 2 2 - - - (48) 54 - 219 793 - - - - - - - - 793 793 - - - - - - - - - - 793 (71) - (329) (329) - - - - - (400) (12) - - (59) (59) - - - - - - (71) 462 - - - - - - - (404) 58 - 710 - - - - - - - - (248) 462 1,398 1,983 - 1,983 - - - - - 3,381 6,654 (710) (4,028) - (4,028) - - - - - (518) 1,398 12,075 1,983 (316) 1,667 112 (47) - 40 (404) 13,443 16,617 - (4,028) (57) (4,085) 264 23 (32) - 54 (766) 12,075 g n i l l o r t n o c - n o N t s e r e t n i E.8 US$m 800 53 - 53 - - - - (67) 786 792 - 53 - 53 - - - - - (45) 800 y t i u q e l a t o T US$m 12,875 2,036 (316) 1,720 112 (47) - 40 (471) 14,229 17,409 - (3,975) (57) (4,032) 264 23 (32) - 54 (811) 12,875 Notes At 1 January 2021 Profit for the period Other comprehensive income/(loss) Total comprehensive income/(loss) for the period Dividend Reinvestment Plan Employee share plan purchases Employee share plan redemptions Share-based payments (net of tax) Dividends paid At 31 December 2021 At 1 January 2020 Transfers Profit/(loss) for the period Other comprehensive income/(loss) Total comprehensive income/(loss) for the period Dividend Reinvestment Plan Shares issued Employee share plan purchases Employee share plan redemptions Share-based payments (net of tax) Dividends paid At 31 December 2020 The accompanying notes form part of the Financial Statements. Woodside Petroleum Ltd 99 NOTES TO THE FINANCIAL STATEMENTS for the year ended 31 December 2021 About these statements Woodside Petroleum 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. 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 17 February 2022. Statement of compliance The financial statements are general purpose financial statements, which have been prepared in accordance with the requirements of the Corporations Act 2001, Australian Accounting Standards (AASBs) and other authoritative pronouncements of the Australian Accounting Standards Board. The financial statements comply with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board. The accounting policies are consistent with those disclosed in the 2020 Financial Statements, except for the impact of all new or amended standards and interpretations adopted with effect from 1 January 2021. The adoption of these standards and interpretations did not result in any significant changes to the Group’s accounting policies, with the exception of AASB 2020-8 Amendments to Australian Accounting Standards - Interest Rate Benchmark Reform (refer to Note E.9(c)). Estimates and judgements reflect current market conditions, including the impact of COVID-19. Estimates used for impairment assessments and the measurement of onerous contracts are disclosed in Notes B.4 and D.5 respectively. Given ongoing economic uncertainty, these assumptions could change in the future. Currency The functional and presentation currency of Woodside Petroleum Ltd and all its 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 amounts contained in these financial statements have been rounded to the nearest million dollars under the option available to the Group under Australian Securities and Investments Commission (ASIC) Corporations (Rounding in Financial/Directors’ Reports) Instrument 2016/191 dated 24 March 2016, unless otherwise stated. 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, 100 Annual Report 2021 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 results of the Group as at 31 December each year (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 subsidiaries of the Group have the same reporting period and accounting policies as the parent company. 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 period. Where required, a reclassification of items in the financial statements of the previous period has been made in accordance with the classification of items in the financial statements of the current period. 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 only when necessary to ensure that these objectives are achieved. Other circumstances that may lead to hedging activities include the management of exposures relating to trading activities and the underpinning of the economics of a new project. It is, and has been throughout the period, the Group Treasury policy that no speculative trading in financial instruments shall be undertaken. Refer to the Risk section of Corporate on pages 51-54 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 Section A Section C Section C Section C Section D Commodity price risk Foreign exchange risk Capital risk Liquidity risk Interest rate risk Credit risk Page 102 Page 102 Page 122 Page 122 Page 122 Page 126 NOTES TO THE FINANCIAL STATEMENTS for the year ended 31 December 2021 Key estimates and judgements In applying the Group’s accounting policies, management continually 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 Note A.5 Note B.2 Note B.3 Note B.4 Note B.5 Note D.5 Note D.6 Note D.7 Note E.6 Revenue from contracts with customers Taxes Exploration and evaluation Oil and gas properties Impairment of exploration and evaluation and oil and gas properties Significant production and growth assets Provisions Other financial assets and liabilities Leases Joint arrangements Page 103 Page 108 Page 112 Page 114 Page 117 Page 120 Page 129 Page 131 Page 133 Page 137 Woodside Petroleum Ltd 101 NOTES TO THE FINANCIAL STATEMENTS A. EARNINGS FOR THE YEAR for the year ended 31 December 2021 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. A.1 A.2 A.3 A.4 A.5 Earnings for the year Segment revenue and expenses Finance costs Dividends paid and proposed Earnings/(losses) per share Taxes Page 103 Page 106 Page 106 Page 106 Page 107 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 swap derivatives to hedge its exposure (refer to Note D.6). The hedged exposure includes LNG revenue related to produced volumes and revenues derived from trading operations. Commodity swap derivatives protect the Group against downside risk within its strategic and trading portfolio. As at the reporting date, the Group held hedging financial instruments with a net liability carrying value of $431 million (2020: $9 million) exposed to commodity price risk. An increase in relevant commodity prices of 10% would decrease the instruments’ carrying value by $255 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. The 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). As at the reporting date, the Group held hedging financial instruments with a net asset carrying value of $10 million (2020: nil) 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% (2020: +12%/-12%)), with all other variables held constant, would not have a material impact on the Group’s equity or the profit or loss in the current period. 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 2021. In order to hedge the foreign exchange risk and interest rate risk (refer to Section C) of a Swiss Franc (CHF) denominated medium term note, Woodside holds a number of cross-currency interest rate swaps (refer to Note C.2 and D.6). The aim of this hedge is to convert the fixed interest CHF bond into variable interest US dollar debt. The Group also 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 expected to be incurred under the Scarborough development (refer to Note D.6). 102 Annual Report 2021 NOTES TO THE FINANCIAL STATEMENTS A. EARNINGS FOR THE YEAR for the year ended 31 December 2021 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 executive management team in assessing performance and in determining the allocation of resources. The Group has reviewed its operating segments and has identified the Sangomar and Scarborough Development as separate operating segments within Development due to the progress and materiality of the related projects. The 2020 amounts have been restated to reflect this change. Management monitors the performance of the operating results of the segments separately for the purpose of making decisions about resource allocation and performance assessment. The performance of operating segments is evaluated based on profit before tax and net finance costs and is measured in accordance with the Group’s accounting policies. Financing requirements, including cash and debt balances, finance income, finance costs and taxes are managed at a Group level. Operating segments outlined below are identified by management based on the nature and geographical location of the business or venture. Producing North West Shelf Project – Exploration, evaluation, development, production and sale of liquefied natural gas, pipeline natural gas, condensate and liquefied petroleum gas in assigned permit areas. Pluto LNG – Exploration, evaluation, development, production and sale of liquefied natural gas, pipeline natural gas and condensate in assigned permit areas. Australia Oil – Exploration, evaluation, development, production and sale of crude oil in assigned permit areas (North West Shelf, Greater Enfield and Vincent). Wheatstone – Exploration, evaluation, development, production and sale of liquefied natural gas, pipeline natural gas and condensate in assigned permit areas. Development Scarborough – Exploration, evaluation and development of liquified natural gas, pipeline natural gas and condensate in assigned permit areas. Sangomar – Exploration, evaluation and development of crude oil in assigned permit areas. Other development segments – This segment comprises exploration, evaluation and development of liquefied natural gas, pipeline natural gas and condensate in the Browse, Kitimat and Sunrise projects. Other Other segments – This segment comprises trading and shipping activities and activities undertaken in other international locations. Unallocated items – Unallocated 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. Major customer information The Group has two major customers which respectively account for 8% and 6% of the Group’s external revenue. The sales are generated by the Pluto, North West Shelf and Wheatstone operating segments (2020: two major customers; 15% and 13% generated by Pluto and North West Shelf). Geographic information Revenue from external customers1 Non-current assets2 Oceania Asia Canada Africa Other 2021 US$m 313 6,029 - - 620 2020 US$m 286 3,076 - - 238 2021 US$m 18,386 - - 2,802 1 2020 US$m 17,559 229 34 1,244 1 19,067 Consolidated 1. Revenue is attributable to geographic region based on the location of the customer. 2. Non-current assets exclude deferred tax of $1,007 million (2020: $1,304 million). 21,189 3,600 6,962 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 constrained until it is highly probable a significant revenue reversal in the amount of cumulative revenue recognised 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, which is typically on delivery. 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 under existing regimes 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. Key estimates and judgements Revenue from contracts with customers Judgement is required to determine the point at which the customer obtains control of hydrocarbons. Factors including transfer of legal title, transfer of significant risks and rewards of ownership and the existence of a present right to payment for the hydrocarbons typically result in control transferring on delivery of hydrocarbons at port of loading or port of discharge. 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 probable that a significant reversal will occur in relation to revenue recognised during open pricing periods in LNG contracts. The Group estimates variable consideration based on reasonably available information from contract negotiations and market indicators. Progress of performance obligations for LNG processing services revenue recognised over time is measured using the output method which most accurately measures the progress towards satisfaction of the performance obligation of the services provided. Woodside Petroleum Ltd 103 NOTES TO THE FINANCIAL STATEMENTS A. EARNINGS FOR THE YEAR for the year ended 31 December 2021 A.1 Segment revenue and expenses (cont.) Producing Development Other t s e W h t r o N f l e h S 2021 US$m 1,209 8 253 - 60 1,530 - - - 1,530 (116) (200) (7) - (323) (3) (9) (183) (3) (198) (45) - - - - (45) o t u P l 2021 US$m 2,415 19 215 - - 2,649 143 2 145 2,794 (192) (9) (19) 1 (219) (28) (27) (827) - (882) (70) (138) - (11) - (219) (566) (1,320) 964 1,474 17 (2) - - (2) (1) - (1) 15 (10) 3 1 - 376 75 (2) - - (2) (2) - (27) - (3) (32) (34) - 682 l i O a i l a r t s u A 2021 US$m - - - 673 - 673 - - - 673 (109) (7) (4) 8 (112) - (21) (199) - (220) - - - - - - (332) 341 5 (1) - - (1) - - - (95) (6) (101) (102) - - e n o t s t a e h W 2021 US$m 581 16 175 - - 772 - - - 772 (72) (2) (2) 8 (68) (20) (22) (207) - (249) (42) - (6) - - (48) (365) 407 (1) (1) - - (1) (1) - - - (38) (39) (40) (10) - h g u o r o b r a c S 2021 US$m - - - - - - - - - r a m o g n a S 2021 US$m - - - - - - - - - s t n e m p o l e v e d r e h t O 2021 US$m - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - (3) - - (3) 5 - - - - 5 2 - - - - - - - - - - - - - - - - - - - - - (1) (2) - - (2) (1) - - 12 (32) (21) (23) - - s t n e m g e s r e h t O 2021 US$m 1,154 - - - - 1,154 - 39 39 1,193 - - - - - - - - - - (53) (1,357) - (1) 140 (1,271) (1,271) (78) - (43) (3) (265) (311) (5) - (47) - - (52) (363) - - d e t a c o l l a n U s m e t i 2021 US$m - - - - - - - - - - 8 - 1 - 9 - - - - - - - - - - - 9 9 44 - - - - (153) (30) (33) - (36) (252) (252) - - Liquefied natural gas Domestic gas Condensate Oil Liquefied petroleum gas Revenue from sale of hydrocarbons Processing and services revenue Shipping and other revenue Other revenue Operating revenue1 Production costs Royalties, excise and levies Insurance Inventory movement Costs of production Land and buildings Transferred exploration and evaluation Plant and equipment Marine vessels and carriers Oil and gas properties depreciation and amortisation Shipping and direct sales costs2 Trading costs3 Other hydrocarbon costs Other cost of sales Movement in onerous contract provision4 Other cost of sales Cost of sales Gross profit Other income5 Exploration and evaluation expenditure Amortisation Write-offs6 Exploration and evaluation General, administrative and other costs Depreciation of other plant and equipment Depreciation of lease assets Restoration movement Other7 Other costs Other expenses Impairment losses Impairment reversals8 Profit/(loss) before tax and net finance costs 1. Operating revenue includes revenue from contracts with customers of $6,923 million and sub-lease income of $39 million disclosed within shipping and other revenue. 2. Includes repurchase and cancellation costs to optimise Group operating revenues. 3. Trading costs within Other segments relate to purchase costs of non-produced volumes (including Corpus Christi) and other volumes purchased to optimise produced 2,197 1,358 (199) (441) 244 356 (24) 2 - d e t a d i l o s n o C 2021 US$m 5,359 43 643 673 60 6,778 143 41 184 6,962 (481) (218) (31) 17 (713) (51) (79) (1,416) (3) (1,549) (210) (1,495) (6) (12) 140 (1,583) (3,845) 3,117 139 (54) (3) (265) (322) (158) (30) (108) (68) (125) (489) (811) (10) 1,058 3,493 LNG revenue. 4. Comprises provisions used of $45 million and changes in estimates of $95 million. Refer to Note D.5 for more details. 5. Includes other income of $67 million relating to Pluto volumes delivered into Wheatstone's sales commitments and net foreign exchange gains of $44 million. 6. $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. Refer to Note B.2. 7. Includes net loss on hedging activities of $91 million and other expenses not associated with the ongoing operations of the business. The Other developments segment also includes $33 million for various costs relating to Woodside's exit from the Kitimat LNG development. 8. Impairment reversals on oil and gas properties. Refer to Note B.4 for more details. 104 Annual Report 2021 NOTES TO THE FINANCIAL STATEMENTS A. EARNINGS FOR THE YEAR for the year ended 31 December 2021 A.1 Segment revenue and expenses (cont.) Producing Development Other t s e W h t r o N f l e h S 2020 US$m 722 44 194 - 16 976 - - - 976 (118) (79) (7) (1) (205) (4) (13) (228) (2) (247) (49) (8) - - - (57) o t u P l 2020 US$m 1,320 11 114 - - 1,445 142 - 142 1,587 (189) - (19) (7) (215) (27) (32) (823) - (882) (53) (49) - - - (102) (509) (1,199) 467 388 12 (3) - - (3) (1) - - (5) (15) (21) (24) (6) (1) - - (1) (1) - (26) - 12 (15) (16) l i O a i l a r t s u A 2020 US$m - - - 432 - 432 - - - 432 (107) (3) (3) (21) (134) - (32) (251) - (283) - - - - - - (417) 15 - (1) - - (1) (1) - - (62) (12) (75) (76) e n o t s t a e h W 2020 US$m 365 18 103 - - 486 - - - 486 (72) - (3) (3) (78) (24) (22) (231) - (277) (44) (10) (4) - - (58) (413) 73 1 (3) - - (3) (1) - - - 8 7 4 (454) (1,291) (674) (1,401) - - - - Liquefied natural gas1 Domestic gas Condensate Oil Liquefied petroleum gas Revenue from sale of hydrocarbons Processing and services revenue Shipping and other revenue Other revenue Operating revenue Production costs Royalties, excise and levies Insurance Inventory movement Costs of production Land and buildings Transferred exploration and evaluation Plant and equipment Marine vessels and carriers Oil and gas properties depreciation and amortisation Shipping and direct sales costs Trading costs Other hydrocarbon costs Other cost of sales Movement in onerous contract provision2 Other cost of sales Cost of sales Gross profit Other income 3 Exploration and evaluation expenditure Amortisation Write-offs Exploration and evaluation General, administrative and other costs Depreciation of other plant and equipment Depreciation of lease assets Restoration movement Other3 Other costs Other expenses Impairment losses4 Impairment reversals h g u o r o b r a c S 20205 US$m - - - - - - - - - r a m o g n a S 20205 US$m - - - - - - - - - s t n e m p o l e v e d r e h t O 20205 US$m - - - - - - - - - - - - - - - - - - - - - - - - - - - - - (2) - - (2) 2 - - - - 2 - - - - - - - - - - - - - - - - - - - - - (1) - - (1) (13) - - 39 (1) 25 24 - - - - - - - - - - - - - - - - - - - (3) - - - - (3) - - - - (3) (3) - - s t n e m g e s r e h t O 2020 US$m 112 - - - - 112 - 7 7 119 - - - - - - - - - - 35 (144) - - (347) (456) (456) (337) (42) (56) (12) (2) (70) (6) - (34) - 42 2 (68) d e t a c o l l a n U s m e t i 2020 US$m - - - - - - - - - - 8 - 1 - 9 - - - - - - - - - - - 9 9 2 - - - - (166) (29) (34) - (93) (322) (322) d e t a d i l o s n o C 2020 US$m 2,519 73 411 432 16 3,451 142 7 149 3,600 (478) (82) (31) (32) (623) (55) (99) (1,533) (2) (1,689) (111) (211) (4) - (347) (673) (2,985) 615 (36) (67) (12) (2) (81) (190) (29) (94) (28) (59) (400) (481) (321) (977) (151) - - - - - (5,269) - (5,171) Profit/(loss) before tax and net finance costs 1. Includes an adjustment of $113 million related to price reviews currently under negotiation for multiple contracts across North West Shelf and Pluto, reducing revenue recognised (1,323) (311) (925) (321) (953) (598) (735) (6) 1 in the current and prior periods and increasing other liabilities. 2. Comprised of the recognition of an onerous contract provision $447 million, offset by changes in estimates of $54 million, provisions used of $41 million and a revision of discount rates of $5 million. Refer to Note D.5 for more details. 3. Includes foreign exchange gains and losses, gains and losses on hedging activities, cancellation costs and other expenses not associated with the ongoing operations of the business. 4. The impairment losses represent charges on exploration and evaluation of $1,557 million and oil and gas properties of $3,712 million. 5. The 2020 amounts have been restated to reflect the changes in the Development segment. Woodside Petroleum Ltd 105 NOTES TO THE FINANCIAL STATEMENTS A. EARNINGS FOR THE YEAR for the year ended 31 December 2021 A.2 Finance costs A.4 Earnings/(losses) per share Interest on interest-bearing liabilities Interest on lease liabilities Accretion charge Other finance costs Less: Finance costs capitalised against qualifying assets 2021 US$m 2020 US$m 201 97 29 26 (123) 230 237 86 32 29 (57) 327 A.3 Dividends paid and proposed Woodside Petroleum Ltd, the parent entity, paid and proposed dividends set out below: (a) Dividends paid during the financial year Prior year fully franked final dividend US$0.12, paid on 24 March 2021 (2020: US$0.55, paid on 20 March 2020) Current year fully franked interim dividend US$0.30, paid on 24 September 2021 (2020: US$0.26, paid on 18 September 2020) (b) Dividend declared subsequent to the reporting period (not recorded as a liability) Final dividend US$1.05 (2020: US$0.12) (c) Other information Franking credits available for subsequent periods Current year dividends per share (US cents) 2021 US$m 2020 US$m 115 518 289 404 248 766 1,018 115 1,744 135 1,823 38 The Dividend Reinvestment Plan (DRP) was approved by the shareholders at the Annual General Meeting in 2003 for activation as required to fund future growth. The DRP was reactivated for the 2019 interim dividend and remains in place until further notice. Profit/(loss) attributable to equity holders of the parent (US$m) Weighted average number of shares on issue for basic earnings/(loss) per share Effect of dilution from contingently issuable shares Weighted average number of shares on issue adjusted for the effect of dilution1 Basic earnings/(losses) per share (US cents) 2021 2020 1,983 (4,028) 962,604,811 951,113,086 - 9,023,439 971,628,250 951,113,086 (423.5) 206.0 Diluted earnings/(losses) per share (US cents) 1. The contingently issuable shares in 2020 have an anti-dilutive impact. 