WOODSIDE ENERGY GROUP LTD (Form: 6-K, Received: 08/30/2022 06:32:33)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 6-K

REPORT OF FOREIGN PRIVATE ISSUER

Pursuant to Rule 13a-16 or 15d-16

of the Securities Exchange Act of 1934

For the month of August 2022

Woodside Energy Group Ltd

(Translation of Registrant’s Name into English)

001-41404

(Commission File Number)

Woodside Energy Group Ltd

Mia Yellagonga, 11 Mount Street

Perth, Western Australia 6000

Australia

(Address of Principal Executive Offices)

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F:

Form 20-F ☒ Form 40-F ☐

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): ☐

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): ☐

INCORPORATION BY REFERENCE

Exhibits 99.1 and 99.2 to this report on Form 6-K are furnished, not filed, and will not be incorporated by reference into any registration statement filed by the registrant under the Securities Act of 1933, except that the financial statements and related notes thereto appearing on pages 28-51 of Exhibit 99.1 shall be deemed to be incorporated by reference in Woodside Energy Group Ltd’s registration statement on Form S-8 (File No. 333-265606) and to be a part thereof from the date of this report, to the extent not superseded by documents or reports subsequently filed or furnished.

EXHIBIT INDEX


99.1		A copy of the registrant’s Half-Year 2022 Report, dated August 30, 2022.

99.2		A copy of the registrant’s Half-Year 2022 Results and Briefing Pack, dated August 30, 2022

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: August 30, 2022


WOODSIDE ENERGY GROUP LTD

By:		/s/ Warren Baillie
		Warren Baillie
		Corporate Secretary

Exhibit 99.1

LOGO

Woodside Energy Group Ltd

ACN 004 898 962

Mia Yellagonga

11 Mount Street

Perth WA 6000

Australia

T +61 8 9348 4000

www.woodside.com

ASX: WDS

NYSE: WDS

LSE: WDS

Announcement

Tuesday, 30 August 2022

HALF-YEAR REPORT FOR PERIOD ENDED 30 JUNE 2022

Financial highlights for H1 2022

•

Net profit after tax of US$1,640 million

•

Underlying net profit after tax of US$1,819 million

•

Positive free cash flow of US$2,568 million

•

Total tax, royalties and excise expense of US$1,476 million, equating to a statutory effective income tax rate of approximately 33% and an all-in effective tax rate of approximately 47%

•

Liquidity of US$7,915 million

•

Declared an interim dividend of 109 US cents per share

•

Results reflect strong operational performance and realised benefits of the merger with BHP’s petroleum business

Operational highlights

•

Delivered production of 54.9 MMboe, including 9.7 MMboe from the former BHP Petroleum assets in June 2022

•

Tolling operations commenced at NWS Project, using Pluto gas transported through the Pluto-KGP Interconnector enabling strong Pluto production performance

•

Delivered subsea projects ahead of schedule and under budget: GWF-3, Pyxis Hub, Julimar-Brunello Phase 2 in Australia and Shenzi subsea multiphase pumping in US Gulf of Mexico

•

Increased production capacity at Bass Strait, enabling Woodside to supply additional gas into the eastern Australian domestic gas market

Business highlights

•

Completed merger with BHP’s petroleum business

•

Commenced trading on the London Stock Exchange and New York Stock Exchange

•

Delivered post-merger synergies of approximately $100 million of the $400+ million per year target

•

Scarborough and Pluto Train 2 is 18% complete: procured all major items, commenced fabrication of floating production unit (FPU) topsides and pipeline, and completed fabrication of subsea trees for initial phase

•

Completed sell-down of a 49% interest in Pluto Train 2

•

Sangomar Phase 1 is 63% complete: completing final dry dock activities for the FPSO, commenced subsea installation scope, and increased drilling activity with arrival of second drillship in July

•

Awarded front-end engineering design (FEED) contract for the H2OK hydrogen project


Woodside Energy Group Ltd \| Half-Year Report 2022		1

Summary

Woodside recorded a half-year reported net profit after tax (NPAT) of US$1,640 million. Underlying NPAT was US$1,819 million, up 414% on the corresponding period in 2021. Operating revenue rose 132% year-on-year to US$5,810 million.

Woodside Energy CEO Meg O’Neill said the results reflect strong operational performance and higher realised prices, which more than doubled year-on-year to $96.4 per barrel of oil equivalent across the expanded portfolio.

“Our first results since the completion of the merger with BHP’s petroleum business highlight the increased financial and operational strength delivered by our larger, geographically diverse portfolio of high-quality operating assets.

“Production for the half year was 19% higher at 54.9 million barrels of oil equivalent, benefiting from the contribution in the month of June of the former BHP assets and improved reliability at our LNG facilities.

“In particular, production from Pluto was increased by the start-up of Pyxis Hub and the commencement of gas flows through the Interconnector pipeline to Karratha Gas Plant. This well-timed investment allowed us to supply three LNG cargoes, one condensate cargo and pipeline gas into a strong market, generating $419 million in revenue and delivering additional value to our shareholders.

“The start-up of the Pluto-KGP Interconnector also marked the beginning of the North West Shelf Project’s transformation into a tolling facility, which is essential to the long-term future of Australia’s first and largest LNG plant.

“Our subsea project teams also successfully delivered the Greater Western Flank Phase 3 and Julimar-Brunello Phase 2 projects in Australia, and the Shenzi subsea multi-phase pump in the Gulf of Mexico.

“We are increasing activities at our Scarborough and Pluto Train 2 projects in Western Australia, with all major equipment items procured, fabrication of the floating production unit topsides and Pluto Train 2 construction works underway, the subsea trees for the initial development phase complete and pipeline manufacturing progressing.

“The Sangomar Field Development Phase 1 in Senegal is also progressing strongly, with drydock activities for the FPSO conversion completed during the period and the subsea installation campaign commencing in August. A second drillship commenced drilling in July, supporting the 23-well development drilling campaign.

“Woodside continues to deliver a disciplined approach to capital management, generating $2,568 million of free cash flow during the half and demonstrating our commitment to shareholder returns with the declaration of a fully franked interim dividend of 109 US cents per share. The dividend payout is based on 80% of underlying NPAT plus 80% of the merger completion payment adjusted for working capital, equivalent to returning approximately 81% of free cash flow. Our credit ratings of BBB+ and Baa1 were reaffirmed by S&P Global and Moody’s respectively.

“We are the largest energy company listed in Australia and we are proud to be making a significant economic contribution through our continued investment in existing operations and growth projects and through our tax payments, including petroleum resource rent tax. We paid approximately A$700 million in Australian taxes, royalties and excise in the first half of this year.

“The upheavals in global and Australian energy markets witnessed over the course of the past six months have shone a spotlight on the importance of gas in the world’s energy mix and underscores our confidence in the longer-term demand outlook for gas, which makes up 70% of Woodside’s portfolio.

“Safe and reliable supplies of gas are not only critical to global energy security but will play a key role as our customers seek to decarbonise, alongside new energy sources such as hydrogen and ammonia that Woodside is investing in.

“Our strategy to thrive through the energy transition as a low-cost, lower-carbon energy provider continues to progress through recently announced initiatives across hydrogen refuelling, carbon capture and storage and carbon to products technologies,” she said.


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Financial summary

Key metrics


				H1 2022		H1 2021		Change %
Operating revenue	$	million			5,810		2,504		132	%
EBITDA¹	$	million			3,971		1,496		165	%
EBIT¹	$	million			2,982		621		380	%
Net profit after tax (NPAT)²^,³	$	million			1,640		317		417	%
Underlying NPAT¹	$	million			1,819		354		414	%
Net cash from operating activities⁴	$	million			2,523		1,333		89	%
Investment expenditure	$	million			1,550		788		97	%
Capital investment expenditure^1,⁵	$	million			1,509		720		110	%
Exploration expenditure^1,⁶	$	million			41		68		(40	%)
Free cash flow^1,4,⁷	$	million			2,568		326		688	%
Dividends distributed	$	million			1,018		115		785	%
Interim dividend declared		US cps			109		30		263	%

Key ratios
Earnings		US cps			145.5		33.3		337	%
Gearing¹			%		6.8		23.3		(17	%)

Production
Gas		MMboe			41.9		37.6		11	%
Liquids		MMboe			13.0		8.7		49	%

Total		MMboe			54.9		46.3		19	%


Sales volumes
Gas		MMboe			47.8		45.5		5	%
Liquids		MMboe			11.8		8.4		40	%

Total		MMboe			59.6		53.9		11	%

Appendix 4D

Results for announcement to the market

More information is available on page 55

US$ million

Revenue from ordinary activities

Increased

132

%⁸

5,810

Net profit for the period attributable to equity holders of the parent¹

Increased

417

%⁸

1,640

Underlying net profit after tax¹

Increased

414

%⁸

1,819

Free cash flow¹

Increased

688

%⁸

2,568

Interim dividend – fully franked

109 US cps H1 2022

Record date for determining entitlements to the dividend

9 September 2022

These are Alternative Performance Measures (APM) which are non-IFRS measures that are unaudited but derived from auditor reviewed Half-year Financial Statements. These measures are presented to provide further insight into Woodside’s performance. Refer to Alternative Performance Measures for a reconciliation for these measures to Woodside’s financial statements on pages 61-62 and Non-IFRS Measures on pages 65-66 for more information about non-IFRS measures.

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

³	The global operations effective income tax rate (EITR) is ~33%. The EITR is calculated as the Group’s income tax expense divided by profit before income tax. EITR for H1 2021 is ~39%

⁴	H1 2021 comparative has been restated due to the reclassification of purchases of shares and payments relating to employee share plans from cash flows from operating to financing activities.

⁵	Excludes exploration capitalised and the benefit of Global Infrastructure Partners’ (GIP) additional contribution to Pluto Train 2.

⁶	Excludes prior period expenditure written off and permit amortisation and includes evaluation expense.

⁷	Cash flow from operating activities and cash flow from investing activities.

⁸	Comparisons are to half-year ended 30 June 2021.


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Net profit after tax reconciliation

The following table summarises the variance between the H1 2021 and H1 2022 results for the contribution of each line item to net profit after tax (NPAT).


2021 H1 reported NPAT	$317 million
Sales revenue – price	+$2,482 million	Higher realised prices across all markers
Sales revenue – volume	+$820 million	Increased volume due to contribution of BHP Petroleum assets and Interconnector volumes
Movement in onerous contract provision	+$195 million	Derecognition and unwind of the Corpus Christi onerous contract provision
Other income	+$474 million	Primarily sale of 49% of the Pluto Train 2 Joint Venture
Cost of production	-$309 million	Increased royalties and excise due to higher revenue
Trading costs	-$435 million	Higher prices but fewer cargoes traded
General, administrative and other costs	-$474 million	Primarily due to merger transaction costs
Other expenses	-$343 million	Primarily losses associated with hedging
Income tax and PRRT	-$1,087 million	Increased taxes due to higher revenue
2022 H1 reported NPAT	$1,640 million
2022 H1 NPAT adjustments	+$179 million	Adjustment for merger transaction costs and derecognition of the Corpus Christi onerous contract provision
2022 H1 underlying NPAT	$1,819 million

Capital management

Interim dividend

Woodside’s capital management framework is focused on disciplined capital management to optimise value and shareholder returns through the cycle. A 2022 interim fully franked dividend of 109 US cents per share (cps) has been declared, reflecting Woodside’s strong operational performance and the contribution of BHP’s petroleum business from the merger effective date of 1 July 2021.

The interim dividend comprises:

•

76 US cps, being an 80% payout of underlying NPAT, which is at the top end of Woodside’s target range of 50% to 80%

•

33 US cps, being 80% of the net cash payment received from BHP following completion of the merger, adjusted for a minimum working capital requirement.

The value of the interim dividend payment is $2,070 million.

Dividend reinvestment plan

The dividend reinvestment plan (DRP) remains active, allowing eligible shareholders to reinvest their dividends directly into shares. The discount has been reduced to nil and Woodside intends to purchase on-market the shares to be distributed under the DRP. To the extent that the on-market purchase is not able to be completed for any reason, Woodside may issue new ordinary shares to meet its obligation under the DRP. Eligible shareholders have until 12 September 2022 to change their DRP election.⁹ The DRP Rules were amended with effect from 30 August 2022. A copy of the revised DRP Rules is available on Woodside’s website www.woodside.com/investors/dividends/dividend-reinvestment-plan.

⁹

Eligibility is addressed in the DRP Rules. A Shareholder is not eligible to participate in the DRP if they are a “U.S. person” (as defined in Regulation S under the U.S. Securities Act of 1933), or if they are representing the estate of any deceased person where Woodside has been notified of the estate.


Woodside Energy Group Ltd \| Half-Year Report 2022		4

Liquidity and debt service

During the half, Woodside generated $2,523 million of cash flow from operating activities and delivered positive free cash flow of $2,568 million.

Woodside increased its standby debt facilities from $3,100 million to $3,300 million and refinanced near-term maturities. Liquidity at the end of the period was $7,915 million and Woodside’s drawn debt at the end of the period was $5,404 million. Woodside will continue to actively manage its debt portfolio throughout 2022.

Credit rating management

Woodside’s gearing at the end of 2021 was 21.9%, within our target range of 15% to 35%. The merger transaction was on a debt-free basis and on completion Woodside issued 914,768,948 new shares. The increase in equity, increased cashflows and immaterial change in debt resulted in Woodside’s gearing reducing to 6.8% at the end of H1 2022.

Given the structural changes to Woodside’s balance sheet, management has reviewed the target balance sheet metrics and determined that a target gearing range of 10% to 20% through the cycle is appropriate for the scale and financial strength of the new organisation. Following the distribution of the 2022 interim dividend, gearing is expected to increase to approximately 13%, which is within the new target range.

A low level of net debt positions Woodside’s balance sheet for the significant capital expenditure program ahead and is designed to protect against external volatility through the investment cycle. As a result, Woodside’s gearing may at times fall outside the target range of 10% to 20% as the balance sheet is managed through the investment cycle. Woodside’s estimated capital expenditure for the Scarborough, Pluto Train 2 and Sangomar projects from 1 July 2022 to 31 December 2024 is approximately $9 billion at current equity levels.¹⁰

Woodside’s commitment to an investment grade credit rating remains unchanged and supports Woodside’s aim of providing sustainable returns to shareholders and to investing in future growth opportunities, in accordance with the capital allocation framework.

During the half, our credit ratings of BBB+ and Baa1 were both reaffirmed by S&P Global and Moody’s respectively.¹¹

Commodity price risk management

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

As at 30 June 2022, Woodside has placed oil price hedges for:

•

approximately 17.5 MMboe of 2022 production at an average price of $74.6 per barrel of which approximately 5.8 MMboe has been delivered

•

approximately 21.8 MMboe of 2023 production at an average price of $74.5 per barrel.

Woodside has also placed a number of hedges for Corpus Christi LNG volumes to protect against downside pricing risk. These hedges are Henry Hub and Title Transfer Facility (TTF) commodity swaps. As a result of hedging and term sales, approximately 94% of Corpus Christi volumes in 2022, approximately 73% in 2023 and approximately 27% of 2024 have reduced pricing risk (as at 30 June 2022).

¹⁰	Indicative only, not guidance. Excludes the benefit of the additional capital contribution by GIP for Pluto Train 2.

¹¹	A securities rating is not a recommendation to buy, sell or hold securities and may be subject to revision or withdrawal at any time.


Woodside Energy Group Ltd \| Half-Year Report 2022		5

Woodside and BHP Petroleum merger

The merger of Woodside and BHP’s petroleum business completed on 1 June 2022 following Woodside shareholder approval on 19 May 2022.

On completion, Woodside acquired the entire share capital of BHP Petroleum International Pty Ltd (BHPP) and issued 914,768,948 new Woodside shares to BHP. Woodside received net cash of approximately $1.1 billion, which included the cash remaining in BHPP bank accounts of $399 million immediately prior to completion. All completion payments are subject to a customary post-completion review which may result in an adjustment.

Trading commenced on 2 June 2022 under the ticker WDS of the new Woodside shares on the Australian Securities Exchange (ASX), and Woodside depository shares on the New York Stock Exchange (NYSE).

Trading commenced on 6 June 2022 of Woodside shares on the Main Market for listed securities of the London Stock Exchange (LSE), also under the ticker WDS.

The proposed appointment of a BHP director to the Board of Woodside following completion of the merger has been reviewed by both Woodside and BHP and is not considered necessary.

Woodside has delivered synergies of approximately $100 million of the $400+ million per year synergies target, with more than $300 million of further opportunities for synergies identified.¹²

Operational overview

Pluto LNG

Pluto LNG is an LNG facility in the Pilbara region of Western Australia, comprising an offshore platform and one onshore LNG processing train. Woodside is operator and holds a 90% participating interest.

Woodside achieved strong production performance at Pluto LNG, delivering 24.3 MMboe production (Woodside share) in the first half of 2022. This was an 11% increase compared to the first half of 2021 due to the start-up of the first phase of the Pyxis Hub and the Pluto-Karratha Gas Plant Interconnector, enabling Pluto gas to be processed at the Karratha Gas Plant (KGP).

The tenth anniversary of the first LNG produced at Pluto occurred in May 2022. The project also delivered its 700th cargo in June 2022. The sale of LNG and condensate produced at Pluto LNG in the past decade has generated approximately $23 billion in revenue for Woodside.

Preparatory siteworks and installation of high-voltage cable were undertaken to support the potential future use of imported lower-carbon electricity in Pluto LNG operations.

The Pyxis Hub infill campaign involves the subsea tie-back of the Pyxis, Pluto North and Xena fields to the Pluto offshore platform. The Pyxis and Pluto North wells commenced operations in January 2022, increasing offshore deliverability and enabling the delivery of Pluto gas to North West Shelf through the Pluto-KGP Interconnector. The Xena-02 well is on track to achieve ready for start-up (RFSU) in the second half of 2022.

North West Shelf Project

The North West Shelf Project (NWS) is one of Australia’s largest resources projects and includes three offshore platform hubs and five onshore LNG processing trains. It produces LNG, condensate, pipeline gas and natural gas liquids (NGLs). Woodside is operator and holds a 33.33% participating interest.

Woodside’s share of production was 13.1 MMboe. This was a 1% decrease compared to H1 2021 due to natural field decline and planned maintenance, partially offset by the start-up of Greater Western Flank Phase 3 (GWF-3) and the contribution of Woodside’s increased participating interest in June.

A major turnaround was successfully completed on LNG Train 3 at KGP in May 2022.

The GWF-3 infill project achieved RFSU in April 2022 and the Lambert Deep infill well achieved RFSU in July 2022. Both projects were delivered ahead of schedule and under budget.

Tolling operations commenced at the NWS Project in March 2022 with the processing of gas delivered from Pluto through the Pluto-KGP Interconnector. The first LNG cargo produced from gas delivered through the Interconnector was loaded in April 2022. This is the first example of KGP processing gas owned by other resource owners, utilising spare capacity for LNG and domestic gas production. The NWS Project is also expected to commence processing Waitsia gas from 2023.

¹²	Delivered synergies of $100 million is on a pre-tax 100% basis and excludes transition and separation costs.


Woodside Energy Group Ltd \| Half-Year Report 2022		6

With the additional gas supplied from GWF-3, Lambert Deep and through the Interconnector, KGP is expected to operate near full production rates for the remainder of 2022.

The Western Australian Environmental Protection Authority (EPA) recommended in June 2022 that the NWS Project Extension proposal may be implemented subject to key environmental conditions being met. The proposal supports the long-term operations and processing of future third-party gas resources. The EPA’s report is subject to a statutory appeals process before the Western Australian Minister for the Environment makes a decision on the proposal.

Wheatstone and Julimar-Brunello

Wheatstone is an LNG processing facility near Onslow, Western Australia, comprising an offshore production platform and two onshore LNG production trains. It processes gas from several offshore gas fields including Julimar and Brunello. Woodside holds a 13% non-operating interest in the Wheatstone project; and a 65% participating interest in the Julimar-Brunello fields, for which Woodside is operator.

Woodside’s share of production was 5.2 MMboe. This was a decrease from the 7.4 MMboe produced in the first half of 2021, driven predominantly by planned onshore and offshore turnaround activity which was completed in the first half of 2022.

The Julimar-Brunello Phase 2 project, which included the tie-back of the Julimar field to the Wheatstone platform, achieved steady-state operations in March 2022.

Australia Oil

Woodside operates three floating production storage and offloading (FPSO) facilities off the north-west coast of Western Australia – the Okha FPSO (Woodside interest: 50%), Ngujima-Yin FPSO (Woodside interest: 60%) and Pyrenees FPSO (Woodside interest: 40% in WA-43-L and 71.4% in WA-42-L). The Pyrenees FPSO was added to Woodside’s portfolio on 1 June 2022 on completion of the merger.

Woodside’s share of production from the Okha FPSO, which produces oil from the Cossack, Wanaea, Lambert and Hermes fields, was 0.9 MMboe compared to 0.6 MMboe in H1 2021.

Woodside’s share of production from the Ngujima-Yin FPSO, which produces oil from the Vincent and Greater Enfield resources, was 3.7 MMboe. This was 12% higher compared to the first half of 2021 due to the impact on production of Tropical Cyclone Seroja in H1 2021 and increased production rates when the Cimatti field oil and water injection wells were brought back online in March 2022.

Woodside’s share of production from the Pyrenees FPSO, which produces oil from the Crosby, Ravensworth, Stickle, Wildbull, Tanglehead and Moondyne fields, was 0.2 MMboe in June 2022.

Macedon

Macedon produces pipeline gas for the Western Australian domestic gas market and was added to Woodside’s portfolio on 1 June 2022. Gas is piped from a field located off the coast of Exmouth, Western Australia, to an onshore gas treatment plant located near Onslow, Western Australia. Woodside is operator and holds a 71.4% participating interest. Woodside’s share of production was 0.7 MMboe in June 2022.

Bass Strait

The Gippsland Basin Joint Venture (GBJV) produces gas and oil from the Bass Strait in the south-east of Australia and was added to Woodside’s portfolio on 1 June 2022. Gas produced by the GBJV is supplied into the eastern Australian domestic gas market.

Woodside holds a 50% non-operating interest in the GBJV and a 32.5% non-operating interest in the Kipper Unit Joint Venture. Kipper unit production is processed by the GBJV under a processing agreement. Woodside’s share of production from the Bass Strait was 3.3 MMboe in June 2022.

An offshore fuel gas pipeline was redirected in June 2022 to increase production capacity from 970 terajoules to 1,020 terajoules per day (100%). This enabled Woodside to supply additional gas into the eastern Australian domestic gas market.

The GBJV is progressing a feasibility study of the potential development of a south-east Australian carbon capture and storage hub (SEA CCS) to support the decarbonisation goals of the GBJV participants, other local industry, and the Victorian and Commonwealth Governments. SEA CCS aims to utilise existing infrastructure to capture and store up to 2 MtCO₂ per year in the depleted Bream reservoir located offshore Victoria.


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In August 2022, the GBJV executed a long-term supply agreement with BOC for the supply of carbon dioxide (CO₂) from the GBJV’s Longford Gas Conditioning Plant. The CO₂ will be captured and transformed into products for the food, beverage, hospitality, manufacturing and medical industries through an adjacent treatment facility to be constructed by BOC.

Atlantis

Atlantis is a conventional oil and gas development and is one of the largest producing fields in the US Gulf of Mexico (GoM). Atlantis was added to Woodside’s portfolio on 1 June 2022 and Woodside holds a 44% non-operating interest. The Atlantis development includes a semi-submersible facility with 26 active producer wells and two water injector wells. Oil and gas from the field is transported onshore through existing pipeline infrastructure, including the Caesar and Cleopatra pipelines in which Woodside has a participating interest.

Woodside’s share of production from Atlantis was 1.1 MMboe in June 2022. Ocean bottom node (OBN) seismic acquisition was completed in June 2022, supporting optimisation of future development opportunities. A planned seven-week turnaround was completed in August 2022.

Mad Dog

Mad Dog is a conventional oil and gas development located in the US GoM and was added to Woodside’s portfolio on 1 June 2022. The Phase 1 development includes a spar facility with drilling capability and 10 active producer wells. Further drilling operations are in progress, with an 11th producing well underway and three additional wells or side tracks planned. Oil and gas from the field is transported onshore through existing pipeline infrastructure, including the Caesar and Cleopatra pipelines. Woodside holds a 23.9% non-operating interest in Mad Dog.

Woodside’s share of production from Mad Dog was 0.4 MMboe in June 2022. OBN seismic acquisition is in progress to inform subsequent development phases.

Shenzi

Shenzi is a conventional oil and gas field developed through a tension leg platform (TLP) located in the US GoM. It was added to Woodside’s portfolio on 1 June 2022. The field has 16 active producer wells and five water injector wells. Crude oil is transported to connecting pipelines for sale to Gulf coast customers. Natural gas is transported onshore through a lateral pipeline tied into the Cleopatra natural gas pipeline.

