Half-Year 2024 Report
HALF-YEAR REPORT FOR PERIOD ENDED 30 JUNE 2024
ASX: WDS | NYSE: WDS | LSE: WDS
Tuesday, 27 August 2024
High-quality business delivering strong dividends
Financial highlights
· Net profit after tax of $1,937 million.
· Underlying net profit after tax of $1,632 million.[1]
· Operating cash flow of $2,393 million and positive free cash flow of $740 million.1
· Australian tax and royalty payments of
A$2,682 million.
· Liquidity of $8,479 million.1,[2]
· Determined a fully franked interim dividend of 69 US cents per share (cps), at the top end of the payout range and representing a half-year annualised dividend yield of 7.3%.[3]
Operational highlights
· Delivered H1 production of 89.3 MMboe (491 Mboe/d). Full year production guidance remains unchanged.
· Reduced unit production cost to $8.3/boe ($8.8/boe in H1 2023) despite the inflationary environment.
· Achieved first oil at the Sangomar Project in June 2024. Subsequent to the period the project achieved nameplate capacity with gross production rates of 100,000 barrels per day.
· Continued to embed the Field Leadership Program to strengthen our learning culture and improve safety outcomes.
· Took a final investment decision (FID) on Lambert West, Xena-3 and Atlantis Drill Centre 1 Expansion (DC1X).
Business highlights
· The Scarborough Energy Project was 67% complete at the end of H1 2024, with first LNG cargo expected in 2026.[4]
· Signed an agreement with JERA for the sale of a 15.1% non-operated participating interest in the Scarborough Joint Venture (SJV). Estimated total consideration for the sale is $1,400 million.[5]
· Completed the sale of a 10% non-operated participating interest in the SJV to LNG Japan for $910 million.[6]
· Signed sale and purchase agreements (SPAs) with Korea Gas Corporation (KOGAS) and CPC Corporation, Taiwan (CPC) for the long-term supply of LNG to Korea and Taiwan respectively.
· Continued to progress the Trion Project engineering, procurement and contracting.
· Subsequent to the period, Woodside entered into two transactions that have significant cash generation potential to underpin long-term shareholder value.[7] These are agreements to acquire:
o Tellurian, including its US Gulf Coast Driftwood LNG development opportunity,
for an all-cash payment of approximately $900 million; and
o OCI's Clean Ammonia Project in Beaumont, Texas for an all-cash consideration of approximately $2,350 million.
Summary
Woodside reported net profit after tax (NPAT) for the half-year of $1,937 million. Production was 89.3 MMboe (491 Mboe/d) and underlying NPAT was $1,632 million, down 14% on the corresponding period in 2023.
The directors have determined a fully franked interim dividend of 69 US cents per share (cps), representing an approximately 80% payout ratio of underlying NPAT.
Woodside Energy CEO Meg O'Neill said the results demonstrate how Woodside's high performing base business continues to deliver strong dividends to shareholders while laying a foundation for future success.
"We maintained high reliability of 97.9% at our operated LNG assets and continue to manage costs effectively in an inflationary environment.
"In the first half of 2024 we delivered on a significant element of our strategy, achieving first production from Sangomar, Senegal's first offshore oil project. Production ramp-up at Sangomar has progressed well and subsequent to the period, peak gross production rate of 100,000 barrels per day was achieved, demonstrating Woodside's world-class project execution capability. Sangomar will deliver enduring value for Woodside shareholders and benefits for our partner Petrosen and the people of Senegal.
"We also made good progress on the Scarborough Energy Project in Western Australia, which is more than two-thirds complete and on track for first LNG cargo in 2026. Work on the Scarborough floating production unit passed a major milestone with structural completion of the topsides. Pluto Train 2 site works continued with 29 of the 51 modules delivered and 25 modules set in position.
"We completed the sale of a 10% non-operating participating interest in the Scarborough Joint Venture (SJV) to LJ Scarborough Pty Ltd (LNG Japan) for $910 million and executed a binding sale and purchase agreement for the sale of a further 15.1% non-operating participating interest in the SJV to JERA.
"Long-term LNG supply agreements were also reached with Korea Gas Corporation and with CPC Corporation, Taiwan, underlining the importance of LNG in regional energy security.
"Our agreement last month to acquire Tellurian, including its US Gulf Coast Driftwood LNG development further strengthens our LNG portfolio, complementing our existing Pacific basin position with additional exposure in the Atlantic basin. Woodside expects to leverage its global LNG expertise to unlock this development and enable long-term cashflow generation.