204.1 (423.5) Earnings/(losses) per share is calculated by dividing the profit/(loss) 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 2021, 9,023,439 awards granted under the Woodside employee share plans are considered dilutive. Total outstanding share awards as at 31 December 2020 were 9,392,203 and considered anti-dilutive due to the loss position in 2020. On 22 November 2021, Woodside and BHP Group (BHP) signed a binding share sale agreement to combine their respective oil and gas portfolios by an all stock merger (the Transaction). On completion of the Transaction, BHP's oil and gas business would merge with Woodside, and Woodside would issue new shares to be distributed to BHP shareholders. The expanded Woodside would be owned 52% by existing Woodside shareholders and 48% by existing BHP shareholders. This Transaction is not considered dilutive for the current period. There have been no significant transactions involving ordinary shares between the reporting date and the date of completion of these financial statements. 106 Annual Report 2021 NOTES TO THE FINANCIAL STATEMENTS A. EARNINGS FOR THE YEAR for the year ended 31 December 2021 A.5 Taxes (a) Tax expense comprises Petroleum resource rent tax (PRRT) Deferred tax expense/(benefit) PRRT expense/(benefit) Income tax Current year Current tax expense Deferred tax expense/(benefit) Adjustment to prior years Current tax (benefit)/expense Deferred tax expense/(benefit) Income tax expense/(benefit) Tax expense/(benefit) (b) Reconciliation of income tax expense Profit/(loss) before tax PRRT (expense)/benefit Profit/(loss) before income tax Income tax expense/(benefit) calculated at 30% Foreign income tax expense/(benefit) Non-deductible items Foreign expenditure not brought to account Adjustment to prior years Foreign exchange impact on tax (benefit)/ expense Income tax expense/(benefit) (c) Reconciliation of PRRT benefit Profit/(loss) before tax Non-PRRT assessable (profit)/loss PRRT projects profit/(loss) before tax1 PRRT expense/(benefit) calculated at 40%2 Augmentation Derecognition of Pluto general expenditure1 Other PRRT expense/(benefit) (d) Deferred tax income statement reconciliation PRRT Production and growth assets Augmentation for current year Provisions Other PRRT expense/(benefit) Income tax Oil and gas properties Exploration and evaluation assets Provisions PRRT liabilities Lease assets and liabilities Unused tax losses and tax credits Non-current assets held for sale Other Income tax deferred tax expense/(benefit) Deferred tax expense/(benefit) (e) Deferred tax balance sheet reconciliation Deferred tax assets PRRT Production and growth assets Augmentation for current year Provisions Other 2021 US$m 2020 US$m 2021 US$m 2020 US$m 297 297 658 301 (20) 18 957 1,254 3,290 (297) 2,993 898 23 7 49 (2) (18) 957 3,290 (2,134) 1,156 462 (166) - 1 297 455 (166) (29) 37 297 674 (204) (10) (88) 1 149 (205) 2 319 616 767 166 75 (1) 1,007 (439) (439) 275 (1,308) 16 (9) (1,026) (1,465) (5,440) 439 (5,001) (1,500) (11) 2 473 7 3 (1,026) (5,440) 3,080 (2,360) (944) (138) 627 16 (439) (242) (138) (32) (27) (439) (981) (210) (106) 134 (16) (149) - 11 (1,317) (1,756) 1,098 124 46 36 1,304 (e) Deferred tax balance sheet reconciliation (cont.) Deferred tax liabilities PRRT Production and growth assets Augmentation for current year Provisions Other Income tax Oil and gas properties Exploration and evaluation assets Lease assets and liabilities Provisions PRRT liabilities Unused tax losses and tax credits Non-current assets held for sale Other3 (f) Tax payable reconciliation Income tax payable (g) Effective income tax rate: Australian and global operations Effective income tax rate4 Australia Global (h) Current income tax expense reconciliation Profit/(loss) before income tax Income tax expense/(benefit) at the statutory tax rate of 30% Foreign income tax expense/(benefit) Non-temporary differences5,6 Temporary differences: deferred tax6 Foreign exchange impact on tax (benefit)/ expense - - - - 1,520 51 (38) (706) 303 - (205) (47) 878 413 413 224 (14) (214) 4 846 255 (39) (696) 391 (149) - (59) 549 46 46 30.6% 32.0% 29.6% 20.5% 2,993 (5,001) 898 23 56 (301) (18) (1,500) (11) 475 1,308 3 275 Current income tax expense 1. The net $348 million reduction of the Pluto PRRT deferred tax asset in 2020 658 includes derecognition of general expenditure of $627 million (based on expected future utilisation) offset by a reduction in the Pluto asset accounting base of $279 million (included within 'PRRT projects profit/(loss) before tax'). 2. Includes a $226 million PRRT expense as a result of the 2021 Pluto-Scarborough impairment reversal increasing the asset accounting base and thereby reducing the deferred tax asset. 3. Includes $10 million tax expense recognised in other comprehensive income (2020: $19 million benefit). 4. 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. 5. Primarily expenditure in respect of foreign operations, including the impairment of foreign assets and onerous contract provision. 6. Excludes adjustment to prior years. Woodside Petroleum Ltd 107 NOTES TO THE FINANCIAL STATEMENTS A. EARNINGS FOR THE YEAR for the year ended 31 December 2021 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 Australian tax losses: A deferred tax asset (DTA) of nil (2020: $149 million) has been recognised for carry forward unused tax losses and credits. The 2020 DTA was fully utilised in 2021. Foreign tax losses: Deferred tax assets of $497 million (2020: $477 million) relating to unused foreign tax losses have not been recognised on the basis that it is not probable that the assets will be utilised based on current planned activities in those regions. PRRT: The recoverability of PRRT deferred tax assets is primarily assessed with regard to future oil price assumptions. As a result of the Pluto impairment reversal (as disclosed in Note B.4) increasing the Pluto PRRT accounting base, the Pluto PRRT DTA has been reduced by $226 million. The Pluto PRRT DTA of $785 million continues to be recognised on the basis that it is probable that future taxable profits will be available to utilise the deductible expenditure. 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 1.5% (31 December 2020: 1.0%) was used for the purposes of augmentation. All other deferred PRRT and income tax movements are a result of the effective income tax rates applicable to each Australian or foreign jurisdiction. Certain deferred tax assets on deductible temporary differences have not been recognised on the basis that deductions from future augmentation of the deductible temporary difference will be sufficient to offset future taxable profit. $4,507 million (2020: $4,167 million) relates to the North West Shelf Project, $1,432 million (2020: $1,345 million) relates to the quarantined exploration spend and unrecognised general spend of Pluto LNG and $1,071 million (2020: $1,049 million) relates to Wheatstone. A long-term bond rate of 1.5% (31 December 2020: 1.0%) 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, the additional deferred tax assets would be recognised, with a corresponding benefit to income 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 AASB 112 Income Taxes. A.5 Taxes (cont.) 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. Woodside has addressed the recommended disclosures in two parts. The Part A disclosures are addressed within this Taxes note; the Part B disclosures are addressed in our Sustainable Development Report. 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 year and any adjustment to tax payable 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 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. 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 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 group. 108 Annual Report 2021 NOTES TO THE FINANCIAL STATEMENTS B. PRODUCTION AND GROWTH ASSETS for the year ended 31 December 2021 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. B.1 B.2 B.3 B.4 B.5 B.6 Production and growth assets Segment production and growth assets Exploration and evaluation Oil and gas properties Impairment of exploration and evaluation and oil and gas properties Page 110 Page 112 Page 113 Page 115 Significant production and growth asset acquisitions Page 120 Non-current assets held for sale Page 121 Woodside Petroleum Ltd 109 NOTES TO THE FINANCIAL STATEMENTS B. PRODUCTION AND GROWTH ASSETS for the year ended 31 December 2021 B.1 Segment production and growth assets Producing Development Other t s e W h t r o N f l e h S o t u P l l i O a i l a r t s u A e n o t s t a e h W h g u o r o b r a c S s t n e m p o l e v e d r e h t O r a m o g n a S d e t a d i l o s n o C r e h t O 2021 US$m 2021 US$m 2021 US$m 2021 US$m 2021 US$m 2021 US$m 2021 US$m 2021 US$m 2021 US$m 9 - - - - 9 16 65 1,757 8 226 2,072 11 - 1 12 - - - - 119 2 (12) 109 - - - - - - - - - - 321 234 7,651 - 403 8,609 52 - 132 184 - - - - 268 20 4 292 - - - - 13 - - - - 13 - 69 585 - 10 664 - - - - - - - - 13 - (13) - - - - - 4 - - - - 4 401 158 2,315 - 27 2,901 3 - - 3 1 - - 1 112 15 39 166 - - - - 43 - - - - 43 - - - - 1,980 1,980 10 - - 10 - 446 - 446 559 9 - 568 - - - - - - - 58 - 58 - - - - 2,195 2,195 11 167 9 187 7 - - 7 1,049 77 14 1,140 14 205 9 228 477 - - - - 477 - - - - - - - - - - - 5 6 11 - - - - - - - - - - - 10 - 10 1 - 5 - 7 546 - - 68 - 614 739 526 12,313 8 4,848 13 18,434 290 - 394 684 34 2 - 36 6 - - 6 - - - - 377 167 536 1,080 42 453 6 501 2,126 123 32 2,281 14 205 9 228 Balance as at 31 December Oceania Asia Canada Africa Other Total exploration and evaluation Balance as at 31 December Land and buildings Transferred exploration and evaluation Plant and equipment Marine vessels and carriers Projects in development Total oil and gas properties Balance as at 31 December Land and buildings Plant and equipment Marine vessels and carriers Total lease assets Additions to exploration and evaluation: Exploration Evaluation Restoration Additions to oil and gas properties: Oil and gas properties Capitalised borrowings costs1 Restoration Additions to lease assets: Land and buildings Plant and equipment Marine vessels and carriers 1. Borrowing costs capitalised were at a weighted average interest rate of 3.6%. Refer to Note A.1 for descriptions of the Group’s segments and geographical regions. 110 Annual Report 2021 NOTES TO THE FINANCIAL STATEMENTS B. PRODUCTION AND GROWTH ASSETS for the year ended 31 December 2021 B.1 Segment production and growth assets (cont.) Producing Development Other t s e W h t r o N f l e h S o t u P l l i O a i l a r t s u A e n o t s t a e h W h g u o r o b r a c S s t n e m p o l e v e d r e h t O r a m o g n a S d e t a d i l o s n o C r e h t O 2020 US$m 2020 US$m 2020 US$m 2020 US$m 20202 US$m 20202 US$m 20202 US$m 2020 US$m 2020 US$m Balance as at 31 December Oceania Asia Canada Africa Other Total exploration and evaluation Balance as at 31 December Land and buildings Transferred exploration and evaluation Plant and equipment Marine vessels and carriers Projects in development Total oil and gas properties Balance as at 31 December Land and buildings Plant and equipment Marine vessels and carriers Total lease assets Additions to exploration and evaluation: Exploration Evaluation Restoration Additions to oil and gas properties: Oil and gas properties Capitalised borrowings costs1 Restoration 9 - - - - 9 9 61 1,574 11 131 1,786 12 - 1 13 - - - - 68 1 34 103 - - - - - - 307 167 7,498 - 549 8,521 22 - 156 178 - - - - 322 17 68 407 13 - - - - 13 - 90 784 - 10 884 - - - - - - - - 432 113 2,074 - 395 3,014 3 - - 3 1 - - 1 93 2 42 137 287 10 43 340 3 - - - - 3 1,261 - - - - 1,261 - - - - - - 4 - - 4 - 255 - 255 - - - - Additions to lease assets: Land and buildings Plant and equipment Marine vessels and carriers 6 - - 6 1. Borrowing costs capitalised were at a weighted average interest rate of 3.8%. 2. The 2020 amounts have been restated to reflect the changes in the Development segment. Refer to Note A.1 for details. 12 - 1 13 3 - - 3 - - - - - - - - - - - 51 - 51 - - - - - - 1 - - 1 26 - - 26 767 27 - 794 - - - - 466 - - - - 466 - - - - 1,055 1,055 33 - - 33 - 39 44 83 - - - - 1 - - 1 - 229 - 13 - 242 1 - 3 - 3 7 317 - 435 752 18 16 - 34 2 - - 2 2 - 101 103 1,752 229 - 64 - 2,045 749 431 11,933 11 2,143 15,267 392 - 592 984 45 310 44 399 1,539 57 187 1,783 24 - 102 126 Woodside Petroleum Ltd 111 NOTES TO THE FINANCIAL STATEMENTS B. PRODUCTION AND GROWTH ASSETS for the year ended 31 December 2021 B.2 Exploration and evaluation Year ended 31 December 2021 Carrying amount at 1 January 2021 Additions Amortisation of licence acquisition costs Expensed1 Transferred exploration and evaluation Carrying amount at 31 December 2021 Year ended 31 December 2020 Carrying amount at 1 January 2020 Additions Amortisation of licence acquisition costs Expensed1 Impairment losses2 Transferred exploration and evaluation Carrying amount at 31 December 2020 Exploration commitments Oceania US$m Asia US$m Canada US$m Africa US$m Other US$m 1,752 458 - - (1,664) 546 2,243 272 (5) - (748) (10) 1,752 229 36 - (265) - - 199 34 (4) - - - 229 - - - - - - 742 67 - - (809) - - 64 7 (3) - - 68 623 26 (3) - - (582) 64 - - - - - - 2 - - (2) - - - Total US$m 2,045 501 (3) (265) (1,664) 614 3,809 399 (12) (2) (1,557) (592) 2,045 94 Year ended 31 December 2021 Year ended 31 December 2020 115 1. $56 million (2020: $2 million) relates to costs of unsuccessful wells. $209 million (2020: nil) relates to capitalised costs written off due to the Group's decision to withdraw from 8 55 77 46 8 11 1 3 - - its interests in Myanmar. 2. Refer to Note B.4 for details on impairment. Recognition and measurement Expenditure on exploration and evaluation is accounted for in accordance with the area of interest method. The Group’s application of the accounting policy is closely aligned to the US GAAP-based successful efforts 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 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. 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. 112 Annual Report 2021 NOTES TO THE FINANCIAL STATEMENTS B. PRODUCTION AND GROWTH ASSETS for the year ended 31 December 2021 B.3 Oil and gas properties Year ended 31 December 2021 Carrying amount at 1 January 2021 Additions Disposals at written down value Depreciation and amortisation Impairment losses1 Impairment reversals1 Completions and transfers Transfer to non-current assets held for sale2 Carrying amount at 31 December 2021 At 31 December 2021 Historical cost Accumulated depreciation and impairment Net carrying amount Year ended 31 December 2020 Carrying amount at 1 January 2020 Additions Disposals at written down value Depreciation and amortisation Impairment losses1 Completions and transfers Carrying amount at 31 December 2020 At 31 December 2020 Historical cost Accumulated depreciation and impairment Land and buildings US$m Transferred exploration and evaluation US$m Plant and equipment US$m Marine vessels and carriers US$m Projects in development US$m 749 - (2) (51) (10) 44 11 (2) 739 1,701 (962) 739 1,068 - - (55) (264) - 749 1,722 (973) 431 - - (79) - 66 108 - 526 1,495 (969) 526 729 - - (99) (199) - 431 1,348 (917) 431 11,933 13 (2) (1,416) - 911 874 - 12,313 32,241 (19,928) 12,313 15,813 150 (3) (1,533) (2,636) 142 11,933 31,225 (19,292) 11,933 11 - - (3) - - - - 8 184 (176) 8 36 - - (2) (23) - 11 184 (173) 11 2,143 2,268 (19) - - 37 671 (252) 4,848 5,250 (402) 4,848 652 1,633 (2) - (590) 450 2,143 2,791 (648) 2,143 Total US$m 15,267 2,281 (23) (1,549) (10) 1,058 1,664 (254) 18,434 40,871 (22,437) 18,434 18,298 1,783 (5) (1,689) (3,712) 592 15,267 37,270 (22,003) 15,267 Net carrying amount 1. Refer to Note B.4 for details on impairment losses and impairment reversals. 2. Refer to Note B.6 for details on non-current assets held for sale. 749 Woodside Petroleum Ltd 113 NOTES TO THE FINANCIAL STATEMENTS B. PRODUCTION AND GROWTH ASSETS for the year ended 31 December 2021 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 reserve base applied to each asset. Typically, late life oil assets use proved reserves. 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 proved plus probable (2P) reserves estimates are revised downwards, earnings could be affected by higher depreciation expense or an immediate write-down of the asset’s carrying value. For more information regarding reserve assumptions, refer to the Reserves and resources statement on pages 55-59 of the Annual Report. (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 useful life As a result of FID on the Scarborough Development and Pluto Train 2, the Group conducted a review of the expected utilisation of the Pluto LNG onshore assets. Pluto LNG onshore assets were previously intended for use until the cessation of production from Pluto LNG. A number of Pluto LNG onshore assets are now expected to be utilised in the processing of Scarborough reserves and as a result the expected useful lives of these assets have increased by a range of 1-23 years. The change in useful life has been applied prospectively from the month of FID and has resulted in a decrease in depreciation expense of $60 million for the year ended 31 December 2021. B.3 Oil and gas properties (cont.) 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 and other plant and equipment are depreciated to their estimated residual values at rates based on their expected useful lives. Transferred exploration and evaluation and offshore plant and equipment are depreciated using the unit of production basis over proved plus probable reserves or proved reserves for late life assets. The depreciable amount for the unit of production basis excludes future development costs necessary to bring probable reserves into production. Onshore plant and equipment is 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 – 24-40 years; • Marine vessels and carriers – 10-40 years; • Other plant and equipment – 5-15 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 financials statements, of $7,875 million (2020: $1,569 million) as at 31 December 2021. Subsequent to year end, capital commitments contracted for has reduced by approximately $2,876 million due to the Group’s participating interest in the Pluto Train 2 Joint Venture reducing from 100% to 51% (refer to Note E.5). 114 Annual Report 2021 NOTES TO THE FINANCIAL STATEMENTS B. PRODUCTION AND GROWTH ASSETS for the year ended 31 December 2021 B.4 Impairment of exploration and evaluation and oil and gas properties 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 also assessed for impairment before they are transferred to oil and gas properties. Impairment calculations The recoverable amounts of exploration and evaluation assets are determined using FVLCD as there is no value in use (VIU). Costs to dispose are the incremental costs directly attributable to the disposal of an asset, excluding finance costs and income tax expense. 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 income statement. For assets previously impaired, if the recoverable amount exceeds the carrying amount, the impairment is reversed, but only to the extent that the asset’s carrying amount does not exceed the carrying amount that would have been recognised if no impairment had occurred. Oil and gas properties Impairment testing The carrying amounts of oil and gas properties are assessed half- yearly to determine whether there is an indication of impairment or impairment reversal for those assets which have previously been impaired. Indicators of impairment and impairment reversals include changes in future selling prices, future costs and reserves. Oil and gas properties are assessed for impairment indicators and impairments on a cash-generating unit (CGU) basis. CGUs are determined as an FPSO and associated oil fields for an oil asset, and an LNG plant, offshore infrastructure and associated gas fields for a gas asset. If there is an indicator of impairment or impairment reversal for a CGU then the recoverable amount is calculated. Impairment calculations The recoverable amount of an asset or CGU is determined as the higher of its VIU and FVLCD. VIU is determined by estimating future cash flows after taking into account the risks specific to the asset and discounting to present value using an appropriate discount rate. If the carrying amount of an asset or CGU exceeds its recoverable amount, the asset or CGU is written down and an impairment loss is recognised in the income statement. For assets previously impaired, if the recoverable amount exceeds the carrying amount, the impairment is reversed. The carrying amount of the asset or CGU is increased to the revised estimate of its recoverable amount, but only to the extent that the asset’s carrying amount does not exceed the carrying amount that would have been determined, net of depreciation or amortisation, if no impairment had been recognised. Woodside Petroleum Ltd 115 NOTES TO THE FINANCIAL STATEMENTS B. PRODUCTION AND GROWTH ASSETS for the year ended 31 December 2021 B.4 Impairment of exploration and evaluation and oil and gas properties (cont.) Recognised impairment and impairment reversals As at 31 December 2021, the Group identified the following indicators for impairment and impairment reversals: • Pluto-Scarborough and Wheatstone CGU - a reduction of 2P total reserves within the Greater Pluto and Wheatstone reserves and resources estimates. • Pluto-Scarborough CGU - additional value generated by Scarborough and Pluto Train 2, which have been combined with Pluto into a new Pluto-Scarborough CGU following the final investment decision for Scarborough and Pluto Train 2 in November 2021. • North West Shelf CGU - updated cost and production profiles, including the impact of third-party processing agreements, and short- term pricing assumptions. • NWS Oil (Okha) CGU - the reclassification to a late life oil asset due to natural reservoir decline and short-term pricing assumptions. No impairment was recognised for Wheatstone and NWS Oil (Okha) as the recoverable amount exceeds the carrying amount of the CGU. Impairment reversals were recognised for Pluto-Scarborough and NWS Gas (refer to Note A.1). The results were as follows: Impairment reversal Oil and gas properties Segment CGU Producing and Development Pluto-Scarborough Producing North West Shelf Total Recoverable amount US$m 17,474 2,425 19,899 Land and buildings US$m Transferred exploration and evaluation US$m Plant and equipment US$m Projects in development US$m 42 2 44 53 13 66 563 348 911 24 13 37 Total US$m 682 376 1,058 The recoverable amounts have been determined using the VIU method. The carrying amounts of the CGUs include all assets allocated to the CGU. Refer to key estimates and judgements for further details. Sensitivity analysis Changes in the following key assumptions have been estimated to result in a higher or lower carrying amounts1 than what was determined as at 31 December 2021: Discount rate: increase of 1%3,4 Discount rate: decrease of 1% Brent price: increase of 10% Brent price: decrease of 10% FX: FX: increase of 12%5 decrease of 12% Sensitivity (US$m)2 Oil and gas properties Producing and Development Pluto-Scarborough Producing North West Shelf Wheatstone NWS Oil (Okha) - - (159) (4) - - 178 4 - - 438 39 - (13) (438) (39) - - (122) (28) - - 122 28 1. Increases to carrying amounts are limited to historical impairment losses recognised, net of depreciation and amortisation that would have been incurred had no impairment taken place. 