Woodside is operator for Shenzi and holds a 72% participating interest. Woodside’s share of production from Shenzi was 0.8 MMboe in June 2022. A side track development well was brought online in July 2022, increasing field production rates. A subsea multi-phase pump was installed and commissioned ahead of schedule during a planned Shenzi TLP shutdown in April-May 2022, and is expected to improve recovery from existing producing wells and future infill wells.

Shenzi North is a two-well subsea tieback to the Shenzi TLP. Drilling of the second development well commenced in July 2022. The Shenzi North project is targeting first oil in 2024 following drilling and completion activities and installation of subsea equipment.

Greater Angostura

Greater Angostura includes the Angostura and Ruby conventional oil and gas fields, located offshore Trinidad and Tobago (T&T). It was added to Woodside’s portfolio on 1 June 2022. The development includes an offshore central processing facility and five well head platforms. Oil and gas is exported to shore for sale. Woodside is operator and holds a 45% participating interest in the Angostura field and a 68.5% participating interest in the Ruby field. Woodside’s share of production from Greater Angostura was 1.0 MMboe in June 2022.


Woodside Energy Group Ltd \| Half-Year Report 2022		8

Projects

Scarborough and Pluto Train 2

The Scarborough field is located approximately 375 km off the coast of Western Australia. The development will include a floating production unit (FPU), eight wells drilled in the initial phase and 13 wells drilled over the life of the Scarborough field, a trunkline to shore and new onshore infrastructure.

Expansion of the onshore Pluto LNG facility will include the construction of a second LNG train (Pluto Train 2), associated domestic gas processing facilities and supporting infrastructure and modifications to Pluto Train 1. A final investment decision (FID) was taken in November 2021. Woodside is operator and has a 100% participating interest in Scarborough and a 51% participating interest in Pluto Train 2. The sale to Global Infrastructure Partners (GIP) of a 49% non-operating participating interest in the Pluto Train 2 Joint Venture was completed in January 2022.

The Scarborough and Pluto Train 2 projects are progressing with all major equipment items procured, including compressors, generators and turbines. Fabrication of the FPU topsides has commenced, pipeline manufacturing was 25% progressed as of 30 June and fabrication of the subsea trees for the initial development phase is complete. Pluto Train 2 construction works have commenced.

Woodside is working with its key contractors to maximise local content and Indigenous contracting opportunities.

Front-end engineering design (FEED) activities for Pluto Train 1 modifications continued on schedule during the first half of 2022.

Approval was granted in April 2022 by the Commonwealth-Western Australian Joint Authority for the Scarborough Field Development Plan, enabling commencement of petroleum recovery operations from Petroleum Production Licences WA-61-L and WA-62-L. Woodside received government approval to construct and operate the Scarborough pipeline in Commonwealth and State waters.

Approval was granted in June 2022 to increase the diameter of the Scarborough trunkline within State waters from 32 inches to 36 inches. Assessment by regulators of secondary environmental approvals continues for offshore execution activities.

The sell-down process for equity in the Scarborough Joint Venture is progressing. Woodside is targeting first LNG cargo in 2026.

Sangomar Field Development Phase 1

The Sangomar Field Development Phase 1 is Senegal’s first offshore oil project and includes a stand-alone FPSO, 23 wells and supporting subsea infrastructure. It is designed to allow the tie-in of subsequent phases. Woodside is operator and has an 82% participating interest in the project. The project was 63% complete at 30 June 2022.

Key work scopes completed for the FPSO in the first half of 2022 included final dry dock activities for the facility and installation of the external turret. The FPSO conversion activities were disrupted by COVID restrictions at several construction yards in the first half of 2022. As a result, the FPSO is expected to be moved during Q4 2022 from China to the Keppel Shipyard in Singapore to complete the topside integration and commissioning.

In Senegal, installation of the mooring system for the FPSO in the Sangomar field was successfully completed in July 2022. In August 2022, the subsea installation campaign commenced in the field and the majority of the subsea equipment manufacturing was completed. The 23-well development drilling campaign is progressing and the second drillship, the Ocean BlackHawk, commenced drilling in July 2022.

Confirmation was received from the Government of Senegal that a two-year exploration period extension has been granted for the Production Sharing Contract (PSC) area covering SNE North-Spica in March 2022 and an appraisal well is planned in H2 2022.

Woodside has ended the current sell-down process for Sangomar. Woodside is targeting first oil in the second half of 2023.

Mad Dog Phase 2

Mad Dog Phase 2 is a development of the southern flank of the Mad Dog field and includes the installation of a new floating production facility, Argos, with production capacity of up to 140,000 gross barrels of oil equivalent per day (Woodside interest: 23.9%). The hook-up and commissioning program of the Argos platform topsides is proceeding, and a successful drilling campaign is nearing completion. An issue with two of the production flexible joints was detected during testing. This is being assessed and an update on whether the expected project start-up in 2022 is impacted will be provided in due course.


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Development activities

Trion

Trion is a greenfield oil and gas opportunity in the Mexican waters of the western Gulf of Mexico. The Trion field is located in a water depth of 2,500 m approximately 180 km off the Mexican coastline and 30 km south of the US/Mexico maritime border. The Trion development would be Mexico’s first deepwater oil development. Woodside is operator and has a 60% participating interest.

Trion is a large field with unrisked 2C contingent resources of 536 MMboe 100% (Woodside share: 321.6 MMboe), with 88% being oil.

Trion is a proposed 24 well subsea development connected to a FPU capable of producing and transferring 100,000 barrels of oil per day to a floating storage and offloading (FSO) vessel, from where the oil will be transported to markets. Produced gas will primarily be injected into the reservoir for enhancing recovery and excess gas will be transported by a pipeline. By using new technologies and optimising operating practices, Trion carbon emissions are expected to be lower than industry average for this type of deepwater development (<15 kgCO₂e/boe compared to industry average of 20 kgCO₂e/boe).

A six-penetration appraisal program was completed in 2021. Trion was approved to move into FEED in August 2021 and the FEED studies were completed in June 2022. Due to volatility in the supply chain and market, the project team is re-assessing the best contracting strategies and engaging with contractors with the objectives of increasing predictability of cost and schedule ahead of a potential FID in 2023. Woodside and PEMEX are actively collaborating on finalising the field development plan to support this decision.

Wildling

Wildling was a two-well tieback opportunity to the Shenzi TLP in the central GoM. Drilling of an appraisal well was completed in July 2022 and sub-commercial quantities of hydrocarbons were encountered. The well was plugged and abandoned, and Woodside does not plan to pursue any further Wildling development activities in Blocks GC564 or GC520.

Browse

The Browse development comprises the Calliance, Brecknock and Torosa gas and condensate fields located approximately 425 km north of Broome, Western Australia. Woodside is operator and holds a 30.6% participating interest.

Commercial discussions and technical studies, along with title and primary environmental approvals, are being progressed in support of the Browse to NWS development concept.

Carbon management is a key focus for the development and a carbon capture and storage (CCS) concept is being evaluated. In August, Woodside was awarded a greenhouse gas assessment permit over the Calliance field.

Calypso

Calypso is located in Trinidad and Tobago, approximately 220 km off the coast of Trinidad, and comprises several gas discoveries in Block 23(a) and Block TTDAA 14. Woodside is operator and holds a 70% participating interest. Two appraisal wells were drilled in 2021 to delineate the resource and provide information for development studies. Appraisal results are being assessed in conjunction with conceptual engineering studies.

Sunrise

The Sunrise development comprises the Sunrise and Troubadour gas and condensate fields which are located approximately 450 km north-west of Darwin and 150 km south of Timor-Leste. Woodside is operator and holds a 33.44% participating interest. The Sunrise Joint Venture participants continue to engage the Australian and Timor-Leste Governments on a new Greater Sunrise PSC, which is required under the 2019 Maritime Boundary Treaty. In the first half of 2022, two PSC trilateral meetings were held with the Australian and Timor-Leste Governments with further meetings anticipated in the second half of 2022.


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Exploration

Woodside is participating in the non-operated Starman-1 well, which is currently drilling in the US Gulf of Mexico. Woodside is also planning to drill the operated Hoodoo prospect in the western Gulf of Mexico in the second half of 2022 with co-owner Oxy, which acquired a 30% working interest in the Hoodoo-1 exploration well and 28 blocks around the prospect via a farm-down agreement executed in August 2022.

In the western US Gulf of Mexico, a lease exchange agreement was executed with Shell in April 2022, swapping working interest on multiple lease blocks to create two hubs; one Woodside-operated (Woodside interest 60%) and one Shell-operated (Woodside interest 40%).

In Barbados, a farm-out agreement with Shell was signed in March 2022 to assign a 40% interest in two offshore exploration licences for the Bimshire and Carlisle Bay Blocks. The agreement is subject to customary regulatory approvals and third-party consents and completion is targeted for H2 2022.

Woodside and operating partner, TotalEnergies, have completed a joint farm-down of a 30% working interest in block Marine XX in the Congo to Petronas. This was effective 27 July 2022 and Woodside’s working interest is now 22.5%.

Seismic surveys were completed offshore northern Australia (2D Galactic Marine Seismic Survey) in May 2022 and in the Egyptian Red Sea Blocks 3 and 4 in July 2022.

New energy and technology

Woodside is intending to thrive through the energy transition and has set a target to invest $5 billion in new energy products and lower-carbon services by 2030, in alignment with Woodside’s capital allocation framework.¹³ In support of this strategy a range of opportunities are being progressed.

H2OK

H2OK is a proposed liquid hydrogen project in the Westport Industrial Park, Ardmore, Oklahoma. Woodside is operator and holds a 100% interest. Phase 1 involves construction of an initial 290-megawatt (MW) facility, producing up to 90 tonnes per day (tpd) of liquid hydrogen through electrolysis, initially targeting the heavy transport sector.

FEED commenced in January 2022, with award of contracts for electrolysis and liquefaction equipment packages pending. Woodside is actively marketing hydrogen offtake and is advancing a number of agreements in support of a targeted final investment decision in 2023. Further FEED activities will mature the integrated facility design, cost and schedule.

H2Perth

H2Perth is a proposed world-scale liquid hydrogen and ammonia production facility in Perth, Western Australia. The development concept has been updated to increase ammonia production in the initial phase from 0.6 Mtpa to 0.84 Mtpa. Environmental studies continue, including assessment of flora and fauna, greenhouse gas management, heritage, groundwater sampling, discharge modelling, air, noise, emissions management, traffic modelling and visual impact. A pre-FEED contract was awarded to McDermott in May 2022. Woodside holds a 100% interest in H2Perth and is targeting FID in 2024.

Hydrogen Refueller @H2Perth

Woodside is advancing plans for a proposed self-contained hydrogen production, storage and refuelling station, located in the Rockingham Industry Zone in Western Australia. Subject to necessary commercial agreements and regulatory approvals, Woodside is targeting start-up of the Hydrogen Refueller @H2Perth in 2024.

¹³	Individual investment decisions are subject to Woodside’s investment hurdles. Not guidance. Potentially includes both organic and inorganic investment.


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H2NZ and H2TAS

Woodside has been selected as one of two companies to enter final stage negotiations to become the lead developer of the Southern Green Hydrogen project in Southland, New Zealand. Southern Green Hydrogen is a joint project by Meridian Energy and Contact Energy.

H2TAS is a proposed renewable ammonia and hydrogen production facility in the Bell Bay area of northern Tasmania. The development concept would utilise a combination of wind and hydroelectric power.

Heliogen

Heliogen and Woodside entered into a project agreement in March 2022 to deploy a 5 MWe module of Heliogen’s AI-enabled concentrated solar energy technology in California. In the first half of 2022, Woodside has contributed approximately $11 million to this project. Heliogen and Woodside have also signed a collaboration agreement to jointly market Heliogen’s renewable energy technology in Australia.

Heliogen has established a facility in California to manufacture the solar reflectors and other components required for the 5 MWe module.

Woodside Solar Project

Woodside is progressing the proposed Woodside Solar Project, a solar facility which would initially generate electricity from a large-scale solar photovoltaic farm, complemented by a battery energy storage system.

Negotiations are advancing with key stakeholders and potential industrial customers aiming to integrate renewable energy in their operations.

Carbon management

Woodside continues to grow its portfolio of offsets and carbon origination projects, while also progressing several CCS opportunities across Australia. In addition to its involvement in the south-east Australia CCS hub, Woodside was awarded two greenhouse gas assessment permits by the Australian Department of Industry, Science, Energy and Resources. These permits enable potential CCS in the Browse Basin (operated) and the Bonaparte Basin (non-operated).

Carbon capture and utilisation (CCU)

Woodside launched a CCU collaboration with US-based technology developers ReCarbon and LanzaTech in March 2022. The companies are investigating the viability of a potential CCU pilot facility in Perth, Western Australia.

A term sheet was agreed in May 2022 between Woodside and the Eastern Metropolitan Regional Council (EMRC) for a proposed option to lease land. The option would provide for use of EMRC’s Red Hill Waste Management Eco Park near Perth for a pilot CCU facility, and for the supply of landfill gas by EMRC to Woodside.

Woodside agreed in July 2022 to invest $9.9 million in String Bio Private Limited (String Bio), the developer of a patented process for recycling greenhouse gases into products such as livestock feed. The investment is subject to conditions precedent. Woodside and String Bio entered a strategic development agreement to explore opportunities for the potential commercial scale-up of String Bio technology.

Technology

Woodside committed A$10 million in financial and in-kind support in April 2022 to Curtin University in Perth, Western Australia after it was selected by the Australian Government to receive funding as part of the Trailblazer University Program. Together, Woodside and the Government are supporting the development of a research commercialisation hub for resources technologies, such as hydrogen and critical minerals. This aligns with Woodside’s focus on innovative solutions and the new technology to support industry needs.


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Environmental, Social and Governance (ESG)

Climate

Woodside released its Climate Report 2021, which outlines its response to climate change and strategy to thrive through the energy transition as a low-cost, lower-carbon energy provider. The report is structured to align with the Task Force on Climate-Related Financial Disclosures (TCFD) recommendations framework. Woodside continues to engage with shareholders and other stakeholders on Woodside’s climate strategy.

Woodside participated in the pilot Corporate Emissions Reduction Transparency (CERT) report in the first half of 2022, enabling Australia’s Clean Energy Regulator (CER) to verify that at 31 December 2021, Woodside had made progress towards its goal of a 15% reduction in net equity scope 1 and 2 greenhouse gas emissions by 2025 against its 2016-2020 baseline.

Health, Safety and Environment (HSE)

Woodside experienced one Tier 2 loss of primary containment process safety event on the Goodwyn Alpha platform in the first half of 2022. This event was low impact with no harm to people or the environment.

The year-to-date total recordable injury rate was 1.81 per million work hours compared to 1.74 recorded for full-year 2021. Woodside’s focus remains on understanding and addressing the gaps in our safeguards to improve our overall safety performance. Area specific safety improvement plans are being implemented by Woodside leaders and contractor partners.

Environmental performance remained strong in the first half of 2022, with zero significant environmental events.

ESG Rating

Woodside was recognised by Sustainalytics as an ESG Industry Top Rated Company in the first half of 2022.

Supporting local suppliers

Woodside increased its year-on-year value of awarded contracts to local and Indigenous suppliers, and increased visibility of sustainable contracting opportunities for our local and Indigenous suppliers to our operations and projects.

Woodside continues to work with its key Sangomar contractors to ensure opportunities are maximised for Senegalese people and suppliers, whilst meeting the requirements of in-country local content legislation.

Communities

Woodside released a report on progress made in the first year of its 2021-2025 Reconciliation Action Plan. The report highlighted areas for improvement but also noted the achievements in the areas of respect for culture and heritage, economic participation, further developing capability and capacity, and supporting Indigenous Voice.

Woodside’s 2021 Social Contribution Impact Report was released in March 2022, demonstrating our commitment to creating positive outcomes in the community and progress against Woodside’s primary and secondary Sustainable Development Goals.

Social impact assessments (SIA) are underway for Karratha and Roebourne in the north-west of Australia, and SIA planning activities have commenced for the H2Perth and H2TAS projects.


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Principal risks and uncertainties

There are several risk factors or uncertainties that could result in a material effect on the company results over the next six months. These risks and uncertainties may occur as a result of Woodside’s activities globally, including in connection with its operated (or non-operated) assets, and third parties engaged through the value chain.

The risks are not listed in any particular order.


Climate Change		Risks associated with the transition to a lower carbon economy, including that it may impact demand (and pricing) for oil, gas and its substitutes, the policy and legal environment for its production, Woodside’s reputation and the operating environment

Social Licence to Operate (SLTO)		Risks associated with actual or alleged deviation from social or business expectations of ethical behaviour (including breaches of laws or regulations) and social responsibility (including environmental impact and community contribution), particularly as these expectations evolve

Growth		Risks associated with delivery of both major and complex multi-year execution project activities across multiple global locations with a reliance on third parties for materials, products and services

Operations		Risks associated with safety or major hazard events in connection with our activities or facilities, that may impact production performance. This may also include unanticipated or unforeseeable adverse events or our ability to respond, manage and recover from such events

Finance		Risks associated with the ability to capture value during periods of market volatility, and the impact of interest rate and foreign exchange fluctuations and inflation on expenditure

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

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

Integration		Risks associated with our ability to integrate systems and processes, capture synergies and deliver the value of the combined underlying businesses post-merger with BHP’s petroleum business

Further information on Woodside’s risks and how they are managed can be found on pages 51-54 of the Annual Report 2021.


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Reserves and resources

Following completion of the merger with BHP’s petroleum business on 1 June 2022, Woodside’s Reserves as at 1 June 2022 increased to 2,339.6 MMboe Proved (1P) Reserves and 3,786.4 MMboe Proved plus Probable (2P) Reserves, with an increase in the Best Estimate (2C) Contingent Resources to 8,682.4 MMboe.

Woodside confirms there are no changes to reservoir outcomes compared to Woodside’s most recent reserves statement issued in February 2022 (Reserves Statement). Instead, the changes in the estimates of Reserves and Contingent Resources from those reported in the Reserves Statement are due to the matters noted below, including changes in the basis used to define the volumes reported as Reserves and Contingent Resources and the inclusion of volumes added as a result of the merger.

Specifically:

•

As Woodside is now listed on both the Australian Securities Exchange (ASX) and the New York Stock Exchange (NYSE), it is required to estimate and report its Proved (1P) Reserves in accordance with the United States Securities and Exchange Commission (SEC) regulations, which are also compliant with the Society of Petroleum Engineers Petroleum Resources Management System (SPE-PRMS) guidelines. The adjustment to convert Proved (1P) Reserves to SEC-compliant methods has resulted in reductions in the estimates of Proved (1P) Reserves for some assets. SEC-compliant Proved (1P) Reserves estimates use a more restrictive rules-based approach and are generally lower than estimates prepared solely in accordance with SPE-PRMS guidelines due to certain differences, including because the SEC-compliant Proved (1P) Reserves use specified commodity price assumptions, exclude probabilistic aggregation, use a narrower interpretation around unpenetrated sand bodies and fault blocks, and exclude cross-block volumes. The economic assumptions and pricing used to calculate the SEC-compliant Proved (1P) Reserves are as of 31 December 2021, although the Reserve base has been updated to reflect production during the period from 1 January 2022 to 31 May 2022.

•

Woodside’s Proved plus Probable (2P) Reserves and Best Estimate (2C) Contingent Resources continue to be estimated and reported in accordance with the SPE-PRMS guidelines.

•

Woodside’s Reserves and Contingent Resources are now reported inclusive of all fuel consumed in operations. Previously, Woodside’s Reserves and Contingent Resources were reported net of the fuel consumed in operations up to the outlet of the floating production storage and offloading facility (FPSO) or platform (for offshore oil projects) or the inlet to the downstream (onshore) processing facility (for onshore gas projects).

•

To achieve consistency between Woodside’s reporting of production and reserves volumes, Woodside now uses ‘natural gas’, ‘natural gas liquids’ and ‘oil/condensate’ volumes categories, which are defined based on products. Previously, Woodside used ‘dry gas’ and ‘condensate’ volumes categories, which were defined based on composition.

•

The barrel of oil equivalent (boe) conversion factor for natural gas remains unchanged at 5.7 Bcf per MMboe, the same conversion factor used previously for dry gas. Assets added as a result of the merger are now reported on this basis. Historically, BHP Petroleum used a boe conversion factor of 6.0 Bcf per MMboe.

•

The effective date for the Reserves and Contingent Resources estimates stated in this Reserves and Resources Update is 1 June 2022, with estimates updated for production during the period from 1 January 2022 to 31 May 2022.

In addition:

•

Woodside has transferred 12.6 MMboe Proved (1P) Reserves and 17.5 MMboe Proved plus Probable (2P) Reserves from Undeveloped to Developed as a result of achieving ready for start up (RFSU) of the GWF-3 Project.

•

As identified in the Reserves Statement, the 109.5 MMboe Best Estimate (2C) Contingent Resource associated with the Myanmar A-6 opportunity has been removed.


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Table 1: Woodside’s Reserves¹^,²^,³^,⁴^,⁵ and Contingent Resources⁶ overview (net Woodside share, as at 1 June 2022)


	Natural gas⁷ Bcf⁹		Natural gas liquids⁸ MMbbl¹⁰		Oil/condensate MMbbl		Total MMboe¹¹
Proved¹² Developed¹³ and Undeveloped¹⁴		10,657.2		28.5		441.4		2,339.6
Proved Developed		2,807.9		22.2		196.3		711.1
Proved Undeveloped		7,849.3		6.4		245.1		1,628.6
Proved plus Probable¹⁵ Developed and Undeveloped		17,051.9		48.6		746.3		3,786.4
Proved plus Probable Developed		4,497.9		39.3		348.5		1,177.0
Proved plus Probable Undeveloped		12,554.0		9.2		397.8		2,609.4
Contingent Resources		41,427.5		90.2		1,324.3		8,682.4

Small differences are due to rounding.

243.3 MMboe of fuel consumed in operations included in Proved Developed and Undeveloped Reserves

382.7 MMboe of fuel consumed in operations included in Proved plus Probable Developed and Undeveloped Reserves

Table 2: Proved (1P) and Proved plus Probable (2P) Developed and Undeveloped Reserves reconciliation by product (net Woodside share, as at 1 June 2022)


	Natural gas				Natural gas liquids				Oil/condensate				Total
	Bcf				MMbbl				MMbbl				MMboe
	Proved (1P)		Proved plus Probable (2P)		Proved (1P)		Proved plus Probable (2P)		Proved (1P)		Proved plus Probable (2P)		Proved (1P)		Proved plus Probable (2P)
Reserves at 31 December 2021¹⁶		8,090.7		11,669.4		0.0		0.0		172.9		244.4		1,592.3		2,291.7
Revision of Previous Estimates¹⁷		-590.1		328.5		2.9		4.5		-34.1		0.9		-134.8		63.0
Transfer to/from Reserves¹⁸		—		—		—		—		—		—		—		—
Extensions and Discoveries¹⁹		—		—		—		—		—		—		—		—
Acquisitions and Divestments²⁰		3,347.4		5,244.7		26.0		44.4		309.6		507.9		922.8		1,472.4
Production²¹		-190.7		-190.7		-0.3		-0.3		-6.9		-6.9		-40.7		-40.7
Reserves at 1 June 2022		10,657.2		17,051.9		28.5		48.6		441.4		746.3		2,339.6		3,786.4

Small differences are due to rounding.

Table 3: Best Estimate (2C) Contingent Resources reconciliation by product (net Woodside share, as at 1 June 2022)


	Natural gas Bcf		Natural gas liquids MMbbl		Oil/condensate MMbbl		Total MMboe
Contingent Resources at 31 December 2021		34,768.0		0		499.7		6,599.4
Revision of Previous Estimates¹⁷		1,471.4		8.3		0.4		266.8
Transfer to/from Reserves¹⁸		—		—		—		—
Extensions and Discoveries¹⁹		—		—		—		—
Acquisitions and Divestments²⁰		5,188.1		81.9		824.1		1,816.3
Contingent Resources at 1 June 2022		41,427.5		90.2		1,324.3		8,682.4

Small differences are due to rounding.