"In our new energy business, all primary environmental approvals have been secured for the Hydrogen Refueller @H2Perth, which is targeting supplying industrial customers in Western Australia in 2025. We have also progressed several carbon capture and storage (CCS) opportunities, including the signing of a memorandum of understanding between the Angel CCS Joint Venture and Yara Pilbara Fertilisers to study the use of the technology.
"We continue to deliver on our strategy to thrive through the energy transition whilst maintaining our disciplined capital management. Our agreement to acquire OCI's Clean Ammonia project in Texas positions Woodside to be an early mover in the emerging lower carbon ammonia industry and makes a significant contribution to delivering our Scope 3 targets.
"Above all, we are committed to continually improving safety and have focused on strengthening our safety culture, simplifying our processes and improving our systems.
"As we officially mark 70 years as an Australian company, I am proud that Woodside is facing the future with the same spirit of innovation and determination that our founders showed."
Financial summary
Key metrics
|
|
|
H1 |
H1 |
Change |
|
Operating revenue |
$ million |
5,988 |
7,400 |
(19%) |
|
EBITDA excluding impairment[8] |
$ million |
4,371 |
4,888 |
(11%) |
|
EBIT8 |
$ million |
2,362 |
2,791 |
(15%) |
|
$ million |
1,937 |
1,740 |
11% |
|
|
Underlying NPAT8 |
$ million |
1,632 |
1,896 |
(14%) |
|
Net cash from operating activities[11] |
$ million |
2,393 |
2,951 |
(19%) |
|
Capital expenditure8,[12] |
$ million |
2,365 |
2,769 |
(15%) |
|
Exploration expenditure8,[13] |
$ million |
112 |
187 |
(40%) |
|
Free cash flow8,11,[14] |
$ million |
740 |
314 |
136% |
|
Dividends distributed |
$ million |
1,310 |
1,519 |
(14%) |
|
Interim dividend declared |
US cps |
69 |
80 |
(14%) |
|
|
|
|
|
|
|
Key ratios |
|
|
|
|
|
Earnings |
US cps |
102.2 |
91.7 |
11% |
|
Gearing8 |
% |
13.3 |
8.2 |
5.1% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas |
MMboe |
60.9 |
63.5 |
(4%) |
|
Liquids |
MMboe |
28.4 |
27.8 |
2% |
|
Total |
MMboe |
89.3 |
91.3 |
(2%) |
|
|
|
|
|
|
|
Production volumes per day15 |
|
|
|
|
|
Gas |
MMscf/d |
1,907 |
1,999 |
(5%) |
|
Liquids |
Mbbl/d |
156 |
154 |
1% |
|
Total |
Mboe/d |
491 |
504 |
(3%) |
|
|
|
|
|
|
|
Sales volumes16 |
|
|
|
|
|
Gas |
MMboe |
65.0 |
72.0 |
(10%) |
|
Liquids |
MMboe |
28.9 |
26.8 |
8% |
|
Total |
MMboe |
93.9 |
98.8 |
(5%) |
|
|
|
|
|
|
|
Sales volumes per day |
|
|
|
|
|
Gas |
MMscf/d |
2,035 |
2,268 |
(10%) |
|
Liquids |
Mbbl/d |
159 |
148 |
7% |
|
Total |
Mboe/d |
516 |
546 |
(5%) |
|
|
|
|
|
|
Appendix 4D
Results for announcement to the market
More information is available on page 44
|
|
|
|
|
US$ million |
|
Revenue from ordinary activities |
Decreased |
19%[17] |
to |
5,988 |
|
Profit from ordinary activities after tax attributable to members |
Increased |
11%17 |
to |
1,937 |
|
Net profit for the period attributable to members |
Increased |
11%17 |
to |
1,937 |
|
|
|
|
|
|
|
Interim dividend - fully franked |
69 US cps H1 2024 |
|||
|
Record date for determining entitlements to the dividend |
6 September 2024 |
|||
Net profit after tax reconciliation
The following table summarises the variance between the H1 2023 and H1 2024 results for the contribution of each line item to NPAT.