2. The sensitivities represent reasonable possible changes to the discount rate, oil price and FX assumptions. 3. A change of 1% represents 100 basis points. 4. The relationship between the discount rate and carrying amount is non-linear and as such, the 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. 5. FX sensitivity of +12%/-12% was determined based on historical 5-year standard deviation of AU$/US$. Impairment on non-current assets held for sale The pending sale of a portion of the Wheatstone Construction Village resulted in an impairment loss of $10 million as the asset's carrying value exceeded its FVLCD, which was determined based on the underlying sale agreements, classified as Level 3 on the fair value hierarchy. An impairment loss of $10 million was recognised in the Wheatstone operating segment of Note A.1. Refer to Note B.6 for more details. 116 Annual Report 2021 NOTES TO THE FINANCIAL STATEMENTS B. PRODUCTION AND GROWTH ASSETS for the year ended 31 December 2021 B.4 Impairment of exploration and evaluation and oil and gas properties (cont.) Key estimates and judgements CGU determination Identification of a CGU requires management judgement. In determining the new combined Pluto-Scarborough CGU, management has determined that the Scarborough and Pluto Train 2 development concept integrates with the existing Pluto onshore assets and is the smallest group of assets that generate significant cash inflows that are independent from other assets or group of assets. 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 VIU. 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 2021 is set out below: • Resource estimates – 2P reserves for oil and gas properties, except for NWS Oil (Okha) which is based on 1P reserves due to the reclassification to a late life asset. The reserves are as disclosed in the Reserves and resources statement in the 31 December 2021 Annual Report on pages 55-59. • Inflation rate – an inflation rate of 2.0% has been applied. • Foreign exchange rates – a rate of $0.75 US$:AU$ is based on management’s view of long-term exchange rates. • Discount rates – a range of pre-tax discount rates between 8.9% and 11.6% (post-tax discount rate 7.5%-8.5%) for CGUs has been applied. The discount rate reflects an assessment of the risks specific to the asset. • An evaluation of climate risk is reflected in Woodside's assumptions on carbon cost pricing, including a long-term Australian carbon price of US$80/tonne of emissions (real terms 2022). This is applicable to Australian emissions that exceed facility-specific baselines in accordance with Australian regulations, as well as global emissions that exceed voluntary corporate net emissions targets. Woodside continues to monitor the uncertainty around climate change risks and will revise carbon pricing assumptions accordingly. • LNG price – the majority of LNG sales contracts are linked to an oil price marker; accordingly the LNG prices used are consistent with oil price assumptions. • Brent oil prices – derived from long-term views of global supply and demand, building upon past experience of the industry and consistent with external sources. Prices are adjusted for premiums and discounts based on the nature and quality of the product. Brent oil price estimates have considered the risk of climate policies along with other factors such as industry investment and cost trends. There is significant uncertainty around how society will respond to the climate challenge; Woodside’s pricing assumptions reflect a ‘most-likely’ scenario in which global governments pursue decarbonisation as well as other goals such as energy security and economic development. As with carbon pricing, Woodside continues to monitor this uncertainty and will revise its oil pricing assumptions accordingly in its transition to a lower carbon economy. Further information on climate change risk is provided in Woodside’s Climate Report 2021. The nominal Brent oil prices (US$/bbl) used were: 2023 71 31 December 20211 30 June 20202 62 1. Based on US$65/bbl (2022 real terms) from 2024 with prices escalated at 2025 69 72 2022 73 57 2026 70 73 2024 68 67 2027 72 75 2.0% annually thereafter. 2. Based on US$65/bbl (2020 real terms) from 2025 with prices escalated at 2.0% annually thereafter. Woodside Petroleum Ltd 117 NOTES TO THE FINANCIAL STATEMENTS B. PRODUCTION AND GROWTH ASSETS for the year ended 31 December 2021 B.4 Impairment of exploration and evaluation and oil and gas properties (cont.) Recognised impairment and impairment reversals (cont.) For the year ended 31 December 2020 As at 30 June 2020 the Group assessed each AOI and CGU and identified the following indicators of impairment for certain AOIs and all CGUs: • AOIs – uncertainties on fiscal conditions and/or development strategies have led to a lack of substantive ongoing and/or planned activity; and • CGUs – the decrease in global oil and gas prices due to the impacts of the COVID-19 pandemic, oversupply and weakened global demand. Impairment losses before tax were recognised in profit and loss, refer to Note A.1. The results were as follows, which include the AOIs and CGUs which were subject to impairment testing: Impairment losses Oil and gas properties Segment Producing AOI/CGU Pluto (WA-404-P)²,⁴ Development Kitimat LNG⁵ Other segments Producing Sunrise⁶ Toro (WA-93-R)/ Ragnar (WA- 94-R)³,⁷ North West Shelf Pluto Australia Oil Vincent (Ngujima-Yin) NWS Oil (Okha) Wheatstone Development Sangomar Recoverable amount1 US$m Exploration and evaluation US$m Land and buildings US$m Transferred exploration and evaluation US$m Plant and equipment US$m Marine vessels and carriers US$m Projects in development US$m - - - - 1,922 9,712 836 102 3,029 415 429 809 168 151 - - - - - - - - - - 2 54 - - 208 - - - - - 15 59 64 3 58 - - - - - 387 666 517 61 1,005 - - - - - 23 - - - - - - - - - 27 83 26 3 130 321 590 1. The recoverable amounts for exploration and evaluation assets and oil and gas properties were determined using the FVLCD and VIU methods, respectively. 16,016 2,636 1,557 Total 199 264 23 Total US$m - - - - 454 862 607 67 1,401 321 3,712 The carrying amount of the CGUs include all assets allocated to the CGU. Refer to key estimates and judgements for further details. 2. The impairment of Pluto (WA-404-P) has resulted in a reclassification of the Greater Pluto (WA-404-P) Proved (1P) Undeveloped Reserves of 91 MMboe and Proved plus Probable (2P) Undeveloped Reserves of 123 MMboe, to Best Estimate (2C) Contingent Resources. 3. Converted from WA-430-P. Impairment indicators for exploration and evaluation assets: 4. Increased uncertainty of development timing, given the prioritisation of the higher-value Scarborough resource. 5. The revision of long-term oil and Alberta natural gas market spot price assumptions, and a change to the development concept to a standalone LNG facility, de-linked from the upstream resource, with different accounting requirements. 6. Increased uncertainty of regulatory conditions, fiscal terms and development concept. 7. Increased uncertainty of development timing. 118 Annual Report 2021 NOTES TO THE FINANCIAL STATEMENTS B. PRODUCTION AND GROWTH ASSETS for the year ended 31 December 2021 B.4 Impairment of exploration and evaluation and oil and gas properties (cont.) Following the impairment recognised at 30 June 2020, the Group assessed each AOI and CGU for indicators of impairment as at 31 December 2020 in accordance with the Group's accounting policy. In assessing whether there was an indicator of impairment or impairment reversal, the Group considered whether there were any significant changes in the key estimates and judgements and underlying project assumptions used for the 30 June 2020 impairment assessment and determined that there were none. No indicators of additional impairment or impairment reversal were identified as at 31 December 2020. Key estimates and judgements Recoverable amount calculation key assumptions In determining the recoverable amounts of exploration and evaluation assets, the market comparison approach using adjusted market multiples (fair value hierarchy Level 3) was utilised to determine FVLCD. In determining the recoverable amount of CGUs, estimates are made regarding the present value of future cash flows when determining the VIU. 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 the estimates used to determine recoverable amounts as at 30 June 2020 is set out below: • Resource estimates – 2P reserves for oil and gas properties as disclosed in the Reserves and resources statement in the 31 December 2019 Annual Report on pages 44 to 47. • Inflation rate – an inflation rate of 2.0% has been applied. • Foreign exchange rates – a rate of $0.75 US$:AU$ is based on management’s view of long-term exchange rates. • Discount rates – a range of pre-tax discount rates between 9.3% and 14.8% (post-tax discount rates 7.5% and 11.0%) for CGUs has been applied. The discount rate reflects an assessment of the risks specific to the asset, including country risk. • An evaluation of climate risk impacts, including a long-term Australian carbon price of US$80/tonne (real terms 2020), applicable to Australian emissions that exceed facility-specific baselines in accordance with Australian regulations. • LNG price – the majority of LNG sales contracts are linked to an oil price marker; accordingly the LNG prices used are consistent with oil price assumptions. • Brent oil prices – derived from long-term views of global supply and demand, building upon past experience of the industry and consistent with external sources. Prices are adjusted for premiums and discounts based on the nature and quality of the product. The nominal Brent oil prices (US$/bbl) used were: 30 June 2020 2020 35 2021 45 2022 57 2023 62 2024 67 2025 721 1. Based on US$65/bbl (2020 real terms) from 2025 and prices are escalated at 2.0% onwards (31 December 2019: US$72.5/bbl (2020 real terms) and prices are escalated at 2.0% onwards). Woodside Petroleum Ltd 119 NOTES TO THE FINANCIAL STATEMENTS B. PRODUCTION AND GROWTH ASSETS for the year ended 31 December 2021 B.5 Significant production and growth asset acquisitions a) Sangomar - Acquisition from FAR Senegal RSSD SA b) BHP merger commitment deed 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 $55 million being reached. The contingent payments are accounted for as contingent liabilities in accordance with the Group’s accounting policies. Woodside’s interest has increased to 82% in the Sangomar exploitation area (31 December 2020: 68.33%) and to 90% in the remaining RSSD evaluation area (31 December 2020: 75%). Assets acquired and liabilities assumed The identifiable assets and liabilities acquired as at the date of the acquisition inclusive of transaction costs are: Oil and gas properties Exploration and evaluation Cash acquired Payables Net other assets and liabilities assumed Total identifiable net assets at acquisition Cash flows on acquisition Purchase cash consideration Transaction costs Total purchase consideration Net cash outflows on acquisition US$m 205 7 3 (13) 10 212 US$m 212 - 212 212 Key estimates and judgements Nature of acquisition Judgement is required to determine if the transaction is the acquisition of an asset or a business combination. The Sangomar project is in the early phase of development and a substantive process that has the ability to convert inputs to outputs is not present and therefore the acquisitions in both 2020 and 2021 are treated as asset acquisitions. On 17 August 2021, Woodside and BHP Group (BHP) entered into a merger commitment deed to combine their respective oil and gas portfolios by an all stock merger (the Transaction). The share sale agreement and the integration and transition services agreement were executed on 22 November 2021. On completion of the Transaction, BHP’s oil and gas business will merge with Woodside, and Woodside will issue new shares to be distributed to BHP shareholders. The expanded Woodside will be owned 52% by existing Woodside shareholders and 48% by existing BHP shareholders. The Transaction is subject to satisfaction of conditions precedent including shareholder, regulatory and other approvals. The completion of the proposed merger is targeted for Q2 2022 following all necessary approvals. Woodside and BHP have also agreed on an option for BHP to sell its 26.5% interest in the Scarborough Joint Venture and its 50% interest in the Thebe and Jupiter Joint Ventures to Woodside. The option is exercisable by BHP in the second half of 2022 and, if exercised, consideration of $1,000 million is payable to BHP plus working capital adjustments from 1 July 2021 to completion date. An additional $100 million is payable contingent upon future FID for a Thebe development. c) Sangomar - Acquisition from Capricorn Senegal Limited On 22 December 2020, Woodside completed the acquisition of Capricorn Senegal Limited’s (Cairn’s) interest in the RSSD Joint Venture (36.44% interest in the Sangomar exploitation area and 40% interest in the remaining RSSD evaluation area) for an aggregate purchase price of $527 million. The transaction was accounted for as an asset acquisition. Additional payments of up to $100 million are contingent on future commodity prices and the timing of first oil. The contingent payments are accounted for as contingent liabilities in accordance with the Group’s accounting policies. Assets acquired and liabilities assumed The identifiable assets and liabilities acquired as at the date of the acquisition inclusive of transaction costs were: Oil and gas properties Exploration and evaluation Cash acquired Payables Net other assets and liabilities assumed Total identifiable net assets at acquisition Cash flows on acquisition Purchase cash consideration Transaction costs Total purchase consideration Net cash outflows on acquisition US$m 540 26 5 (51) 7 527 US$m 525 2 527 527 120 Annual Report 2021 NOTES TO THE FINANCIAL STATEMENTS B. PRODUCTION AND GROWTH ASSETS for the year ended 31 December 2021 Impairment relating to the non-current assets held for sale Immediately before the classification as non-current assets held for sale, the recoverable amount of the relevant assets were calculated and an impairment of the Wheatstone Construction Village amounting to $10 million was recognised within oil and gas properties (refer to Note B.4). Assets and liabilities of the non-current assets held for sale As at 31 December 2021, the Group has reclassified $252 million of Pluto Train 2 assets, $1 million of the Wheatstone Construction Village assets and $1 million of the Pluto residential housing to non-current assets held for sale. There are no recognised liabilities associated with the non-current assets held for sale. B.6 Non-current assets held for sale Recognition and measurement The Group classifies non-current assets and liabilities as held for sale if their carrying amounts will be recovered principally through sale rather than through continuing use. Such non-current assets and liabilities classified as held for sale are measured at the lower of their carrying amount and fair value less costs to sell. Costs to sell are the incremental costs directly attributable to the sale, excluding the finance costs and income tax expense. The criteria for held for sale classification is regarded as 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. Property, plant and equipment and intangible 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. Transfers to non-current assets held for sale On 15 November 2021, the Group and Global Infrastructure Partners (GIP) entered into a Sale and Purchase Agreement for GIP to acquire a 49% participating interest in the Pluto Train 2 Joint Venture. The transaction completed on 18 January 2022 (refer to Note E.5), reducing the Group’s participating interest from 100% to 51%. Accordingly, the associated Pluto Train 2 assets within the Development segment have been reclassified to non-current assets held for sale. The arrangements require GIP to fund its 49% share of capital expenditure from 1 October 2021 and an additional amount of capital expenditure of approximately $822 million. If the total capital expenditure incurred is less than $5,600 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 approximately $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. In addition, in December 2021, Woodside committed to sell a portion of the Wheatstone Construction Village and six residential properties. The construction village within the Wheatstone operating segment and the residential properties within the Pluto segment have been reclassified as non-current assets held for sale and both sale transactions are expected to complete in 2022. Woodside Petroleum Ltd 121 NOTES TO THE FINANCIAL STATEMENTS C. DEBT AND CAPITAL for the year ended 31 December 2021 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. C.1 C.2 C.3 C.4 Debt and capital Cash and cash equivalents Interest-bearing liabilities and financing facilities Contributed equity Other reserves Page 123 Page 123 Page 125 Page 125 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 for the 2019 interim dividend and will remain in place until further notice. 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 2021, the Group had a total of $6,125 million (2020: $6,704 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 cross-currency interest rate swaps to hedge the foreign exchange risk (refer to Section A) and interest rate risk of the CHF denominated medium term note. The Group also 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 $2,962 million (2020: $3,527 million) on cash and cash equivalents, $367 million (2020: $450 million) on interest-bearing liabilities (excluding transaction costs) and $9 million (2020: $15 million) on cross-currency interest rate swaps. A reasonably possible change in the USD London Interbank Offered Rate (LIBOR) (+1.0%/-1.0% (2020: +0.5%/-0.5%)), with all variables held constant, would not have a material impact on the Group’s equity or the income statement in the current period. The Group's Treasury function is closely monitoring the market and the output from the various industry working groups managing the transition to new benchmark interest rates. The Treasury function is assessing the implications of the Interbank Offered Rates (IBOR) reform across the Group and will manage and execute the transition from current benchmark rates to alternative benchmark rates. 122 Annual Report 2021 NOTES TO THE FINANCIAL STATEMENTS C. DEBT AND CAPITAL for the year ended 31 December 2021 C.1 Cash and cash equivalents Cash and cash equivalents Cash at bank Term deposits Total cash and cash equivalents 2021 US$m 300 2,725 3,025 2020 US$m 367 3,237 3,604 Recognition and measurement Cash and cash equivalents in the 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 statement of financial position. Foreign exchange risk The Group held $108 million of cash and cash equivalents at 31 December 2021 (2020: $78 million) in currencies other than US dollars. C.2 Interest-bearing liabilities and financing facilities Bilateral Facilities US$m Syndicated Facilities US$m JBIC Facility US$m US Bonds US$m Medium Term Notes US$m Year ended 31 December 2021 At 1 January 2021 Repayments1 Fair value adjustment and foreign exchange movement Transaction costs capitalised and amortised Carrying amount at 31 December 2021 Current Non-current Carrying amount at 31 December 2021 (4) - - - (4) (2) (2) (4) 593 - - 2 595 (2) 597 595 Undrawn balance at 31 December 2021 1,900 1,200 Year ended 31 December 2020 At 1 January 2020 Repayments1 Drawdowns1 Fair value adjustment and foreign exchange movement Transaction costs capitalised and amortised Carrying amount at 31 December 2020 Current Non-current Carrying amount at 31 December 2020 (3) - - - (1) (4) (1) (3) (4) (4) - 600 - (3) 593 (2) 595 593 Undrawn balance at 31 December 2020 1,900 1,200 1. Included in cash flows classified within financing activities in the statement of cash flows. 