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Table 4: Proved (1P) Developed and Undeveloped²² Reserves by region (net Woodside share, as at 1 June 2022)


Country	Asset	Natural gas Bcf						Natural gas liquids MMbbl						Oil/condensate MMbbl						Total MMboe
Country	Asset	Developed		Undeveloped		Total		Developed		Undeveloped		Total		Developed		Undeveloped		Total		Developed		Undeveloped		Total
Australia	Greater Pluto²³		997.0		311.7		1,308.7		0.0		0.3		0.3		12.7		3.9		16.6		187.6		58.9		246.5
	Bass Strait		421.3		34.2		455.5		14.6		1.4		16.0		8.9		1.0		9.8		97.3		8.4		105.7
	North West Shelf²⁴		798.8		100.8		899.6		4.0		0.5		4.5		26.2		2.4		28.6		170.3		20.6		191.0
	Greater Exmouth²⁵		0.0		0.0		0.0		0.0		0.0		0.0		13.5		0.0		13.5		13.5		0.0		13.5
	Pyrenees		0.6		0.0		0.6		0.0		0.0		0.0		9.7		1.7		11.4		9.8		1.7		11.5
	Macedon		224.3		65.0		289.3		0.0		0.0		0.0		0.0		0.0		0.0		39.4		11.4		50.8
	Julimar-Brunello²⁶		157.0		122.0		279.0		0.0		0.0		0.0		2.6		2.1		4.7		30.1		23.5		53.6
	Greater Scarborough²⁷		0.0		7,173.3		7,173.3		0.0		0.0		0.0		0.0		0.0		0.0		0.0		1,258.5		1,258.5

US GoM	Shenzi		18.5		4.8		23.3		1.1		0.9		2.0		49.6		15.4		65.0		54.0		17.1		71.1
	Shenzi North		0.0		4.7		4.7		0.0		1.0		1.0		0.0		14.7		14.7		0.0		16.5		16.5
	Atlantis		35.9		3.6		39.4		1.8		0.4		2.2		47.2		10.5		57.7		55.3		11.6		66.9
	Mad Dog		6.1		29.2		35.3		0.7		1.8		2.5		23.9		112.3		136.2		25.7		119.2		144.9

T&T	Angostura		117.3		0.0		117.3		0.0		0.0		0.0		1.2		0.0		1.2		21.7		0.0		21.7
	Ruby		31.2		0.0		31.2		0.0		0.0		0.0		0.8		0.0		0.8		6.3		0.0		6.3

Senegal	Sangomar²⁸		0.0		0.0		0.0		0.0		0.0		0.0		0.0		81.2		81.2		0.0		81.2		81.2

Total	Reserves		2,807.9		7,849.3		10,657.2		22.2		6.4		28.5		196.3		245.1		441.4		711.1		1,628.6		2,339.6

Small differences are due to rounding.

243.3 MMboe of fuel consumed in operations included in Proved Developed and Undeveloped Reserves


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Table 5: Proved plus Probable (2P) Developed and Undeveloped Reserves by region (net Woodside share, as at 1 June 2022)


Country	Asset	Natural gas						Natural gas liquids						Oil/condensate						Total
		Bcf						MMbbl						MMbbl						MMboe
		Developed		Undeveloped		Total		Developed		Undeveloped		Total		Developed		Undeveloped		Total		Developed		Undeveloped		Total
Australia	Greater Pluto		1,393.1		339.3		1,732.4		0.3		0.1		0.4		19.3		4.4		23.7		264.0		64.0		327.9
	Bass Strait		655.7		54.3		710.0		23.0		1.9		24.8		14.5		1.5		16.0		152.5		12.9		165.5
	North West Shelf		1,404.1		149.5		1,553.6		7.3		0.2		7.6		46.8		3.6		50.4		300.4		30.1		330.5
	Greater Exmouth		0.0		0.0		0.0		0.0		0.0		0.0		22.4		0.0		22.4		22.4		0.0		22.4
	Pyrenees		0.6		0.0		0.6		0.0		0.0		0.0		17.9		3.2		21.1		18.0		3.2		21.2
	Macedon		297.0		40.2		337.2		0.0		0.0		0.0		0.0		0.0		0.0		52.1		7.1		59.2
	Julimar-Brunello		436.6		427.7		864.3		0.0		0.0		0.0		8.4		7.7		16.1		85.0		82.8		167.7
	Greater Scarborough		0.0		11,475.3		11,475.3		0.0		0.0		0.0		0.0		0.0		0.0		0.0		2,013.2		2,013.2
US GoM	Shenzi		25.6		6.8		32.4		2.2		1.2		3.4		71.5		21.8		93.3		78.3		24.2		102.5
	Shenzi North		0.0		10.2		10.2		0.0		2.1		2.1		0.0		32.1		32.1		0.0		36.0		36.0
	Atlantis		81.4		11.3		92.8		5.5		1.5		7.0		114.2		25.5		139.6		133.9		29.0		162.9
	Mad Dog		7.9		39.2		47.1		1.1		2.2		3.3		31.3		149.2		180.5		33.8		158.3		192.1
T&T	Angostura		148.9		0.0		148.9		0.0		0.0		0.0		1.2		0.0		1.2		27.3		0.0		27.3
	Ruby		47.1		0.0		47.1		0.0		0.0		0.0		1.1		0.0		1.1		9.3		0.0		9.3
Senegal	Sangomar		0.0		0.0		0.0		0.0		0.0		0.0		0.0		148.7		148.7		0.0		148.7		148.7

Total	Reserves		4,497.9		12,554.0		17,051.9		39.3		9.2		48.6		348.5		397.8		746.3		1,177.0		2,609.4		3,786.4

Small differences are due to rounding.

382.7 MMboe of fuel consumed in operations included in Proved plus Probable Developed and Undeveloped Reserves


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Table 6: Best Estimate (2C) Contingent Resources summary by region (net Woodside share, as at 1 June 2022)


Country	Asset	Natural gas Bcf		Natural gas liquids MMbbl		Oil/condensate MMbbl		Total MMboe
Australia	Greater Pluto		1,217.6		0.0		22.5		236.1
	Bass Strait		692.6		37.3		58.4		217.3
	North West Shelf		573.6		2.9		37.2		140.7
	Exmouth²⁹		42.1		0.0		1.6		8.9
	Greater Exmouth		307.4		0.0		29.0		82.9
	Pyrenees		0.0		0.0		12.3		12.3
	Macedon		117.0		0.0		0.0		20.5
	Julimar-Brunello		39.4		0.0		0.7		7.6
	Greater Scarborough		1,631.4		0.0		0.0		286.2
	Greater Browse³⁰		4,469.7		6.8		119.4		910.4
	Greater Sunrise³¹		1,778.0		0.0		75.6		387.5
	Stybarrow		0.0		0.0		1.6		1.6
US GoM	Shenzi		21.6		5.9		83.7		93.4
	Shenzi North		1.1		0.2		3.4		3.8
	Atlantis		211.7		32.3		155.1		224.5
	Mad Dog		40.3		1.0		148.6		156.7
	Wildling		17.6		3.7		56.3		63.0
T&T	Angostura		188.1		0.0		0.9		33.9
	Ruby		45.6		0.0		3.2		11.2
	T&T Deep Water		2,517.5		0.0		0.0		441.7
Mexico	Trion		215.4		0.0		283.8		321.6
Canada	Liard³²		27,000.3		0.0		0.0		4,736.9
Senegal	Senegal		299.7		0.0		231.2		283.7
Myanmar	Myanmar		0.0		0.0		0.0		0.0
Total	Resources		41,427.5		90.2		1,324.3		8,682.4

Small differences are due to rounding.

Additional information for recently acquired assets

Woodside is reporting Reserves and Contingent Resources for the first time in respect of each of the assets recently acquired as part of the merger (other than the North West Shelf and Scarborough assets) (Recently Acquired Assets). A brief description of the Recently Acquired Assets, the Reserves and Contingent Resources associated with the Recently Acquired Assets and how the Reserves and Contingent Resources for the Recently Acquired Assets have been estimated is provided below.

The NWS and Scarborough assets are not described below as they have previously been reported by Woodside as a result of Woodside’s interest in those assets prior to the merger. However, Woodside confirms that, as a result of the merger, Woodside’s interest in the Scarborough assets increased from 73.5% to 100%, its interest in the NWS gas assets increased from 15% to 30%, and its interest in the NWS oil assets increased from 33.3% to 50%.

Reserves and Contingent Resources estimates shown are net of royalties owned by others and have been estimated using deterministic methodology. Reserves and Contingent Resources estimates have not been adjusted for risk. Unless noted otherwise, Reserves and Contingent Resources are as of the effective date of 1 June 2022 and are Woodside’s net economic interest volumes.


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Proved (1P) Reserves are estimated and reported on a net interest basis in accordance with the SEC regulations and have been determined in accordance with SEC Rule 4-10(a) of Regulation S-X. As defined by the SEC, Proved (1P) Reserves are those quantities of crude oil, natural gas and natural gas liquids that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs and under existing economic conditions, operating methods, operating contracts and government regulations. Unless evidence indicates that renewal of existing operating contracts is reasonably certain, estimates of economically producible Reserves reflect only the period before the contracts expire. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence within a reasonable time.

Proved (1P) Reserves were estimated by reference to available well and reservoir information, including but not limited to well logs, well test data, core data, production and pressure data, geologic data, seismic data and, in some cases, similar data from analogous, producing reservoirs. A wide range of engineering and geoscience methods, including performance analysis, numerical simulation, well analogues and geologic studies, have been used to develop high confidence Proved (1P) Developed and Undeveloped Reserves estimates for all of the assets described in this Reserves and Resources Update in accordance with SEC regulations.

Proved plus Probable (2P) Reserves and Best Estimate (2C) Contingent Resources are estimated in accordance with the SPE-PRMS guidelines. SPE-PRMS guidelines allow (amongst other things) escalations to prices and costs and, as such, volumes estimates in accordance with those guidelines would be on a different basis than volumes estimated as prescribed by the SEC. Proved plus Probable (2P) Reserves and Best Estimate (2C) Contingent Resources estimates are inherently more uncertain than Proved (1P) Reserves estimates.

Asset description: Bass Strait

Bass Strait is an offshore asset that consists of multiple oil and gas fields in the Gippsland Basin off the south eastern coast of Victoria, Australia. The project consists of an integrated network of offshore platforms and subsea tie-backs connected by extensive pipeline infrastructure to onshore processing facilities at Longford and Long Island Point.

The Bass Strait asset comprises the following joint ventures:

•

Gippsland Basin Joint Venture – located in permits Vic/L1-L11 and Vic/L13-19. Ownership is 50% ExxonMobil (Operator) and 50% Woodside

•

Kipper Unit Joint Venture – located in permits Vic/L9 and Vic/L25. Ownership is 32.5% ExxonMobil (Operator), 32.5% Woodside and 35% Mitsui. Kipper unit production is processed by the Gippsland Basin Joint Venture under a processing agreement.

Bass Strait has been in production since 1969. Natural gas produced from the fields is primarily sold domestically in eastern Australia. Crude oil and secondary natural gas liquid products (butane, propane and ethane) are sold at the onshore processing facilities and transported via pipelines, truck loading and export shipping. Undeveloped Reserves are primarily associated with the Kipper compression project which has a target RFSU in 2024.

Future development potential in this asset are primarily from unsanctioned contingent resources projects targeting deeper, acid gas resources. Several offshore facilities in the asset have ceased production after field depletion and programs for well abandonment, facility decommissioning and removal are currently ongoing.

Asset description: Exmouth, Stybarrow

The Exmouth asset comprises of Contingent Resources associated with gas discoveries at Scafell and oil discoveries at Skiddaw-Laverda in Western Australia. The Stybarrow asset comprises of minor Contingent Resources at the Stybarrow oil field. Cessation of production occurred in 2015.

The Scafell gas field is located approximately 120 km west of Onslow and 40 km north of Exmouth in the WA-43-L production licence. Ownership is 40% Woodside (Operator), 31.5% Santos and 28.5% Inpex.

Development plans have not been sanctioned for these assets and the Contingent Resource is carried in the SPE PRMS CR subclass of Development Currently Not Viable.

Asset description: Macedon

Macedon is an offshore gas field in Western Australia. It is located approximately 40 km north of Exmouth in the Exmouth subbasin in the WA-42-L production licence. Ownership is 71.4% Woodside and 28.6% Santos. The project consists of subsea wells which are produced by pipeline to an onshore gas treatment plant near Onslow.


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Macedon has been in production since 2013. Natural gas from the field is sold domestically in Western Australia. Undeveloped Reserves are associated with a compression project which is currently in execution.

Asset description: Pyrenees

Pyrenees is an offshore asset with six oil fields in Western Australia. It is located approximately 45 km northwest of Exmouth in the Carnarvon basin within the WA-42-L and WA-43-L production licences. Ownership is 71.4% Woodside (Operator) and 28.6% Santos in the WA-42-L licence and 40% Woodside (Operator), 31.5% Santos and 28.5% Inpex in the WA-43-L licence. The project consists of an FPSO, development wells to the Pyrenees oil fields and a well into the Macedon field that can inject or produce gas depending on facility requirements.

Pyrenees has been in production since 2010. Crude oil from the field is offloaded from the FPSO to tankers for international sale. Undeveloped Reserves are associated with infill wells to be drilled in 2023.

Asset description: Trion

Trion is an offshore oil and gas discovery in the Mexican waters of the western Gulf of Mexico. It is located approximately 180 km off the Mexican coast and 30 km south of the US/Mexico maritime border within Block AE-0092 and Block AE-0093. Ownership is 60% Woodside (Operator) and 40% Pemex. The field was discovered in 2012 and is currently being considered for development. No further appraisal wells are planned to be drilled and the field is under evaluation.

Development plans have not been sanctioned and the Contingent Resource is carried in the SPE PRMS CR subclasses of Development Pending and Development Unclarified.

Asset description: Angostura

Angostura is an offshore oil and gas asset in Trinidad and Tobago. It is located approximately 38 km off the northeast coast of Trinidad in Block 2(c). Ownership is 45% Woodside (Operator), 30% National Gas Company and 25% Chaoyang.

The Angostura field has been in production since 2005. Crude oil produced from the field is transported to the terminal facility on the south eastern coast of Trinidad for sale to international markets. Natural gas from the field is transported by pipeline and sold domestically to the National Gas Company.

Asset description: Ruby/Delaware

Ruby and Delaware are offshore oil and gas assets in Trinidad and Tobago. They are located in Block 3(a) and are adjacent to the Angostura asset. Ownership is 68.46% Woodside (Operator) and 31.54% National Gas Company.

The Ruby and Delaware fields have been in production since 2021. Production from these fields are transported by flow lines to the facilities on the Angostura asset for processing. Crude oil produced from these fields are transported to the terminal facility on the south eastern coast of Trinidad for sale to international markets. Natural gas from the fields is transported by pipeline and sold domestically to the National Gas Company.

Asset description: T&T Deep Water

T&T Deep Water comprises the gas discoveries in the Calypso and Magellan opportunities in offshore deepwater Trinidad and Tobago.

The Calypso opportunity is located approximately 217 km off the coast of Trinidad and comprises several gas discoveries in Block 23(a) and Block TTDAA 14. Ownership is 70% Woodside (Operator) and 30% BP. The initial discovery was made in 2018 and additional discoveries were made in subsequent years. Calypso is proximate to existing LNG infrastructure and downstream petrochemical facilities in Trinidad. The opportunity is currently being considered for development. Two appraisal wells were drilled in 2021 and the opportunity is under evaluation. Development plans have not been sanctioned and the Contingent Resource is carried in the SPE PRMS CR subclasses of Development Unclarified and Development Currently Not Viable.

The Magellan opportunity is located approximately 200 km east off the coast of Trinidad and comprises two gas discoveries in 2016 and 2018 in Block TTDAA 5. Ownership is 65% Woodside (Operator) and 35% Shell. No further appraisal wells are planned and the opportunity is under evaluation. Development plans have not been sanctioned and the Contingent Resource is carried in the SPE PRMS CR subclass of Development Currently Not Viable.


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Asset description: Atlantis

Atlantis is an offshore oil and gas asset in the US Gulf of Mexico. It is located approximately 210 km off the coast of Louisiana in the Green Canyon protraction area within the lease blocks C699, GC742, GC743, and GC744. Ownership is 56% BP (Operator) and 44% Woodside.

Future development opportunities in this field that will be leveraging existing infrastructure include:

•

Atlantis Phase 3 project: In-fill development project with some wells already on production

•

Multiple unsanctioned projects currently in planning phases.

Atlantis has been in production since 2007. Crude oil and natural gas produced from the field are transported by pipelines to the Gulf coast for sale.

Asset description: Mad Dog

Mad Dog is an offshore oil and gas asset in the US Gulf of Mexico. It is located approximately 200 km off the coast of Louisiana in the Green Canyon protraction area within the lease blocks GC738, GC781, GC782, GC824, GC825, GC826, GC868, GC869 and GC870. Ownership is 60.5% BP (Operator), 23.9% Woodside and 15.6% Chevron.

Future development opportunities in this field include:

•

Mad Dog Phase 2 project: Sanctioned in 2017 to develop the southern flank of the field. The project is currently under execution

•

Unsanctioned brownfield growth opportunities currently in planning phase.

Mad Dog has been in production since 2005. Crude oil and natural gas produced from the field are transported by pipelines to the Gulf coast for sale.

Asset description: Greater Shenzi

Greater Shenzi is an offshore oil and gas asset in the US Gulf of Mexico. It is located approximately 195 km off the coast of Louisiana in the Green Canyon protraction area. Greater Shenzi comprises:

•

The currently producing Shenzi field located in lease blocks GC609, GC610, GC652, GC653 and GC654. Ownership is 72% Woodside (operator) and 28% Repsol

•

Future tie-back developments at:

•

Shenzi North located in lease blocks GC608 and GC609. Ownership is 72% Woodside (Operator) and 28% Repsol and the project is currently under execution

•

Wildling located in lease blocks GC520 and GC564. Ownership is 100% Woodside and the project is currently under appraisal. Subsequent to 1 June 2022, the Wildling appraisal well SJ101 completed drilling activities and encountered sub-commercial quantities of hydrocarbons. Work is in progress to determine the subsequent revisions to the Contingent Resource estimates.

The Shenzi field has been in production since 2009. Crude oil and natural gas produced from the field are transported by pipelines to the Gulf coast for sale.

Governance and assurance

Woodside is an Australian company listed on the Australian Securities Exchange, the New York Stock Exchange and the London Stock Exchange. Woodside reports its Proved (1P) Reserves in accordance with SEC regulations, which are also compliant with SPE-PRMS guidelines, and prepares and reports its Proved plus Probable (2P) Reserves and Best Estimate (2C) Contingent Resources in accordance with SPE-PRMS guidelines. It reports all of its petroleum resource estimates using definitions 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 and contingent resources reporting, including the Woodside Reserves Policy, the Woodside Petroleum Resources Management Procedure, the Woodside Petroleum Resource Management Guideline, staff training and minimum competency levels and external reserves audits.


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The Reserves and Contingent Resources reported for the Recently Acquired Assets were assured by Woodside in accordance with the process previously applied by the BHP Petroleum business. Each Reserve and Contingent Resource assessment is reviewed to ensure technical quality and compliance with SEC and SPE-PRMS reporting requirements (as applicable).

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 60 degrees Fahrenheit (15.56 degrees Celsius).

Qualified petroleum reserves and resource evaluator statement

The estimates of petroleum resources for the Recently Acquired Assets are based on and fairly represent information and supporting documentation prepared under the supervision of Mr Abhijit Gadgil, Head of Petroleum Reserve Group (PRG), who is a full-time employee of the company and a member of the Society of Petroleum Engineers. Mr Gadgil’s qualifications include a Master of Science (Chemical Engineering) from Rice University, Houston, Texas, and more than 40 years of relevant experience.

The estimates of petroleum resources for all other assets referenced in this Reserves and Resources Update (Woodside Heritage Assets) are based on and fairly represent information and supporting documentation prepared under the supervision of Mr Jason Greenwald, Woodside’s Vice President Corporate Strategy, 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.

Additional information for US investors

The SEC prohibits oil and gas companies, in their filings with the SEC, from disclosing estimates of oil or gas resources other than “reserves” (as that term is defined by the SEC). In this report, Woodside includes estimates of quantities of oil and gas using certain terms, such as “Proved plus Probable (2P) Reserves,” “Best Estimate (2C) Contingent Resources,” “Reserves and Contingent Resources,” “Proved plus Probable,” “Developed and Undeveloped,” “Probable Developed,” “Probable Undeveloped,” “Contingent Resources” or other descriptions of volumes of reserves, which terms include quantities of oil and gas that may not meet the SEC’s definitions of proved, probable and possible reserves, and which the SEC’s guidelines strictly prohibit Woodside from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and would require substantial capital spending over a significant number of years to implement recovery, and accordingly are subject to substantially greater risk of being recovered by Woodside. In addition, actual locations drilled and quantities that may be ultimately recovered from Woodside’s properties may differ substantially. Woodside has made no commitment to drill, and likely will not drill, all of the drilling locations that have been attributable to these quantities. U.S. investors are urged to consider closely the disclosures in Woodside’s filings with the SEC, which are available at www.sec.gov.

Notes to the reserves and resources update

^1.	For offshore oil projects, the reference point is defined as the outlet of the floating production storage and offloading facility (FPSO) or platform, while for the onshore gas projects the reference point is defined as the outlet of the downstream (onshore) gas processing facility.

^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. Woodside reports Reserves inclusive of all fuel consumed in operations. Proved (1P) Reserves are estimated and reported in accordance with SEC regulations which are also compliant with SPE-PRMS guidelines. SEC-compliant Proved (1P) Reserves estimates use a more restrictive, rules-based approach and are generally lower than estimates prepared solely in accordance with SPE-PRMS guidelines due to, among other things, the requirement to use commodity prices based on the average price during the 12-month period in the reporting company’s fiscal year. Proved plus Probable (2P) Reserves are estimated and reported in accordance with SPE-PRMS guidelines, and are not compliant with SEC regulations.

^3.

Assessment of the economic value of the Woodside Heritage Assets, in support of an SPE-PRMS (2018) reserves and resources classification, uses Woodside Portfolio Economic Assumptions (Woodside PEAs). The Woodside 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 Woodside PEAs are approved by the Woodside Board. Specific contractual arrangements for individual projects are also taken into account.

^4.

Assessment of the economic value of the Recently Acquired Assets, in support of an SPE-PRMS (2018) reserves and resources classification, uses economic assumptions that were prepared and adopted by the BHP Petroleum business prior to the Merger (BHP Heritage Assumptions). The BHP Heritage Assumptions were prepared based on historical data and forecast estimates for economic variables such as product prices and exchange rates. Specific contractual arrangements for individual projects are also taken into account. Woodside is of the view that the BHP Heritage Assumptions form an appropriate basis for Woodside’s evaluation of the Reserves and Contingent Resources for the Recently Acquired Assets. Woodside is of the view that there would be no material difference in the Reserve and Contingent Resource estimates for the Recently Acquired Assets reported in this Reserves and Resources Update had the Woodside PEAs been used instead of the BHP Heritage Assumptions.


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Notes to the reserves and resources update

^5.

Woodside uses both deterministic and probabilistic methods for the estimation of Reserves and Contingent Resources at the field and project levels. All Proved (1P) Reserves estimates have been estimated using deterministic methodology and reported on a net interest basis in accordance with the SEC regulations and have been determined in accordance with SEC Rule 4-10(a) of Regulation S-X. Unless otherwise stated, all petroleum estimates reported at the company or region level are aggregated by arithmetic summation by category. The aggregated Proved (1P) Reserves may be a conservative estimate due to the portfolio effects of arithmetic summation.

^6.

‘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 are estimated and reported in accordance with SPE-PRMS guidelines and 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 inclusive of all fuel consumed in operations and net of non-hydrocarbons not present in sales products. Contingent Resources are different from, and should not be construed as, Reserves. 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. Best Estimate (2C) Contingent Resources are not compliant with SEC regulations. The SEC prohibits disclosure of oil and gas resources, including Contingent Resources, in SEC filings. However, Australian securities regulatory authorities allow disclosure of oil and gas resources, including Contingent Resources.

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

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

^9.	‘Bcf’ means Billions (109) of cubic feet of gas at standard oilfield conditions of 14.696 psi (101.325 kPa) and 60 degrees Fahrenheit (15.56 degrees Celsius).

^10.	‘MMbbl’ means millions (106) of barrels of NGL, oil and condensate at standard oilfield conditions of 14.696 psi (101.325 kPa) and 60 degrees Fahrenheit (15.56 degrees Celsius).

^11.	‘MMboe’ means millions (106) of barrels of oil equivalent. Natural Gas volumes are converted to oil equivalent volumes via a constant conversion factor, which for Woodside is 5.7 Bcf of dry gas per 1 MMboe. Volumes of NGL, oil and condensate are converted from MMbbl to MMboe on a 1:1 ratio.

^12.

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

^13.	‘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.

^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.

^15.

‘Probable Reserves’ are those Reserves which analysis of geological and engineering data suggests are more likely than not to be recoverable. Proved plus Probable (2P) Reserves represent the best estimate of recoverable quantities. Where probabilistic methods are used, there is at least a 50% probability that the actual quantities recovered will equal or exceed the sum of estimated Proved plus Probable (2P) Reserves. Proved plus Probable (2P) Reserves are estimated and reported in accordance with SPE-PRMS guidelines and are not compliant with SEC regulations.

^16.	‘Reserves at 31 December 2021’ are estimated and reported in accordance with SPE-PRMS guidelines. Adjustments to convert Proved (1P) Reserves to SEC-compliant methods are included in ‘Revisions of Previous Estimates’ and reflected in ‘Reserves at 1 June 2022’.

^17.

‘Revision of Previous Estimates’ are revisions that represent changes (either upward or downward) in previous estimates of Reserves or Contingent Resources, which, for the purposes of this Reserves and Resources Update, reflect the changes in the basis used to define the volumes reported as Reserves and Contingent Resources as described in the introduction to this Reserves and Resources Update, including adjustments (i) to convert Proved (1P) Reserves to SEC-compliant methods; (ii) to include all fuel consumed in operations in Reserves and Contingent Resources; and (iii) to revise reporting categories to achieve consistency between Woodside’s reporting of production and reserves volumes.