|
|
US$m |
Primary reasons for variance |
|
2023 H1 reported NPAT |
1,740 |
|
|
Revenue from sale of hydrocarbons |
|
|
|
Price |
(1,077) |
Lower average realised prices. |
|
Volume |
(364) |
Fewer third-party LNG trades classified as revenue and natural field decline. |
|
Other operating revenue |
29 |
Increase in processing and services revenue. |
|
Cost of sales |
600 |
Lower royalties, trading costs and depreciation expense in H1 2024 and Pluto turnaround activities in the prior period. |
|
Other income |
181 |
Gain on SJV sell-down to LNG Japan. |
|
Other expenses |
134 |
Lower fair value losses on embedded derivatives. |
|
Impairment losses |
68 |
Pre-tax impairment of Pyrenees recognised in prior period. |
|
Income tax and PRRT expense |
724 |
Recognition of the Trion deferred tax asset (DTA) offset by derecognition of the Pluto PRRT DTA, both not present in the current period. H1 2024 includes the first-time recognition of a net DTA for the Sangomar Project. |
|
Other |
(98) |
|
|
2024 H1 reported NPAT |
1,937 |
|
|
2024 H1 NPAT adjustments |
(305) |
Adjustment for the recognition of the Sangomar DTA. |
|
2024 H1 underlying NPAT |
1,632 |
|
Capital management
Woodside's capital management framework provides us with the flexibility to optimise value and shareholder returns delivered from our portfolio.
Interim dividend and dividend reinvestment plan
A 2024 fully franked interim dividend of 69 US cps has been determined, representing a half-year annualised dividend yield of 7.3%.[18] The total amount of the interim dividend payment is $1,310 million which represents approximately 80% of underlying NPAT for the first half of 2024.[19]
The dividend reinvestment plan (DRP) remains suspended.
Liquidity and Balance sheet
In H1 2024, Woodside generated $2,393 million of cash flow from operating activities and delivered positive free cash flow of $740 million.19,[20]
Woodside increased its standby debt facilities from $6,050 million to $6,500 million. Liquidity at the end of the period was $8,479 million and Woodside's drawn debt at the end of the period was $5,850 million.
Woodside entered into a $1,000 million 10-year loan with the Japan Bank for International Cooperation (JBIC) to support the Scarborough Energy Project which was available for drawdown from the end of June 2024. In addition, Woodside entered into a $450 million 10-year loan from commercial banks for general corporate purposes. Subsequent to the period, $1,550 million of undrawn facilities were cancelled. This cancellation has the effect of reducing our liquidity by $1,550 million. As part of active debt management, Woodside continues to review options to further access the debt market.
Net debt at the end of the period increased 67% from H1 2023 to $5,388 million, in line with planned capital expenditure.19 Woodside's gearing at the end of the first half was 13.3%, within our target range of 10-20%.19
As a result of the recent announcements to acquire Tellurian, including its Driftwood LNG development, and OCI's Clean Ammonia Project, Woodside expects its gearing to be above the top end of the target range for a period of time as the balance sheet is managed through the investment cycle.
Woodside's commitment to an investment grade credit rating remains unchanged and supports our aim of providing sustainable returns to shareholders and investing in future growth opportunities, in accordance with the capital allocation framework.
Commodity price risk management
Woodside hedges to protect the balance sheet against downside commodity price risk, particularly during periods of high capital expenditure.
As at 30 June 2024, Woodside has placed oil price hedges for:
· approximately 29.3 MMboe of 2024 production at an average price of $75.6 per barrel, of which approximately 14.4 MMboe has been delivered; and
· a further 15 MMboe of 2025 production at an average price of approximately $81.2 per barrel.
Woodside has also placed a number of hedges for Corpus Christi LNG volumes to protect against downside commodity price risk. These hedges are Henry Hub and Title Transfer Facility (TTF) commodity swaps. Approximately 70% of Corpus Christi volumes for the remainder of 2024, 48% of 2025 and 9% of 2026 volumes have reduced pricing risk as a result of hedging activities.
Australian operations
Pluto LNG
Pluto LNG is a gas processing facility in the Pilbara region of Western Australia, comprising an offshore platform and one onshore LNG processing train.
Woodside's share of production in H1 2024 was 26.9 MMboe. This was a 15% increase compared with H1 2023 which was impacted by planned turnaround activities, partially offset by reduced reliability following an offshore trip and a separate electrical fault onshore in H1 2024.
Woodside took FID for the Xena-3 well to support ongoing production from the project and started-up the produced water handling unit at the Pluto A platform.
Drilling of the PLA-08 production well commenced in June 2024.
Approvals were also granted to extend Pluto gas flows through the Pluto-Karratha Gas Plant Interconnector (Interconnector) from April 2024 to approximately December 2025, enabling continued acceleration of LNG and domestic gas production. The Interconnector generated incremental revenue of $315 million in H1 2024.