250 (84) - - 166 83 83 166 - 333 (83) - - - 250 83 167 250 - 4,778 (700) - 3 4,081 (2) 4,083 4,081 - 4,775 - - - 3 4,778 696 4,082 4,778 - 597 - (5) - 592 200 392 592 - 578 - - 19 - 597 - 597 597 - Total US$m 6,214 (784) (5) 5 5,430 277 5,153 5,430 3,100 5,679 (83) 600 19 (1) 6,214 776 5,438 6,214 3,100 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 gain of $5 million being recorded (2020: loss of $19 million), and a loss of $7 million recorded on the hedging instrument (2020: gain of $18 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 $4,081 million (2020: $4,778 million) and a fair value of $4,443 million (2020: $5,196 million). The medium term notes have a carrying amount of $592 million (2020: $597 million) and a fair value of $604 million (2020: $617 million). Fair value is calculated based on the present value of future principal and interest cash flows, discounted at the market rate of interest at the reporting date and classified as Level 1 on the fair value hierarchy. Where these cash flows are in a foreign currency, the present value is converted to US dollars at the foreign exchange spot rate prevailing at the reporting date. The Group’s repayment obligations remain unchanged. Foreign exchange risk All interest-bearing liabilities are denominated in US dollars, excluding the CHF175 million medium term note. Woodside Petroleum Ltd 123 NOTES TO THE FINANCIAL STATEMENTS C. DEBT AND CAPITAL for the year ended 31 December 2021 C.2 Interest-bearing liabilities and financing facilities (cont.) Maturity profile of interest-bearing liabilities The table below presents the contractual undiscounted cash flows associated with the Group’s interest-bearing liabilities, representing principal and interest. The figures will not necessarily reconcile with the amounts disclosed in the consolidated statement of financial position. Due for payment in: 1 year or less 1-2 years 2-3 years 3-4 years 4-5 years More than 5 years 2021 US$m 470 462 188 1,169 951 3,320 6,560 2020 US$m 979 470 462 178 1,161 4,266 7,516 Amounts exclude transaction costs. Bilateral facilities The Group has 14 bilateral loan facilities totalling $1,900 million (2020: 14 bilateral loan facilities totalling $1,900 million). Details of bilateral loan facilities at the reporting date are as follows: 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. Medium term notes On 28 August 2015, the Group established a $3,000 million Global Medium Term Notes Programme listed on the Singapore Stock Exchange. Three notes have been issued under this programme as set out below: Maturity date Currency Carrying amount (million) 15 July 2022 11 December 2023 29 January 2027 The unutilised program is not considered to be an unused facility. US$ CHF US$ 200 175 200 Nominal interest rate Floating three month US$ LIBOR 1% 3% US bonds The Group has four unsecured bonds issued in the United States of America as defined in Rule 144A of the US Securities Act of 1933 as set out below: Number of facilities 5 2 7 Term (years) Currency Extension option 5 4 3 US$ US$ US$ Evergreen Evergreen Evergreen Maturity date 5 March 2025 15 September 2026 15 March 2028 4 March 2029 Carrying amount US$m 1,000 800 800 1,500 Nominal interest rate 3.65% 3.70% 3.70% 4.50% Interest on the bonds is payable semi-annually in arrears. During the period, the Group redeemed the $700 million 2021 US bond and repaid $84 million on the JBIC facility. Interest rates are based on USD LIBOR 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 On 14 October 2019, Woodside increased the existing facility to $1,200 million, with $400 million expiring on 11 October 2022 and $800 million expiring on 11 October 2024. Interest rates are based on USD LIBOR and margins are fixed at the commencement of the drawdown period. On 17 January 2020, the Group completed a new $600 million syndicated facility with a term of seven years. Interest is based on the USD London Interbank Offered Rate (LIBOR) 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 $30 million. 124 Annual Report 2021 NOTES TO THE FINANCIAL STATEMENTS C. DEBT AND CAPITAL for the year ended 31 December 2021 C.3 Contributed equity C.4 Other reserves Other reserves Employee benefits reserve Foreign currency translation reserve Hedging reserve Distributable profits reserve Nature and purpose 2021 US$m 2020 US$m 232 793 (400) 58 683 219 793 (71) 462 1,403 Employee benefits reserve Used to record share-based payments associated with the employee share plans and remeasurement adjustments relating to the defined benefit plan. 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 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 are taken to the income statement in the same period during which the hedged expected cash flows affect the income statement. Distributable profits reserve Used to record distributable profits generated by the Parent entity, Woodside Petroleum Ltd. 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 The Group’s own equity instruments, which are reacquired for later use in employee share-based payment arrangements (reserved 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 Year ended 31 December 2021 Opening balance DRP - ordinary shares issued at A$24.77 (2020 final dividend) DRP - ordinary shares issued at A$19.47 (2021 interim dividend) Number of shares US$m 962,225,814 9,297 1,354,072 6,051,940 26 86 Amounts as at 31 December 2021 969,631,826 9,409 Year ended 31 December 2020 Opening balance DRP - ordinary shares issued at A$25.61 (2019 final dividend) DRP - ordinary shares issued at A$18.79 (2020 interim dividend) Employee share plan - ordinary shares issued at A$18.27 (2017 Woodside equity plan) Amounts as at 31 December 2020 942,286,900 9,010 12,072,034 6,091,035 1,775,845 962,225,814 181 83 23 9,297 All shares are a single class with equal rights to dividends, capital, distributions and voting. The Company does not have authorised capital nor par value in relation to its issued shares. (b) Shares reserved for employee share plans Year ended 31 December 2021 Opening balance Purchases during the year Vested during the year Amounts at 31 December 2021 Year ended 31 December 2020 Opening balance Purchases during the year Vested during the year Amounts at 31 December 2020 Number of shares 1,766,099 2,683,469 (2,629,824) 1,819,744 1,985,306 2,242,345 (2,461,552) 1,766,099 US$m (23) (47) 40 (30) (39) (32) 48 (23) Woodside Petroleum Ltd 125 NOTES TO THE FINANCIAL STATEMENTS D. OTHER ASSETS AND LIABILITIES for the year ended 31 December 2021 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. D.1 D.2 D.3 D.4 D.5 D.6 D.7 Other assets and liabilities Segment assets and liabilities Receivables Inventories Payables Provisions Page 127 Page 127 Page 127 Page 128 Page 128 Other financial assets and liabilities Page 130 Leases Page 132 Key financial and capital risks in this section Credit risk management Credit risk is the risk that a counterparty will not meet its 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 collateral 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 verification 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 risk 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. Credit quality of a customer is assessed based on an extensive credit rating scorecard and individual credit limits are defined in accordance with this assessment. Outstanding customer receivables are regularly monitored. At 31 December 2021, the Group had four customers (2020: four customers) that owed the Group more than $10 million each and accounted for approximately 88% (2020: 82%) of all trade receivables. Payment terms are typically 14 to 30 days providing only a short credit exposure. 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 2021, the Group had a provision for credit losses of nil (2020: nil). Subsequent to 31 December 2021, 100% (2020: 100%) of the trade receivables balance of $152 million (2020: $164 million) has been received. Credit risk from balances with banks is managed by the Treasury function in accordance with the Group’s policy. The Group's main funds are placed as short-term deposits with reputable financial institutions with strong investment grade credit ratings. At 31 December 2021 and 31 December 2020, there were no significant concentrations of credit risk within the Group and financial instruments are spread amongst a number of financial institutions to minimise the risk of counterparty default. The maximum exposure to financial institution credit risk is represented by the sum of all cash deposits plus accrued interest, bank account balances and fair value of derivative assets. The Group’s counterparty credit policy limits this exposure to commercial and investment banks, according to approved credit limits based on the counterparty’s credit rating. 126 Annual Report 2021 NOTES TO THE FINANCIAL STATEMENTS D. OTHER ASSETS AND LIABILITIES for the year ended 31 December 2021 D.1 Segment assets and liabilities (a) Segment assets NWS Pluto Australia Oil Wheatstone Scarborough Sangomar Other development Other segments Unallocated items (b) Segment liabilities NWS Pluto Australia Oil Wheatstone Scarborough Sangomar Other development Other segments Unallocated items 2021 US$m 2,208 9,380 758 3,047 2,281 2,872 482 411 5,035 26,474 2021 US$m 647 937 913 302 84 350 83 798 8,131 12,245 2020 US$m 1,943 9,250 978 3,108 1,294 1,254 507 697 5,592 24,623 2020 US$m 679 950 848 281 16 96 153 953 7,772 11,748 Refer to Note A.1 for descriptions of the Group’s segments. Unallocated assets mainly comprise cash and cash equivalents, deferred tax assets and lease assets. Unallocated liabilities mainly comprise interest-bearing liabilities, deferred tax liabilities and lease liabilities. D.2 Receivables (a) Receivables (current) Trade receivables1 Other receivables1 Loans receivable Lease receivables Interest receivable Dividend receivable (b) Receivables (non-current) Loans receivable Lease receivables Defined benefit plan asset 2021 US$m 2020 US$m 152 123 75 18 - - 368 627 26 33 686 164 75 59 3 1 1 303 394 10 19 423 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 AASB 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 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 14 to 30 days from the date of invoice or bill of lading and customers regularly pay on time. There are no significant overdue trade receivables as at the end of the reporting period (2020: nil). Fair value The carrying amount of trade and other receivables approximates their fair value. Foreign exchange risk The Group held $121 million of receivables at 31 December 2021 (2020: $68 million) in currencies other than US dollars (predominantly Australian dollars). 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 $335 million at 31 December 2021 (2020: $113 million), which approximates its fair value. The remaining balance of loans receivable is due from non-controlling interests. D.3 Inventories (a) Inventories (current) Petroleum products Goods in transit Finished stocks Warehouse stores and materials (b) Inventories (non-current) Warehouse stores and materials 2021 US$m 2020 US$m 35 34 133 202 19 19 18 33 74 125 40 40 Recognition and measurement Inventories include hydrocarbon stocks, consumable supplies and maintenance spares. Inventories are valued at the lower of cost and net realisable value. Cost is determined on a weighted average basis and includes direct costs and an appropriate portion of fixed and variable production overheads where applicable. Inventories determined to be obsolete or damaged are written down to net realisable value, being the estimated selling price less selling costs. Woodside Petroleum Ltd 127 NOTES TO THE FINANCIAL STATEMENTS D. OTHER ASSETS AND LIABILITIES for the year ended 31 December 2021 D.4 Payables The following table shows the Group’s payables balances and maturity analysis. 30-60 days < 30 Total days US$m US$m US$m US$m > 60 days Year ended 31 December 2021 Trade payables1 Other payables1 Interest payable2 191 390 7 - - - - - 51 51 - 588 Total payables Year ended 31 December 2020 100 Trade payables1 342 Other payables1 7 Interest payable2 Total payables 449 1. Interest-free and normally settled on 30 day terms. 2. Details regarding interest-bearing liabilities are contained in Note C.2. - - 5 5 - - 51 51 191 390 58 639 100 342 63 505 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 $311 million of payables at 31 December 2021 (2020: $210 million) in currencies other than US dollars (predominantly Australian dollars). D.5 Provisions Year ended 31 December 2021 At 1 January 2021 Change in provision Unwinding of present value discount Carrying amount at 31 December 2021 Current Non-current Net carrying amount Year ended 31 December 2020 At 1 January 2020 Change in provision Unwinding of present value discount Carrying amount at 31 December 2020 Current Non-current Restoration1 US$m Employee benefits Onerous contracts2 US$m US$m Other US$m 2,134 60 24 2,218 235 1,983 2,218 1,869 237 28 2,134 54 2,080 295 (9) - 286 269 17 286 189 106 - 295 272 23 349 (140) 5 214 - 214 214 - 347 2 349 46 303 129 (23) - 106 101 5 106 70 59 - 129 128 1 Total US$m 2,907 (112) 29 2,824 605 2,219 2,824 2,128 749 30 2,907 500 2,407 Net carrying amount 1. 2021 change in provision is due to changes in estimates of $239 million (primarily due to the inclusion of costs for the removal of rigid plastic-coated pipelines, reflecting an update 2,134 2,907 295 129 349 to Woodside’s assumptions based on decommissioning planning activities in 2021), offset by a revision of discount rates of $134 million and provisions used of $45 million. 2. 2021 change in provision is due to provisions used of $45 million and changes in estimates of $95 million. 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. 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). 128 Annual Report 2021 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. NOTES TO THE FINANCIAL STATEMENTS D. OTHER ASSETS AND LIABILITIES for the year ended 31 December 2021 D.5 Provisions (cont.) 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 fulfill each contract. Long-term expectations of reduced spreads between North American and European/Asian LNG or gas markets has given rise to a loss-making contract. Key estimates and judgements (a) Restoration obligations The Group estimates the future remediation and removal costs of offshore oil and gas platforms, production facilities, wells and pipelines at different stages of the development and construction of assets or facilities. In many instances, removal 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 and are often non-prescriptive. Australian legislation requires removal of structures, equipment and property, or alternative arrangements to removal which 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, future removal technologies in determining the removal cost, and liability-specific discount rates to determine the present value of these cash flows. The Group's provision includes the following costs: • for onshore assets, provision has been made for the full removal of production facilities and aboveground pipelines. (b) Long service leave Long service leave is measured at the present value of benefits accumulated up to the end of the reporting period. The liability is discounted using an appropriate discount rate. Management uses judgement to determine key assumptions used in the calculation including future increases in salaries and wages, future on-cost rates and future settlement dates of employees’ departures. (c) Legal case outcomes Provisions for legal cases are measured at the present value of the amount expected to settle the claim. Management is required to use judgement when assessing the likely outcome of legal cases, estimating the risked amount and whether a provision or contingent liability should be recognised. (d) 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. The present value of the provision was estimated using the assumptions set out below: • Contract term – 19 years; the provision is released as contract deliveries • for offshore assets, provision has been made for the plug and are made up to 2040. abandonment of wells and the removal of offshore platform topsides, floating production storage offloading (FPSO) and some subsea infrastructure. It is currently the Group’s assumption that certain pipelines and infrastructure, parts of offshore platform substructures, and certain subsea infrastructure remain in-situ where it can be demonstrated that this will deliver equal or better health, safety and environmental outcomes than full removal and that regulatory approval is obtained where arrangements are satisfactory to the regulator. Elements composed of steel, or steel and concrete, with hydrocarbons removed have previously been accepted by the Australian regulator to be decommissioned in-situ where it has been demonstrated there is an acceptable impact to the environment and to current and future marine users (i.e. fishing, shipping and other activities). 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 performed near the end of their operational life and/or 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 2021. A range of pre-tax discount rates between 0.4% and 2.4% (2020: 0.1% to 2%) has been applied. If the discount rates were decreased by 0.5% then the provision would be $134 million higher. If the cost estimates were increased by 10% then the provision would be $225 million higher. The proportion of the non-current balance not expected to be settled within 10 years is 65% (2020: 73%). In the event that the removal of all, or a substantial portion of, the elements was required, Woodside estimates the additional cost would lead to an increase to the provision of approximately $300 - $500 million. This excludes costs related to large diameter trunklines between the offshore platforms and onshore plants as further assessment is required for these pipelines which are buried below the seabed or heavily stabilised by rock or concrete due to their location and metocean conditions. • Discount rate – a pre-tax, risk free US government bond rate of 1.855% (2020: 1.390%) has been applied. • LNG pricing – forecast sales and purchase prices are subject to a number of price markers. Price assumptions are based on the best information on the market available at measurement date and derived from short- and long-term views of global supply and demand, building upon past experience of the industry and consistent with external sources. The forecasted sales are linked to gas hub prices (Title Transfer Facility (TTF)) at which physical sales are expected to occur and incorporates known pricing information related to sales1. The long-term gas sales price is estimated on the basis of the Group's Brent price forecast. The estimated purchase price is linked to US gas hub prices (Henry Hub (HH)) at which physical purchases are expected to occur. The nominal TTF, Brent oil prices and HH gas prices used at 31 December 2021 were: TTF (US$/MMBtu) Brent (US$/bbl) HH (US$/MMBtu) 2022 15.0 73 4.0 2023 8.2 71 3.6 2024 6.9 68 3.1 2025 7.0 69 3.2 2026 7.2 70² 3.33 The nominal impact of the effects of changes to discount rate and long- term price assumptions are estimated as follows: Change in assumption4 LNG sales price1: increase of 10% LNG sales price1: decrease of 10% US hub gas price (HH)3: increase of 10% US hub gas price (HH)3: decrease of 10% Discount rate: increase of 1%5 Discount rate: decrease of 1%5 1. For committed volumes, contracted pricing has been applied. For hedge US$m 500 (509) (282) 282 19 (20) accounted volumes, the relevant hedged prices have been applied. 2. Long-term oil prices are based on US$65/bbl (2022 real terms) from 2024 and prices are escalated at 2.0% onwards. 3. Long-term gas prices are based on US$3.0/MMBtu (2022 real terms) from 2025 to 2029 and thereafter US$3.5/MMBtu (2022 real terms). All long- term prices are escalated at 2.0%. 4. Amounts shown represent the change of the present value of the contract keeping all other variables constant. Any reduction in the onerous provision recognised would not exceed the balance of the provision itself. 5. A change of 1% represents 100 basis points. Woodside Petroleum Ltd 129 NOTES TO THE FINANCIAL STATEMENTS D. OTHER ASSETS AND LIABILITIES for the year ended 31 December 2021 D.6 Other financial assets and liabilities Other financial assets Financial instruments at fair value through profit and loss Derivative financial instruments designated as hedges Other financial assets Total other financial assets Current Non-current Net carrying amount Other financial liabilities Financial instruments at fair value through profit and loss Derivative financial instruments designated as hedges Other financial liabilities Total other financial liabilities Current Non-current Net carrying amount 2021 US$m 2020 US$m 134 293 427 320 107 427 563 9 572 411 161 572 31 195 226 172 54 226 68 3 71 37 34 71 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 LNG 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. 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 income statement. 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. 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 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 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 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. 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. 130 Annual Report 2021 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. 