^18.

‘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 petroleum resource estimates (i.e. from Reserves to Contingent Resources or vice versa) associated with one or more reference project(s).

^19.

‘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 Resources in new fields or new reservoirs in old fields.


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Notes to the reserves and resources update

^20.

‘Acquisitions and Divestments’ are revisions that represent changes (either upward or downward) in previous estimates of Reserves or Contingent Resources, which result from either purchase or sale of interests and/or execution of contracts conveying entitlement, and, in this Reserves and Resources Update, includes volumes added as a result of the merger.

^21.

‘Production’ is the volume of natural gas, NGLs, condensate and oil produced during the period from 1 January 2022 to 31 May 2022 and converted to ‘MMboe’ for the specific purpose of reserves reconciliation. The production volume figures in this Reserves and Resources Update differ from the production volume figures reported in Woodside’s annual and quarterly reports, due to the fact that the production volume figures reported in this Reserves and Resources Update include all fuel consumed in operations, but exclude NWS domestic gas overlift volumes and Pluto Interconnector gas purchased in excess of Reserves and Resources working interest percentage.

^22.

Material concentrations of undeveloped reserves in the North West Shelf, Greater Pluto and Julimar-Brunello regions have remained undeveloped for longer than five 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.

^23.	The ‘Greater Pluto’ region comprises the Pluto-Xena, Pyxis, Larsen, Martell, Martin, Noblige and Remy fields.

^24.	The ‘North West Shelf’ (NWS) region includes all oil and gas fields within the North West Shelf Project Area.

^25.	The ‘Greater Exmouth’ region comprises Vincent, Enfield, Greater Enfield, Greater Laverda, Ragnar and Toro fields.

^26.	The ‘Julimar-Brunello’ region comprises the Julimar and Brunello fields.

^27.	The ‘Greater Scarborough’ region comprises the Jupiter, Scarborough and Thebe 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 ‘Exmouth’ region comprises Contingent Resources associated with gas discoveries at Scafell and oil discoveries at Skiddaw-Laverda.

^30.	The ‘Greater Browse’ region comprises the Brecknock, Calliance and Torosa fields.

^31.	The ‘Greater Sunrise’ region comprises the Sunrise and Troubadour fields.

^32.	The ‘Liard’ region comprises unconventional resources in the Liard Basin.


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Governance

The directors of Woodside Energy Group Ltd present their report (including the review of operations set out on pages 1-25) together with the Financial Statements of the Group.

Board of directors

The names of directors in office during or since the end of the period are as follows:


Mr Richard Goyder, AO (Chairman)		Ms Meg O’Neill (CEO and Managing Director)
Mr Larry Archibald		Mr Frank Cooper, AO
Ms Swee Chen Goh		Dr Christopher Haynes, OBE
Mr Ian Macfarlane		Ms Ann Pickard
Dr Sarah Ryan		Mr Gene Tilbrook
Mr Ben Wyatt

Rounding of amounts

The amounts contained in this report have been rounded to the nearest million dollars under the option available to the Group under Australian Securities and Investments Commission (ASIC) Instrument 2016/191 dated 24 March 2016, unless otherwise stated.

Management assurance

Consistent with recommendation 4.2 of the ASX Corporate Governance Council’s Corporate Governance Principles and Recommendations (4th edition), before the adoption by the Board of the Half-Year Financial Statements 2022, the Board received written declarations from the Chief Executive Officer (CEO) and the Chief Financial Officer (CFO) that the financial records of the company have been properly maintained in accordance with section 286 of the Corporations Act 2001, and the company’s financial statements and notes comply with accounting standards and give a true and fair view of the consolidated entity’s financial position and performance for the financial period. The CEO and the CFO have also stated in writing to the Board that the statement relating to the integrity of Woodside’s financial statements is founded on a sound system of risk management and internal control that is operating effectively.

Signed in accordance with a resolution of the directors.

/s/ R J Goyder, AO

R J Goyder, AO

Chairman

Perth, Western Australia

30 August 2022


Woodside Energy Group Ltd \| Half-Year Report 2022		26


Woodside Energy Group Ltd \| Half-Year Report 2022		27

LOGO

HALF-YEAR FINANCIAL

STATEMENTS

for the half-year ended 30 June 2022


Woodside Energy Group Ltd \| Half-Year Report 2022		28

HALF-YEAR FINANCIAL STATEMENTS

CONTENTS


CONDENSED CONSOLIDATED INCOME STATEMENT		30

CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME		31

CONDENSED CONSOLIDATED STATEMENT OF FINANCIAL POSITION		32

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS		33

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY		34

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS		35

A.	Earnings for the period	37
	A.1 Segment revenue and expenses	37
	A.2 Finance costs	38
	A.3 Dividends paid and proposed	38
	A.4 Earnings per share	38

B.	Production and growth assets	39
	B.1 Exploration and evaluation	39
	B.2 Oil and gas properties	40
	B.3 Impairment of non-current assets	40
	B.4 Business combination	41
	B.5 Disposal of assets	43

C.	Debt and capital	44
	C.1 Contributed equity	44
	C.2 Interest-bearing liabilities and financing facilities	44

D.	Other assets and liabilities	45
	D.1 Segment assets and liabilities	45
	D.2 Provisions	45
	D.3 Other financial assets and liabilities	47

E.	Other items	49
	E.1 Contingent liabilities and assets	49
	E.2 Related party transactions	49
	E.3 Changes to the composition of the Group	49
	E.4 Events after the end of the reporting period	51

DIRECTORS’ DECLARATION		52

INDEPENDENT REVIEW REPORT		53

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 18 January 2022, the Group completed the sell-down of a 49% participating interest in the Pluto Train 2 Joint Venture to Global Infrastructure Partners (GIP). As a result, the Group recognised a pre-tax gain of $427 million on the transaction (refer to Note B.5).

•

The Pluto-KGP Interconnector achieved ready for start-up and commenced flowing gas from the offshore Pluto fields to Karratha Gas Plant (KGP) for processing in March 2022.

•

On 1 June 2022, the Group acquired 100% of the issued share capital of BHP Petroleum International Pty Ltd (BHPP) (subsequently renamed Woodside Energy Global Holdings Pty Ltd), which held BHP Group’s oil and gas business (refer to Note B.4).

•

An increase in the risk free rates and current period payments offset by an increase in cost estimates has decreased restoration liabilities by $393 million (refer to Note D.2). The majority of this was recognised as a corresponding decrease in oil and gas properties.

•

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.3).


Woodside Energy Group Ltd \| Half-Year Report 2022		29

CONDENSED CONSOLIDATED INCOME STATEMENT

for the half-year ended 30 June 2022

Notes

2022
US$m

2021
US$m

Operating revenue

A.1

5,810

2,504

Cost of sales

A.1

(2,238

)

(1,535

)

Gross profit

3,572

969

Other income

A.1

503

Other expenses

A.1

(1,093

)

(377

)

Profit before tax and net finance costs

2,982

621

Finance income

Finance costs

A.2

(86

)

(130

)

Profit before tax

2,927

503

Petroleum resource rent tax (PRRT) (expense)/benefit

(424

)

Income tax expense

(824

)

(221

)

Profit after tax

1,679

342

Profit attributable to:

Equity holders of the parent

1,640

317

Non-controlling interest

Profit for the period

1,679

342

Basic earnings per share attributable to equity holders of the parent (US cents)

A.4

145.5

33.3

Diluted earnings per share attributable to equity holders of the parent (US cents)

A.4

144.0

33.0

The accompanying notes form part of the half-year financial statements.


Woodside Energy Group Ltd \| Half-Year Report 2022		30

CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

for the half-year ended 30 June 2022


	2022 US$m			2021 US$m
Profit for the period		1,679			342
Other comprehensive income
Items that may be reclassified to the income statement in subsequent periods:
(Losses)/gains on cash flow hedges		(1,582	)		17
Losses on cash flow hedges reclassified to the income statement		255			50
Tax recognised within other comprehensive income		270			(20	)
Exchange fluctuations on translation of foreign operations taken to equity		2			—
Items that will not be reclassified to the income statement in subsequent periods:
Remeasurement gains on defined benefit plan		—			12
Net gain on financial instruments at fair value through other comprehensive income		4			—

Other comprehensive (loss)/income for the period, net of tax		(1,051	)		59

Total comprehensive income for the period		628			401

Total comprehensive income attributable to:
Equity holders of the parent		589			376
Non-controlling interest		39			25

Total comprehensive income for the period		628			401

The accompanying notes form part of the half-year financial statements.


Woodside Energy Group Ltd \| Half-Year Report 2022		31

CONDENSED CONSOLIDATED STATEMENT OF FINANCIAL POSITION

As at 30 June 2022


	Notes	30 June 2022 US$m			31 December 2021 US$m
Current assets
Cash and cash equivalents			4,615			3,025
Receivables			1,779			368
Inventories			550			202
Other financial assets	D.3		493			320
Non-current assets held for sale			2			254
Tax receivable			78			—
Other assets			65			109

Total current assets			7,582			4,278

Non-current assets
Receivables			910			686
Inventories			20			19
Other financial assets	D.3		92			107
Exploration and evaluation assets	B.1		1,192			614
Oil and gas properties	B.2		38,666			18,649
Deferred tax assets			899			1,007
Lease assets			1,282			1,080
Investments accounted for using the equity method			238			2
Goodwill	B.4		3,975			—
Other assets			96			32

Total non-current assets			47,370			22,196

Total assets			54,952			26,474

Current liabilities
Payables			1,993			639
Interest-bearing liabilities			277			277
Other financial liabilities	D.3		1,302			411
Provisions	D.2		1,021			605
Tax payable			926			413
Lease liabilities			273			191
Other liabilities			159			86

Total current liabilities			5,951			2,622

Non-current liabilities
Interest-bearing liabilities			5,103			5,153
Deferred tax liabilities			1,765			878
Other financial liabilities	D.3		423			161
Provisions	D.2		5,956			2,219
Tax payable			33			—
Lease liabilities			1,345			1,176
Other liabilities			952			36

Total non-current liabilities			15,577			9,623

Total liabilities			21,528			12,245

Net assets			33,424			14,229

Equity
Issued and fully paid shares	C.1		29,001			9,409
Shares reserved for employee share plans	C.1		(42	)		(30	)
Other reserves			1,697			683
Retained earnings			1,978			3,381

Equity attributable to equity holders of the parent			32,634			13,443

Non-controlling interest			790			786

Total equity			33,424			14,229

The accompanying notes form part of the half-year financial statements.


Woodside Energy Group Ltd \| Half-Year Report 2022		32

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS

for the half-year ended 30 June 2022


	Notes	2022 US$m			2021 US$m
Cash flows from operating activities
Profit after tax for the period			1,679			342
Adjustments for:
Non-cash items
Depreciation and amortisation			927			821
Depreciation of lease assets			62			54
Change in fair value of derivative financial instruments			326			80
Net finance costs			55			118
Tax expense			1,248			161
Exploration and evaluation written off			1			56
Restoration			38			14
Gain on disposal of oil and gas properties			(430	)		—
Onerous contracts provision			(245	)		(4	)
Other			18			18
Changes in assets and liabilities
Increase in trade and other receivables			(186	)		(44	)
Increase in inventories			(39	)		(31	)
Increase in lease assets			—			(2	)
Decrease in provisions			(43	)		(86	)
Decrease in lease liabilities			(24	)		(8	)
(Increase)/decrease in other assets and liabilities			(810	)		52
Increase in trade and other payables			314			6
Cash generated from operations			2,891			1,547
Interest received			17			7
Dividends received			14			4
Borrowing costs relating to operating activities			(7	)		(58	)
Income tax paid			(322	)		(146	)
Payments for restoration			(70	)		(21	)

Net cash from operating activities			2,523			1,333

Cash flows from/(used in) investing activities
Cash received on acquisition of BHPP, including cash acquired	B.4		1,082			—
Payments for capital and exploration expenditure			(998	)		(831	)
Borrowing costs relating to investing activities			(103	)		(50	)
Advances to other external entities			(48	)		(126	)
Proceeds from disposal of non-current assets			112			—

Net cash from/(used in) investing activities			45			(1,007	)

Cash flows used in financing activities
Repayment of borrowings	C.2		(42	)		(742	)
Borrowing costs relating to financing activities			(6	)		(6	)
Repayment of the principal portion of lease liabilities			(91	)		(45	)
Borrowing costs relating to lease liabilities			(50	)		(46	)
Purchases of shares and payments relating to employee share plans			(17	)		(15	)
Contributions to non-controlling interests			(45	)		(48	)
Dividends paid (net of DRP)			(717	)		(88	)

Net cash used in financing activities			(968	)		(990	)

Net increase/(decrease) in cash held			1,600			(664	)
Cash and cash equivalents at the beginning of the period			3,025			3,604

Effects of exchange rate changes			(10	)		(2	)

Cash and cash equivalents at the end of the period			4,615			2,938

The accompanying notes form part of the half-year financial statements.


Woodside Energy Group Ltd \| Half-Year Report 2022		33

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

For the half-year ended 30 June 2022


	Issued and fully paid shares			Shares reserved for employee share plans			Employee benefits reserve			Foreign currency translation reserve		Hedging reserve			Distributable profits reserve			Other reserve		Retained earnings			Equity holders of the parent			Non-controlling interest			Total equity
Notes	C.1 US$m			C.1 US$m			US$m			US$m		US$m			US$m			US$m		US$m			US$m			US$m			US$m
At 1 January 2022		9,409			(30	)		232			793		(400	)		58			—		3,381			13,443			786			14,229
Transfers		—			—			—			—		—			2,025			—		(2,025	)		—			—			—
Profit for the period		—			—			—			—		—			—			—		1,640			1,640			39			1,679
Other comprehensive income/(loss)		—			—			—			2		(1,057	)		—			4		—			(1,051	)		—			(1,051	)

Total comprehensive income/(loss) for the period		—			—			—			2		(1,057	)		—			4		1,640			589			39			628

Dividend Reinvestment Plan		332			—			—			—		—			—			—		—			332			—			332
Shares issued for acquisition of BHPP		19,265			—			—			—		—			—			—		—			19,265			—			19,265
Replacement employee share plan issued on acquisition of BHPP		—			—			18			—		—			—			—		—			18			—			18
Employee share plan purchases		—			(17	)		—			—		—			—			—		—			(17	)		—			(17	)
Employee share plan redemptions		—			5			(5	)		—		—			—			—		—			—			—			—
Share-based payments (net of tax)		—			—			27			—		—			—			—		—			27			—			27
Dividends paid		—			—			—			—		—			—			—		(1,018	)		(1,018	)		(35	)		(1,053	)
Transaction costs associated with the issue of shares		(5	)		—			—			—		—			—			—		—			(5	)		—			(5	)

At 30 June 2022		29,001			(42	)		272			795		(1,457	)		2,083			4		1,978			32,634			790			33,424

At 1 January 2021		9,297			(23	)		219			793		(71	)		462			—		1,398			12,075			800			12,875
Profit for the period		—			—			—			—		—			—			—		317			317			25			342
Other comprehensive income		—			—			12			—		47			—			—		—			59			—			59

Total comprehensive income for the period		—			—			12			—		47			—			—		317			376			25			401

Dividend Reinvestment Plan		26			—			—			—		—			—			—		—			26			—			26
Employee share plan purchases		—			(15	)		—			—		—			—			—		—			(15	)		—			(15	)
Employee share plan redemptions		—			6			(6	)		—		—			—			—		—			—			—			—
Share-based payments (net of tax)		—			—			20			—		—			—			—		—			20			—			20
Dividends paid		—			—			—			—		—			(115	)		—		—			(115	)		(31	)		(146	)

At 30 June 2021		9,323			(32	)		245			793		(24	)		347			—		1,715			12,367			794			13,161

The accompanying notes form part of the half-year financial statements.


Woodside Energy Group Ltd \| Half-Year Report 2022		34

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2022

About these statements

Following the approval by shareholders at the Annual General Meeting on 19 May 2022, Woodside Petroleum Ltd has registered the change of company name to Woodside Energy Group Ltd (Woodside or the Group). Woodside is a for-profit entity limited by shares, incorporated and domiciled in Australia. Its shares are publicly traded on the Australian Securities Exchange (ASX), on the Main Market for listed securities of the London Stock Exchange (LSE) (with trades settled in the form of UK Depository Interests) and on the New York Stock Exchange (NYSE) (in the form of Woodside American Depositary Shares). The nature of the operations and principal activities of the Group are described in the Operational Overview, Projects and Development Activities sections and in the segment information below.

The condensed consolidated half-year financial statements were authorised for issue in accordance with a resolution of the Directors on 30 August 2022.

Statement of compliance

The condensed consolidated half-year financial statements are condensed general purpose financial statements, which have been prepared in accordance with Australian Accounting Standard (AASB) 134 Interim Financial Reporting as issued by the Australian Accounting Standards Board and the Australian Corporations Act 2001. Compliance with AASB 134 Interim Financial Reporting ensures compliance with International Accounting Standard (IAS) 34 Interim Financial Reporting as issued by the International Accounting Standards Board.

The condensed consolidated half-year financial statements do not include all notes of the type normally included in annual financial statements. Accordingly, these condensed consolidated half-year financial statements are to be read in conjunction with the Financial Statements within the Annual Report for the year ended 31 December 2021 (2021 Financial Statements) and any public announcements made by Woodside during the period ended 30 June 2022 in accordance with the continuous disclosure requirements of the Australian Corporations Act 2001 and the relevant ASX, LSE and NYSE Listing Rules.

Subsequent to the merger with BHP Petroleum International Pty Ltd (subsequently renamed Woodside Energy Global Holdings Pty Ltd), BHPP’s accounting policies have been aligned with the Group. The Group’s accounting policies are consistent with those disclosed in the Group’s 2021 Financial Statements. Adoption of new or amended standards and interpretations effective 1 January 2022 did not result in any significant changes to the Group’s accounting policies.

The significant accounting estimates and judgements are consistent with those disclosed in the 2021 Financial Statements. Estimates have been revised, where required, to reflect current market conditions including the impact of COVID-19 and climate change. Updated estimates used for impairment assessments and the measurement of onerous contracts are disclosed in Notes B.3 and D.2 respectively. Given ongoing economic uncertainty, these assumptions could change in the future. New estimates and judgements for significant transactions during the period including the recognition of goodwill as a result of the business combination and the sell-down of Train 2 are disclosed in Notes B.4 and B.5 respectively.

Currency

The functional and presentation currency of Woodside and all its material subsidiaries is US dollars.

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 the condensed consolidated half-year 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 condensed consolidated half-year financial statements have been prepared on a historical cost basis, except for derivative financial instruments and certain other financial assets and financial liabilities, which have been measured at fair value or amortised cost, adjusted for changes in fair value attributable to the risks that are being hedged in effective hedge relationships. Where not carried at fair value, if the carrying value of financial assets and financial liabilities does not approximate their fair value, the fair value has been included in the notes to the condensed consolidated half-year financial statements.


Woodside Energy Group Ltd \| Half-Year Report 2022		35

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2022

Basis of preparation (continued)

The condensed consolidated half-year financial statements comprise the financial results of the Group and its subsidiaries for the period ended 30 June 2022. 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 apply the same reporting period and accounting policies as the parent company in preparation of the condensed consolidated half-year financial statements. All intercompany balances and transactions, including unrealised profits and losses arising from intra-group transactions, have been eliminated in full.

Non-controlling interests are allocated their share of the net profit after tax in the consolidated income statement, 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.

Comparative information

The condensed consolidated half-year 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 condensed consolidated half-year financial statements of the current period.

Reporting segments

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 determining the allocation of resources.

As a result of the merger with BHPP on 1 June 2022, the Group has transformed into a global energy company which has led to a change in how financial information is reported in the Group. The disclosed operating segments have been updated to reflect this change and 2021 amounts have been restated to be presented on the same basis.

Operating segments outlined below are identified by management based on the nature and geographical location of the business and venture.

Australia – Exploration, evaluation, development, production and sale of liquified natural gas, pipeline gas, crude oil and condensate and natural gas liquids in Australia.

International – Exploration, evaluation, development, production and sale of pipeline gas, crude oil and condensate and natural gas liquids in international jurisdictions outside of Australia.

Marketing – Trading of liquified natural gas (non-produced) and optimisation activities generating incremental value from produced liquified natural gas via scheduling, shipping and/or contract management. The incremental income and expenses from marketing activities relating to hydrocarbons other than liquified natural gas (e.g. liquids, pipeline gas) are not included in the segment for the half-year ended 30 June 2022.

Corporate/Other items – Corporate/Other items comprise primarily corporate non-segmental items of revenue and expenses and associated assets and liabilities not allocated to operating segments as they are not considered part of the core operations of any segment.

In addition to the updated segments, the Group has reassessed the reporting of revenue from the sale of liquified natural gas on a portfolio basis. With the Marketing segment separately reported for the half-year ended 30 June 2022, the Group will no longer report revenue from the sale of liquified natural gas on a portfolio basis to better represent the revenues and margins generated by each segment. 2021 amounts have been restated to be presented on the same basis.


Woodside Energy Group Ltd \| Half-Year Report 2022		36

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2022

A. Earnings for the period

A.1 Segment revenue and expenses


	Australia						International						Marketing						Corporate/ Other						Consolidated
	2022 US$m			2021⁷ US$m			2022 US$m			2021⁷ US$m			2022 US$m			2021⁷ US$m			2022 US$m			2021⁷ US$m			2022 US$m			2021 US$m
Liquified natural gas		3,119			1,470			—			—			986			338			—			—			4,105			1,808
Pipeline gas		232			22			57			—			—			—			—			—			289			22
Crude oil and condensate		1,066			566			243			—			—			—			—			—			1,309			566
Natural gas liquids		11			21			5			—			—			—			—			—			16			21

Revenue from sale of hydrocarbons		4,428			2,079			305			—			986			338			—			—			5,719			2,417

Intersegment revenue¹		(323	)		(102	)		—			—			323			102			—			—			—			—
Processing and services revenue		77			70			—			—			—			—			—			—			77			70
Shipping and other revenue		6			4			—			—			8			13			—			—			14			17

Other revenue		(240	)		(28	)		—			—			331			115			—			—			91			87

Operating revenue²		4,188			2,051			305			—			1,317			453			—			—			5,810			2,504

Production costs		(350	)		(229	)		(33	)		—			—			—			(14	)		4			(397	)		(225	)
Royalties, excise and levies		(189	)		(75	)		(14	)		—			—			—			(17	)		—			(220	)		(75	)
Insurance		(18	)		(13	)		(1	)		—			—			—			(3	)		(3	)		(22	)		(16	)
Inventory movement		15			1			—			—			—			—			—			—			15			1

Costs of production		(542	)		(316	)		(48	)		—			—			—			(34	)		1			(624	)		(315	)

Land and buildings		(25	)		(26	)		—			—			—			—			—			—			(25	)		(26	)
Transferred exploration and evaluation		(50	)		(40	)		(1	)		—			—			—			—			—			(51	)		(40	)
Plant and equipment		(774	)		(738	)		(58	)		—			—			—			(16	)		(15	)		(848	)		(753	)

Oil and gas properties depreciation and amortisation		(849	)		(804	)		(59	)		—			—			—			(16	)		(15	)		(924	)		(819	)

Shipping and direct sales costs		(92	)		(78	)		(4	)		—			(15	)		(15	)		17			26			(94	)		(67	)
Trading costs		—			—			—			—			(790	)		(355	)		—			—			(790	)		(355	)
Other hydrocarbon costs		(19	)		—			—			—			—			—			—			—			(19	)		—
Other cost of sales		(3	)		—			—			—			—			—			—			—			(3	)		—
Movement in onerous contract provision³		—			—			—			—			216			21			—			—			216			21

Other cost of sales		(114	)		(78	)		(4	)		—			(589	)		(349	)		17			26			(690	)		(401	)

Cost of sales		(1,505	)		(1,198	)		(111	)		—			(589	)		(349	)		(33	)		12			(2,238	)		(1,535	)

Gross profit		2,683			853			194			—			728			104			(33	)		12			3,572			969

Other income⁴		494			11			4			(2	)		5			—			—			20			503			29

Exploration and evaluation expenditure		(7	)		(8	)		(19	)		(18	)		—			—			(14	)		(6	)		(40	)		(32	)
Amortisation		—			—			(3	)		(2	)		—			—			—			—			(3	)		(2	)
Write-offs		—			—			(1	)		(56	)		—			—			—			—			(1	)		(56	)

Exploration and evaluation		(7	)		(8	)		(23	)		(76	)		—			—			(14	)		(6	)		(44	)		(90	)

General, administration and other costs⁵		(5	)		(1	)		(12	)		3			—			—			(525	)		(70	)		(542	)		(68	)
Depreciation of lease assets		(21	)		(14	)		(1	)		—			—			—			(40	)		(40	)		(62	)		(54	)
Restoration movement		(31	)		(22	)		(10	)		8			—			—			3			—			(38	)		(14	)
Other⁶		(18	)		(10	)		(64	)		(42	)		(227	)		(31	)		(98	)		(68	)		(407	)		(151	)

Other costs		(75	)		(47	)		(87	)		(31	)		(227	)		(31	)		(660	)		(178	)		(1,049	)		(287	)

Other expenses		(82	)		(55	)		(110	)		(107	)		(227	)		(31	)		(674	)		(184	)		(1,093	)		(377	)

Profit/(loss) before tax and finance costs		3,095			809			88			(109	)		506			73			(707	)		(152	)		2,982			621

1.	Intersegment revenue comprises the incremental income net of all associated expenses generated by the Marketing activities optimising the liquified natural gas portfolio. The value is incremental income net of incremental costs.