Woodside is operator and holds a 90% participating interest.
Woodside Solar
Woodside is progressing a potential opportunity to reduce gross Scope 1 greenhouse gas emissions at Pluto LNG by utilising solar energy from the proposed Woodside Solar Project.
In H1 2024, Woodside continued to work closely with the Western Australian Government to progress its plans to develop common user transmission infrastructure that will be required to transmit renewable energy from the proposed solar facility to Pluto LNG via the North-West Interconnected System.
Woodside Solar FID and first solar energy import timing are subject to securing access to this new power transmission infrastructure and finalising associated commercial agreements.
North West Shelf Project
The North West Shelf Project (NWS) consists of three offshore platforms and the onshore Karratha Gas Plant (KGP) which includes five onshore LNG processing trains and two domestic gas trains.
Woodside's share of production in H1 2024 was 19.6 MMboe. This was a 14% decrease compared with H1 2023 due to planned offshore maintenance and natural field decline. In H1 2024, 6.0 MMboe of Pluto gas was processed at KGP through the Interconnector.
Woodside continues to look for opportunities to harness value from our late-life assets. In H1 2024, the NWS Joint Venture participants took FID on the Lambert West Project which will support ongoing production from NWS. Discussions continue between the NWS Joint Venture participants and other resource owners for the processing of third-party gas to utilise ullage at KGP. Processing of Waitsia gas continued and is expected to ramp up when the Waitsia Stage 2 facility commences production, which is expected in late 2024.
As the NWS celebrates 40 years of operations, the project is entering a period of production decline. KGP currently has processing ullage due to natural field decline and the current level of third-party gas processing demand. To manage both operating costs and emissions, NWS is preparing to take one LNG train offline between late 2024 and mid-2025.
State and Commonwealth regulatory approval processes are progressing for the North West Shelf Project Extension, which will support long-term operations and processing of future third-party gas resources at KGP.
Woodside is operator and holds a 33.33% participating interest.
Wheatstone and Julimar-Brunello
Wheatstone is an LNG processing facility near Onslow, Western Australia, comprising an offshore production platform and two onshore LNG production trains. It processes gas from several offshore gas fields including Julimar and Brunello.
Woodside's share of Wheatstone production in H1 2024 was 5.8 MMboe. This was a 12% decrease compared with H1 2023, due to unplanned outages impacting the Julimar subsea production system and the Wheatstone facility respectively.
Woodside is operator and holds a 65% participating interest in the Julimar-Brunello fields.
Woodside holds a 13% non-operating participating interest in the Wheatstone Project.
Bass Strait
Bass Strait is located in the south east of Australia and produces oil and gas through a network of offshore platforms, pipelines and onshore processing facilities. The Bass Strait assets include the Gippsland Basin Joint Venture (GBJV) and the Kipper Unit Joint Venture (KUJV).
Woodside's share of production from Bass Strait was 8.5 MMboe in H1 2024, a 22% decrease from H1 2023 predominantly due to lower domestic gas market demand, offshore maintenance, and reduced crude oil production due to field decline. All of Woodside's share of the gas produced from Bass Strait is supplied into the eastern Australian domestic gas market.
The GBJV is optimising facilities through the Gippsland Asset Streamlining project as production rates from the Bass Strait decline. As planned, production from the West Kingfish and Halibut oil platforms ceased in March and April 2024 respectively.
The Kipper Compression Project offshore modules have been successfully installed. The project is planning for startup in Q3 2024, to enable continued supply of gas to the domestic market.
Woodside holds a 50% non-operating participating interest in the GBJV and a 32.5% non-operating participating interest in the KUJV.
Other Australian oil and gas assets
Woodside operates three FPSO facilities off the north west coast of Western Australia. These are the Okha FPSO (Woodside participating interest: 50%), Ngujima-Yin FPSO (Woodside participating interest: 60%) and Pyrenees FPSO (Woodside participating interest: 40% in WA-43-L and 71.4% in WA-42-L).
Woodside's share of production from the FPSO assets was 3.0 MMboe in H1 2024. This was a 3% decrease from H1 2023 primarily due to the planned five-yearly Pyrenees FPSO maintenance turnaround and the Pyrenees shut-in following a produced-water leak identified subsea at the facility. Production at Pyrenees recommenced in June 2024 and the produced-water leak has been rectified.
Macedon (Woodside participating interest: 71.4%), also operated by Woodside, is a gas project located near Onslow, Western Australia which produces pipeline gas for the Western Australian domestic gas market.