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: • The Group hedged a percentage of its oil-linked exposure, entering into oil swap derivatives settling between 2021 to 2023 in order to achieve a minimum average sales price per barrel. • The Group also entered into separate HH commodity swaps to hedge the purchase leg of the Corpus Christi volumes and separate TTF commodity swaps to hedge the sales leg of Corpus Christi volumes effectively protecting against pricing risk for 2022 and 2023. As a result of hedging and term sales, approximately 97% of Corpus Christi volumes in 2022 and 70% in 2023 have hedged pricing risk. • The Group entered into TTF commodity swaps to hedge equity LNG cargoes expected to be exposed to winter 2021/22 natural gas pricing. • 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 expected to be incurred under the Scarborough development. NOTES TO THE FINANCIAL STATEMENTS D. OTHER ASSETS AND LIABILITIES for the year ended 31 December 2021 D.6 Other financial assets and liabilities (cont.) Hedging activities (cont.) For the year ended 31 December 2020 the following main hedging activities were undertaken: The Group hedged a percentage of its exposure to commodity price risk, entering into 13.4 million barrels of oil swap derivatives to achieve a minimum average sales price of $33 per barrel. The Group also entered into 7.9 million barrels of oil call options, to take advantage of increases in oil prices above $40 per barrel, for a premium of $37 million. Most of the derivatives settled between April 2020 and December 2020, with swaps and options for 1.3 million barrels settling in 2021. The swaps and call options were designated as cash flow hedges. 2021 2020 Oil swaps (cash flow hedges) Carrying amount (US$m) Notional amount (MMbbl) Maturity date Hedge ratio Weighted average hedged rate (US$/MMbbl) HH Corpus Christi commodity swaps (cash flow hedges) Carrying amount (US$m) Notional amount (TBtu) Maturity date Hedge ratio Weighted average hedged rate (US$/MMBtu) TTF Corpus Christi commodity swaps (cash flow hedges) Carrying amount (US$m) Notional amount (TBtu) Maturity date Hedge ratio Weighted average hedged rate (US$/MMBtu) TTF commodity swaps (cash flow hedges) Carrying amount (US$m) Notional amount (TBtu) Maturity date Hedge ratio Weighted average hedged rate (US$/MMBtu) Interest rate swap (cash flow hedges) Carrying amount (US$m) Notional amount (US$m) Maturity date Hedge ratio Weighted average hedged rate Cross currency interest rate swap (cash flow and fair value hedges) Carrying amount (US$m) Notional amount (Swiss Franc) Maturity date Hedge ratio Weighted average hedged rate Oil call options (cash flow hedges) Carrying amount (US$m) Notional amount (MMbbl) Maturity date Hedge ratio Weighted average hedged rate (US$/MMbbl) FX forwards (cash flow hedges) Carrying amount (US$m) Notional amount (AUD$m) Maturity date Hedge ratio Weighted average hedged rate (AUD:USD) (1) 30 2022-2023 1:1 74 31 65 2022-2023 1:1 3 (465) 49 2022-2023 1:1 9 4 3 2022 1:1 26 (17) 600 2027 1:1 1.7% (22) 1 2021 1:1 33 - - - - - - - - - - - - - - - (43) 600 2027 1:1 1.7% 9 175 2023 1:1 Three month US$ LIBOR +2.8% 15 175 2023 1:1 Three month US$ LIBOR +2.8% - - - - - 10 934 2022-2025 1:1 0.71 13 1 2021 1:1 33 - - - - - Hedge ineffectiveness of $38 million (2020: $1 million) has been recognised in the profit and loss. Other financial assets Other financial assets measured at fair value include receivables subject to provisional pricing adjustments of $163 million (2020: $144 million) and repurchase agreements entered into for the purposes of net settlement rather than for physical delivery of $69 million (2020: nil). 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'). The Group has exposures to IBORs on its financial instruments that will be impacted as part of these market- wide initiatives. The Group's main IBOR exposure at the reporting date is USD LIBOR. In 2020, the Federal Reserve announced that LIBOR will be phased out and eventually replaced by June 2023. The Group anticipates that IBOR reform will impact its operational and risk management processes and hedge accounting. The main risks to which the Group is exposed as a result of IBOR reform are operational, for example renegotiating borrowing contracts through bilateral negotiation with counterparties, implementing new fallback clauses with its derivative counterparties, updating contractual terms and revising operational controls related to the reform. Financial risk is predominantly limited to interest rate risk. Hedging relationships may experience ineffectiveness due to uncertainty about when and how replacement may occur with respect to the relevant hedged item and hedging instrument or the difference in the timing of a replacement. The Group's financial instruments have not yet transitioned to an alternative interest rate benchmark. The Group has financial liabilities and financial assets with a total carrying value of $957 million and $367 million respectively, with reference to USD LIBOR. The Group has the following hedging relationships which are exposed to interest rate benchmarks impacted by IBOR Reform: • Interest rate swaps to hedge the LIBOR interest rate risk associated with the $600 million syndicated facility (refer to Note C.2). The interest rate swaps are designated as cash flow hedges, converting the variable interest into fixed interest US dollar debt, and mature in 2027. • A fixed rate 175 million Swiss Franc (CHF) denominated medium term note, which it hedges with cross-currency interest rate swaps designated in both fair value and cash flow hedge relationships. The cross-currency interest rate swaps are referenced to LIBOR (refer to Note C.2). The Group's Treasury function continues to assess the implications of the IBOR reform across the Group and will manage and execute the transition from current benchmark rates to alternative benchmark rates. Key estimates and judgements Fair value of other financial assets and liabilities Estimates have been applied in the measurement of other financial assets and liabilities and, where required, judgement is applied in the settlement of any financial assets or liabilities. In the current period, this included a $56 million periodic adjustment which increased other financial liabilities, reflecting the arrangements governing Wheatstone LNG sales (2020: $12 million decrease). Woodside Petroleum Ltd 131 NOTES TO THE FINANCIAL STATEMENTS D. OTHER ASSETS AND LIABILITIES for the year ended 31 December 2021 D.7 Leases Lease assets Year ended 31 December 2021 Carrying amount at 1 January 2021 Additions Lease remeasurements Disposals at written down value Depreciation Carrying amount at 31 December 2021 At 31 December 2021 Historical cost and remeasurements Accumulated depreciation, impairment and disposals Net carrying amount Lease liabilities Year ended 31 December 2021 At 1 January 2021 Additions Repayments (principal and interest) Accretion of interest Lease remeasurements Carrying amount at 31 December 2021 Current Non-current Carrying amount at 31 December 2021 Lease assets Year ended 31 December 2020 Carrying amount at 1 January 2020 Additions Lease remeasurements Depreciation Carrying amount at 31 December 2020 At 31 December 2020 Historical cost Accumulated depreciation and impairment Net carrying amount Lease liabilities Year ended 31 December 2020 At 1 January 2020 Additions Repayments (principal and interest) Accretion of interest Lease remeasurements Carrying amount at 31 December 2020 Current Non-current Carrying amount at 31 December 2020 Marine vessels and carriers Total US$m US$m US$m Plant and equipment Land and buildings US$m 392 14 15 (12) (32) 377 - 205 - - (38) 167 592 9 16 - (81) 984 228 31 (12) (151) 536 1,080 462 205 743 1,410 (85) 377 484 7 (70) 25 (9) 437 19 418 437 396 24 1 (29) 392 447 (55) 392 431 24 (34) 23 40 484 16 468 484 (38) (207) (330) 167 536 1,080 3 231 (48) 7 (1) 192 87 105 192 791 13 (144) 65 13 1,278 251 (262) 97 3 738 1,367 85 653 191 1,176 738 1,367 - - - - - - - - - 3 - - - 3 1 2 3 552 102 4 (66) 592 948 126 5 (95) 984 718 1,165 (126) (181) 592 984 739 107 (123) 1,170 134 (157) 63 5 86 45 791 1,278 77 714 94 1,184 791 1,278 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 $476 million of lease liabilities at 31 December 2021 (2020: $518 million) in currencies other than the US dollar (predominantly Australian dollars). 132 Annual Report 2021 NOTES TO THE FINANCIAL STATEMENTS D. OTHER ASSETS AND LIABILITIES for the year ended 31 December 2021 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 $1,654 million (2020: $1,670 million) were not included in the measurement of lease liabilities. (c) lnterest in joint arrangements Judgement is required to determine the Group's rights and obligations for lease contracts within joint operations, to assess whether lease liabilities are recognised gross (100%) or in proportion to the Group’s participating interest in the joint operation. This includes an evaluation of whether the lease arrangement contains a sublease with the joint operation. (d) Discount rates Judgement is required to determine the discount rate, where the discount rate is the Group’s incremental borrowing rate if the rate implicit in the lease cannot be readily determined. The incremental borrowing rate is determined with reference to the Group's borrowing portfolio at the inception of the arrangement or the time of the modification. D.7 Leases (cont.) Maturity profile of lease liabilities The table below presents the contractual undiscounted cash flows associated with the Group’s lease liabilities, representing principal and interest. The figures will not necessarily reconcile with the amounts disclosed in the consolidated statement of financial position. Due for payment in: 1 year or less 1-2 years 2-3 years 3-4 years 4-5 years More than 5 years 2021 US$m 283 283 191 171 161 789 1,878 2020 US$m 184 181 180 174 174 994 1,887 Lease commitments The table below presents the contractual undiscounted cash flows associated with the Group's future lease commitments for non- cancellable leases not yet commenced, representing principal and interest. Due for payment: Within one year After one year but not more than five years Later than five years 2021 US$m 2020 US$m 80 159 49 288 90 365 45 500 Subsequent to year end, contractual undiscounted future lease commitments for non-cancellable leases not yet commenced increased by $634 million. The leases commence from 2025 and relate to facilities, marine vessels and carriers (refer to Note E.5). Payments of $68 million (2020: $101 million) for short-term leases (lease term of 12 months or less) and payments of $18 million (2020: $17 million) for leases of low value assets were expensed in the consolidated income statement. Total payments for leases in the statement of cash flows are $330 million (2020: $275 million), with $244 million (2020: $157 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 $53 million (2020: $94 million). Woodside Petroleum Ltd 133 NOTES TO THE FINANCIAL STATEMENTS E. OTHER ITEMS for the year ended 31 December 2021 In this section This section addresses information on items which require disclosure to comply with Australian Accounting Standards and the Corporations Act 2001, however are not considered critical in understanding the financial performance or position of the Group. This section includes Group structure information and other disclosures. E. E.1 E.2 E.3 E.4 E.5 E.6 E.7 E.8 E.9 Other items Contingent liabilities and assets Employee benefits Related party transactions Auditor remuneration Events after the end of the reporting period Joint arrangements Parent entity information Subsidiaries Other accounting policies Page 135 Page 135 Page 137 Page 137 Page 137 Page 137 Page 138 Page 139 Page 141 134 Annual Report 2021 NOTES TO THE FINANCIAL STATEMENTS E. OTHER ITEMS for the year ended 31 December 2021 E.1 Contingent liabilities and assets (b) Compensation of key management personnel 2021 US$m 20201 US$m Key management personnel (KMP) compensation for the financial year was as follows: Contingent liabilities at reporting date Contingent liabilities Guarantees 195 7 202 587 10 597 1. Contingent payments of $450 million were paid in 2021 due to a positive FID to develop the Scarborough field and capitalised to oil and gas properties. 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. 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 above table includes contingent payments of $155 million (31 December 2020: $100 million) relating to the Sangomar development, dependent on commodity prices and the timing of first oil. Additionally, the Group has issued guarantees relating to workers’ compensation liabilities. There were no contingent assets as at 31 December 2021 or 31 December 2020. E.2 Employee benefits Employee benefits Share-based payments Defined contribution plan costs Defined benefit plan expense 2021 US$m 2020 US$m 217 12 26 1 256 252 19 27 2 300 (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 superannuation plan. The majority of employees are party to a defined contribution scheme and 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. The Group also operates a defined benefit superannuation scheme, the membership of which is now closed. The net defined benefit plan asset at 31 December 2021 was $33 million (2020: $19 million). Short-term employee benefits Post-employment benefits Share-based payments Long-term employee benefits Termination benefits (c) Share plans 2021 US$ 2020 US$ 6,599,678 77,515 5,609,022 717,223 2,447,525 15,450,963 5,868,476 63,805 7,201,653 515,585 390,087 14,039,606 The Group provides benefits to its employees (including KMP) in the form of share-based payments whereby employees render services for shares (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 EIS participants. The number of Equity Rights (ERs) offered to each eligible employee is calculated with reference to salary and performance. 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 relating to the WEP for 2018 and prior years entitles the participant to receive a Woodside share on a vesting date three years after the grant date. From the 2019 WEP onwards, 75% of the ERs offered to each participant will vest three years after the grant date, with the remaining 25% vesting five years after the grant date. The SWEP award is available to employees identified as being retention critical. Each ER entitles the participant to receive a Woodside share on the vesting date three years after the effective grant date. Participants do not make any payment in respect of the ERs at grant or at vesting. Executive incentive plans (EIP) The EIP operated as Woodside’s Executive incentive framework until the end of 2017, after which the Board introduced the EIS. The EIP was used to deliver short-term awards (STA) and long- term awards (LTA) to Senior Executives. Short-term awards (STA) STAs were delivered in the form of restricted shares to Executives, including all Executive KMP. There are no further performance conditions for vesting of deferred STA. Participants are not required to make any payments in respect of STA awards at grant or at vesting. Restricted shares entitle their holders to receive dividends. Long-term awards (LTA) LTAs were granted in the form of Performance Rights (PRs) to Executives, including all Executive KMP. Vesting of LTA is subject to achievement of relative total shareholder return (RTSR) targets, with 33% measured against the ASX 50 and the remaining 67% tested against an international group of oil and gas companies. Participants are not entitled to receive dividends and are not required to make any payments in respect of LTA awards at grant or at vesting. Woodside Petroleum Ltd 135 NOTES TO THE FINANCIAL STATEMENTS E. OTHER ITEMS for the year ended 31 December 2021 E.2 Employee benefits (cont.) 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 2020 Restricted Shares and Performance Rights for Executives were granted on 17 February 2021, while the Performance Rights for the outgoing CEO were granted on 15 April 2021 and have been included in the table below. The expense estimated as at 31 December 2021 in relation to the 2021 performance year was updated to the fair value on grant date during the period. The 2021 Restricted Shares and Performance Rights have not been included in the table below as they have not been approved as at 31 December 2021. An expense related to the 2021 performance year has been estimated for Restricted Shares and Performance Rights, using fair value estimates based on inputs at 31 December 2021. Recognition and measurement All compensation under WEP, SWEP and Executive share plans is accounted for as share-based payments to employees for Year ended 31 December 2021 Opening balance Granted during the year1,2 Vested during the year Forfeited during the year Awards at 31 December 2021 Fair value of awards granted during the year Year ended 31 December 2020 Opening balance Granted during the year1,2 Vested during the year Forfeited during the year Awards at 31 December 2020 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 RTSR PRs was estimated 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 STA3 LTA3 5,618,603 2,507,167 (1,999,676) (476,311) 5,649,783 US$m 39 - - - - - US$m - 975,295 353,412 (307,402) (26,869) 994,436 US$m 7 2,798,305 553,849 (322,746) (650,188) 2,379,220 US$m 9 Number of performance awards Employee plans Executive plans WEP SWEP STA3 LTA3 6,911,551 1,127,546 (1,943,777) (476,717) 5,618,603 17,678 - (17,678) - - 867,716 373,774 (257,489) (8,706) 975,295 2,704,143 617,091 (242,608) (280,321) 2,798,305 US$m US$m US$m US$m Fair value of awards granted during the year 1. For the purpose of valuation, the share price on grant date for the 2021 WEP allocations was $15.17 (2020: WEP allocations $12.57). 2. For the purpose of valuation, the share price on grant date for Restricted Shares was $20.18 (2020: $22.76) and Performance Rights were $11.66 and $14.44 (2020: $15.81). 3. Includes awards issued under EIP and EIS. 13 9 - 12 For more detail on these share plans and performance rights issued to KMPs, refer to the Remuneration Report on pages 69-92. 136 Annual Report 2021 NOTES TO THE FINANCIAL STATEMENTS E. OTHER ITEMS for the year ended 31 December 2021 E.3 Related party transactions (b) Interest percentage in joint operations Transactions with directors There were no transactions with directors during the year. Key management personnel compensation is disclosed in Note E.2(b). E.4 Auditor remuneration The auditor of Woodside Petroleum Ltd is Ernst & Young (EY). Amounts received or due and receivable to: Ernst & Young (Australia) - Fees for auditing the statutory financial report of the parent covering the group and auditing the statutory financial reports of any controlled entities - Fees for assurance services that are required by legislation to be provided by the auditor - Fees for other assurance and agreed upon procedures services under other legislation or contractual arrangements where there is discretion as to whether the service is provided by the auditor or another firm - Other services Other overseas member firms of Ernst & Young (Australia) - Audit of the financial reports of controlled entities - Fees for other assurance and agreed upon procedures services under other legislation or contractual arrangements where there is discretion as to whether the service is provided by the auditor or another firms - Other services 2021 US$000 2020 US$000 1,455 1,521 2,687 - 22 134 4,298 110 164 1,795 277 165 11 14 302 30 14 209 E.5 Events after the end of the reporting period On 15 November 2021, the Group and Global Infrastructure Partners (GIP) entered into a Sale and Purchase Agreement for GIP to acquire a 49% participating interest in the Pluto Train 2 Joint Venture. The transaction completed on 18 January 2022, reducing the Group’s participating interest from 100% to 51% and reducing the Group’s future capital commitments by approximately $2,876 million. The full financial effect of the transaction is still being assessed. Subsequent to year end, the Group entered into new lease arrangements (refer to Note D.7). E.6 Joint arrangements (a) Interest percentage in joint ventures Entity North West Shelf Gas Pty Ltd North West Shelf Liaison Company Pty Ltd China Administration Company Pty Ltd North West Shelf Shipping Service Company Pty Ltd North West Shelf Lifting Coordinator Pty Ltd Principal activity Marketing services for ventures in the sale of gas to the domestic market. Liaison for ventures in the sale of LNG to the Japanese market. Marketing services for ventures in the sale of LNG to international markets. LNG vessel fleet advisor. Coordinator for venturers for all equity liftings. Group Interest % 2021 2020 16.67 16.67 16.67 16.67 16.67 16.67 16.67 16.67 16.67 16.67 Producing and developing assets Oceania North West Shelf Greater Enfield and Vincent Stybarrow Balnaves Pluto Wheatstone Scarborough1 Africa Senegal2 Exploration and evaluation assets Oceania Browse Basin Carnarvon Basin and Scarborough1 Bonaparte Basin Africa Congo Senegal2 Americas Kitimat3 Asia Republic of Korea Myanmar4 Europe Ireland5 Bulgaria5 Group Interest % 2021 2020 12.5 - 50 60.0 50.0 65.0 90.0 13.0 - 65.0 73.5 12.5 - 50 60.0 50.0 65.0 90.0 13.0 - 65.0 - 82.0 68.3 30.6 15.8 - 70.0 26.7 - 35.0 30.6 15.8 - 73.5 26.7 - 35.0 42.5 90.0 50.0 42.5 75.0 50.0 50.0 40.0 - 50.0 50.0 40.0 - 50.0 - - 90.0 30.0 1. FID taken on permits WA-61-L and WA-62-L announced on 22 November 2021. 