2.	Operating revenue includes revenue from contracts with customers of $5,802 million (2021: $2,488 million) and sub-lease income of $8 million (2021: $16 million) disclosed within shipping and other revenue.

3.	Comprises changes in estimates of $245 million offset by provisions used of $29 million (2021: Comprised provisions used of $17 million, revision of discount rates of $8 million offset by changes in estimates of $4 million). Refer to Note D.2 for more details.

4.	Includes gain on Train 2 sell-down, fees and recoveries, foreign exchange gains and other income not associated with the ongoing operations of the business.

5.	Transaction costs incurred as a result of the BHPP merger on 1 June 2022 are included in the Corporate/Other segment. Refer to Note B.4.

6.	Includes losses on hedging activities and other expenses not associated with the ongoing operations of the business.

7.	The 2021 amounts have been restated to reflect the changes in operating segments and portfolio reporting for LNG revenue.


Woodside Energy Group Ltd \| Half-Year Report 2022		37

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2022

A.2 Finance costs


	2022 US$m			2021 US$m
Interest on interest-bearing liabilities		101			104
Interest on lease liabilities		58			46
Accretion charge		26			13
Other finance costs		14			15
Less: Finance costs capitalised against qualifying assets		(113	)		(48	)

		86			130

A.3 Dividends paid and proposed

Woodside Energy Group Ltd, the parent entity, paid and proposed dividends as set out below:


	2022 US$m		2021 US$m
(a) Dividends paid during the financial period
Prior year fully franked final dividend US$1.05, paid on 23 March 2022 (2021: US$0.12, paid on 24 March 2021)		1,018		115
(b) Dividend declared subsequent to the reporting period (not recorded as a liability)
Current year fully franked interim dividend US$1.09 to be paid on 6 October 2022 (2021: US$0.30, paid on 24 September 2021)		2,070		289

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 will remain in place until further notice.

A.4 Earnings per share


	2022		2021
Profit attributable to equity holders of the parent (US$m)		1,640		317
Weighted average number of shares on issue for basic earnings per share		1,127,109,476		951,489,253
Effect of dilution from contingently issuable shares		11,895,577		9,069,843
Weighted average number of shares on issue adjusted for the effect of dilution		1,139,005,053		960,559,096
Basic earnings per share (US cents)		145.5		33.3
Diluted earnings per share (US cents)		144.0		33.0

Earnings per share is calculated by dividing the profit for the period attributable to ordinary equity holders of the parent by the weighted average number of shares on issue during the period. 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. As at 30 June 2022, 11,895,577 (2021: 9,069,843) awards granted under the Woodside employee share plans are considered dilutive.


Woodside Energy Group Ltd \| Half-Year Report 2022		38

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2022

B. Production and growth assets

B.1 Exploration and evaluation


	Asia Pacific US$m			Americas US$m			Africa US$m			Other US$m			Total US$m
Half-year ended 30 June 2022
Carrying amount at 1 January 2022		546			—			68			—			614
Acquisitions through business combination¹		112			465			—			—			577
Additions		6			—			—			1			7
Amortisation of licence acquisition costs		—			(2	)		(1	)		—			(3	)
Expensed²		—			—			—			(1	)		(1	)
Transferred exploration and evaluation		—			—			(2	)		—			(2	)

Carrying amount at 30 June 2022		664			463			65			—			1,192

Year ended 31 December 2021
Carrying amount at 1 January 2021		1,981			—			64			—			2,045
Additions		494			—			7			—			501
Amortisation of licence acquisition costs		—			—			(3	)		—			(3	)
Expensed²		(265	)		—			—			—			(265	)
Transferred exploration and evaluation		(1,664	)		—			—			—			(1,664	)

Carrying amount at 31 December 2021		546			—			68			—			614

1.	Acquisitions through business combination have been recognised on a provisional basis. Adjustments will be made to the provisional amounts if new information is obtained within 12 months from the acquisition date. Refer to Note B.4 for details.

2.	$1 million (31 December 2021: $56 million) relates to costs of unsuccessful wells. For the year ended 31 December 2021, $209 million relates to capitalised costs written off due to the Group’s decision to withdraw its interests in Myanmar.


Woodside Energy Group Ltd \| Half-Year Report 2022		39

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2022

B.2 Oil and gas properties


	Land and buildings US$m			Transferred exploration and evaluation US$m			Plant and equipment US$m			Projects in development US$m			Total US$m
Half-year ended 30 June 2022
Carrying amount at 1 January 2022		739			526			12,465			4,919			18,649
Acquisitions through business combination¹		63			—			13,869			5,778			19,710
Additions²		—			—			(404	)		1,676			1,272
Disposals at written down value		(3	)		(10	)		(28	)		—			(41	)
Depreciation and amortisation		(25	)		(50	)		(849	)		—			(924	)
Completions and transfers		1			2			542			(545	)		—

Carrying amount at 30 June 2022		775			468			25,595			11,828			38,666

At 30 June 2022
Historical cost		1,759			1,497			46,807			12,227			62,290
Accumulated depreciation and impairment		(984	)		(1,029	)		(21,212	)		(399	)		(23,624	)

Net carrying amount		775			468			25,595			11,828			38,666

Year ended 31 December 2021
Carrying amount at 1 January 2021		749			431			12,091			2,195			15,466
Additions		—			—			13			2,321			2,334
Disposals at written down value		(2	)		—			(5	)		(22	)		(29	)
Depreciation and amortisation		(51	)		(79	)		(1,450	)		—			(1,580	)
Impairment losses		(10	)		—			—			—			(10	)
Impairment reversals		44			66			911			37			1,058
Completions and transfers		11			108			905			640			1,664
Transfer to non-current assets held for sale		(2	)		—			—			(252	)		(254	)

Carrying amount at 31 December 2021		739			526			12,465			4,919			18,649

At 31 December 2021
Historical cost		1,701			1,495			32,797			5,321			41,314
Accumulated depreciation and impairment		(962	)		(969	)		(20,332	)		(402	)		(22,665	)

Net carrying amount		739			526			12,465			4,919			18,649

1.	Acquisitions through business combination have been recognised on a provisional basis. Adjustments will be made to the provisional amounts if new information is obtained within 12 months from the acquisition date. Refer to Note B.4 for details.

2.	Includes $1,509 million of capital additions and $113 million of capitalised borrowing costs offset by $350 million following changes in restoration provision assumptions.

The Group has capital expenditure commitments contracted for, but not provided for in the financial statements, of$7,899 million (31 December 2021: $7,875 million).

B.3 Impairment of non-current assets

For the purpose of impairment testing, goodwill acquired in a business combination is, from the acquisition date, allocated to each of the Group’s cash-generating units (CGUs) that are expected to benefit from the combination, irrespective of whether other assets or liabilities of the acquiree are assigned to those units. Goodwill that is created on acquisition as a consequence of deferred tax balances is tested for impairment net of those associated deferred tax balances. Goodwill is tested at least annually for impairment and more frequently if events or changes in circumstances indicate that it mightbe impaired.

The Group assessed each CGU for indicators of impairment and impairment reversal. No indicators of impairment or impairment reversal were identified in the period ended 30 June 2022. Revised Brent oil price estimates are disclosed in Note D.2. Other key estimates and judgements used have not materially changed from those disclosed in Note B.4 in the 2021 Financial Statements.


Woodside Energy Group Ltd \| Half-Year Report 2022		40

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2022

B.4 Business combination

BHP Petroleum merger

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 Share Sale Agreement (SSA) and the integration and transition services agreement were executed on 22 November 2021. Under the SSA, the merger took economic effect from 1 July 2021 and Woodside became entitled to the economic benefits and risks of the assets and liabilities that were the subject of the merger from that date.

On 19 May 2022, 98.66% of Woodside shareholders voted in favour of the merger at Woodside’s Annual General Meeting.

On 1 June 2022, the transaction was completed with the Group acquiring 100% of the issued share capital of BHP Petroleum International Pty Ltd (subsequently renamed Woodside Energy Global Holdings Pty Ltd), which held BHP’s oil and gas business. In exchange, the Group issued 914,768,948 new Woodside shares to BHP as part of the merger consideration. The transaction has been accounted for as a business combination with an acquisition date of 1 June 2022. The Group’s net profit after tax for the period ended 30 June 2022 will incorporate BHPP results from acquisition date. The merger is expected to create opportunities to realise ongoing synergies.

Due to the size, complexity and timing of the transaction, the related acquisition accounting is not yet finalised and accordingly the assets acquired and liabilities assumed are measured on a provisional basis. If new information is obtained within 12 months from the acquisition date about facts and circumstances that existed at the acquisition date, adjustments will be made to the provisional amounts recognised including the value of goodwill.

The merged Group’s financial results could be adversely affected by impairments of goodwill or other intangible assets, the application of future accounting policies or interpretations of existing accounting policies including by regulatory direction, and changes in estimates of decommissioning costs. Details and risks have been included in the Merger Explanatory Memorandum released on 8 April 2022.

Given the purchase consideration was agreed on 22 November 2021 based on a fixed number of shares, the final value of consideration paid was subject to fluctuations in share price until completion on 1 June 2022. This has resulted in a material goodwill number which will be subject to impairment in future, for example should commodity prices decrease.

Details of the purchase consideration and the provisional fair value of goodwill, identifiable assets and liabilities of BHPP acquired are as follows:


Provisional fair value of net identifiable assets and goodwill arising on acquisition date	US$m
Cash and cash equivalents		399
Receivables		1,170
Inventories		295
Investments accounted for using the equity method		240
Other financial assets		59
Other assets		19
Exploration and evaluation assets		577
Oil and gas properties		19,710
Lease assets		142
Payables		(925	)
Lease liabilities		(268	)
Other liabilities		(1,071	)
Provisions		(4,806	)
Tax payable		(366	)
Deferred tax liabilities		(550	)

Net identifiable assets acquired		14,625

Goodwill arising on acquisition		3,975

Purchase consideration		18,600


Purchase consideration	US$m
Shares issued, at fair value		19,265
Other reserves (Share replacement awards)		18
Provisional locked box payment received¹		(683	)

Total purchase consideration		18,600

1.	Represents the positive net cash flow of $1,513 million generated by BHPP assets from the effective date of the business combination offset by the notional dividend distribution of $830 million paid to BHP.


Woodside Energy Group Ltd \| Half-Year Report 2022		41

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2022

B.4 Business combination (continued)


Analysis of cash flows on acquisition	US$m
Cash acquired on acquisition		399
Provisional locked box payment received		683

Net cash flow received on acquisition (included in the Statement of Cash Flows as Investing activities)		1,082

Acquisition-related costs of $424 million that were not directly attributable to the issue of shares are included as an expense in General, Administration and Other Costs in the Income Statement. $258 million have been paid and included in the Statement of Cash Flows as Operating activities. Acquisition-related costs of $5 million directly attributable to the issue of shares are included in Contributed Equity.

Shares issued, at fair value

The fair value of 914,768,948 shares issued as part of the consideration paid to BHP was $19,265 million. This was based on the published share price on 1 June 2022 of US$21.06 per share.

Provisional locked box payment received

The Group received $683 million as part of the merger consideration which includes the locked box payment of$1,513 million representing the positive net cash flow generated by BHPP assets from the effective date of the transaction to completion date offset by the notional dividend distribution of $830 million paid to BHP.

Revenue and contribution to the Group

The acquired business contributed operating revenue of $650 million and profit before tax of $341 million to the Group from the acquisition date to 30 June 2022. If the acquisition had occurred on 1 January 2022, consolidated operating revenue and profit before tax would have been higher by $3,115 million and $1,265 million respectively.

Acquired receivables

The fair value of receivables approximates the gross amount of trade receivables. None of the receivables have been impaired and the full contractual amounts are expected to be collected.

Other liabilities

The Group recognised contingent liabilities of $39 million within Other Liabilities. This is based on the Group’s assessment of the fair value of contingent liabilities acquired on acquisition, taking into account a range of possible outcomes. The contingent liabilities include $27 million as a result of previous audits of production sharing agreements.

As at 30 June 2022, there have been no changes to the amount recognised on acquisition date.

Goodwill

Goodwill arising from the acquisition has been recognised as the excess of consideration paid above the fair value of the assets acquired and liabilities assumed as part of the business combination. A portion of the goodwill arises from the net deferred tax liability recognised on acquisition as a consequence of asset tax bases received in the merger being lower than the fair value of the assets acquired. Given the timing of the acquisition, it has been impracticable to complete the allocation of the remaining goodwill to the Group’s CGUs. As such, the Group cannot make disclosures and information on goodwill allocation that will be provided as part of the 31 December 2022 financial statements. The goodwill is not deductible for tax purposes.

Goodwill is initially measured at cost and is subsequently measured at cost less any accumulated impairment losses. For the purposes of impairment testing, goodwill acquired in a business combination is, from the acquisition date, allocated to each of the Group’s CGUs or groups of CGUs no larger than an operating segment that are expected to benefit from the combination, irrespective of whether other assets or liabilities of the acquiree are assigned to those units.

Where goodwill has been allocated to a CGU and part of the operation within that unit is disposed of, the goodwill associated with the disposed operation is included in the carrying amount of the operation when determining the gain or loss on disposal. Goodwill is not amortised but will be assessed at least annually for impairment and more frequently if events or changes in circumstances indicate that it might be impaired.


Woodside Energy Group Ltd \| Half-Year Report 2022		42

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2022

B.4 Business combination (continued)

Share replacement awards

In accordance with the terms of the SSA, the Group exchanged equity-settled share-based payment awards held by employees of BHPP for equity-settled share-based payment awards of Woodside. The replacement awards are based on service conditions with a vesting date of 31 August 2023 and 31 August 2024. The fair value of the replacement awards on acquisition is $49 million based on a forfeiture rate of 3%. $18 million has been included as part of the purchase consideration and the remaining amount will be recognised as post-acquisition compensation cost.

Business combination accounting

The acquisition method of accounting is used to account for all business combinations, including business combinations involving entities or businesses under common control, regardless of whether equity instruments are issued or liabilities incurred or assumed at the date of exchange. Where equity instruments are issued in an acquisition, the fair value of the instruments is their published market price as at the date of exchange.

Transaction costs arising on the issue of equity instruments are recognised directly in equity. Transaction costs that were not directly attributable to the issue of shares are expensed as incurred.

Contractual assets and liabilities in respect of sales agreements are recognised at fair value.

Restoration provisions are recognised on acquisition at fair value.

B.5 Disposal of assets

Sell-down of Train 2

On 15 November 2021 the Group entered into a sale and purchase agreement with Global Infrastructure Partners (GIP) for the sale of a 49% non-operating participating interest in the Pluto Train 2 Joint Venture. The transaction completed on 18 January 2022, reducing the Group’s participating interest from 100% to 51%. The Group recognised a pre-tax gain on sale of $427 million.

The arrangements require GIP to fund its 49% share of capital expenditure from 1 October 2021 and an additional amount of construction capital expenditure of $822 million on behalf of the Group. If the total capital expenditure incurred is less than $5,800 million, GIP will pay Woodside an additional amount equal to 49% of the under-spend. In the event of a cost overrun, Woodside will fund up to $822 million of GIP’s share of the overrun. Delays to the expected start-up of production will result in payments by Woodside to GIP in certain circumstances. The arrangements include provisions for GIP to be compensated for exposure to additional Scope 1 emissions liabilities above agreed baselines, and to sell its 49% interest back to Woodside if the status of key regulatory approvals materially changes. As at 30 June 2022, the fair value of the remaining unpaid funding has been recognised as a current receivable and will be recognised as Oil and Gas Properties in the future as paid by GIP.

Key estimates and judgements

Sell-down of Train 2

Given the arrangements include provisions for GIP to sell its 49% interest back to Woodside if the status of key regulatory environmental approvals materially changes and the requirement for Woodside to fund up to $822 million of GIP’s share in the event of a cost overrun, judgement is required to determine if the sell-down of Train 2 constitutes a sale and if a portion of the transaction price should be considered a variable consideration.

Judgement was used to determine that the sell-down of Train 2 constituted a sale given the various conditions included in the sale and purchase agreement. The Group determined that a sale occurred as control of the 49% interest was passed to GIP on completion date. Control is determined as the ability to direct the use of, and obtain substantially all of the economic benefits of, the associated interest.

Judgement was used to determine if it is highly probable that a significant reversal will not occur in relation to the consideration received. For the half-year ended 30 June 2022, the Group estimated the variable consideration based on the construction capital expenditure cost profile, the development schedule, and assessing the probability and impact of any event which may result in a significant reversal. The constraining estimates of variable consideration have been applied resulting in the pre-tax gain on sale of $427 million. The variable consideration will be remeasured at each reporting period with any changes recognised through the Income Statement. The variable consideration has been remeasured as at 30 June 2022 with no revaluation gain or loss recognised.


Woodside Energy Group Ltd \| Half-Year Report 2022		43

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2022

C.	Debt and capital

C.1 Contributed equity


Issued and fully paid shares	Number of shares		US$m
Half-year ended 30 June 2022
Opening balance		969,631,826		9,409
DRP – ordinary shares issued at US$23.14 (2021 final dividend)		14,348,997		332
Ordinary shares issued at US$21.06 for the acquisition of BHPP¹		914,768,948		19,265
Transaction costs associated with the issue of shares		—		(5	)

Amounts as at 30 June 2022		1,898,749,771		29,001

Year ended 31 December 2021
Opening balance		962,225,814		9,297
DRP – ordinary shares issued at US$19.03 (2020 final dividend)		1,354,072		26
DRP – ordinary shares issued at US$14.21 (2021 interim dividend)		6,051,940		86

Amounts as at 31 December 2021		969,631,826		9,409

1.	914,768,948 new Woodside shares were issued as consideration for the BHPP merger. Refer to Note B.4 for details.

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 respect of its issued shares.


Shares reserved for employee share plans	30 June 2022 US$m			31 December 2021 US$m
2,289,826 (2021: 1,819,744) reserved shares		(42	)		(30	)

C.2 Interest-bearing liabilities and financing facilities

During the period, the Group repaid $42 million of the Japan Bank for International Cooperation (JBIC) facility. There were no other material changes to interest-bearing liabilities and financing facilities. For the year ended 31 December 2021, the Group redeemed the $700 million 2021 US bond and repaid $84 million on the JBIC facility.

Subsequent to period end, the Group repaid a number of its financing facilities. In addition, the Group also refinanced and increased an existing committed undrawn syndicated facility (refer to Note E.4).

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 $4,083 million (31 December 2021: $4,081 million) and a fair value of $3,920 million (31 December 2021: $4,443 million). The medium-term notes have a carrying amount of $583 million (31 December 2021: $592 million) and a fair value of $567 million (31 December 2021: $604 million). The fair value of the bonds and notes was determined using quoted prices in an active market, classified as Level 1 on the fair value hierarchy.


Woodside Energy Group Ltd \| Half-Year Report 2022		44

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2022

D.	Other assets and liabilities

D.1 Segment assets and liabilities


	30 June 2022 US$m		31 December 2021² US$m
(a) Segment assets¹
Australia		28,483		18,163
International		17,483		2,877
Marketing		182		217
Corporate/Other		8,804		5,217

		54,952		26,474


	30 June 2022 US$m		31 December 2021² US$m
(b) Segment liabilities¹
Australia		6,696		2,889
International		2,926		435
Marketing		731		639
Corporate/Other		11,175		8,282

		21,528		12,245

1.	Acquisitions through business combination have been recognised on a provisional basis. Adjustments will be made to the provisional amounts if new information is obtained within 12 months from the acquisition date. Refer to Note B.4 for details.

2.	The 2021 amounts have been restated to reflect the changes in operating segments. Refer to ‘Reporting Segments’ for details.

Refer to ‘About these statements’ for information relating to the Group’s segments. Corporate/other assets mainly comprise cash and cash equivalents, lease assets and deferred tax assets. Corporate/other liabilities mainly comprise interest-bearing liabilities, lease liabilities and deferred tax liabilities.

D.2 Provisions


	Restoration¹ US$m			Employee benefits US$m			Onerous contracts² US$m			Other US$m			Total US$m
Half-year ended 30 June 2022
At 1 January 2022		2,218			286			214			106			2,824
Acquisitions through business combination³		4,312			329			—			165			4,806
Change in provision		(393	)		(162	)		(216	)		62			(709	)
Unwinding of present value discount		24			30			2			—			56

Carrying amount at 30 June 2022		6,161			483			—			333			6,977

Current		482			252			—			287			1,021
Non-current		5,679			231			—			46			5,956
Net carrying amount		6,161			483			—			333			6,977
Year ended 31 December 2021
At 1 January 2021		2,134			295			349			129			2,907
Change in provision		60			(9	)		(140	)		(23	)		(112	)
Unwinding of present value discount		24			—			5			—			29

Carrying amount at 31 December 2021		2,218			286			214			106			2,824

Current		235			269			—			101			605
Non-current		1,983			17			214			5			2,219

Net carrying amount		2,218			286			214			106			2,824

1.	2022 change in provision is due to a revision of discount rates of $492 million (primarily due to an increase in risk free rates) and provisions used of $68 million, offset by changes in estimates of $167 million.

2.	2022 change in provision is due to changes in estimates of $245 million offset by provisions used of $29 million.

3.	Acquisitions through business combination have been recognised on a provisional basis. Adjustments will be made to the provisional amounts if new information is obtained within 12 months from the acquisition date. Refer to Note B.4 for details.


Woodside Energy Group Ltd \| Half-Year Report 2022		45

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2022

D.2 Provisions (continued)

Key estimates and judgements

Restoration obligations

The key estimates and judgements of the Group’s restoration obligations have not materially changed from those disclosed in Note D.5 in the 2021 Financial Statements. Whilst the provisions reflect the Group’s best estimate based on current knowledge and information, actual costs and cash outflows may 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 30 June 2022.

Onerous contracts

The onerous contract provision assessment requires management to make certain estimates regarding the unavoidable costs and the expected economic benefits from the contract. These estimates require significant management judgement and are subject to risk and uncertainty, and hence changes in economic conditions can affect the assumptions.

As at 30 June 2022, the Corpus Christi contract is expected to return a positive value and on this basis the provision has been reversed to nil (31 December 2021: $214 million). Changes in assumptions predominantly relating to the narrowing of the spread between the sales price and purchase price could result in the contract becoming onerous in the future.

Assumptions used to determine the present value as at 30 June 2022 are set out below:

•

Remaining contract term – 18.5 years.

•

Discount rate – a pre-tax, risk free US government bond rate of 3.32% (31 December 2021: 1.855%) has been applied.

•

LNG pricing – forecast sales and purchase prices are subject to a number of price markers. Price assumptions are based on the best information on the market available at measurement date and derived from short- and long-term views of global supply and demand, building upon past experience of the industry and consistent with external sources. The forecasted sales are linked to gas hub prices (Title Transfer Facility (TTF)) at which physical sales are expected to occur and incorporate known sales pricing information¹. The long-term gas sales price is estimated on the basis of the Group’s Brent price forecast. The estimated purchase price is linked to US gas hub prices (Henry Hub (HH)) at which physical purchases are expected to occur. The nominal TTF, Brent oil prices and HH gas prices used at 30 June 2022 were:


	2022		2023		2024		2025		2026
TTF (US$/MMBtu)		26.0		19.4		13.5		7.0		7.2
Brent (US$/bbl)		100		87		78		69		70	²
Henry Hub (US$/MMBtu)		6.0		4.6		3.6		3.2		3.3	³

1.	For committed volumes, contract pricing has been applied.

2.	Long-term oil prices are based on US$65/bbl (2022 real terms) from 2025 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%.


Woodside Energy Group Ltd \| Half-Year Report 2022		46

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2022

D.3 Other financial assets and liabilities


	30 June 2022 US$m		31 December 2021 US$m
Other financial assets
Financial instruments at fair value through profit and loss
Derivative financial instruments designated as hedges		158		134
Other financial assets		427		293

Total other financial assets		585		427

Current		493		320
Non-current		92		107
Net carrying amount		585		427
Other financial liabilities
Financial instruments at fair value through profit and loss
Derivative financial instruments designated as hedges		1,700		563
Other financial liabilities		25		9

Total other financial liabilities		1,725		572

Current		1,302		411
Non-current		423		161

Net carrying amount		1,725		572

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 2022 to 2023 in order to achieve a minimum average sales price of $75 per barrel.

•

The Group entered into additional 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 to mitigate pricing risk for 2022 to 2024. As a result of hedging and term sales, approximately 94% of Corpus Christi volumes in 2022, 73% in 2023 and 27% in 2024 have reduced pricing risk.