Woodside's share of production from Macedon was 3.9 MMboe, down from 4.1 MMboe in H1 2023. The Macedon facility delivered approximately 11% of the Western Australian domestic gas market supply in H1 2024.
International operations
Sangomar
The Sangomar Field Development Phase 1 is a deepwater project including a stand-alone FPSO facility moored approximately 100 kilometres offshore Senegal and subsea infrastructure that is designed to allow subsequent development phases.
First oil was achieved in June 2024, marking the delivery of Senegal's first offshore oil project. Woodside's share of production from Sangomar in H1 2024 was 0.5 MMboe. Subsequent to the period, nine production wells have come online, and the project successfully achieved peak gross rate of 100,000 barrels per day. Commissioning activities are expected to continue through 2024.
Sales of the initial Sangomar crude cargoes have been finalised, with interest received from European and Asian refiners. Subsequent to the period, the first two cargoes were loaded and delivered to Europe and a third cargo was loaded for delivery to Asia.
The project was 98% complete at the end of H1 2024. The development drilling program continues with 22 of the 23 wells drilled and completed.[21] An additional 24th well approved by the Rufisque, Sangomar and Sangomar Deep (RSSD) Joint Venture was also drilled and completed.
Woodside has filed action with the High Court of Dakar disputing a tax assessment from the Senegalese tax authorities. The majority of the tax claims relate to the application of an exemption that applied during the project development phase.
Woodside is operator and has an 82% participating interest in the project.
Shenzi
Shenzi is a conventional oil and gas field developed through a tension leg platform located in the US Gulf of Mexico. Woodside's share of production in H1 2024 was 5.2 MMboe. This was a 7% decrease compared with H1 2023 due to natural field decline and maintenance activity. Woodside is operator and holds a 72% participating interest.
Atlantis
Atlantis is a conventional oil and gas development and is one of the largest producing fields in the US Gulf of Mexico. The Atlantis development includes a semi-submersible facility with 28 active producer wells and three water injector wells.
Woodside's share of production in H1 2024 was 5.1 MMboe. This was a 19% decrease compared with H1 2023 due to planned turnaround activity.
In H1 2024, the first horizontal well in the field was successfully completed, potentially unlocking future infill opportunities for the asset. An FID was taken at DC1X, which will be a two-well tie back to the Atlantis facility through the existing DC1 manifold in the southwest of the field. Woodside holds a 44% non-operating participating interest.
Mad Dog
Mad Dog is a conventional oil and gas development located in the US Gulf of Mexico. Mad Dog Phase 2 is a development of the southern flank of the Mad Dog field though the new Argos floating production facility.
Woodside's share of production in H1 2024 was 6.0 MMboe. This was a 122% increase compared with H1 2023 primarily due to a full period of production from Mad Dog Phase 2.
The Argos facility continued to safely and systematically ramp up production in H1 2024, following completion of the riser flex joint remediation, and achieved peak production of approximately 130 Mbbl/d. The first water injection at the Argos platform was achieved in April 2024. Woodside holds a 23.9% non-operating participating interest.
Greater Angostura
Greater Angostura includes the Angostura and Ruby conventional oil and gas fields, located offshore Trinidad and Tobago. The development includes an offshore central processing facility and five wellhead platforms.
Woodside's share of production in H1 2024 was 4.5 MMboe. This was a 20% decrease compared with H1 2023 due to the planned maintenance activity.
In H1 2024, Woodside continued to pursue opportunities to maximise value and safely optimise production and operating costs. A planned facility maintenance turnaround was completed in June 2024.
Woodside is operator of both fields and holds a 45% participating interest in the Angostura field and a 68.5% participating interest in the Ruby field.
Marketing and Trading
The marketing segment's profit before tax and net finance costs in H1 2024 was $218 million. This reflected the optimisation activities and incremental value generated through the marketing, trading and shipping of Woodside's oil and gas and through third-party purchased volumes.
In H1 2024, Woodside signed SPAs with KOGAS and CPC for the long-term supply of LNG to Korea and Taiwan respectively. The KOGAS SPA is for the supply of approximately 0.5 Mtpa of LNG from 2026, for a period of 10.5 years.
The CPC SPA is for the supply of approximately 6 million tonnes of LNG over 10 years, from July 2024. Under the CPC SPA, Woodside may also deliver approximately 8.4 million tonnes of LNG for a further 10 years, from 2034 to 2043.[22]
LNG delivered under both SPAs will be sourced from volumes across Woodside's global portfolio.