2. Following the completion of the sale of FAR's interest in the RSSD joint venture during the year, Woodside's participating interest increased to 82% in the exploitation area and 90% in the exploration area (refer to Note B.5 more details). 3. Woodside is retaining an upstream position in the Liard Basin by taking on full equity in 28 non-infrastructure related Liard Basin leases from Chevron Canada. 4. The Group completed the relinquishment of permits AD-2, AD-5 and A-4 in 2021 and is in the process of withdrawing from AD-6, AD-7 and A-7. In 2022, the Group will also commence arrangements to formally exit AD-1, AD-8, the A-6 Joint Venture and the A-6 production sharing contract. 5. Licence surrendered in 2021. The principal activities of the joint operations above are exploration, development and production of hydrocarbons. Key estimates and judgements 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. Woodside Petroleum Ltd 137 NOTES TO THE FINANCIAL STATEMENTS E. OTHER ITEMS for the year ended 31 December 2021 E.6 Joint arrangements (cont.) E.7 Parent entity information 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 AASB 3 Business Combinations. Joint arrangements which are not deemed to be carrying on a business are treated as asset acquisitions. Woodside Petroleum Ltd: Current assets Non-current assets Current liabilities Non-current liabilities Net assets Issued and fully paid shares Shares reserved for employee share plans Employee benefits reserve Foreign currency translation reserve Distributable profits reserve Retained earnings Total shareholders equity Profit of parent entity Total comprehensive income of parent entity 2021 US$m 456 10,037 (357) (300) 9,836 9,409 (30) 112 296 58 (9) 9,836 18 18 2020 US$m 444 10,257 - (579) 10,122 9,297 (23) 117 296 462 (27) 10,122 852 852 Guarantees Woodside Petroleum Ltd and Woodside Energy Ltd (a subsidiary company) are parties to a Deed of Cross Guarantee as disclosed in Note E.8. The effect of the Deed is that Woodside Petroleum Ltd has guaranteed to pay any deficiency in the event of winding up of the subsidiary company under certain provisions of the Corporations Act 2001. The subsidiary company has also given a similar guarantee in the event that Woodside Petroleum Ltd is wound up. Woodside Petroleum Ltd has guaranteed the discharge by a subsidiary company of its financial obligations under debt facilities disclosed in Note C.2. Woodside Petroleum Ltd has guaranteed certain obligations of subsidiaries to unrelated parties on behalf of their performance in contracts. No liabilities are expected to arise from these guarantees. 138 Annual Report 2021 NOTES TO THE FINANCIAL STATEMENTS E. OTHER ITEMS for the year ended 31 December 2021 E.8 Subsidiaries (a) Subsidiaries Name of entity Ultimate Parent Entity Woodside Petroleum Ltd Subsidiaries Company name Woodside Energy Ltd Woodside Browse Pty Ltd Woodside Burrup Pty Ltd Burrup Facilities Company Pty Ltd Burrup Train 1 Pty Ltd Pluto LNG Pty Ltd Woodside Burrup Train 2 A Pty Ltd Woodside Burrup Train 2 B Pty Ltd Woodside Energy (LNG Fuels and Power) Pty Ltd Woodside Energy (Domestic Gas) Pty Ltd Woodside Energy (Algeria) Pty Ltd Woodside Energy Australia Asia Holdings Pte Ltd y Woodside Energy Holdings International Pty Ltd Woodside Energy Mediterranean Pty Ltd Woodside Energy International (Canada) Limited t Woodside Energy (Canada LNG) Limited t Woodside Energy (Canada PTP) Limited t KM LNG Operating General Partnership t KM LNG Operating Ltd t Woodside Energy Holdings Pty Ltd Woodside Energy Holdings (USA) Inc q Woodside Energy (USA) Inc q Gryphon Exploration Company q Woodside Energy (Cameroon) SARL n Woodside Energy (Gabon) Pty Ltd Woodside Energy (Indonesia) Pty Ltd Woodside Energy (Indonesia II) Pty Ltd Woodside Energy (Malaysia) Pty Ltd Woodside Energy (Ireland) Pty Ltd Woodside Energy (Korea) Pte Ltd y Woodside Energy (Korea II) Pte Ltd y Woodside Energy (Myanmar) Pte Ltd y Woodside Energy (Morocco) Pty Ltd Woodside Energy (New Zealand) Limited z Woodside Energy (New Zealand 55794) Limited z Woodside Energy (Peru) Pty Ltd Woodside Energy (Senegal) Pty Ltd Woodside Energy (Tanzania) Limited ¥ Woodside Energy Holdings II Pty Ltd Woodside Power Pty Ltd Woodside Power (Generation) Pty Ltd Woodside Energy Holdings (South America) Pty Ltd Woodside Energia (Brasil) Apoio Administrativo Ltda l Woodside Energy Holdings (UK) Pty Ltd Woodside Energy (UK) Limited p Woodside Energy Finance (UK) Limited p Woodside Energy (Congo) Limited p Woodside Energy (Bulgaria) Limited p Woodside Energy Holdings (Senegal) Limited p Woodside Energy (Senegal) B.V. Woodside Energy (France) SAS £ Woodside Energy Iberia S.A. º Woodside Energy (N.A.) Ltd p Woodside Energy Services (Qingdao) Co Ltd Woodside Energy Julimar Pty Ltd Woodside Energy (Norway) Pty Ltd Notes (1,2,3) (2,3,4) (2,4) (2,4) (5) (5) (5) (2,4) (2,4) (2,4) (2,4) (2,4) (4) (2,4) (2,4) (4) (4) (4) (8) (4) (2,4) (4) (4) (4) (4) (2,4) (2,4) (2,4) (2,4,10) (2,4) (4) (4) (4) (2,4) (4) (4) (2,4) (2,4) (6) (2,4) (2,4) (2,4) (2,4) (7) (2,4) (4) (4) (4) (4) (4) (4) (4) (4) (4) (4) (2,4) (2,4) Name of entity Woodside Energy Technologies Pty Ltd Woodside Technology Solutions Pty Ltd Woodside Energy Scarborough Pty Ltd Woodside Energy Carbon Holdings Pty Ltd Woodside Energy Carbon (Assets) Pty Ltd Woodside Energy Carbon (Services) Pty Ltd Woodside Energy (Financial Advisory Services) Pty Ltd Woodside Energy Trading Singapore Pte Ltd y WelCap Insurance Pte Ltd y Woodside Energy Shipping Singapore Pte Ltd y Metasource Pty Ltd Mermaid Sound Port and Marine Services Pty Ltd Woodside Finance Limited Woodside Petroleum (Timor Sea 19) Pty Ltd Woodside Petroleum (Timor Sea 20) Pty Ltd Woodside Petroleum Holdings Pty Ltd Notes (2,4,9) (2,4) (2,4,11) (2,4,12) (2,4,13) (2,4,13) (2,4,13) (4) (4) (4) (2,4) (2,4) (2,4) (2,4) (2,4) (2,4) 1. Woodside Petroleum Ltd is the ultimate holding company and the head entity within the tax consolidated group. 2. These companies were members of the tax consolidated group at 31 December 2021. 3. Pursuant to ASIC Instrument 2016/785, relief has been granted to the controlled entity, Woodside Energy Ltd, from the Corporations Act 2001 requirements for the preparation, audit and publication of accounts. As a condition of the Instrument, Woodside Petroleum Ltd and Woodside Energy Ltd are parties to a Deed of Cross Guarantee. 4. All subsidiaries are wholly owned except those referred to in Notes 5, 6, 7 and 8. 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 2021, Woodside Energy Holdings Pty Ltd held a 99.99% interest in the shares of Woodside Energy (Tanzania) Limited and Woodside Energy Ltd held the remaining 0.01% interest. 7. As at 31 December 2021, Woodside Energy Holdings (South America) Pty Ltd held a 99.99% interest in the shares of Woodside Energia (Brasil) Apoio Administrativo Ltda and Woodside Energy Ltd held the remaining 0.01% interest. 8. As at 31 December 2021, 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. 9. Woodside Energy Technologies Pty Ltd owns 30% in Blue Ocean Seismic Services Limited which is accounted for as an investment in associate. 10. On 4 May 2021, Woodside Energy (Indonesia III) Pty Ltd changed its name to Woodside Energy (Malaysia) Pty Ltd. 11. Woodside Energy Scarborough Pty Ltd was incorporated on 13 May 2021. 12. Woodside Energy Carbon Holdings Pty Ltd was incorporated on 29 July 2021. 13. Woodside Energy Carbon (Assets) Pty Ltd, Woodside Energy Carbon (Services) Pty Ltd and Woodside Energy (Financial Advisory Services) Pty Ltd were incorporated on 3 August 2021. All subsidiaries were incorporated in Australia unless identified with one of the following symbols: The Netherlands ¥ Tanzania l Brazil n Cameroon z New Zealand t Canada £ France y Singapore º Spain p England and Wales q USA China 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. Woodside Petroleum Ltd 139 NOTES TO THE FINANCIAL STATEMENTS E. OTHER ITEMS for the year ended 31 December 2021 E.8 Subsidiaries (cont.) (b) Subsidiaries with material non-controlling interests The Group has two Australian subsidiaries with material non-controlling interests (NCI). Name of entity Burrup Facilities Company Pty Ltd Burrup Train 1 Pty Ltd Principal place of business Australia Australia % held by NCI 10% 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: 2021 US$m 2020 US$m Burrup Facilities Company Pty Ltd Current assets Non-current assets Current liabilities Non-current liabilities Net assets Accumulated balance of NCI Revenue Profit Profit allocated to NCI Dividends paid to NCI Operating Investing Financing 518 5,038 (71) (528) 4,957 496 858 328 33 (40) 633 (111) (522) Net increase/(decrease) in cash and cash equivalents - Burrup Train 1 Pty Ltd Current assets Non-current assets Current liabilities Non-current liabilities Net assets Accumulated balance of NCI Revenue Profit Profit allocated to NCI Dividends paid to NCI Operating Investing Financing 435 2,915 (110) (345) 2,895 290 1,421 200 20 (27) 393 (4) (389) Net increase/(decrease) in cash and cash equivalents - 425 5,224 (51) (571) 5,027 503 859 318 32 (32) 652 (69) (583) - 372 3,081 (103) (385) 2,965 297 1,423 208 21 (13) 473 (2) (471) - (c) Deed of Cross Guarantee and Closed Group Woodside Petroleum Ltd and Woodside Energy Ltd are parties to a Deed of Cross Guarantee under which each company guarantees the debts of the other. By entering into the Deed, the entities have been granted relief from the Corporations Act 2001 requirements for the preparation, audit and publication of accounts, pursuant to ASIC Instrument 2016/785. The two entities represent a Closed Group for the purposes of the Instrument. 140 Annual Report 2021 The consolidated income statement and statement of financial position of the members of the Closed Group are set out below: 2021 US$m 2020 US$m Closed Group Consolidated Income Statement and Statement of Retained Earnings Profit/(loss) before tax Tax (expense)/benefit Profit/(loss) after tax Retained earnings at the beginning of the financial year Transfer of retained earnings to distributable profits reserve Dividends 1,599 (50) 1,549 111 - - Retained earnings at the end of the financial year 1,660 (3,195) 955 (2,240) 3,579 (710) (518) 111 131 488 46 118 20 803 29 19 31,771 1,059 2,688 185 580 340 - 160 948 47 173 22 1,350 40 - 36,432 31 2,758 172 579 319 13 40,344 36,671 41,694 37,474 186 409 34 320 357 23 1,329 26,668 - 153 15 1,179 360 156 46 48 261 - 24 535 24,570 - - 12 1,272 392 28,375 26,246 29,704 26,781 11,990 10,693 9,409 (30) 951 1,660 9,297 (23) 1,308 111 11,990 10,693 Closed Group Consolidated Statement of Financial Position Current assets Cash and cash equivalents Receivables Inventories Other financial assets Other assets Total current assets Non-current assets Receivables Inventories Other financial assets Exploration and evaluation assets Oil and gas properties Other plant and equipment Deferred tax assets Lease assets Other assets Total non-current assets Total assets Current liabilities Payables Other financial liabilities Other liabilities Provisions Tax payable Lease liabilities Total current liabilities Non-current liabilities Payables Deferred tax liabilities Other financial liabilities Other liabilities Provisions Lease liabilities Total non-current liabilities Total liabilities Net assets Equity Issued and fully paid shares Shares held for employee share plan Other reserves Retained earnings Total equity NOTES TO THE FINANCIAL STATEMENTS E. OTHER ITEMS for the year ended 31 December 2021 E.9 Other accounting policies (c) New and amended accounting standards and interpretations adopted The Group adopted AASB 2020-8 Amendments to Australian Accounting Standards – Interest Rate Benchmark Reform as of 1 January 2021. The amendments provide temporary reliefs which address the financial reporting effects when an interbank offered rate (IBOR) is replaced with an alternative nearly risk-free interest rate (RFR). The amendments include the following practical expedients: • practical expedients when accounting for changes in the basis for determining the contractual cash flows of financial assets and liabilities; • reliefs from discontinuing hedge relationships; • temporary relief from having to meet the separately identifiable requirement when a RFR instrument is designated as a hedge of a risk component; and • additional AASB 7 - Financial Instruments disclosures. These amendments did not impact the financial statements of the Group other than additional required disclosures (refer to Note D.6). The Group intends to use the practical expedients in future periods when existing IBORs are replaced by RFRs. A number of other new standards are also effective from 1 January 2021 but they do not have a material effect on the Group's financial statements. (a) Summary of other significant accounting policies Tax consolidation The parent and its wholly owned Australian controlled entities have elected to enter a tax consolidation, with Woodside Petroleum Ltd as the head entity of the tax consolidated group. The members of the 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 Petroleum 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. (b) New and amended accounting standards and interpretations issued but not yet effective A number of new standards, amendments of standards and interpretations have recently been issued but are not yet effective and have not been adopted by the Group as at the financial reporting date. The Group has reviewed these standards and interpretations and has determined that none of the new or amended standards will significantly affect the Group’s accounting policies, financial position or performance. Woodside Petroleum Ltd 141 DIRECTORS’ DECLARATION In accordance with a resolution of directors of Woodside Petroleum Ltd, we state that: 1. In the opinion of the directors: (a) the financial statements and notes thereto, and the disclosures included in the audited 2021 Remuneration Report, comply with Australian Accounting Standards and the Corporations Act 2001; (b) the financial statements and notes thereto give a true and fair view of the financial position of the Group as at 31 December 2021 and of the performance of the Group for the financial year ended 31 December 2021; (c) the financial statements and notes thereto also comply with International Financial Reporting Standards as disclosed in the ‘About these statements’ section within the notes to the 2021 Financial Statements; (d) there are reasonable grounds to believe that the company will be able to pay its debts as and when they become due and payable; and (e) there are reasonable grounds to believe that the members of the Closed Group identified in Note E.8 will be able to meet any obligations or liabilities which they are or may become subject to, by virtue of the Deed of Cross Guarantee. 2. This declaration has been made after receiving the declarations required to be made to the directors in accordance with section 295A of the Corporations Act 2001 for the year ended 31 December 2021. For and on behalf of the Board R J Goyder, AO Chairman Perth, Western Australia 17 February 2022 M E O’Neill Chief Executive Officer and Managing Director Perth, Western Australia 17 February 2022 142 Annual Report 2021 INDEPENDENT AUDIT REPORT Ernst & Young 11 Mount s Bay Road Pert h WA 6000 Australia GPO Box M939 Pert h WA 6843 Tel: +61 8 9429 2222 Fax: +61 8 9429 2436 ey.com/au Independent audit or's report t o t he members of Woodside Pet roleum Lt d Report on t he audit of t he financial report Opinion We have audited the financial report of Woodside Pet roleum Ltd (t he Company) and its subsidiaries (collectively the Group), which comprises the consolidated statement of financial position as at 31 December 2021, the consolidated income statement, the consolidated statement of comprehensive income, the consolidated statement of changes in equit y and the consolidated statement of cash flows for the year then ended, notes to the financial statements, including a summary of significant accounting policies, and the directors' declaration. In our opinion, the accompanying financial report of the Group is in accordance with the Corporations Act 2001, including: a) giving a true and fair view of the Group’s financial position as at 31 December 2021 and of its financial performance for the year ended on that date. b) complying with Australian Accounting Standards and the Corporations Regulations 2001. Basis for opinion We conducted our audit in accordance with Australian Auditing Standards. Our responsibilities under those standards are further described in the Auditor’s responsibilities for the audit of the financial report section of our report. We are independent of the Group in accordance with the auditor independence requirements of the Corporations Act 2001 and the ethical requirements of the Accounting Professional and Ethical Standards Board’s APES 110 Code of Ethics for Professional Accountants (including Independence Standards) (t he Code) that are relevant to our audit of the financial report in Australia. We have also fulfilled our other et hical responsibilities in accordance with the Code. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion. Key audit mat t ers Key audit matters are those matters that , in our professional judgment, were of most significance in our audit of the financial report of the current year. These matters were addressed in the context of our audit of the financial report as a whole, and in forming our opinion thereon, but we do not provide a separate opinion on these matters. For each matter below, our description of how our audit addressed the matter is provided in that context. A member firm of Ernst & Young Global Limited Liability limited by a scheme approved under Professional Standards Legislation Woodside Petroleum Ltd 143 Independent audit report (cont.) We have fulfilled the responsibilities described in the Auditor’s responsibilities for the audit of the financial report section of our report, including in relation to these matters. Accordingly, our audit included the performance of procedures designed to respond to our assessment of the risks of material misstatement of the financial report. The results of our audit procedures, including the procedures performed to address the matters below, provide the basis for our audit opinion on the accompanying financial report. 1. Rest orat ion obligat ions Why significant How our audit addr essed t he key audit mat t er We assessed the restoration obligation provisions prepared by the Group, evaluating the assumptions and methodologies used and the estimates made. Our audit procedures included the following: ► ► ► ► ► ► ► ► evaluating the Group’s process for identif ying legal and regulatory obligations for restoration and testing the completeness of operating locations included in the restoration provision and the completeness and accuracy of data used within the Group’s estimates; in conjunction with our environmental specialists, we evaluated the restoration cost estimates based on the relevant current legal and regulator y requirements; compared current year cost estimates to those of the prior year and considered management’s explanations where these changed; compared the timing of the future cash outflows against the anticipated end of field life, cross-checking these dates were consistent to the Group’s reserves estimates and impairment calculations; evaluated the appropriateness of the discount rates used to calculate the present value of the provision; evaluated the appropriateness of management’s methodology for estimating future costs. For a sample of locations within the Group, we assessed the reasonableness of key assumptions in the estimation of future costs; assessed the competence, capability and objectivity of the Group’s internal exper ts used in the determination of the restoration provision; tested the mathematical accuracy of the restoration provision calculations and the sensitivity analysis. We also considered the adequacy and completeness of the financial report disclosure of the assumptions, key estimates and judgements applied by the Group. At 31 December 2021, the Group has recognised provisions for restoration obligations relating to onshore and offshore assets of $2,218 million. As disclosed in Note D.5, the calculation of restoration provisions is conducted by specialist engineers and requires judgemental assumptions to be made by the Group regarding removal date, compliance with environmental legislation and regulations, the extent of restoration activities required, the engineering methodology for estimating cost, future removal technologies in deter mining the removal cost, and liability-specific discount rates to determine the present value of these cash flows. The judgements and estimates in respect of restoration provisions are based on conditions existing at 31 December 2021 including key assumptions related to certain items composed of steel, or steel and concrete, with hydrocar bons removed remaining in-situ. Australian regulator approval for these items remaining in-situ will only be provided towar ds the end of field life and accordingly at 31 December 2021, there is uncertainty whether the Australian regulator will approve plans for these items to be decommissioned in-situ. Significant assumptions and estimates outlined above are inherently subjective. Changes in these assumptions can lead to significant changes in the restoration provision. In this context, the disclosures in the financial report provide particularly impor tant information about the assumptions made in the calculation of the restoration provision and uncertainties at 31 December 2021. As a result, we consider the restoration