•

The Group also restruck $150 million of the TTF hedges at current market prices to reduce the derivative financial liability.

•

Through the use of foreign exchange forward contracts, the Group hedged its Australian dollar to US dollar exchange rate in relation to a portion of the Australian dollar denominated capital expenditure expected to be incurred under the Scarborough development.

The following table presents the Group’s derivative financial instruments designated as hedges, measured and recognised at fair value:


	30 June 2022 US$m			31 December 2021 US$m
Oil swaps (cash flow hedges)		(720	)		(1	)
HH Corpus Christi commodity swaps (cash flow hedges)		85			31
TTF Corpus Christi commodity swaps (cash flow hedges)		(917	)		(465	)
TTF commodity swaps (cash flow hedges)		—			4
Interest rate swaps (cash flow hedges)		32			(17	)
Cross-currency interest rate swaps (cash flow and fair value hedges)		1			9
FX forwards (cash flow hedges)		(23	)		10

Total derivative financial instruments designated as hedges		(1,542	)		(429	)


Woodside Energy Group Ltd \| Half-Year Report 2022		47

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2022

D.3 Other financial assets and liabilities (continued)

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 the three-month and six-month LIBOR will be phased out and eventually replaced by June 2023.

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 $916 million (31 December 2021: $957 million) and $377 million (31 December 2021: $367 million) respectively, which reference 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. 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.

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.

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. Other financial assets and other financial liabilities set out in this note are classified as Level 2 on the fair value hierarchy with market observable inputs. During the period, there were no reclassifications between the fair value hierarchy levels.

There were no changes to the Group’s valuation processes, valuation techniques and types of inputs used in the fair value measurements during the period.

Financial risk factors

The Group’s activities expose its financial instruments to a variety of market risks, including foreign exchange, commodity price and interest rate risk. The half-year financial report does not include all financial risk management information and disclosures required in the annual report and as such, should be read in conjunction with the Group’s 2021 Financial Statements. There have been no significant changes in the risk management policies since 31 December 2021.


Woodside Energy Group Ltd \| Half-Year Report 2022		48

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2022

E. Other items

E.1 Contingent liabilities and assets


	30 June 2022 US$m		31 December 2021 US$m
Contingent liabilities at reporting date
Not otherwise provided for in the financial statements:
Contingent liabilities		166		195
Guarantees		2		7

		168		202

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 condensed half-year 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.

There were no contingent assets as at 30 June 2022 or 31 December 2021.

E.2 Related party transactions

The Group’s related parties transactions are predominantly with associates of the Group. During the period, the transactions with related parties include purchases of goods/services of $2 million and dividend income of $3 million. As at 30 June 2022, the total amounts owing to related parties is $2 million.

E.3 Changes to the composition of the Group

Since the last annual reporting, PT Woodside Energy Indonesia, a wholly owned subsidiary, was incorporated in Indonesia on 27 April 2022. In addition, as a result of the merger with BHPP on 1 June 2022, the following subsidiaries, joint arrangements and associates were acquired. The list below includes entity name changes in July 2022:


Entities acquired	Location	Ownership %
Woodside Energy Global Holdings Pty Ltd	Australia		100.00
Woodside Energy Global Pty Ltd	Australia		100.00
North West Shelf Liaison Company Pty Ltd	Australia		16.67	¹
North West Shelf Shipping Service Company Pty Ltd	Australia		16.67	¹
Perdido Mexico Pipeline Holdings, S.A. de C.V.	Mexico		99.99	²
Perdido Mexico Pipeline, S. de R.L. de C.V.	Mexico		99.99	²
Woodside Energy Investments Pty Ltd	Australia		100.00
Woodside Energia Brasil Investimentos Ltda.	Brazil		99.97	³
Woodside Energia Brasil Exploração e Produção Ltda.	Brazil		99.99	⁴
Woodside Energy (Great Britain) Limited	United Kingdom		100.00
Woodside Energy (North West Shelf) Pty Ltd	Australia		100.00
North West Shelf Lifting Coordinator Pty Ltd	Australia		16.67	¹
North West Shelf Gas Pty Limited	Australia		16.67	¹
International Gas Transportation Company Limited	Bermuda		16.67	⁵
China Administration Company Pty Ltd	Australia		16.67	¹
Woodside Energy (Trinidad) Holdings Ltd.	Saint Lucia		100.00
Woodside Energy (Trinidad-3A) Ltd	Republic of Trinidad and Tobago		100.00
Woodside Energy USA Operations Inc	United States		90.00	⁶
Hamilton Brothers Petroleum Corporation	United States		100.00
Hamilton Oil Company LLC	United States		100.00
Woodside Energy Boliviana Inc.	United States		100.00
Woodside Energy (North America) LLC	United States		100.00
Woodside Energy (Americas) Inc.	United States		100.00
Woodside Energy (GOM) Inc.	United States		100.00


Woodside Energy Group Ltd \| Half-Year Report 2022		49

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2022

E.3 Changes to the composition of the Group (continued)


Entities acquired	Location	Ownership %
Woodside Energy Hawaii Inc.	United States		100.00
Iwilei District Participating Parties, LLC	United States		14.96	⁵
Woodside Energy Resources Inc.	United States		100.00
Woodside Energy Holdings (Resources) Inc.	United States		100.00
Woodside Energy USA Services Inc.	United States		100.00
Woodside Energy Marketing Inc.	United States		100.00
Woodside Energy (Deepwater) Inc.	United States		100.00
Caesar Oil Pipeline Company, LLC	United States		25.00	⁵
Cleopatra Gas Gathering Company LLC	United States		22.00	⁵
Marine Well Containment Company LLC	United States		10.00	⁵
Woodside Energy (Foreign Exploration Holdings) LLC	United Kingdom		100.00
Woodside Energy (Trinidad Block 3) Limited	United Kingdom		100.00
Woodside Energy (Trinidad Block 6) Limited	United Kingdom		100.00
Woodside Energy (Trinidad Block 5) Limited	United Kingdom		100.00
Woodside Energy (Trinidad Block 7) Limited	United Kingdom		100.00
Woodside Energy (Trinidad Block 14) Limited	United Kingdom		100.00
Woodside Energy (Trinidad Block 23A) Limited	United Kingdom		100.00
Woodside Energy (Trinidad Block 23B) Limited	United Kingdom		100.00
Woodside Energy (Trinidad Block 28) Limited	United Kingdom		100.00
Woodside Energy (Trinidad Block 29) Limited	United Kingdom		100.00
Woodside Energy (Bimshire) Limited	United Kingdom		100.00
Woodside Energy (South Africa 3B/4B) Limited	United Kingdom		100.00
Woodside Energy (Egypt) Limited	United Kingdom		100.00
Woodside Energy (Carlisle Bay) Limited	United Kingdom		100.00
Woodside Energy (Mexico) Limited	United Kingdom		100.00
Woodside Energía Servicios Administrativos, S. de R.L. de C.V.	Mexico		99.00	⁷
Woodside Energía Servicios de México, S. de R.L. de C.V.	Mexico		99.00	⁷
Woodside Energy (Mexico Holdings) LLC	United States		100.00
Operaciones Conjuntas, S. de R.L. de C.V.	Mexico		99.00	⁷
Woodside Energía Holdings de México, S. de R.L. de C.V.	Mexico		99.99	⁷
Woodside Petróleo Operaciones de México, S. de R.L. de C.V.	Mexico		99.00	⁷
Woodside Energy (Australia) Pty Ltd	Australia		100.00
Woodside Energy (International Exploration) Pty Ltd	Australia		100.00
Woodside Energy (Bass Strait) Pty Ltd	Australia		100.00
Woodside Energy (Victoria) Pty Ltd	Australia		100.00
Woodside Energy Holdings LLC	United States		100.00
Woodside Energy (Trinidad-2C) Ltd	Canada		100.00
Woodside Energy (Canada) Corporation	Canada		100.00

1.	16.67% relates to BHPP’s interest percentage in North West Shelf. As a result of the merger, the Group’s interest percentagein the North West Shelf joint venture has increased to 33.34%.

2.	0.01% owned by Woodside Energy Investments Pty Ltd.

3.	0.03% owned by Woodside Energy Global Holdings Pty Ltd.

4.	<0.01% owned by Woodside Energy Global Holdings Pty Ltd.

5.	Investments in associates held by BHPP. Remaining interest externally owned.

6.	Woodside Energy USA Operations Inc: 90% voting and 37.67% capital. Woodside Energy Holdings LLC: 10% voting and62.33% capital.

7.	Woodside Energy (Mexico Holdings) LLC: 0.01-1%.


Woodside Energy Group Ltd \| Half-Year Report 2022		50

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

for the half-year ended 30 June 2022

E.4 Events after the end of the reporting period

Subsequent to period end, the following repayments and refinancing of interest-bearing liabilities were undertaken:

•

Repaid $200 million of the Yucho 2022 Medium Term Note and $42 million of the JBIC facility.

•

Refinanced and increased an existing committed undrawn syndicated facility by $800 million.

•

Renewed 2 bilateral loan facilities of $300 million.

The Group also entered into an agreement to invest $10 million in String Bio Private Limited, the developer of a patented process for recycling greenhouse gases into products such as livestock feed.

On 7 August, the United States Senate passed the Inflation Reduction Act (IRA) which has subsequently been signed into law. This law will impose a minimum corporate tax on Adjusted Financial Statement Income (AFSI) from 2023 which could impact cash tax payments of the Group in the future. Given the IRS regulations have not yet been published, an assessment of the impact of this law has not yet been completed.


Woodside Energy Group Ltd \| Half-Year Report 2022		51

DIRECTORS’ DECLARATION

For the half-year ended 30 June 2022

In accordance with a resolution of directors of Woodside Energy Group Ltd, we state that:

In the opinion of the directors:

the financial statements and notes of the Group are in accordance with the Australian Corporations Act 2001, including:

giving a true and fair view of the Group’s financial position as at 30 June 2022 and of its performance for the half-year ended on that date; and

complying with Accounting Standard AASB 134 Interim Financial Reporting and the Corporations Regulations 2001; and

there are reasonable grounds to believe that Woodside Energy Group Ltd will be able to pay its debts as and when they become due and payable.

For the purposes of the UK Disclosure Guidance and Transparency Rules, the directors confirm that to the best of their knowledge:

the financial statements, prepared in accordance with applicable set of accounting standards, give a true and fair view of the assets, liabilities, financial position and profit or loss of Woodside Energy Group Limited and the undertakings included in the consolidation taken as a whole; and

the half-year report includes a fair review of the:

important events that have occurred during the first six months of the financial year and their impact on the half-year financial statements;

ii.

principal risks and uncertainties for the remaining six months of the financial year; and

iii.

related party transactions that have taken place in the first six months of the financial year and that have materially affected financial position or performance during that period and any changes in the related party transactions described in the last annual report that could have a material effect on financial position or performance in the first six months of the financial year.

On behalf of the Board


/s/ R J Goyder, AO		/s/ M E O’Neill

R J Goyder, AO		M E O’Neill

Chairman		Chief Executive Officer and Managing Director

Perth, Western Australia		Sydney, New South Wales

30 August 2022		30 August 2022


Woodside Energy Group Ltd \| Half-Year Report 2022		52

INDEPENDENT REVIEW REPORT

LOGO

Independent auditor’s review report to the members of Woodside Energy Group Ltd

Report on the half-year financial report

Conclusion

We have reviewed the half-year financial report of Woodside Energy Group Ltd (the Company) and the entities it controlled from time to time during the half-year (together the Group), which comprises the condensed consolidated statement of financial position as at 30 June 2022, the condensed consolidated income statement, condensed consolidated statement of comprehensive income, condensed consolidated statement of changes in equity and the condensed consolidated statement of cash flows for the half-year ended on that date, significant accounting policies and explanatory notes and the directors’ declaration.

Based on our review, which is not an audit, we have not become aware of any matter that makes us believe that the accompanying half-year financial report of Woodside Energy Group Ltd does not comply with the Corporations Act 2001 including:

1.	giving a true and fair view of the Group’s financial position as at 30 June 2022 and of its performance for the half-year ended on that date, and

2.	complying with Accounting Standard AASB 134 Interim Financial Reporting and the Corporations Regulations 2001.

Basis for conclusion

We conducted our review in accordance with ASRE 2410 Review of a Financial Report Performed by the Independent Auditor of the Entity (ASRE 2410). Our responsibilities are further described in the Auditor’s responsibilities for the review of the half-year 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 & Ethical Standards Board’s APES 110 Code of Ethics for Professional Accountants (including Independence Standards) (the Code) that are relevant to the audit of the annual financial report in Australia. We have also fulfilled our other ethical responsibilities in accordance with the Code.

Responsibilities of the directors for the half-year financial report

The directors of the Company are responsible for the preparation of the half-year financial report that gives a true and fair view in accordance with Australian Accounting Standards and the Corporations Act 2001 and for such internal control as the directors determine is necessary to enable the preparation of the half-year financial report that gives a true and fair view and is free from material misstatement whether due to fraud or error.

PricewaterhouseCoopers, ABN 52 780 433 757

Brookfield Place, 125 St Georges Terrace, PERTH WA 6000, GPO Box D198, PERTH WA 6840

T: +61 8 9238 3000, F: +61 8 9238 3999, www.pwc.com.au

Liability limited by a scheme approved under Professional Standards Legislation.


Woodside Energy Group Ltd \| Half-Year Report 2022		53

LOGO

Auditor’s responsibilities for the review of the half-year financial report

Our responsibility is to express a conclusion on the half-year financial report based on our review. ASRE 2410 requires us to conclude whether we have become aware of any matter that makes us believe that the half-year financial report is not in accordance with the Corporations Act 2001 including giving a true and fair view of the Group’s financial position as at 30 June 2022 and of its performance for the half-year ended on that date, and complying with Accounting Standard AASB 134 Interim Financial Reporting and the Corporations Regulations 2001.

A review of a half-year financial report consists of making enquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures. A review is substantially less in scope than an audit conducted in accordance with Australian Auditing Standards and consequently does not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion.


/s/ PricewaterhouseCoopers
PricewaterhouseCoopers

/s/ Justin Carroll
Justin Carroll		Perth
Partner		30 August 2022

/s/ Anthony Hodge
Anthony Hodge		Perth
Partner		30 August 2022


Woodside Energy Group Ltd \| Half-Year Report 2022		54

Appendix 4D

Dividends


Ex-dividend date		8 September 2022
Record date for the interim dividend		9 September 2022
DRP election date		12 September 2022
Date the dividend is payable		6 October 2022



		Current period		Previous corresponding period¹
Interim dividend – fully franked	US cents per share		109		30

None of these dividends are foreign sourced.

Net Tangible Assets (NTA) per ordinary security


	Current period US$		Previous corresponding period¹ US$
Net Tangible Assets (US$ per ordinary security)²		15.06		12.83

Details of Associates and Joint Venture Entities


	Percentage of ownership interest held at end of period or date of disposal
Name of entity	Current period			Previous corresponding period¹
North West Shelf Gas Pty Ltd		33.33	%		16.67	%
North West Shelf Liaison Company Pty Ltd		33.33	%		16.67	%
China Administration Company Pty Ltd		33.33	%		16.67	%
International Gas Transportation Company Limited		33.33	%		16.67	%
North West Shelf Shipping Service Company Pty Ltd		33.33	%		16.67	%
North West Shelf Lifting Coordinator Pty Ltd		33.33	%		16.67	%
Blue Ocean Seismic Services Limited		28.50	%		28.50	%
Iwilei District Participating Parties, LLC		14.96	%		—
Caesar Oil Pipeline Company, LLC		25.00	%		—
Cleopatra Gas Gathering Company LLC		22.00	%		—
Marine Well Containment Company LLC		10.00	%		—

Shareholder information

Key announcements 2022


January		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
February		Full-year 2021 results
		Sustainable Development Report 2021
		Climate Report 2021
March		Court dismisses challenges to environmental approvals
March		Processing of Pluto gas starts at North West Shelf
April		Supporting information for shareholder vote on merger released
April		First quarter 2022 report
May		Woodside shareholders approve merger
May		Woodside changes company name to Woodside Energy Group Ltd and ticker code change
June		Woodside completes merger with BHP Petroleum
		Admission to trading on the New York Stock Exchange
		Admission to trading on the London Stock Exchange
		Bumi appeal dismissed
July		Second quarter 2022 Report
July		2022 Production guidance clarification
August		Segment reporting restatement and other items

¹	Comparisons are to half-year ended 30 June 2021.

Includes lease assets and liabilities as a result of AASB 16 Leases. This is an Alternative Performance Measure (APM) which is a non-IFRS measure that is unaudited but derived from auditor reviewed Half-year Financial Statements. This measure is presented to provide further insight into Woodside’s performance. Refer to Alternative Performance Measures for a reconciliation of this measure to Woodside’s financial statements on page 61-62 and Non-IFRS Measures on pages 65-66 for more information about non-IFRS measures.


Woodside Energy Group Ltd \| Half-Year Report 2022		55

Events calendar 2022-2023

Key calendar dates for Woodside shareholders in 2022-23. Please note dates are subject to review.


August	30	Half-year 2022 results
September	8	Ex-dividend date for interim dividend
	9	Record date for interim dividend
	12	Dividend reinvestment plan election date
October	6	Payment date for interim dividend
October	20	Third quarter 2022 report
December	1	Investor Briefing Day 2022
December	31	Year-end 2022
January	25	Fourth quarter 2022 report

Business directory

Registered office:

Postal address:

Woodside Energy Group Ltd

Mia Yellagonga

11 Mount Street

Perth WA 6000

Australia

GPO Box D199

Perth WA 6840

Australia

T: +61 8 9348 4000

Investor enquiries

Requests for specific information on the company can be directed to Investor Relations at:

Postal address:

Investor Relations

GPO Box D188

Perth WA 6840

Australia

T: +61 8 9348 4000

E: investor@woodside.com

W: woodside.com

Share registry enquiries

Investors seeking information about their shareholdings should contact the company’s share registry:

Registered office:

Postal address:

Computershare Investor Services Pty Limited

Level 11

172 St Georges Terrace

Perth WA 6000

GPO Box D182

Perth WA 6840

T: 1300 558 507 (within Australia)

+61 3 9415 4632 (outside Australia)

E: web.queries@computershare.com.au

W: investorcentre.com/wds

The share registry can assist with queries on share transfers, dividend payments, the dividend reinvestment plan, notification of tax file numbers and changes of name, address or bank details.

Details of shareholdings can be checked conveniently and simply by visiting the share registry website at www.investorcentre.com/wds.

Details of our registrar in the United Kingdom and our authorised depositary bank for Woodside’s American Depositary Receipt programme can be found on our website.


Woodside Energy Group Ltd \| Half-Year Report 2022		56

Assets

Producing facilities

Australia


Asset	Role	Equity			Product
Pluto LNG	Operator		90	%	LNG, pipeline gas and condensate
North West Shelf	Operator		33.33	%	LNG, pipeline gas, condensate and NGLs
Okha FPSO	Operator		50	%	Crude oil
Ngujima-Yin FPSO	Operator		60	%	Crude oil
Pyrenees FPSO	Operator		40-71.4	%	Crude oil
Macedon	Operator		71.4	%	Pipeline gas
Bass Strait	Non-operator		32.5-50	%	Crude oil and condensate, pipeline gas and NGLs
Wheatstone	Non-operator		13	%	LNG, pipeline gas and condensate
Julimar-Brunello	Operator		65	%

International


Asset	Role	Equity			Product
Atlantis	Non-operator		44	%	Crude oil and condensate, pipeline gas and NGLs
Mad Dog	Non-operator		23.9	%	Crude oil and condensate, pipeline gas and NGLs
Greater Shenzi	Operator		72	%	Crude oil and condensate, pipeline gas and NGLs
Greater Angostura	Operator		45-68.46	%	Crude oil and condensate and pipeline gas

Developments

Australia


Asset	Role	Equity			Product
Scarborough¹	Operator		100	%	LNG, pipeline gas and condensate
Browse	Operator		30.6	%	LNG, pipeline gas and condensate
Pyxis Hub	Operator		90	%	LNG, pipeline gas and condensate
Greater Western Flank Phase 3	Operator		33.33	%	LNG, pipeline gas and condensate

¹	“Scarborough” includes the Scarborough, Jupiter and Thebe fields. Woodside is also operator of Pluto Train 2, which achieved FID in 2021, and holds a 51% participating interest.


Woodside Energy Group Ltd \| Half-Year Report 2022		57

International


Asset	Role	Equity			Product
Sangomar Phase 1	Operator		82	%	Crude oil
Mad Dog Phase 2	Non-operator		23.9	%	Crude oil and condensate, pipeline gas and NGLs
Trion	Operator		60	%	Gas and oil
Calypso	Operator		70	%	Gas
Shenzi North	Operator		72	%	Crude oil and condensate, pipeline gas and NGLs
Liard	Operator		100	%	Gas
	Non-operator		50	%	Gas
Wildling	Operator		100	%	Crude oil and condensate, pipeline gas and NGLs
Sunrise	Operator		33.44	%	LNG, pipeline gas and condensate
Myanmar A-6	Joint operator		40	%	Withdrawing; handover in progress

Exploration

Asia-Pacific


Country	Permit	Role	Equity	Product
Myanmar¹	A-7	Operator	Relinquished, formalities pending	Gas prone basin
	AD-7	Non-operator	Relinquished, formalities pending	Gas prone basin
	AD-1	Joint operator	Relinquished, formalities pending	Gas prone basin
	AD-8	Joint operator	To be relinquished on 30 September 2022, formalities pending	Gas prone basin
Republic of Korea	8, 6-1N	Joint operator	50%	Gas prone basin

Europe


Country	Permit	Role	Equity			Product
Ireland	FEL 5/13	Operator		100	%	Oil or gas prone basin

¹	Woodside announced its decision to withdrawn from its interests in Myanmar on 27 January 2022.


Woodside Energy Group Ltd \| Half-Year Report 2022		58

Africa


Country	Permit	Role	Equity			Product
Senegal	Rufisque, Sangomar and Sangomar Deep	Operator		90	%	Oil prone basin
Congo	Marine XX	Non-operator		22.5	%¹	Oil or gas prone basin
Egypt	Red Sea Block 1	Non-operator		45	%	Oil or gas prone basin
	Red Sea Block 3	Non-operator		30	%	Oil and gas prone basin
	Red Sea Block 4	Non-operator		25	%	Oil and gas prone basin

Caribbean

Country

Permit

Role

Equity

Product

Barbados

Carlisle Bay, Bimshire Bay

Operator

100

%²

Oil or gas prone basin

Trinidad & Tobago

TTDAA5 MDP³

Operator

Gas prone basin

Latin America

Country

Permit

Role

Equity

Product

Peru

108

Non-operator

Oil or gas prone basin

North America


Country	Permit	Role	Equity			Product
Canada (Offshore)	EL1157	Operator		100	%	Oil or gas prone basin
	EL1158	Operator		100	%	Oil or gas prone basin
US Gulf of Mexico	GB 640, GB 641, GB 685, GB 555, GB 556, GB 726, GB 770, GB 771, GB 604, GB 605, GB 647, GB 648, GB 649, GB 772, GB 728, GB 729, GB 773, GB 774, GB 421, GB 464, GB 465, GB 508, GB 509, GB 736, GB 780, GB 824	Non-operator		40	%	Oil prone basin

	GB 630, GB 719, GB 720, GB 763, GB 807, GB 501, GB 502, GB 545, GB 676, GB 677, GB 721, GB 762, GB 805, GB 806, GB 851, GB 852, GB 895, GB 672, GB 716, GB 760	Operator		60	%	Oil prone basin
	GC 282, GC 237	Non-operator		50	%	Oil prone basin

	GB 574, GB 575, GB 619, DC 667, DC 802, DC 803, EB 655, EB 656, EB 699, EB 700, EB 701, AC 34, AC 35, AC 36, AC 78, AC 79, AC 80, EB 870, EB 871, EB 872, EB 914, EB 915, EB 742, EB 785, EB 786, EB 830, AC 125, AC 126, AC 127, AC 170, AC 39, AC 81, AC 82, AC 83, GC 564, GC 520	Operator		100	%	Oil prone basin
	MC 798, MC 842	Non-operator		45	%	Oil prone basin
	GC 679, GC 768	Non-operator		31.875	%	Oil prone basin
	GC 238	Non-operator		60	%	Oil prone basin
	MC 368, MC 369, MC 411, MC 412, MC 455, MC 456	Non-operator		25	%	Oil prone basin
	GC 80, GC 123, GC 124, GC 168	Operator		75	%	Oil prone basin
	GC 738, GC 870	Non-operator		23.9	%	Oil prone basin

¹	Effective July 2022.

²	40% working interest farm out to Shell subsidiary (BG) pending Ministry approval.

³	Market Development Phase Area (MDP).