In Western Australia, Woodside executed 14 PJ of sales for delivery into the domestic market from May to the end of 2024. Woodside continues to support the Western Australian domestic market by offering additional supply for 2025, 2026 and 2027.
A record quantity of trucked LNG (approximately 850 TJ) was delivered in H1 2024 to customers in northern Western Australia. Since the commencement of operations at the Pluto LNG Truck Loading Facility in 2019, Woodside has delivered more than 2,000 trailers of LNG (approximately 2,240 TJ), offering a lower-carbon alternative to diesel.[23]
In the east coast of Australia, Woodside was granted an exemption under the applicable domestic gas price cap legislation. The exemption provides Woodside the opportunity to increase delivery to the domestic market by more than 260 PJ (100% share) through to 2033 if needed. Woodside conducted an expression of interest for Bass Strait supply for 2025 and 2026 totalling 50 PJ and is progressing towards final offers in line with the conditions set under the Mandatory Code of Conduct.
In Trinidad and Tobago, incremental gas production from the Angostura field was placed under the existing gas SPA with the National Gas Company of Trinidad and Tobago (NGC). This ongoing optimisation maximises our production efficiency and provides a reliable supply of natural gas to meet growing customer demand.
Woodside's marketing and trading portfolio is supported by our shipping capacity, which includes seven vessels under long-term charter and multiple vessels on short-term charter. A new 174,000m3 long-term charter LNG vessel, the Woodside Scarlet Ibis, was delivered in June 2024 and the vessel's efficiency will support efforts to lower the carbon intensity of Woodside's LNG deliveries.
Projects
Scarborough Energy Project
The Scarborough gas field is located in the Carnarvon basin, approximately 375 km off the coast of Western Australia.
The development includes installation of a floating production unit (FPU) with eight wells drilled in the initial phase and 13 wells drilled over the life of the Scarborough field. Expansion of the Pluto LNG facility includes construction of a second LNG train (Pluto Train 2), installation of additional domestic gas processing facilities and supporting infrastructure, and modifications to Pluto Train 1 to allow it to process Scarborough gas.
The project was 67% complete at the end of H1 2024.[24] Pluto Train 2 module delivery and site works progressed and at the end of H1 2024, 29 modules were delivered to site, with 25 modules set in position. Site integration activities continue to ramp up and are expected to peak in H2 2024.
The FPU reached a major milestone, achieving structural completion of the topsides. The monoethylene glycol (MEG) module and living quarters were installed on the topsides and, subsequent to the period, the hull entered its second dry dock.
Trunkline installation is more than 50% complete and the pipe diameter has transitioned from 36" to 32". All crossings of other pipelines are complete.
Installation and testing of the three subsea flowlines has been successfully completed. The drilling campaign commenced with the installation of conductors for all eight wells. Two development wells have been drilled, with one well completed and the other to be completed as part of the forward campaign. Reservoir quality was in line with expectations.
All major engineering reviews for Pluto Train 1 modifications have been completed and approximately 80% of materials and equipment have been ordered. Contractor mobilisation to the Thailand module yard and Pluto site commenced.
Subsequent to the period, the Integrated Remote Operating Centre building works were completed with fit out now underway.
In February 2024, Woodside signed an agreement with JERA, as part of a broader strategic relationship, for the sale of a 15.1% non-operated participating interest in the SJV. Estimated total consideration for the sale is $1,400 million, subject to completion which is targeted for the second half of 2024.[25]
In March 2024, Woodside completed the sale of a 10% non-operated participating interest in the SJV to LNG Japan for $910 million.[26]
Woodside is operator and holds a 90% participating interest in Scarborough and a 51% participating interest in Pluto Train 2.[27]
Trion
Trion is an oil development located in the Gulf of Mexico, approximately 180 km off the Mexican coastline and 30 km south of the United States/Mexico maritime border. The Trion project includes a semi-submersible FPU capable of producing and transferring 100,000 barrels of oil per day to a floating storage and offloading (FSO) vessel. Oil from the FSO is expected to be exported to the market, with excess gas transferred to existing offshore gas export infrastructure.
The project progressed engineering, procurement and contracting (EPC) activities in H1 2024. The FPU detailed engineering achieved key milestones including the completion of integrated model reviews of the hull and topsides with key vendor data and formal risk assessments of the facility's design and operability. Technical maturity in engineering has enabled the FPU EPC contractor to start procurement of equipment.
Model testing was completed as part of FSO front-end engineering design (FEED). Other key achievements include completion of hull and disconnectable turret module model reviews and the hazards and operability assessment.