provision calculation and the related disclosures in the financial report to be a key audit matter. For the same reasons, we consider it important to draw attention to the information in Note D.5. A member firm of Ernst & Young Global Limited Liability limited by a scheme approved under Professional Standards Legislation 144 Annual Report 2021 Independent audit report (cont.) 2. Carrying value of oil and gas propert ies Why significant How our audit addressed t he key audit mat t er Australian Accounting Standar ds require an entity to assess throughout the reporting period whether there is any indication that an asset may be impaired, or that reversal of a previously recognised impairment may be required. If any such indication exists, an entity shall estimate the recoverable amount of the asset. At 31 December 2021, the Group concluded that there were impairment/ impairment reversal indicators for the Pluto-Scarborough, NWS Gas, NWS Oil and Wheatstone cash generating units (CGUs). Impairment testing was undertaken as outlined in Note B.4, resulting in an impairment reversal of $1,058 million relating to Pluto-Scarborough and NWS Gas CGUs. No impairment/ impairment reversal was recognised in respect to the NWS Oil and Wheatstone CGUs. Key assumptions, judgements and estimates, used in the formulation of the Group’s impairment testing of the oil and gas properties are disclosed in Note B.4. The assessment of indicators of impairment and reversal of impairment and the impairment testing process are complex and highly judgemental and are based on assumptions which are impacted by expected future performance and mar ket conditions. Accordingly, this matter was considered to be a key audit matter. We evaluated the Group’s consideration of internal and external sources of information in assessing whether indicators of impairment or reversal of impairment existed. Where impairment or impairment reversal indicators were present and impairment testing was conducted by the Group, we evaluated the assumptions and methodologies used by the Group and the estimates made in conducting this testing. In par ticular, we considered those judgements and estimates related to the determination of CGUs, the forecast cash flows and the inputs used to formulate those cash flows such as commodity prices, discount rates, reserves, inflation rates, operating costs and foreign exchange rates. We involved our valuations, modelling and economics specialists to assist in the impairment assessment for the audit. Our audit procedures were undertaken across the CGUs for which impairment and impairment reversal indicators were identified. Specifically, we evaluated the discounted cash flow models and other data supporting the Group’s assessment. In doing so, we: ► ► ► ► ► ► ► ► considered future production profiles compared to reserves, current approved budgets and historical production, and tested variations were in accor dance with our expectations based upon other information obtained throughout the audit; evaluated commodity prices with reference to contractual arrangements, market prices (where available), broker consensus, analyst views and historical performance; evaluated discount rates, inflation rates and foreign exchange rates with reference to market prices (where available), market indices, broker consensus and historical performance; compared future operating and development expenditure to current sanctioned budgets, historical expenditure and tested variations were in accor dance with our expectations based upon other information obtained throughout the audit; evaluated how the Group’s response to climate risk has been reflected in the assessment of the recoverable amount of the CGUs; assessed whether the reversal of impairment charge recor ded in the financial statements agreed to the underlying impairment testing models; assessed the impact of changes to key assumptions on the recoverable amount of the CGUs; and tested the mathematical accuracy of the discounted cash flow models and the sensitivity analysis. We reviewed the calculation of the extent of the original cost impaired adjusted for depreciation for the Pluto-Scarborough and NWS Gas CGUs at 31 December 2021 to test the amount recorded did not exceed the carrying value of the CGU if the prior year impairments were not initially recorded. A member firm of Ernst & Young Global Limited Liability limited by a scheme approved under Professional Standards Legislation Woodside Petroleum Ltd 145 Independent audit report (cont.) Why significant How our audit addressed t he key audit mat t er We used the work of the Group’s internal experts with respect to the hydrocarbon reserve estimates used in the Group’s impairment testing. This included understanding the reserve estimation processes carried out, the Group’s internal certification process for technical and commercial experts who are responsible for reserves, the design of the Group’s Petroleum Resources Management procedures and its alignment with the guidelines prepared by the Society of Petroleum Engineers. We also examined the competence and objectivity of the Group’s internal and external experts and the scope and appropriateness of their work. We involved our oil and gas reserves engineering specialists in the assessment of the reserves estimation methodology and to test significant revisions. We also considered the adequacy of the financial report disclosures regar ding the assumptions, key estimates and judgements applied by management for the Group’s impairment assessments, and in respect of sensitivity analysis disclosed. These disclosures are included in Note B.4. Informat ion ot her t han t he financial report and audit or’s report t hereon The directors are responsible for the other information. The other information comprises the information included in the Company’s Annual Report for the year ended 31 December 2021, but does not include the financial report and our auditor’s report thereon. Our opinion on the financial report does not cover the other information and accordingly we do not express any form of assurance conclusion thereon, with the exception of the Remuneration Report and our related assurance opinion. In connection wit h our audit of the financial report, our responsibility is to read the other information and, in doing so, consider whether the other information is materially inconsistent with the financial report or our knowledge obtained in the audit or otherwise appears to be materially misstated. If, based on the work we have performed, we conclude that there is a material misstatement of this other information, we are required to report that fact. We have nothing to report in this regard. Responsibilit ies of t he direct ors for t he financial report The directors of the Company are responsible for the preparation of the financial report that gives a true and fair view in accordance with Australian Accounting Standards and the Corporations Act 2001 and for such internal cont rol as the directors determine is necessary to enable the preparation of the financial report that gives a true and fair view and is free from material misstatement, whether due to fraud or error. In preparing the financial report, the directors are responsible for assessing the Group’s ability to continue as a going concern, disclosing, as applicable, matters relating to going concern and using the going concern basis of accounting unless the directors either intend to liquidate the Group or to cease operations, or have no realistic alternative but to do so. A member firm of Ernst & Young Global Limited Liability limited by a scheme approved under Professional Standards Legislation 146 Annual Report 2021 Independent audit report (cont.) Audit or's r esponsibilit ies for t he audit of t he financial report Our objectives are to obtain reasonable assurance about whether the financial report as a whole is free from material misstatement, whether due to fraud or error, and to issue an auditor’s report that includes our opinion. Reasonable assurance is a high level of assurance, but is not a guarantee that an audit conducted in accordance with the Australian Auditing Standards will always detect a material misstatement when it exists. Misstatements can arise from fraud or error and are considered material if, individually or in the aggregate, they could reasonably be expected to influence the economic decisions of users taken on the basis of this financial report. As part of an audit in accordance wit h the Australian Auditing Standards, we exercise professional judgment and maintain professional scepticism throughout the audit. We also: ► Ident ify and assess the risks of material misstatement of the financial report, whether due to fraud or error, design and perform audit procedures responsive to those risks, and obtain audit evidence that is sufficient and appropriate to provide a basis for our opinion. The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control. ► Obtain an understanding of internal control relevant to the audit in order to design audit procedures t hat are appropriate in t he circumstances, but not for t he purpose of expressing an opinion on the effectiveness of the Group’s internal control. ► Evaluate the appropriateness of accounting policies used and the reasonableness of accounting estimates and related disclosures made by the directors. ► Conclude on the appropriateness of the directors’ use of the going concern basis of accounting and, based on the audit evidence obtained, whether a material uncertainty exists related to events or conditions that may cast significant doubt on the Group’s ability to continue as a going concern. If we conclude that a material uncer tainty exists, we are required to draw attention in our auditor’s report to the related disclosures in the financial report or, if such disclosures are inadequate, to modify our opinion. Our conclusions are based on the audit evidence obtained up to the date of our auditor’s repor t. However, future events or conditions may cause the Group to cease to continue as a going concern. ► Evaluate the overall presentation, structure and content of the financial report, including the disclosures, and whether the financial report represents t he underlying transactions and events in a manner that achieves fair presentation. We communicate wit h the directors regarding, among other matters, the planned scope and timing of the audit and significant audit findings, including any significant deficiencies in internal control that we identify during our audit. We also provide the directors with a statement that we have complied with relevant ethical requirements regarding independence, and to communicate with them all relationships and other matters that may reasonably be thought to bear on our independence, and where applicable, actions taken to eliminate threats or safeguards applied. A member firm of Ernst & Young Global Limited Liability limited by a scheme approved under Professional Standards Legislation Woodside Petroleum Ltd 147 Independent audit report (cont.) From the matters communicated to the directors, we determine those matters that were of most significance in the audit of the financial report of the current year and are therefore the key audit matters. We describe these matters in our auditor’s report unless law or regulation precludes public disclosure about the matter or when, in extremely rare circumstances, we determine that a matter should not be communicated in our report because the adverse consequences of doing so would reasonably be expected to outweigh the public interest benefits of such communication. Report on t he audit of t he Remunerat ion Repor t Opinion on t he Remunerat ion Report We have audited the Remuneration Report included in pages 73 to 92 of the directors' report for the year ended 31 December 2021. In our opinion, the Remuneration Report of Woodside Pet roleum Ltd for the year ended 31 December 2021, complies wit h section 300A of the Corporations Act 2001. Responsibilit ies The directors of the Company are responsible for the preparation and presentation of the Remuneration Report in accordance wit h section 300A of the Corporations Act 2001. Our responsibilit y is to express an opinion on the Remuneration Report, based on our audit conducted in accordance with Australian Auditing Standards. Ernst & Young Robert A Kirkby Partner Perth 17 February 2022 A member firm of Ernst & Young Global Limited Liabilit y limit ed by a scheme approved under Professional Standards Legislat ion 148 Annual Report 2021 SHAREHOLDER INFORMATION SHAREHOLDER STATISTICS as at 1 February 2022 Number of shareholdings There were 261,019 shareholders. All issued shares carry voting rights on a one-for-one basis. Distribution of shareholdings Size of shareholding 1–1,000 1,001–5,000 5,001–10,000 10,001–100,000 Greater than 100,000 Total Number of holders 179,074 70,912 7,400 3,506 127 261,019 Unmarketable parcels There were 3,874 members holding less than a marketable parcel of shares in the company. Twenty largest shareholders HSBC Custody Nominees (Australia) Limited J P Morgan Nominees Australia Pty Limited Citicorp Nominees Pty Limited National Nominees Limited BNP Paribas Noms Pty LtdBNP Paribas Nominees Pty Ltd BNP Paribas Nominees Pty Ltd Acf Clearstream Citicorp Nominees Pty Limited BNP Paribas Nominees Pty Ltd Six Sis Ltd HSBC Custody Nominees (Australia) Limited CPU Share Plans Pty Ltd Citicorp Nominees Pty Limited Netwealth Investments Limited BNP Paribas Nominees Pty Hub24 Custodial Serv Ltd Australian Foundation Investment Company Limited McCusker Holdings Pty Ltd HSBC Custody Nominees (Australia) Limited – A/C 2 HSBC Custody Nominees (Australia) Limited-Gsco Eca Mutual Trust Pty Ltd Netwealth Investments Limited Total Number of shares 67,124,640 151,140,220 52,141,268 70,060,949 629,164,749 969,631,826 Shares Held 260,034,518 127,490,065 90,714,937 26,216,870 17,496,172 11,123,795 7,781,089 6,400,390 6,272,928 5,200,129 4,855,862 4,538,938 4,529,798 4,328,312 2,954,652 2,220,000 2,109,365 2,079,933 1,920,514 1,816,394 % of issued capital 6.92 15.59 5.38 7.23 64.89 100.00 % of issued capital 26.82 13.15 9.36 2.70 1.80 1.15 0.80 0.66 0.65 0.54 0.50 0.47 0.47 0.45 0.30 0.23 0.22 0.21 0.20 0.19 590,084,661 60.87 Substantial shareholders as disclosed in substantial shareholder notices given to the company are as follows: BlackRock Group (BlackRock Inc. and subsidiaries) 57,411,550 6.13 BlackRock Group’s substantial shareholder notice was given on 30 May 2019. There has been no notice of a change of interest of the substantial shareholder since that date. State Street Corporation and subsidiaries 50,409,641 5.20 State Street Corporation’s substantial shareholder notice was given on 4 November 2021. There has been no notice of a change of interest of the substantial shareholder since that date. 150 Annual Report 2021 Annual General Meeting The 2022 Annual General Meeting (AGM) of Woodside Petroleum Ltd will be held at 10.00 am (AWST) on 19 May 2022. 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 is 7 March 2022. Refer to Woodside’s website for copies of the Chairman’s and CEO’s speeches at woodside.com.au. Share registry enquiries Investors seeking information about their shareholdings should contact Woodside’s share registry: Computershare Investor Services Pty Limited Address: Level 11, 172 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) Facsimile: +61 3 9473 2500 Email: web.queries@computershare.com.au Website: investorcentre.com/wpl 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. 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 and Australia 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. Refer to Woodside’s website for the history of dividends paid by the company at woodside.com.au. 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. Refer to the share registry website to change details at www.investorcentre.com/wpl. Australian Securities Exchange listing Woodside Petroleum Ltd securities are listed on the ASX under the code WPL. American Depositary Receipts Citibank (Citi) sponsors a level-one American Depositary Receipts (ADR) program in the USA. One Woodside share equals one ADR and trades over the counter under the symbol ‘WOPEY’. ADR holders should deal directly with Citi on all matters related to their ADRs. Enquiries should be directed to: Citibank Shareholder Services Address: PO Box 43077 Providence Rhode Island 02940-3077 USA Toll Free Number: 1-877-CITI-ADR International callers: +1 781 575 4555 Refer to the share registry website for details of shareholdings at investorcentre.com/wpl. Facsimile: Email: +1 201 324 3284 citibank@shareholders-online.com Dividend payments Woodside declares 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. Investor Relations enquiries Requests for specific information on Woodside can be directed to Investor Relations: Address: Shareholders may have their dividends paid directly into any bank or building society account in Australia, the USA or the UK. 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 (www.investorcentre.com/wpl). Postal address: Telephone: Email: Website: Woodside Petroleum Ltd Mia Yellagonga 11 Mount Street Perth WA 6000 GPO Box D188 Perth WA 6840 +61 8 9348 4000 investor@woodside.com.au woodside.com.au Woodside Petroleum Ltd 151 Key announcements 2021 Events calendar 2022 Key calendar dates for Woodside shareholders in 2022. Please note dates are subject to review. February 17 Full-year 2021 results and briefing 17 Annual Report 2021 17 Sustainable Development Report 2021 17 Climate Report 2021 24 Ex-dividend date for dividend entitlement 25 Record date for final dividend entitlement March 23 Payment of dividend April May June July 26 First quarter 2022 results 19 Annual General Meeting 30 Half-year end 2022 21 Second quarter 2022 results August October 11 Half-year 2022 results 20 Third quarter 2022 results December 31 Year-end 2022 January Woodside expands long-term LNG supply agreement Fourth quarter 2020 report February Full-year 2020 results and briefing Annual Report 2020 Sustainable Development Report 2020 Woodside signs agreement for LNG supply March Climate reporting and non-binding shareholder vote April CEO succession update May June July Annual General Meeting First quarter 2021 report Woodside to exit Kitimat LNG Appointment of Non-Executive Director Woodside completes Sangomar acquisition from FAR Second quarter 2021 report August Scarborough project update and line item guidance Meg O’Neill appointed Woodside CEO Woodside and BHP to create a global energy company Half-year 2021 results October Third quarter 2021 report November Greater Pluto reserves and resource update Woodside agrees to sell 49% stake in Pluto Train 2 to GIP Chief Financial Officer resignation Woodside and BHP agree to create a global energy company Scarborough and Pluto Train 2 developments approved Scarborough FID teleconference and investor presentation Pluto Train 2 project December Investor Update 2021 Appointment of Chief Financial Officer January 2022 Woodside completes Pluto Train 2 sell-down to GIP Non-cash impairment reversal and other items Fourth quarter 2021 report Woodside to withdraw from Myanmar 152 Annual Report 2021 Unreasonable prejudice As permitted by sections 299(3) and 299A(3) of the Corporations Act 2001, we have omitted certain information from this operating and financial review 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, including statements of current intention, statements of opinion and expectations regarding Woodside’s present and future operations, possible future events and future financial prospects. Such statements are not statements of fact and may be affected by a variety of known and unknown risks, variables and changes in underlying assumptions or strategy that could cause Woodside’s actual results or performance to differ materially from the results or performance expressed or implied by such statements. There can be no certainty of outcome in relation to the matters to which the statements relate, and the outcomes are not all within the control of Woodside. Further information on some important factors that could cause actual results or performance to differ materially from those projected in such statements is contained in the ‘Risk’ section on pages 51-54. Woodside makes no representation, assurance or guarantee as to the accuracy or likelihood of fulfilment of any forward- looking statement or any outcomes expressed or implied in any forward-looking statement. The forward-looking statements in this report reflect expectations held at the date of this report. Except as required by applicable law or the Australian Securities Exchange (ASX) Listing Rules, Woodside disclaims any obligation or undertaking to publicly update any forward-looking statements, or discussion of future financial prospects, whether as a result of new information or of future events. 