Greenhouse gas assessment permits


Country	Permit	Role	Joint venture	Comment
Australia	G-7-AP	Non-operator	Bonaparte CCS Assessment Joint Venture	Located in the Bonaparte Basin off the north-western coast of the Northern Territory
Australia	G-8-AP	Operator	Browse Joint Venture	For carbon capture and storage evaluation for Browse


Woodside Energy Group Ltd \| Half-Year Report 2022		60

Alternative Performance Measures

Woodside uses various Alternative Performance Measures (APM) which are non-IFRS measures that are unaudited but derived from auditor reviewed Half-Year Financial Statements. These measures are presented to provide further insight into Woodside’s performance. See Non-IFRS Measures on pages 65-66 for more information.

APMs and their nearest respective IFRS measure.


APMs derived from Consolidated Income Statement	30 June 2022 US$m			30 June 2021 US$m
EBIT/EBITDA
Net profit after tax		1,679			342
Adjusted for:
Finance income		(31	)		(12	)
Finance costs		86			130
PRRT expense/(benefit)		424			(60	)
Income tax expense		824			221

EBIT		2,982			621

Adjusted for:
Oil and gas properties depreciation and amortisation		924			819
Amortisation of licence acquisition costs		3			2
Depreciation of lease assets		62			54

EBITDA		3,971			1,496

Underlying NPAT
Net profit after tax attributable to equity holders of the parent		1,640			317
Adjusted for the following exceptional items:
Add: Merger transaction costs		424			—
Add: Kitimat exit costs		—			33
Add: Port operations provisions		—			4
Less: Derecognition of the Corpus Christi onerous contract provision		(245	)		—

Underlying NPAT		1,819			354


APMs derived from Consolidated Cash Flow Statement	30 June 2022 US$m			30 June 2021 US$m
Capital investment expenditure
Capital additions on evaluation		—			124
Capital additions on oil and gas properties		1,509			596

Capital investment expenditure		1,509			720

Exploration expenditure
Exploration and evaluation expenditure		44			90
Adjusted for:
Amortisation expense		(3	)		(2	)
Prior year expense written off		—			(20	)

Exploration expenditure		41			68

Free cash flow
Cash flow from operating activities		2,523			1,333
Cash flow from/(used in) investing activities		45			(1,007	)

Free cash flow		2,568			326


Woodside Energy Group Ltd \| Half-Year Report 2022		61


APMs derived from Consolidated Balance Sheet	30 June 2022 US$m			30 June 2021 US$m
Net tangible assets per ordinary security
Net assets		33,424			13,161
Adjusted for:
Goodwill		(3,975	)		—
Non-controlling interest		(790	)		(794	)
Intangible assets		(64	)		(2	)

Net tangible assets		28,595			12,365

Number of issued and fully paid shares		1,898,749,771			963,579,886

Net tangible assets per ordinary security		15.06			12.83


Gearing
Interest-bearing liabilities (Current and non-current)		5,380			5,467
Lease liabilities (Current and non-current)		1,618			1,234
Adjusted for:
Cash and cash equivalents		(4,615	)		(2,938	)

Net debt		2,383			3,763

Equity attributable to equity holders of the parent		32,634			12,367

Total net debt and equity attributable to equity holders of the parent		35,017			16,130

Gearing (%)		6.8			23.3


Woodside Energy Group Ltd \| Half-Year Report 2022		62

Notes

Glossary


Term		Definition
$, $m		US dollars unless otherwise stated, millions of dollars

1P		Proved reserves

2C		Best Estimate of Contingent resources

2P		Proved plus Probable reserves

Brent		Intercontinental Exchange (ICE) Brent Crude deliverable futures contract (oil price)

Capital investment expenditure		Includes capital additions on oil and gas properties and evaluation capitalised

Cash margin		Revenue from sale of produced hydrocarbons less production costs, royalties, excise and levies, insurance, inventory movement, shipping and direct sales costs and other hydrocarbon costs; excludes exploration and evaluation, general administrative and other costs, depreciation and amortisation, PRRT and income tax

CCS		Carbon capture and storage

CCUS		Carbon capture utilisation and storge

cps		Cents per share

DRP		Dividend reinvestment plan

EBIT		Calculated as profit before income tax, PRRT and net finance costs

EBITDA		Calculated as profit before income tax, PRRT, net finance costs, depreciation and amortisation, impairment losses, impairment reversals

EPS		Earnings per share

Exploration expenditure		Includes exploration and evaluation expenditure less amortisation of licence acquisition costs and prior year exploration expense written off

FEED		Front-end engineering design

FID		Final investment decision

FPSO		Floating production storage and offloading

FPU		Floating production unit

Free cash flow		Cash flow from operating activities and cash flow from investing activities

Gearing		Net debt divided by the total of net debt and equity attributable to equity holders of the parent.

GHG or greenhouse gas		The seven greenhouse gases listed in the Kyoto Protocol are: carbon dioxide (CO₂); methane (CH₄); nitrous oxide (N₂O); hydrofluorocarbons (HFCs); nitrogen trifluoride (NF₃); perfluorocarbons (PFCs); and sulphur hexafluoride (SF₆)¹

Gross margin		Gross profit divided by operating revenue. Gross profit excludes income tax, PRRT, net finance costs, other income and other expenses

GWF		Greater Western Flank

H1		H1 is 1 January to 30 June

HSE		Health, safety and environment

IFRS		International Financial Reporting Standards

JV		Joint venture

KGP		Karratha Gas Plant

Liquidity		Total cash and cash equivalents and available undrawn debt facilities

LNG		Liquified natural gas

Lower-carbon services		Woodside uses this term to describe technologies, such as CCUS or offsets, that may be capable of reducing the net greenhouse gas emissions of our customers

Net debt		Interest-bearing liabilities and lease liabilities less cash and cash equivalents

Net profit attributable to equity holders of the parent		Net profit after tax excluding non-controlling interests from the Group’s operations.

Net tangible assets		The Group’s net assets less goodwill, non-controlling interest and intangible assets

¹	See IFRS Foundation 2021: Climate Related Disclosures Prototype. Appendix A.


Woodside Energy Group Ltd \| Half-Year Report 2022		63



Net tangible assets per ordinary security		Net tangible assets divided by the number of issued and fully paid shares

New energy		Woodside uses this term to describe energy technologies, such as hydrogen and ammonia, that are emerging in scale but which are expected to grow during the energy transition due to having lower greenhouse gas emissions at the point of use than conventional fossil fuels

NPAT		Net profit after tax

NWS		North West Shelf

Offsets		Carbon offsets. Avoided GHG emissions, GHG emissions reduction or GHG removal and sequestration made available in the form of a carbon credit to counterbalance unabated/residual GHG emissions

PRRT		Petroleum resources rent tax

PSC		Production sharing contract

Revenue from ordinary activities		Revenue from the sale of hydrocarbons, processing and services revenue and shipping and other revenue.

RFSU		Ready for start-up

TRIR		Total recordable injury rate. The number of recordable injuries (fatalities, lost workday cases, restricted work day cases and medical treatment cases) per million work hours

Underlying NPAT		Net profit after tax from the Group’s operations excluding any exceptional items

Unit production costs		Production costs ($ million) divided by production volume (MMboe)

USA		United States of America

USD		US dollars

WA		Western Australia

Conversion factors


Product	Unit	Conversion factor
Natural gas	5,700 scf	1 boe
Condensate	1 bbl	1 boe
Oil	1 bbl	1 boe
Natural gas liquids (NGLs)	1 bbl	1 boe

Units of measure


Term		Definition
bbl		barrel
boe		barrel of oil equivalent
Mbbl		thousand barrels
Mboe		thousand barrels of oil equivalent
MMboe		million barrels of oil equivalent
Bcf		billion cubic feet of gas
MMBtu		million British thermal units
MMscf		million standard cubic feet of gas
scf		standard cubic feet of gas

About this report

This Half-Year Report 2022 is a summary of Woodside’s operations, activities and financial position as at 30 June 2022. Woodside Energy Group Ltd (ABN 55 004 898 962) is the parent company of the Woodside group of companies. In this report, unless otherwise stated, references to ‘Woodside’, ‘the company’, ‘the Group’, ‘we’, ‘us’ and ‘our’ refer to Woodside Energy Group Ltd and its controlled entities as a whole. The text does not distinguish between the activities of the parent company and those of its controlled entities.

References to ‘H1’ refer to the first half of the year, i.e. the period between 1 January 2022 and 30 June 2022. All dollar figures are expressed in US currency unless otherwise stated. Production and sales volumes, reserves and resources are quoted as Woodside share. A glossary of key terms, units of measure and conversion factors is on pages 63-64.

This report should be read in conjunction with the Annual Report 2021, Sustainable Development Report 2021 and the Climate Report 2021, available on Woodside’s website, www.woodside.com.


Woodside Energy Group Ltd \| Half-Year Report 2022		64

Forward looking statements

This report may contain forward-looking statements with respect to Woodside’s business and operations, market conditions, results of operations and financial condition, including, for example, but not limited to, statements about expectations regarding long-term demand for Woodside’s products, timing of completion of Woodside’s projects, adjustments to completion payments in respect of the BHPP merger, if any, expected synergies from the BHPP merger, future results of projects, operating activities, and new energy products, and expectations regarding the achievement of Woodside’s scope 1 and 2 net equity emissions targets. All forward-looking statements contained in this report reflect Woodside’s views held as at the date of this report. All statements, other than statements of historical or present facts, are forward-looking statements and generally may be identified by the use of forward-looking words such as ‘guidance’, ‘foresee’, ‘likely’, ‘potential’, ‘anticipate’, ‘believe’, ‘aim’, ‘estimate’, ‘expect’, ‘intend’, ‘may’, ‘target’, ‘plan’, ‘forecast’, ‘project’, ‘schedule’, ‘will’, ‘should’, ‘seek’ and other similar words or expressions. Similarly, statements that describe the objectives, plans, goals or expectations of Woodside are or may be forward-looking statements.

The information and statements in this report about Woodside’s future strategy and other forward-looking statements are not guidance, forecasts, guarantees or predictions of future events or performance, but are in the nature of aspirational targets that Woodside has set for itself and its management of the business.

Those statements and any assumptions on which they are based are only opinions and are subject to change without notice and are subject to inherent known and unknown risks, uncertainties, assumptions and other factors, many of which are beyond the control of Woodside, its related bodies corporate and their respective Beneficiaries.

Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, fluctuations in commodity prices, actual demand, currency fluctuations, geotechnical factors, drilling and production results, gas commercialisation, development progress, operating results, engineering estimates, reserve estimates, loss of market, industry competition, environmental risks, physical risks, legislative, fiscal and regulatory developments, changes in accounting standards, economic and financial markets conditions in various countries and regions, political risks, project delay or advancement, approvals, cost estimates and the effect of future regulatory or legislative actions on Woodside or the industries in which it operates, including potential changes to tax laws, as well as general economic conditions, prevailing exchange rates and interest rates and conditions in financial markets.

Details of the key risks relating to Woodside and its business can be found in the “Risk” section of Woodside’s most recent Annual Report released to the Australian Securities Exchange and in Woodside’s filings with the US Securities and Exchange Commission. You should review and have regard to these risks when considering the information contained in this presentation.

If any of the assumptions on which a forward-looking statement is based were to change or be found to be incorrect, this would likely cause outcomes to differ from the statements made in this presentation.

Investors are strongly cautioned not to place undue reliance on any forward-looking statements. Actual results or performance may vary materially from those expressed in, or implied by, any forward-looking statements. None of Woodside nor any of its related bodies corporate, nor any of their respective beneficiaries, nor any person named in this presentation or involved in the preparation of the information in this presentation, makes any representation, assurance, guarantee or warranty (either express or implied) as to the accuracy or likelihood of fulfilment of any forward-looking statement, or any outcomes, events or results expressed or implied in any forward-looking statement in this presentation.

Past performance (including historical financial information and pro forma information) is given for illustrative purposes only. It should not be relied on and is not necessarily a reliable indicator of future performance, including future security prices.

Non-IFRS Measures

Certain parts of this report contain financial measures that have not been prepared in accordance with IFRS and are not recognized measures of financial performance or liquidity under IFRS. In addition to the financial information contained in this report presented in accordance with IFRS, certain “non-GAAP financial measures” (as defined in Item 10(e) of Regulation S-K under the U.S. Securities Act of 1933, as amended) have been included in this report. These measures include EBIT, EBITDA, Gearing, Underlying NPAT, Net debt, Free cash flow, Capital expenditure, Exploration expenditure, Net tangible assets, and Net tangible asset per ordinary security. These non-IFRS financial measures are defined in the glossary on pages 63-64 of this report. Refer to Alternative Performance Measures for a reconciliation of these measures to Woodside’s financial statements on pages 61-62.

Woodside believes that the non-IFRS financial measures it presents provide a useful means through which to examine the underlying performance of its business. These measures, however, should not be considered to be an indication of, or alternative to, corresponding measures of gross profit, net profit, cash flows from operating activities, or other figures determined in accordance with IFRS. In addition, such measures may not be comparable to similar measures presented by other companies.


Woodside Energy Group Ltd \| Half-Year Report 2022		65

Undue reliance should not be placed on the non-IFRS financial measures contained in this report, and the non-IFRS financial measures should not be considered in isolation or as a substitute for financial measures computed in accordance with IFRS. Although certain of these data have been extracted or derived from Woodside’s consolidated financial statements, these data have not been audited or reviewed by Woodside’s independent auditors. You are urged to read carefully the auditor-reviewed Half-year Financial Statements and related notes thereto.

Other important information

All references to dollars, cents or $ in this presentation are to US currency, unless otherwise stated.

References to “Woodside” may be references to Woodside Energy Group Ltd or its applicable subsidiaries.

This report does not include any express or implied prices at which Woodside will buy or sell financial products.


Contacts:

INVESTORS Matthew Turnbull M: +1 (713) 448-0956 M: +61 410 471 079 Sarah Peyman M: +61 457 513 249 E: investor@woodside.com		MEDIA Christine Forster M: +61 484 112 469 E: christine.forster@woodside.com

This announcement was approved and authorised for release by Woodside’s Disclosure Committee.


Woodside Energy Group Ltd \| Half-Year Report 2022		66

Exhibit 99.2

LOGO

Woodside Energy Group Ltd

ACN 004 898 962

Mia Yellagonga

11 Mount Street

Perth WA 6000

Australia

T +61 8 9348 4000

www.woodside.com

ASX: WDS

NYSE: WDS

LSE: WDS

Announcement

Tuesday, 30 August 2022

HALF-YEAR 2022 RESULTS BRIEIFING PRESENTATION

Attached is an overview presentation of Woodside’s Half-Year Report 2022, which should be read in conjunction with Woodside’s Half-Year Report 2022 released to the market on 30 August 2022.

Contacts:

INVESTORS

Matthew Turnbull

M: +1 (713) 448-0956

Sarah Peyman

M: +61 457 513 249

E: investor@woodside.com

MEDIA

Christine Forster

M: +61 484 112 469

E: christine.forster@woodside.com

This announcement was approved and authorised for release by Woodside’s Disclosure Committee.

HALF-YEAR RESULTS BRIEFING 2022 30 August 2022 www.woodside.com investor@woodside.com INVESTOR PRESENTATION

Disclaimer, important notes and assumptions Information This presentation has been prepared by Woodside Energy Group Ltd (“Woodside”). By accessing/attending this presentation you agree to be bound by the following conditions. The release, presentation, publication or distribution of this document, in whole or in part, in certain jurisdictions may be restricted by law or regulation and persons into whose possession this document comes should inform themselves about, and observe, any such restrictions. All information included in this presentation, including any forward-looking statements, speak only as of the date of this presentation. Except as required by law, neither Woodside, its related bodies corporate, nor any of their respective officers, directors, employees, advisers or representatives (“Beneficiaries”) intends to, or undertakes to, or assumes any obligation to, provide any additional information or revise the statements in this presentation, whether as a result of a change in expectations or assumptions, new information, future events, results or circumstances. This presentation may contain industry, market and competitive position data that is based on industry publications and studies conducted by third parties as well as Woodside’s internal estimates and research. While Woodside believes that each of these publications and third party studies is reliable, Woodside has not independently verified the market and industry data obtained from these third party sources. Accordingly, undue reliance should not be placed on any of the industry, market and competitive position data contained in this presentation. To the maximum extent permitted by law, neither Woodside, its related bodies corporate, nor any of their respective Beneficiaries, assume any responsibility for, or make any representation or warranty (express or implied) as to, the fairness, currency, accuracy, adequacy, reliability or completeness of the information in this presentation. No offer or advice This presentation is not intended to and does not constitute, form part of, or contain an offer or invitation to sell to Woodside shareholders (or any other person), or a solicitation of an offer from Woodside shareholders (or any other person), or a solicitation of any vote or approval from Woodside shareholders (or any other person) in any jurisdiction. This presentation has been prepared without reference to the investment objectives, financial and taxation situation or particular needs of any Woodside shareholder or any other person. The information and recommendations contained in this presentation do not constitute, and should not be taken as, financial product advice. The Woodside Board encourages you to seek independent legal, financial, taxation and other professional advice before making any investment decision. This presentation shall not be distributed, transmitted, published, reproduced or otherwise made available to any other person, in whole or in part, directly or indirectly, for any purposes whatsoever. In particular, this presentation and the information contained herein may not be taken or transmitted, in, into or from and may not be copied, forwarded, distributed or transmitted in or into any jurisdiction in which such release, publication or distribution would be unlawful. The distribution of this presentation may be restricted by law, and persons into whose possession this presentation comes should inform themselves about, and observe, any such restrictions. Any failure to comply with these restrictions may constitute a violation of the laws of the relevant jurisdiction. Forward looking statements This presentation may contain forward-looking statements with respect to Woodside’s business and operations, market conditions, results of operations and financial condition which reflect Woodside’s views held as at the date of this presentation. All statements, other than statements of historical or present facts, are forward-looking statements and generally may be identified by the use of forward-looking words such as ‘guidance’, ‘foresee’, ‘likely’, ‘potential’, ‘anticipate’, ‘believe’, ‘aim’, ‘estimate’, ‘expect’, ‘intend’, ‘may’, ‘target’, ‘plan’, ‘forecast’, ‘project’, ‘schedule’, ‘will’, ‘should’, ‘seek’ and other similar words or expressions. Forward-looking statements are not guarantees of future performance and are subject to inherent known and unknown risks, uncertainties, assumptions and other factors, many of which are beyond the control of Woodside, its related bodies corporate and their respective Beneficiaries. Details of the key risks relating to Woodside and its business can be found in the “Risk” section of Woodside’s most recent Annual Report released to the Australian Securities Exchange and in Woodside’s filings with the U.S. Securities and Exchange Commission. You should review and have regard to these risks when considering the information contained in this presentation. Investors are strongly cautioned not to place undue reliance on any forward-looking statements. Actual results or performance may vary materially from those expressed in, or implied by, any forward-looking statements. Notes to petroleum resources estimates Unless otherwise stated, all petroleum resource estimates are quoted as at the effective date (i.e. 1 June 2022) of the Reserves and Resources Update included in Woodside’s Half-Year Report released to ASX on 30 August 2022 and available at https://www.woodside.com/news-and-media/announcements, net Woodside share at standard oilfield conditions of 14.696 psi (101.325 kPa) and 60 degrees Fahrenheit (15.56 degrees Celsius). Woodside is not aware of any new information or data that materially affects the information included in the Reserves and Resources Update. All the material assumptions and technical parameters underpinning the estimates in the Reserves and Resources Update continue to apply and have not materially changed. Proved (1P) Reserves are estimated and reported in accordance with the United States Securities and Exchange Commission (SEC) regulations, which are also compliant with SPE-PRMS guidelines. SEC-compliant Proved (1P) Reserves estimates use a more restrictive, rules-based approach and are generally lower than estimates prepared solely in accordance with SPE-PRMS guidelines due to, among other things, the requirement to use commodity prices based on the average price during the 12-month period in the reporting company’s fiscal year. Proved plus Probable (2P) Reserves and Best Estimate (2C) Contingent Resources are estimated and reported in accordance with SPE-PRMS guidelines and are not compliant with SEC regulations.

Disclaimer, important notes and assumptions (continued) XX% XXX cps Notes to petroleum resources estimates (continued) Woodside reports its petroleum resource estimates inclusive of all fuel consumed in operations. For offshore oil projects, the reference point is defined as the outlet of the floating production storage and offloading facility (FPSO) or platform, while for the onshore gas projects the reference point is defined as the outlet of the downstream (onshore) gas processing facility. Woodside uses both deterministic and probabilistic methods for the estimation of Reserves and Contingent Resources at the field and project levels. All Proved (1P) Reserves estimates have been estimated using deterministic methodology and reported on a net interest basis in accordance with the SEC regulations and have been determined in accordance with SEC Rule 4-10(a) of Regulation S-X. Unless otherwise stated, all petroleum estimates reported at the company or region level are aggregated by arithmetic summation by category. The aggregated Proved (1P) Reserves may be a conservative estimate due to the portfolio effects of arithmetic summation. ‘MMboe’ means millions (106) of barrels of oil equivalent. Natural Gas volumes are converted to oil equivalent volumes via a constant conversion factor, which for Woodside is 5.7 Bcf of dry gas per 1 MMboe. Volumes of natural gas liquids, oil and condensate are converted from MMbbl to MMboe on a 1:1 ratio. Assumptions Unless otherwise indicated, the targets set out in this presentation have been estimated on the basis of a variety of economic assumptions including: (1) a US$65/bbl Brent oil price (2022 real terms, inflated at 2.0%); (2) currently sanctioned projects being delivered in accordance with their current project schedules; and (3) applicable growth opportunities being sanctioned and delivered in accordance with the target schedules provided in this presentation. These growth opportunities are subject to relevant joint venture participant approvals, commercial arrangements with third parties and regulatory approvals being obtained in the timeframe contemplated or at all. Woodside expresses no view as to whether its joint venture participants will agree with and support Woodside’s current position in relation to these opportunities, or such commercial arrangements and regulatory approvals will be obtained. Additional assumptions relevant to particular targets or other statements in this presentation may be set out in the relevant slides. Any such additional assumptions are in addition to the assumptions and qualifications applicable to the presentation as a whole. 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/or Scope 3 GHG emissions. For more information on emissions data refer to Climate Report 2021. Other important information All references to dollars, cents or $ in this presentation are to US currency, unless otherwise stated. References to “Woodside” may be references to Woodside Energy Group Ltd or its applicable subsidiaries. This presentation does not include any express or implied prices at which Woodside will buy or sell financial products. A securities rating is not a recommendation to buy, sell or hold securities and may be subject to revision or withdrawal at any time. Non-IFRS financial information Throughout this presentation a range of financial and non-financial measures are used to assess Woodside’s performance, including a number of financial measures that are not defined or specified under IFRS (International Financial Reporting Standards), which are termed Non-IFRS Financial Measures. These measures include EBIT, EBITDA, Gearing, Underlying NPAT, Net debt, Free cash flow, Capital expenditure, Exploration Expenditure, and Net tangible assets. Refer to the glossary section of the Woodside Half-Year Report 2022 for the definition of these terms and to section on ‘Alternative Performance Measures and non-IFRS Financial Measures’ for a reconciliation of these measures to Woodside's financial statements. Management uses these measures to monitor Woodside’s financial performance alongside IFRS measures to improve the comparability of information between reporting periods and business units. These Non-IFRS Financial Measures should be considered in addition to, and not as a substitute for, or as superior to, measures of financial performance, financial position or cash flows reported in accordance with IFRS. Non-IFRS Financial Measures are not uniformly defined by all companies, including those in Woodside’s industry. Accordingly, they may not be comparable with similarly titled measures and disclosures by other companies. Disclosure of reserve information and cautionary note to US investors Woodside is an Australian company listed on the Australian Securities Exchange, the New York Stock Exchange and the London Stock Exchange. Woodside reports its Proved (1P) Reserves in accordance with SEC regulations, which are also compliant with SPE-PRMS guidelines, and prepares and reports its Proved plus Probable (2P) Reserves and Best Estimate (2C) Contingent Resources in accordance with SPE-PRMS guidelines. It reports all of its petroleum resource estimates using definitions 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). The SEC prohibits oil and gas companies, in their filings with the SEC, from disclosing estimates of oil or gas resources other than “reserves” (as that term is defined by the SEC). In this presentation, Woodside includes estimates of quantities of oil and gas using certain terms, such as “Proved plus Probable (2P) Reserves”, “Best Estimate (2C) Contingent Resources”, “Reserves and Contingent Resources”, “Proved plus Probable”, “Developed and Undeveloped”, “Probable Developed”, “Probable Undeveloped”, “Contingent Resources” or other descriptions of volumes of reserves, which terms include quantities of oil and gas that may not meet the SEC’s definitions of proved, probable and possible reserves, and which the SEC’s guidelines strictly prohibit Woodside from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and would require substantial capital spending over a significant number of years to implement recovery, and accordingly are subject to substantially greater risk of being recovered by Woodside. In addition, actual locations drilled and quantities that may be ultimately recovered from Woodside’s properties may differ substantially. Woodside has made no commitment to drill, and likely will not drill, all of the drilling locations that have been attributable to these quantities. US investors are urged to consider closely the disclosures in Woodside’s filings with the SEC, which are available at www.sec.gov.