Subsea delivery also advanced with the start of manufacturing activities.
Key contracts were awarded for subsea marine installation, FPU dry transportation, gas gathering line pipe and drilling equipment and consumables.
Woodside is currently carrying Pemex's portion of development capital expenditure (approximately $460 million post FID) and Pemex is not expected to contribute to cash calls until 2025.
Woodside is targeting first oil in 2028. Woodside is operator and holds a 60% participating interest in the project.
Driftwood LNG
Subsequent to the period, Woodside entered into a definitive agreement to acquire all issued and outstanding common stock of Tellurian including its owned and operated US Gulf Coast Driftwood LNG development opportunity.
Driftwood LNG is a fully permitted, pre-FID development opportunity located near Lake Charles, Louisiana. The current development plan comprises five LNG trains through four phases, with a total permitted capacity of 27.6 Mtpa. Once operating, the Driftwood LNG development will increase Woodside's LNG portfolio, complementing the significant Pacific basin exposure with additional Atlantic basin exposure.
The transaction remains subject to approvals and conditions precedent, with completion targeted in Q4 2024. If completed, Woodside is targeting FID readiness for Phase 1 of the development opportunity from Q1 2025.
Decommissioning
Woodside continued execution of planned decommissioning activities in H1 2024, spending approximately $325 million across our portfolio.
At Enfield, the final two of 18 xmas trees were removed and wellhead severance activities commenced. Deconstruction of the Nganhurra riser turret mooring (RTM) was completed at the Australian Marine Complex, enabling more than 95% of the RTM to be recycled or reused.
At Griffin, all rigid piping has been recovered and wellhead severance activities have been completed.
The Transocean Endurance drill rig mobilised to the Stybarrow field and commenced the ten well plug and abandonment (P&A) campaign.
At Bass Strait, the GBJV continued to progress significant decommissioning activity including ongoing execution of P&A of platform wells and commenced execution of the P&A of two subsea wells. In addition, FEED for the removal of platforms no longer in use has progressed.
Exploration and Development
Calypso
Calypso is located approximately 220 km off the coast of Trinidad in 2,100m water depth. The resource comprises several gas discoveries in Block 23(a) and Block TTDAA 14. The development is located in a region with existing infrastructure and a favourable demand outlook.
In H1 2024, Woodside continued pre-FEED engineering studies to mature the technical definition and cost estimate for the deepwater infield host. Marketing and commercial discussions continue with key stakeholders to evaluate options to monetise the resource.
Woodside is operator and holds a 70% participating interest.
Browse
The Browse development comprises the Calliance, Brecknock and Torosa gas and condensate fields located approximately 425 km north of Broome, Western Australia.
Key work scopes continued in support of the proposed Browse to NWS Project development, including engagement with regulators on environmental and regulatory approvals and progressing commercial discussions. A carbon capture and storage solution has been incorporated into the offshore infrastructure, designed to sequester the majority of Browse reservoir CO2. In June 2024, a Declaration of an Identified Greenhouse Gas Storage Formation was made by the Commonwealth Government over the Calliance Storage Formation within the G-8-AP Greenhouse Gas Assessment Permit.
Woodside is operator and holds a 30.6% participating interest.
Liard
The Liard field is an unconventional gas field located in British Columbia, Canada. Woodside holds a 50% non-operating participating interest.
Sunrise
The Sunrise development comprises the Sunrise and Troubadour gas and condensate fields, located approximately 450 km north-west of Darwin and 150 km south of Timor-Leste.
The Sunrise Joint Venture participants continued to negotiate a new Production Sharing Contract, Petroleum Mining Code and fiscal regime with the Australian and Timor-Leste Governments in H1 2024. The Greater Sunrise Concept Study commenced in April 2024, with local content and socio-economic data gathering and engagement with potential site owners planned for H2 2024.
Woodside is operator and holds a 33.44% participating interest.
Exploration
Woodside continued to build its position in the US Gulf of Mexico during the period, acquiring 18 leases in Lease Sale 261 in the central and western Gulf of Mexico areas within the highly contested Paleogene trends. Woodside also participated in the Corvus well (non-operated) in the Gulf of Mexico which completed drilling in March 2024. The well did not encounter commercial hydrocarbons and detailed analysis of well results is ongoing.
In Congo, Woodside is participating in the Niamou Marine-1 well (non-operated) which is currently drilling.