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. Woodside “greenhouse gas” or “emissions” information reported are Scope 1 GHG emissions, Scope 2 GHG emissions, and Scope 3 GHG emissions. For more information on emissions data refer to Climate Report 2021 and the Sustainable Development 2021. Other important information This report also contains references to the proposed combination of Woodside and BHP Group Limited’s oil and gas business (Proposed Transaction). The Proposed Transaction remains subject to satisfaction of certain conditions precedent including shareholder and regulatory approvals. Completion is targeted in early June 2022, with an effective date of 1 July 2021. There is no certainty or assurance that the Proposed Transaction will complete on the intended schedule or at all. Information in this report regarding the Proposed Transaction must be read subject to that uncertainty. For more information, refer to the announcement “Woodside and BHP to create a global energy company” by Woodside dated 22 November 2021, available at https:// www.woodside.com.au/media-centre/announcements. Woodside Petroleum Ltd 153 BUSINESS DIRECTORY Roebourne 39 Roe Street Roebourne WA 6718 AUSTRALIA T: +61 8 9158 8949 Seoul 11F Kwanghwamun Building 149, Sejong-daero, Jongno-gu Seoul 03186 REPUBLIC OF KOREA T: +82 2 739 3290 Singapore 12 Marina View Asia Square Tower 2 #18-03 Singapore 018961 SINGAPORE T: +65 6709 8000 Tokyo Imperial Tower 1-1 Uchisaiwaicho 1-Chome Chiyoda-ku Tokyo 100-0011 JAPAN T: +81 3 3501 7031 Yangon Level 6, Vantage Tower 623 Pyay Road Kamayut Township 11041 Yangon MYANMAR (BURMA) T: +95 1 230 7460 Dakar Serenity Building 1 Route du King Fahd Palace 2nd & 3rd floor Almadie, Dakar SENEGAL T: +221 32 824 40 60 Dili Palm Business and Trade Centre Block E01-06 Surik Mas, Fatumeta BairroPite Dili TIMOR-LESTE T: +670 3310804 Houston 3040 Post Oak Blvd Floor 18, Suite 1800-134 Houston TX 77056 USA T: +1 713 401 0000 Karratha The Quarter HQ Level 3, 24 Sharpe Avenue Karratha WA 6714 AUSTRALIA T: +61 8 9158 8100 Postal address: PO Box 517 Karratha WA 6714 AUSTRALIA London 3rd Floor, Pollen House 10-12 Cork Street Mayfair, London W1S 3NP UNITED KINGDOM T: +44 20 7009 3900 Business directory Perth Mia Yellagonga 11 Mount Street Perth WA 6000 AUSTRALIA T: +61 8 9348 4000 Postal address: GPO Box D188 Perth WA 6840 AUSTRALIA Beijing 16/F, West Tower, 1607 World Financial Centre No. 1 East 3rd Ring Middle Road Chaoyang District, Beijing, 100020 CHINA T: +86 10 8591 0577 Calgary Suite 3750 421-7th Avenue SW Calgary Alberta T2P 4K9 CANADA T: +1 855 956 0916 Postal address: PO Box 22240 Bankers Hall Calgary Alberta T2P 4J6 CANADA Canberra Suite 12.03 15 London Circuit Canberra ACT 2601 AUSTRALIA T: +61 8 9348 4000 154 Annual Report 2021 ASSET FACTS PRODUCING FACILITIES Australia1 North West Shelf Karratha Gas Plant North Rankin Complex Goodwyn A Platform Angel Platform Pluto LNG Pluto A Platform Australia Oil Wheatstone Pluto LNG Plant Ngujima-Yin FPSO Okha FPSO Julimar- Brunello Role Operator Operator Operator Operator Operator Operator Operator Operator Non- operator Equity 16.67% 16.67% 16.67% 16.67% 90% 90% Product LNG, pipeline natural gas, condensate and LPG LNG, pipeline natural gas, condensate and LPG LNG, pipeline natural gas, condensate and LPG LNG, pipeline natural gas, condensate and LPG LNG, pipeline natural gas and condensate LNG, pipeline natural gas and condensate 60% Oil 33.33% 13% Gas and Oil LNG, pipeline natural gas and condensate DEVELOPMENTS Australia1 Greater Scarborough Browse Pyxis Hub3 Julimar- Brunello Phase 22 Greater Western Flank Phase 3 Senegal Sangomar- Phase 1 Myanmar4 A-6 Development Canada Kitimat LNG5 Australia/ Timor-Leste Sunrise Role Operator Operator Operator Operator Operator Operator Equity 50-73.5% 30.6% 65% 90% Product LNG, pipeline natural gas and condensate LNG, pipeline natural gas and condensate LNG, pipeline natural gas and condensate LNG, pipeline natural gas and condensate 82% Oil 15.78 - 16.67% LNG, pipeline natural gas and condensate Joint operator 40% Non- operator 50% Operator 33.44% Pipeline natural gas LNG, Pipeline natural gas LNG, pipeline natural gas and condensate EXPLORATION Asia Pacific1 Myanmar4 Europe Republic of Korea Ireland A-76 AD-7 AD-1 and AD-8 8, 6-1N FEL 5/13 Africa Senegal Rufisque, Sangomar and Sangomar Deep Congo Marine XX Role Operator Joint Operator Joint Operator Joint Operator Operator Operator Non-operator Equity 45% 40% 50% 50% 100% 90% 42.5% Product Gas prone basin Gas prone basin Gas prone basin Gas prone basin Oil or gas prone basin Oil prone basin Oil or gas prone basin 1 For further information on Woodside’s Australian titles, please refer to the titles register website (neats.nopta.gov.au). 2 RFSU was achieved in December 2021. 3 Pyxis Hub comprises the subsea tie-back of the Pyxis, Pluto North and Xena fields to the Pluto offshore platform. RFSU was achieved for the Pyxis and Pluto North fields in October 2021. Project delivery of the Xena well is ongoing. 4 Woodside announced its decision to withdraw from its interests in Myanmar on 27 January 2022. 5 Woodside and Chevron are jointly exiting the Kitimat LNG project. Liard infrastructure free leases are progressively being transferred to Woodside at 100% during 2021. 6 Notice to terminate the Production Sharing Contract was provided to Myanma Oil and Gas Enterprise on 23 November 2021. The effective date is 30 September 2021 with the formal relinquishment process ongoing. Woodside Petroleum Ltd 155 GLOSSARY, UNITS OF MEASURE AND CONVERSION FACTORS Glossary $, $m 1P 2C 2P AGM AOI Appraisal well ASX AWST A$ Average unit cash sales Brent Cash margin CCUS CHF CO2-e Condensate COP-26 cps DRP EBIT EBITDA EBITDAX EPC, EPCI EPS US dollars unless otherwise stated, millions of dollars Proved reserves Best Estimate of Contingent resources Proved plus Probable reserves Annual General Meeting Area of interest Equity greenhouse gas emissions A well drilled to follow up a discovery and evaluate its commercial potential Australian Securities Exchange Equity lifted LNG 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.2 The proportion of LNG which Woodside is entitled to lift and sell, in its own right, as a result of its participating interest in the relevant project Front-end engineering design Australian Western Standard Time Australian dollars Average unit cash cost of sales includes production costs, cost of sales royalty and excise, shipping and direct sales costs, carbon costs and insurance; excludes exploration and evaluation, general administrative and other costs, depreciation and amortisation, PRRT and income tax Intercontinental Exchange (ICE) Brent Crude deliverable futures contract (oil price) Revenue from sale of produced hydrocarbons less production costs, royalties and excise, insurance and shipping and direct sales costs, divided by revenue from sale of produced hydrocarbons Carbon capture utilisation and storage Swiss francs 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 for 100 years. It is used to evaluate releasing (or avoiding releasing) any greenhouse gas against a common basis.1 Hydrocarbons that are gaseous in a reservoir but that condense to form liquids as they rise to the surface The 26th Conference of the Parties to the United Nations Framework Convention on Climate Change, meeting in Glasgow, November 2021. Cents per share Dividend reinvestment plan Calculated as a profit before income tax, PRRT and net finance costs Calculated as a profit before income tax, PRRT, net finance costs, depreciation and amortisation and impairment losses and impairment reversals Calculated as a profit before income tax, PRRT, net finance costs, depreciation and amortisation, impairment losses, impairment reversals and exploration and evaluation expense Engineering, procurement, construction and installation Earnings per share Frontier exploration licence FEED FEL FID Flaring FPSO Free cash flow Cash flow from operating activities less cash flow from Floating production storage and offloading Final investment decision The controlled burning of gas found in oil and gas reservoirs FVLCD GDP Gearing GHG or greenhouse gas investing activities Fair value less costs to dispose Gross domestic product Net debt divided by net debt and equity attributable to the equity holders of the parent The seven greenhouse gases listed in the Kyoto Protocol are: carbon dioxide (CO2); methane (CH4); nitrous oxide (N20); hydrofluorocarbons (HFCs); nitrogen trifluoride (NF3); perfluorocarbons (PFCs); and sulphur hexafluoride (SF6).1 Gross margin Gross profit divided by operating revenue. Gross profit excludes income tax, PRRT, net finance costs, other income and other expenses Greater Western Flank Halves of the calendar year (H1 is 1 January to 30 June and H2 is 1 July to 31 December) Health, safety and environment International Organisation for Standardisation 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 Joint venture Karratha Gas Plant Calculated as the sum of cash on hand and undrawn debt facilities Liquefied natural gas 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. Liquefied petroleum gas Total debt less cash and cash equivalents GWF H1, H2 HSE ISO JCC JV KGP Liquidity LNG Lower-carbon services LPG Net debt 1 See IFRS Foundation 2021: Climate Related Disclosures Prototype. Appendix A. 2 World Resources Institute and World Business Council for Sustainable Development 2004. “GHG Protocol: a corporate accounting and reporting standard”. 3 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.)]. In Press. Page 555. 4 IPIECA 2022. “Net zero emissions: glossary of terms”. https://www.ipieca.org/resources/awareness-briefing/net-zero-emissions-glossary-of-terms/, page 5. 156 Annual Report 2021 Net equity greenhouse gas emissions Net greenhouse gas emissions Net zero Woodside's equity share of 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 reductions achieved from the use of offsets. Net greenhouse gas emissions are equal to an entity's gross greenhouse gas emissions reduced by the number of retired offsets. 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).3 New energy Woodside uses this term to describe energy technologies, such as hydrogen or 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. Carbon offsets. Avoided GHG emission, GHG emission reduction or GHG removal and sequestration made available to another organization in the form of a carbon credit to counterbalance unabated/residual GHG emissions. Offsets Avoidance offsets: Offsets which result in the avoidance of GHG emissions that would otherwise occur without the protective actions implemented to generate the offset, for example, the avoidance of deforestation. Reduction offsets: Offsets that result in a reduction of GHG emissions from an activity that is additional, for example, CO2 capture and geological storage. Removal offsets: Offsets based on the withdrawal of GHG emissions from the atmosphere, for example through the use of GHG sinks or GHG removal technologies. Removal offsets are important in achieving net-zero emissions as they help remove and store residual emissions.4 National Offshore Petroleum Titles Administrator Net profit after tax Northern Territory North West Shelf Petroleum resources rent tax Production sharing contract Process safety event Quarters of the calendar year (Q1 is 1 January to 31 March, Q2 is 1 April to 30 June, Q3 is 1 July to 30 September, Q4 is 1 October to 31 December) Woodside’s Reconciliation Action Plan NOPTA NPAT NT NWS PRRT PSC PSE Q1, Q2, Q3, Q4 RAP *All footnotes related to this table are displayed on page 156. Units of measure bbl bbl/d Bcf Bcm boe CO₂-e kPa kt MMbbl MMboe MMBtu mmscf mmscf/d MPa Mtpa MW psi t TBtu Tcf TJ barrel barrels per day billion cubic feet billion cubic metres barrel of oil equivalent carbon dioxide equivalent thousand Pascals thousand tonnes million barrels million barrels of oil equivalent million British thermal units million standard cubic feet million standard cubic feet per day million Pascals million tonnes per annum megawatt pounds per square inch tonnes trillion British thermal units trillion cubic feet terajoules Return on equity RFSU ROACE RSSD Scope 1 GHG emissions Scope 2 GHG emissions Scope 3 GHG emissions Tier 1 PSE Tier 2 PSE TRIR TSR Unit production cost USA USD WA NPAT (excluding non-controlling interests) divided by equity attributable to the equity holders of the parent Ready for start-up Return on average capital employed, calculated as EBIT divided by average non-current liabilities and average equity attributable to equity holders of the parent Rufisque Offshore, Sangomar Offshore and Sangomar Deep Offshore 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 in accordance with the National Greenhouse and Energy Reporting (NGER) methodology as applicable in FY20-21. 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.2 Woodside estimates greenhouse gas emissions, energy values and global warming potentials in accordance with the National Greenhouse and Energy Reporting (NGER) methodology as applicable in FY20-21. Other indirect GHG emissions. Scope 3 is an optional 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.2 A typical Tier 1 process safety event is loss of containment of hydrocarbons greater than 500 kg (in any one-hour period) 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. The number of recordable injuries (fatalities, lost workday cases, restricted workday cases and medical treatment cases) per million work hours Total shareholder return Production cost ($ million) divided by production volume (MMboe) United States of America US dollars Western Australia Conversion factors1 Product Pipeline natural gas Liquefied natural gas (LNG) Condensate Oil Liquefied petroleum gas (LPG) Natural gas Dry gas Factor 1 TJ 1 tonne 1 bbl 1 bbl 1 tonne 1 MMBtu 1 MMBoe Conversion factors¹ 163.6 boe 8.9055 boe 1.000 boe 1.000 boe 8.1876 boe 0.1724 boe 5.7 Bcf 1. Minor changes to some conversion factors can occur over time due to gradual changes in the process stream. Woodside Petroleum Ltd 157 Summary charts Product view Regional view Investment Gas and condensate* Oil* Exploration and other 2021 2020 56% 39% 5% 50% 42% 8% *Indicative only as some assets produce oil and gas. Investment Australia Senegal Rest of world 2021 2020 59% 39% 2% 56% 39% 5% Our investment expenditure was primarily on Sangomar and subsea tie-backs to Pluto, NWS Project and Wheatstone. The majority of our 2021 investment was in Australia, and we continued execution of the Sangomar Field Development in Senegal. Production Natural Gas* Oil Condensate 2021 2020 81% 9% 10% 80% 10% 10% *Includes LNG, LPG and pipeline gas. Production Australia Rest of world 2021 100% 0% 2020 100% 0% The majority of our production is natural gas produced through Pluto LNG and NWS Project. Australian assets provide all of Woodside’s production volumes. Sales Revenue Natural Gas* Oil Condensate 2021 2020 81% 10% 9% 76% 12% 12% *Includes LNG, LPG and pipeline gas. Sales Revenue Australia Purchased Rest of world 2021 2020 83% 17% 0% 97% 3% 0% Gas, largely sold as LNG, continues to provide the majority of our sales revenue. Our revenue is currently derived from Australian sources, supplemented with LNG purchased in the international market. Reserves (Proved plus Probable) Dry gas Oil Condensate 2021 2020 89% 8% 3% 76% 17% 7% Reserves (Proved plus Probable) Australia Senegal Rest of world 2021 2020 94% 6% 0% 88% 12% 0% Gas represents the largest portion of Woodside’s Proved plus Probable reserves. The majority of Woodside’s Proved plus Probable reserves are located in Australia. 158 Annual Report 2021 TEN-YEAR COMPARATIVE DATA SUMMARY 2021 2020 20192,3 2018 20171 2016 2015 2014 2013 2012 Profit and loss (USDm)1,2,3 Balance sheet (USDm)2 Cashflow (USDm) and capital expenditure (USDm) Volumes1,3 Other ASX data Operating revenues Group LNG Australia domestic gas Australia LPG Australia condensate Australia Oil Australia processing and services revenue Trading revenue Other hydrocarbon revenue Shipping and other revenue Other international Total EBITDAX EBITDA4 EBIT4 Exploration and evaluation (excluding amortisation of permit acquisition) Depreciation and amortisation Amortisation of license acquisition costs Impairment/(impairment reversal) Net finance costs Tax expense Non-controlling interest Reported NPAT Reported EPS (cents)5 DPS (cents) Total assets Debt Net debt Shareholder equity Cashflow from operations Cashflow from investing Cashflow from financing Capital expenditure Exploration and evaluation Oil and gas properties and property, plant and equipment ROACE6 (%) Return on equity (%) Gearing (%) Sales (million boe) Group LNG Australia domestic gas Australia LPG Australia condensate Australia Oil Other international Total (million boe) Production (million boe) Australia LNG Australia domestic gas Australia LPG Australia condensate Australia Oil Other international Total (million boe) Reserves (Proved plus Probable) Gas (Tcf) Reserves (Proved plus Probable) Condensate (MMbbl) Reserves (Proved plus Probable) Oil (MMbbl) Other Employees Shares High (A$) Low (A$) Close (A$) Number (000’s) Number of shareholders Market capitalisation (USD equivalent at reporting date) Market capitalisation (AUD equivalent at reporting date) Finding costs ($/boe) (3 year average)7 Reported effective income tax rate (%) Net debt/total market capitalisation (%) 5,359 43 60 643 673 143 - - 41 - 6,962 4,454 4,135 3,493 319 1,687 3 (1,048) 203 1,254 53 1,983 206 135 26,474 6,797 3,772 13,443 3,792 (2,941) (1,424) 2,519 73 16 411 432 142 - - 7 - 3,600 1,991 1,922 (5,171) 3,664 83 44 586 360 119 - - 15 2 4,873 3,680 3,531 1,091 3,761 84 25 651 301 202 210 1 - 5 5,240 4,041 3,814 2,278 2,674 142 43 422 391 192 53 47 - 11 3,975 3,095 2,918 1,714 2,751 292 34 413 302 202 70 - - 11 4,075 3,004 2,734 1,388 3,095 295 34 421 650 180 354 - - 1 5,030 3,443 3,063 441 4,563 376 80 901 1,133 198 161 - - 23 7,435 5,853 5,568 3,672 3,347 366 88 1,000 896 150 - - - 79 5,926 4,460 4,188 2,538 2,834 367 125 903 1,918 125 - - - 76 6,348 5,528 5,162 3,795 69 149 227 177 270 380 285 272 366 1,812 12 5,269 269 (1,465) 53 (4,028) (424) 38 24,623 7,492 3,888 12,075 1,849 (2,112) (203) 1,688 15 737 229 480 39 343 37 91 29,353 6,849 2,791 16,617 3,305 (1,238) 317 460 355 2,178 1,591 15.6 14.8 21.9 (21.0) (33.4) 24.4 91.2 2.5 0.7 8.7 8.5 - 111.6 70.8 2.5 0.5 8.7 8.6 - 91.1 11.67 60.2 184.2 81.2 5.3 0.4 10.2 9.7 - 106.8 75.0 5.3 0.5 9.8 9.7 - 100.3 4.50 72.9 177.8 443 749 4.1 2.1 14.4 75.3 5.7 0.7 9.7 5.5 0.5 97.4 67.7 5.6 0.5 9.7 5.6 0.5 89.6 5.65 100 122.4 1,451 46 39 183 628 103 1,364 148 144 27,088 4,071 2,397 17,489 3,296 (1,772) (159) 728 993 9.3 7.8 12.1 69.6 4.6 0.4 9.2 4.2 1.2 89.2 71.9 4.6 0.6 9.3 3.8 1.2 91.4 6.05 108.2 67.7 1,188 16 - 84 465 96 1,069 123 98 25,399 5,065 4,747 15,081 2,400 (1,568) (805) 1,320 26 - 48 367 105 868 104 83 24,753 4,973 4,688 14,839 2,587 (2,473) 51 1,517 22 1,083 85 243 87 26 3 109 23,839 4,441 4,319 14,226 2,475 (5,555) (58) 328 965 1,305 1,039 1,214 4,309 7.4 7.1 23.9 61.2 6.3 0.7 7.7 6.9 1.3 84.1 61.7 6.0 0.6 8.0 6.8 1.3 84.4 6.54 117.0 69.9 6.2 5.8 24.0 63.6 12.9 0.7 9.3 6.9 1.6 95.0 63.7 12.9 0.7 9.3 6.7 1.6 94.9 7.09 124.2 74.4 2.0 0.2 23.3 57.6 13.2 0.7 8.5 12.5 0.2 92.7 57.5 13.1 0.7 8.4 12.3 0.2 92.2 7.59 133.5 42.6 1,441 21 434 163 993 102 2,414 293 255 24,082 2,586 (682) 15,876 4,785 (617) (3,119) 1,218 45 387 179 545 65 1,749 213 249 23,770 3,764 1,541 15,225 3,330 (1,059) (2,470) 261 425 17.5 15.2 (4.5) 58.3 13.3 0.8 9.4 11.2 0.2 93.2 60.3 13.3 0.8 9.1 11.4 0.2 95.1 6.65 117.1 54.1 166 420 12.0 11.5 9.2 52.4 14.0 0.9 9.5 8.0 0.9 85.7 53.6 13.9 0.9 9.5 8.2 0.9 87.0 7.09 125.2 67.0 1,184 26 157 137 614 61 2,983 366 130 24,810 4,340 1,918 15,148 3,475 161 (1,252) 383 1,145 18.3 19.7 11.2 42.6 13.9 1.1 8.6 16.8 0.8 83.8 43.9 13.8 1.1 9.3 16.0 0.8 84.9 7.51 130.9 95.9 3,670 36.14 15.27 22.74 3,684 27.40 19.20 21.93 3,834 37.40 30.49 34.38 969,632 962,226 942,287 261,019 3,662 39.00 28.45 31.32 3,511 3,597 31.88 33.97 23.94 28.16 31.16 33.08 936,152 842,445 842,445 214,350 3,456 38.33 26.20 28.72 823,911 225,138 3,803 44.23 33.71 38.01 823,911 227,798 3,896 39.54 33.29 38.90 823,911 217,383 3,997 38.16 30.09 33.88 823,911 208,277 276,431 220,065 209,753 209,383 15,948 16,817 22,666 20,681 21,762 18,922 17,250 25,664 28,579 28,983 21,264 21,881 32,396 29,320 27,868 26,251 23,663 31,317 32,050 27,914 14.65 32.0 23.7 30.44 20.5 23.1 21.71 57.2 12.3 29.90 31.7 11.6 26.21 34.0 21.8 39.06 35.9 24.8 107.45 49.8 25.0 44.09 30.1 (2.7) 30.43 29.8 5.4 14.09 27.2 6.6 1. 2017 has been restated for the impact of AASB 15 Revenue from contracts with customers. Comparative financial information prior to 2016 has not been restated for AASB 15. 2. 2019 includes the adoption of AASB 16 Leases. 3. 2019 amounts have been restated for the application of reporting on a LNG Portfolio basis. Comparative financial information prior to 2018 has not been restated. 4. The calculation for EBITDA has been updated to exclude impairment, impairment reversals and amortisation of licence acquisition costs. 2012 to 2013 EBITDA numbers have been restated to reflect this change in calculation. EBIT is calculated as a profit before income tax, PRRT and net finance costs. 5. Earnings per share has been calculated using the following weighted average number of shares (2021: 962,604,811; 2020: 951,113,086; 2019: 935,833,092; 2018: 921,165,018; 2017: 866,201,877; 2016: 835,011,896; 2015: 822,943,960; 2014: 822,771,118; 2013:822,983,715; 2012: 814,751,356). 6. The calculation for ROACE has been revised in 2014 to use EBIT as the numerator, in addition to a change in the composition of capital employed. ROACE for 2012 to 2013 has been restated to include this change. 7. Finding cost methodology is in accordance with SEC industry standard. The 2020 outcome excludes the impact of Greater Pluto (WA-404-P) Proved (1P) Undeveloped Reserves of 91 MMboe being reclassified to Best Estimate (2C) Contingent Resources, resulting from impairment of Pluto (WA-404-P). Woodside Petroleum Ltd 159 Head Office: Woodside Petroleum Ltd Mia Yellagonga 11 Mount Street Perth WA 6000 Postal Address: GPO Box D188 Perth WA 6840 Australia T: +61 8 9348 4000 F: +61 8 9214 2777 E: companyinfo@woodside.com.au Woodside Petroleum Ltd ABN 55 004 898 962 woodside.com.au