DELIVERED VALUE EXECUTED STRATEGY Strong financial and strategic achievements Completed merger with BHP’s petroleum business 414% Underlying net profit after tax $1,819 million 89% Operating cash flow $2,523 million 263% 109 US cps Interim dividend, fully franked Project execution of Scarborough and Pluto Train 2, Sangomar and minor capital projects Completed sell-down of Pluto Train 2 Progressing new energy projects to support the energy transition 417% Net profit after tax $1,640 million

Maximising value through operational excellence Production 54.9 MMboe 132% Operating revenue $5,810 million 47% Unit production cost $7.2 per boe 2% LNG reliability 98.3 % 688% Free cash flow1 $2,568 million FINANCIAL PERFORMANCE OPERATIONAL PERFORMANCE 116% Realised price $96.4 per boe Increased realised prices and production volume Higher operating revenue and BHP merger completion payment Significant increase in oil and gas prices Includes one full month of production from the merged portfolio Ongoing strong performance Includes impact of planned turnarounds and the Interconnector (see slide 21) Start-up of Pluto-KGP Interconnector Paid back capital investment within 3 months Delivered subsea projects GWF-3, Pyxis Hub, Julimar-Brunello Phase 2 and Shenzi subsea multi-phase pump on schedule and under budget Cash flow from operating activities and cash flow from investing activities (including all major capital expenditure). 19% Additional gas supplied Into the eastern Australian domestic gas market

Health and safety One Tier 2 loss of primary containment process safety event; no impact to people or environment Focus on return to leading personal safety performance Implementation of asset-specific safety improvement plans Total recordable injuries (TRI) and total recordable injury rate (TRIR) Tier 1 or Tier 2 loss of primary containment process safety events

Merger benefits being realised PORTFOLIO QUALITY CASH GENERATION AND BALANCE SHEET SHAREHOLDER RETURNS AND CAPITAL DISCIPLINE DEVELOPMENT OPTIONALITY ENERGY TRANSITION LEADERSHIP SYNERGIES AND VALUE CREATION Completed merger with BHP’s petroleum business Maintained 80% cash margin from producing assets 109 US cps dividend declared for H1 2022 (up 263%), including a portion of the completion payment from BHP Clear capital allocation and capital management framework Progressing Scarborough, Sangomar and Mad Dog Phase 2 Progressing FEED activities for Trion Assessing future development options Progressing opportunities in support of the target to invest $5 billion in new energy products and lower-carbon services $100 million of annual synergies realised1 On track to realise $400+ million in annual synergies by early 20241 Generated $2,568 million of free cash flow (up 688%) BBB+ / Baa1 credit rating confirmed with $7.9B liquidity Balance sheet positioned to support major project expenditure Positioned for success through the cycle Pre-tax 100% basis. Excluding transition and separation costs.

Strong market conditions Products HY222 HY21 LNG produced $/boe 89.4 40.9 LNG purchased $/boe 139.6 39.2 Pipeline gas $/boe 51.6 16.9 Crude oil and condensate $/boe 113.8 70.8 NGLs $/boe 47.7 59.7 Average realised price $/boe 96.4 44.6 Q1: $44 Q1 2021 Q2 2021 Q3 2021 Q4 2021 Q2: $46 Q3: $59 Q4: $90 18.5% YTD gas hub exposure spot percentage3 Full year gas hub exposure expected to be in 20-25% range Average realised price1 116% Woodside quarterly average realised price (LHS) Dated Brent oil price (LHS) Monthly Japan Customs-cleared Crude oil price (JCC, LHS) Asian spot LNG price (JKM, RHS) Average realised price and oil and gas price markers Average realised price represents weighted average realised price for all sales, including purchased volumes. HY22 realised price incorporates the updated boe conversion factors. Gas hub exposure, which 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 (excluding Henry Hub). Q1 20222 Q1: $100 Q2 20222 Q2: $95 $96.4 2

Largest interim dividend declared since 2014 Interim and final dividend (US cps) Optimising value and shareholder returns Interim dividend payment value of $2.1 billion Reflects strong operational performance, higher realised prices and contribution from the BHPP assets H1 2022

Sangomar Field Development Phase 1 – 63% complete Final drydock activities for the FPSO conversion activities completed in March 2022 FPSO scheduled to move in Q4 2022 from China to Singapore to complete integration and commissioning Ocean BlackRhino drillship Five of 23 wells drilled and completed Operations ongoing on next batch of four wells Second drillship, Ocean BlackHawk, commenced drilling in July 2022 FPSO CONVERSION DRILLING SUBSEA Installation of the mooring system completed in July 2022 Subsea installation campaign commenced in August 2022 FPSO Léopold Sédar Senghor in shipyard Overhead view of subsea structures

Scarborough targeting first LNG cargo 2026 Commenced Pluto Train 2 construction works FEED activities for Pluto Train 1 modifications on schedule LNG refrigeration compressor casing nozzle Bechtel construction accommodation village Scarborough subsea xmas trees All major equipment items procured; compressors, generators and turbines ONSHORE PROCUREMENT FLOATING PRODUCTION UNIT Commenced fabrication of the floating production unit topsides SUBSEA Pipeline manufacturing 25% complete Subsea tree manufacturing 100% complete Topside steel cut for FPU topsides

LNG markets are incentivising new global LNG projects as Europe replaces Russian gas Gaseous fuels remain critical to the energy transition with low-risk and reliable sources advantaged Asian LNG demand not expected to peak before mid-2040s1 Woodside is well positioned to supply customers with close proximity and security of supply Strong and sustained LNG outlook Source: Wood Mackenzie, 10 August 2022. LNG supply and demand gap1 Supply – operational LNG supply/demand gap (high case) LNG supply/demand gap (low case) Supply – under construction

Committed to strong ESG performance Environmental Social Governance Zero significant environmental events Ongoing decommissioning campaigns at Enfield and Balnaves Undertook a range of biodiversity-related research programs in the areas where we are active Increased value of contracts to local and Indigenous suppliers Bechtel local supplier program in Karratha Released report on progress made on the Stretch 2021-2025 Reconciliation Action Plan ESG Industry Top Rated company by Sustainalytics for 2022 Woodside paid ~A$700 million in Australian taxes, royalties and excise in H1 2022 Since 2011 Woodside has paid ~A$12 billion in Australian taxes, royalties and excise

Scope 1 and 2 decarbonisation plan underway Reduce our net equity greenhouse gas emissions (Scope 1 & 2) Design out Operate out Offset portfolio 15% by 2025 30% by 2030 Net zero aspiration by 2050 or sooner Net equity emissions reduction targets1 STRATEGY TARGETS PROGRESS 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. Asset decarbonisation plans | Developing plans for emissions reduction at operated assets Carbon capture and storage | Awarded two greenhouse gas assessment permits in H1 2022 for the Bonaparte and Browse basins SCOPE 1 AND 2 STRATEGY AND TARGETS Reporting | Participated in the pilot Corporate Emissions Reduction Transparency (CERT) report in H1 2022

Investing in new energy and lower carbon services STRATEGY TARGET PROGRESS Individual investment decisions are subject to Woodside’s investment hurdles. Not guidance. Potentially includes both organic and inorganic investment. CCU = Carbon Capture and Utilisation. Capturing greenhouse gases and converting them into useful products (also referred to as “carbon-to-products”) has the potential to support both Woodside’s net equity scope 1 and 2 emissions reduction targets and also the provision of new energy products and lower carbon services. SCOPE 3 STRATEGY AND TARGET Invest in the products and services our customers need as they reduce their emissions Capital allocation targets Support Value chain PROMOTE MEASUREMENT & REPORTING $5 billion Invested in new energy products and lower carbon services by 20301 Woodside Solar | In advanced negotiations with stakeholders and potential industrial customers H2OK | FEED activities progressing; in discussions with potential customers regarding offtake agreements Advancing pilots of multiple technologies | Carbon to products investment; collaboration to drive development of Western Australia hydrogen market; multiple CCU collaborations2

Financial update Graham Tiver | Chief Financial Officer

Optimising value; preparing for major capital expenditure Increased realised prices and contribution from the BHPP assets driving higher revenue and profit Significant operating and free cash flow Balance sheet positioned to support major project expenditure Delivering strong shareholder returns HY22 HY21 Change Operating revenue $m 5,810 2,504 132% EBITDA $m 3,971 1,496 165% EBIT $m 2,982 621 380% NPAT $m 1,640 317 417% Underlying NPAT $m 1,819 354 414% Operating cash flow $m 2,523 1,333 89% Free cash flow $m 2,568 326 688% Liquidity $m 7,915 6,038 31% Half-year dividend US cps 109 30 263%

Increased profit moderated by higher tax expense Increased royalties and excise due to higher revenue Primarily due to merger transaction costs Higher realised prices across all markers Increased volume due to contribution of BHPP assets and interconnector volumes Derecognition and unwind of the Corpus Christi onerous contract provision Primarily sale of 49% of Pluto Train 2 Increased trading cost (and revenue) for third-party trades Primarily losses associated with hedging Increased taxes due to higher revenue Category $ million Merger transaction costs 424 Derecognition of the Corpus Christi onerous contract provision (245) Total 179

414% increase in underlying NPAT EBIT Operating revenue Underlying NPAT Higher revenue driven by higher realised prices, additional volume from the BHPP assets and the contribution of the Interconnector In addition to higher operating revenue, positive impacts include the sale of Pluto Train 2, offset by higher royalties, excise and levies due to higher revenue, transaction costs and hedging losses In addition to EBIT, impacted by higher tax expense and PRRT relating to increased revenue 1 Underlying NPAT includes an adjustment of $179m for merger transaction costs as well as derecognition of the Corpus Christi onerous contract provision.

Cash generative business through the cycle The BHP merger completion payment is represented in the consolidated statement of cash flows as cash received on acquisition of BHP Petroleum, including cash acquired ($1.082 billion). Cash flow from operating activities less cash flow from investing activities (including all major capital expenditure). Investing cash flow (excluding BHP merger completion payment)1 Operating cash flow Free cash flow2 Higher net cash as a result of increased realised prices as well as the inclusion of the BHPP assets from 1 June 2022 Offset by an increase in the tax paid and increased payments for decommissioning activities Increased investing cash flow primarily due to execution of Sangomar, Scarborough and Pluto Train 2 Increased cash generated from operations and the BHP merger completion payment Proceeds of merger completion payment 2.6 Benefit of GIP’s additional contribution to Pluto Train 2

Production cost Includes costs related to the purchase of Pluto feed gas from non-operating JV participants and the tolling of Pluto volumes transported through the Pluto-KGP Interconnector for processing at KGP. Production cost Unit production cost impacted by: Planned major shutdown at Wheatstone Phasing of maintenance across the portfolio Commencement of Interconnector Value accretion from Interconnector: Delivered revenue of $419 million (7% of Group revenue) Increased Group realised price by $5/boe for Q2 Paid back capital investment within first 3 months of operation Unit production cost reconciliation One month of BHPP included Unit production cost ($/boe) Production cost (BHPP) Production cost (WDS)

Maintained cash margin above 80% Cash margin excludes revenue and costs from purchased LNG. Royalties and excise from higher associated revenue Insurance and shipping costs Inclusion of BHPP assets Associated cost with Interconnector Wheatstone shutdown Impact of higher realised prices Strong underlying cost control Cash margin1 CASH MARGIN 76.9 $/boe PRODUCTION COSTS (Based on sales boe excluding purchased LNG) 7.6 $/boe OTHER CASH COSTS 6.2 $/boe

Tax expense reflects higher realised prices and increased profitability Impacted by higher taxable income Impacted by higher asset profitability Effective statutory income tax rate Increase in oil and gas prices reflected in higher PRRT, royalty and excise expenses Income tax expense increased by 273% from H1 2021 to H1 2022 ~33 % Effective income tax and PRRT rate ~43 % All-in effective tax rate ~47 % H1 2022 tax expense reconciliation (USD)

Disciplined capital management for future investment Indicative only, not guidance. Woodside’s estimated capital expenditure for Scarborough, Pluto Train 2 and Sangomar projects from 1 July 2022 to 31 December 2024 at current equity levels. Excludes the benefit of the additional contribution by GIP for Pluto Train 2. Previous target was 15-35%. Annualised yield based on interim dividend only. Woodside’s closing share price on Monday 29 August was A$35.35 and the AUD/USD exchange rate was 0.689. Investing cashflow excluding merger completion payment is approximately $1.0 billion. Safe, reliable and low cost operations Investment expenditure Strong balance sheet Dividend policy (minimum 50% payout ratio) Special dividends Share buy-backs Excess cash Investment grade credit rating Maintain dividend based on NPAT excluding non-recurring items, targeting 50-80% payout ratio Targeting 10-20% gearing Future investment Reliable framework to optimise value and shareholder returns through the cycle Preparing the balance sheet for ~$9 billion in capital expenditure through to 20241 Gearing target updated to 10-20% through the cycle2 9% interim dividend yield3 Capital management framework Operating cash flow $2,523 million Investing cash flow4 $45 million Dividend declared $2,070 million

Returning value to shareholders Interim 2022 fully franked dividend of 109 US cents per share ($2.1B): 80% of Woodside’s underlying net profit after tax for H1 2022 $0.6B of the BHP merger completion payment BASED ON UNDERLYING NPAT 1 BHP MERGER COMPLETION PAYMENT 2 Total interim 2022 dividend of $2.1 billion or 109 US cents per share 80% ordinary dividend component (76 US cents per share), at top end of target range 1.5 80% additional dividend component (33 US cents per share) $ billion

Prepared for upcoming capital expenditure phase Balanced debt maturity profile1 Continuing strong liquidity Low portfolio cost of debt (3.6%) 3.6 years portfolio weighted average term to maturity Credit ratings of BBB+ and Baa1 reaffirmed Refinanced and increased an existing committed facility in July As at 30 June 2022.

OUTLOOK Meg O’Neill | Chief Executive Officer

Capital allocation framework CCUS refers to carbon capture utilisation and storage. Payback refers to RFSU + X years. Target is for net equity Scope 1 and 2 emissions. Baseline is set as the gross average equity Scope 1 and 2 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. OFFSHORE High cash generation 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 IRR > 15% Payback within 5 years1 IRR > 12% Payback within 7 years1 PIPELINE LNG DIVERSIFIED OIL GAS NEW ENERGY 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, CCUS FOCUS OPPORTUNITY TARGETS CHARACTERISTICS 30% net emissions reduction by 2030, net zero aspiration by 2050 or sooner2 IRR > 10% Payback within 10 years1 EMISSIONS REDUCTIONS

Clear priorities CREATE AND PROTECT VALUE OPERATIONS BUILD OUR SUSTAINABLE FUTURE Return to leading personal safety performance Maintain safe, reliable and low-cost operations Advance new energy and CCUS opportunities Drive opportunities to support emissions reduction goals Continue execution of Scarborough, Pluto Train 2, Sangomar and Shenzi North Focus on disciplined capital management and allocation Progress future growth options SYNERGIES Deliver merger synergies and progress merger integration 1 2 3 4

ANNEXURE

Minor capital projects Redirected offshore fuel gas pipeline to supply additional gas into the eastern Australian domestic gas market Progressing feasibility study for a south-east Australian carbon capture and storage hub Paid back capital investment within first three months of operation Pluto LNG Pyxis Hub infill campaign on track; Xena well on track for RFSU in H2 2022 NWS Project GWF-3 infill project achieved RFSU in April 2022; Lambert Deep infill well achieved RFSU in July 2022 Tolling operations commenced in March 2022 Bass Strait Julimar-Brunello Julimar-Brunello Phase 2 tie-back to Wheatstone achieved steady-state operations in March 2022 Pluto-KGP Interconnector Ocean bottom node (OBN) seismic acquisition completed in June 2022 OBN seismic acquisition also in progress to inform subsequent development phases Subsea multi-phase pump installed and commissioned Drilling of the second well for Shenzi North, a two-well subsea tieback, commenced in July 2022 Atlantis Mad Dog Shenzi AUSTRALIA INTERNATIONAL

New segment performance 2,683 194 728 3,095 88 AUSTRALIA INTERNATIONAL MARKETING Pluto LNG, NWS Project, Bass Strait, Wheatstone, Nguijima-Yin, Macedon, Pyrenees and Okha Shenzi, Mad Dog, Ruby/Angostura, Atlantis and Other Trading of LNG (non-produced) and optimisation activities DESCRIPTION EBIT ($ million) GROSS PROFIT ($ million) 506 (33) CORPORATE/OTHER Revenue and expenses not allocated to operating segments (707) H1 2022 KEY ITEMS Impact of higher realised prices across products Addition of the Pluto-KGP Interconnector and BHPP assets volumes Gain on sale of Pluto Train 2 Offset by increased cost of sales and royalties and excise 215% 283% NA 181% 600% 593% 375% 365% One-month of addition of BHPP assets volumes Heliogen technology costs Increased trading revenue (and cost) for third-party trades Lower shipping and other revenue due to decreased sub-chartering Derecognition and unwind of onerous contract provision Includes impact of hedging for Corpus Christi Transaction costs incurred from BHPP merger Includes losses associated with hedging

Cash flow reconciliation Cash flow from financing ($968 million) Free cash flow $2,568 million Dividends paid (2021 final dividend) Cash flow generated from operations, includes income tax paid Includes Scarborough, Pluto Train 2 and Sangomar expenditure partially offset by additional capital contribution by GIP for Pluto Train 2 Higher lease repayments due to new leases for drill rigs and equipment for the Sangomar drilling campaign

2022 full-year guidance Capital and exploration expenditure related to former BHPP assets included from 1 June 2022. Sangomar represents 82% participating interest. Scarborough represents 100% participating interest (from 1 June 2022). Pluto Train 2 represents 51% participating interest. Excludes the benefit of Global Infrastructure Partners’ additional contribution of $822 million for Pluto Train 2. Other growth includes primarily Shenzi North, Mad Dog Phase 2, Trion, New Energy and Browse. Base business includes Pluto LNG, NWS Project, Gulf of Mexico (Atlantis, Shenzi, Mad Dog), Bass Strait, Wheatstone, Macedon, Pyrenees, Ngujima-Yin, Okha, Ruby, Angostura and Corporate. 2022 guidance LNG MMboe 77 – 79 Pipeline gas MMboe 27 – 29 Crude and condensate MMboe 36 – 40 Natural gas liquids MMboe ~5 Total MMboe 145 - 153 2022 production guidance Woodside’s production guidance is 145 – 153 MMboe 2022 gas hub exposure Woodside’s 2022 gas hub exposure guidance for the portfolio, as a % of produced LNG, is 20 – 25% 2022 guidance Sangomar2 % ~25% Scarborough and Pluto Train 23 % ~45% Other growth4 % ~10% Base business5 % ~20% Total $ million 4,300 – 4,800 2022 capital expenditure guidance1 Woodside’s capital expenditure guidance is $4,300 – 4,800 million 2022 exploration expenditure1 Woodside’s 2022 exploration expenditure guidance is $400 – 500 million

Reserves update Reserves are based on an effective date of 1 June 2022. The percentage increase is from volumes reported in Woodside’s most recent Reserves and Resources Statement, which had an effective date of 31 December 2021. Estimates have been updated for production during the period from 1 January 2022 to 31 May 2022. Proved plus Probable (2P) Developed and Undeveloped Reserves 2,340 MMboe Proved (1P) Developed and Undeveloped Reserves No changes to reservoir outcomes compared to Woodside’s most recent Reserves and Resources Statement issued in February 2022 Inclusive of all fuel consumed in operations Barrel of oil equivalent conversion factor for natural gas remains at 5.7 Bcf per MMboe Natural gas liquids (1%) Oil and condensate (19%) Natural gas (80%) Natural gas liquids (1%) Oil and condensate (20%) Natural gas (79%) 47%1 65%1 3,786 MMboe

Asset tables Asset Operating revenue $ million EBITDA $ million Depreciation and amortisation $ million EBIT $ million Capital and exploration expenditure $ million Production costs $ million Australia North West Shelf 912 628 170 458 50 60 Pluto 2,058 1,896 384 1,512 117 163 Wheatstone 460 365 128 237 10 47 Bass Strait 234 193 36 157 5 24 Macedon 16 19 6 13 - 1 Pyrenees 1 8 4 4 3 4 Ngujima-Yin 436 352 100 252 2 38 Okha 67 53 9 44 1 13 Scarborough - 418 - 418 766 - Other Australia 4 33 33 - 6 - Total Australia 4,188 3,965 870 3,095 960 350 International Trinidad & Tobago 66 65 10 55 - 8 Atlantis 109 86 15 71 26 7 Shenzi 83 22 23 (1) 27 13 Mad Dog 44 48 8 40 21 2 Trion - - - - 11 - Sangomar - 4 - 4 449 - Other International 3 (74) 7 (81) 3 3 Total International 305 151 63 88 537 33 Marketing 1,317 506 - 506 - - Corporate/Other - (651) 56 (707) 18 14 Total 5,810 3,971 989 2,982 1,515 397

Realised price Products Units H1 20221 H1 2021 Variance % Revenue impact $ million LNG produced2 $/boe 89 41 117 1,428 LNG traded3 $/boe 140 39 259 709 Pipeline gas $/boe 52 17 206 6 Oil and condensate $/boe 114 71 61 339 NGLs $/boe 48 60 (20) - Average realised price $/boe 96 45 113 Average Dated Brent $/bbl 108 65 66 JCC (lagged three months) $/bbl 83 50 66 JKM $/MMbtu 31 9 244 WTI $/bbl 101 62 63 TTF4 $/MMbtu 33 7 371 HY22 realised price incorporates the updated boe conversion factors. Realised prices include the impact of periodic adjustments reflecting the arrangements governing Wheatstone LNG sales. Excludes any additional benefit attributed to produced LNG through third-party trading activities. TTF is converted from EUR/MWh to US$/MMBtu using published exchange rates and conversion factors.

Corporate performance H1 2022 H1 2021 Production volume MMboe 54.9 46.3 Operating revenue $ million 5,810 2,504 EBITDA $ million 3,971 1,496 EBIT $ million 2,982 621 Net finance costs $ million 55 118 Tax expense/(benefit) $ million 1,248 161 Non-controlling interest $ million 39 25 NPAT $ million 1,640 317

Glossary $, $m, $B US dollar unless otherwise stated, millions of dollars, billions of dollars A$, AUD Australian dollar ASX Australian Securities Exchange 2P Proved plus Probable reserves 2C Best Estimate of Contingent resources Bcf Billion cubic feet BHP Petroleum or BHPP BHP Petroleum International Pty Ltd ACN 006 923 897. References to “BHP Petroleum International Pty Ltd” are to “BHP Petroleum International Pty Ltd” excluding its subsidiaries boe, MMboe, Bboe Barrel of oil equivalent, million barrels of oil equivalent, billion barrels of oil equivalent Cash margin Revenue from sale of produced hydrocarbons less production costs, royalties, excise and levies, insurance, inventory movement, shipping and direct sales costs and other hydrocarbon costs; excludes exploration and evaluation, general administrative and other costs, depreciation and amortisation, PRRT and income tax CCS Carbon capture and storage CCU Carbon capture and utilisation CCUS Carbon capture, utilisation and storage Conventional Conventional resources exist in porous and permeable rock with pressure equilibrium. The hydrocarbons are trapped in discrete accumulations related local geological structure feature and/or stratigraphic condition cps Cents per share EBIT Calculated as a profit before income tax, PRRT and net finance costs EBITDA Calculated as a profit before income tax, PRRT, net finance costs, depreciation and amortisation and impairment EBITDAX Calculated as a profit before income tax, PRRT, net finance costs, depreciation and amortisation, impairment and exploration and evaluation expense FEED Front-end engineering design FID Final investment decision FPSO Floating production storage and offloading FPU Floating production unit Free cash flow Cash flow from operating activities and cash flow from investing activities Gearing Net debt divided by net debt and equity attributable to the equity holders of the parent GHG or greenhouse gas The seven greenhouse gases listed in the Kyoto Protocol are: carbon dioxide (CO2); methane (CH4); nitrous oxide (N2O); hydrofluorocarbons (HFCs); nitrogen trifluoride (NF3); perfluorocarbons (PFCs); and sulphur hexafluoride (SF6) IRR Internal rate of return JCC The Japan customs-cleared crude is the average price of customs-cleared crude oil imports into Japan as reported in customs statistics (also known as ‘Japanese crude cocktail’) and is used as a reference price for long-term supply LNG contracts JV Joint venture KGP Karratha Gas Plant LNG Liquefied natural gas MMbbl Million barrels MMBtu Million British thermal units MMboe Million of barrels of oil equivalent Mtpa Million tonnes per annum MWh Megawatt hour NGLs Natural gas liquids NPAT Net profit after tax NWS North West Shelf OBN Ocean bottom node PRRT Petroleum resource rent tax RFSU Ready for start-up Shareholder or Woodside Shareholder A holder of Woodside Shares from time to time T&T Trinidad and Tobago Tcf Trillion cubic feet TRIR Total recordable injury rate Underlying NPAT Net profit after tax excluding any exceptional items Unit production cost or UPC Production cost divided by production volume USD United States dollar Woodside Woodside Energy Group Ltd ACN 004 898 962 Woodside Shares or Shares Fully paid ordinary shares in the capital of Woodside YTD Year to date