Woodside also continued to optimise its exploration portfolio, exiting blocks that are no longer considered prospective. This included a decision to exit Block 2 in the offshore Herodotus basin in Egypt and completing all formal exit activities for permit WA-356-P in Australia and the Carlisle Bay Block in Barbados.
New energy
Beaumont Clean Ammonia Project
Subsequent to the period, Woodside entered into a binding agreement to acquire 100% of OCI Clean Ammonia Holding B.V. and its lower carbon ammonia project in Beaumont, Texas. This acquisition provides Woodside with an early-mover advantage in the growing lower carbon ammonia market.
Phase 1 of the project, which is expected to exceed Woodside's capital allocation target for new energy projects has a design capacity of 1.1 Mtpa and is under construction.
The transaction is subject to an OCI shareholder vote and satisfaction of customary conditions precedent, with completion targeted in H2 2024. If completed, Woodside is targeting production of first ammonia from 2025 and lower carbon ammonia from 2026 following commencement of CCS operations.[28]
H2OK
H2OK is a proposed liquid hydrogen project in Ardmore, Oklahoma, and is expected to produce up to 60 tonnes per day of liquid hydrogen.
In H1 2024, Woodside continued to progress discussions with potential offtakers on pricing and volumes. Woodside also provided comments on the proposed 45V Clean Hydrogen Production Tax Credit guidelines issued by the United States Department of Treasury and the Internal Revenue Service.
Hydrogen Refueller @H2Perth
The Hydrogen Refueller @H2Perth is a proposed self-contained hydrogen production, storage and refuelling station.
All primary environmental approvals have been secured for the project. Woodside awarded the major services contract which includes detailed engineering, construction, commissioning and startup work scopes to enable progression towards ready for start-up.
Woodside is targeting supply of hydrogen to customers in 2025.
H2Perth
Woodside has changed the H2Perth concept from ammonia and hydrogen production to liquid hydrogen only, following feedback from potential customers. In supporting the opportunity, Woodside progressed engineering and technology studies for large-scale liquefied hydrogen production.
H2TAS
H2TAS is a proposed renewable ammonia and hydrogen production facility to be located in Tasmania.
Subsequent to the period, Woodside withdrew environmental applications submitted under the Environmental Management and Pollution Control Act 1994 and Environment Protection and Biodiversity Conservation Act 1999. Woodside continues to assess the viability of this potential opportunity.
Southern Green Hydrogen
Subsequent to the period, Woodside ceased discussions with Meridian Energy Limited, Mitsui & Co.,Ltd and Murihiku Regeneration, representing Ngāi Tahu, regarding a potential collaboration with respect to the Southern Green Hydrogen Project.
Carbon solutions
Carbon capture and storage (CCS)
Woodside is progressing several CCS opportunities in Australia, including Angel CCS (as operator), South East Australia (SEA) CCS (non-operator) and Bonaparte CCS (non-operator).
The proposed Angel CCS Project progressed engineering and marketing activities to support FEED entry. In April 2024, the Angel CCS Joint Venture announced a non-binding memorandum of understanding with Yara Pilbara Fertilisers Pty Ltd (Yara) to study the feasibility of using CCS to decarbonise Yara's existing operations near Karratha in Western Australia. Terrestrial ecological surveys have been completed and heritage surveys are scheduled for August 2024.
The Bonaparte CCS Joint Venture progressed appraisal activities in the G-7-AP Assessment Permit Area, which included the acquisition of the West Peron Marine 3D Seismic Survey.
The SEA CCS continued to progress engineering studies.
Carbon credits portfolio
Woodside acquires carbon credits through both market purchases and the development of its own carbon origination projects.
During H1 2024, Woodside began planting activities on approximately 4,900 hectares of land at Woodside-owned properties as part of our Native Reforestation Project. The full-year program is forecast to plant over 3.2 million mixed biodiverse seedlings. These activities were 40% complete by the end of H1 2024. Subsequent to the period, Woodside signed an agreement to fund the reforestation of 5,000 hectares of land in the Chaco region in Paraguay. The Woodside portion of the project is expected to generate approximately 1.6 million carbon credits over 40 years.
Climate and Sustainability
Climate
Woodside released its Climate Transition Action Plan and 2023 Progress Report (CTAP) on 27 February 2024. The CTAP was put to a non-binding advisory vote of shareholders at the 2024 Annual General Meeting (AGM) on 24 April 2024 and received a vote of 58.36% against the resolution. All other Board proposed resolutions were approved including the Remuneration Report and Director elections.
Management is reflecting on the results of the CTAP vote and is engaging with investors to seek feedback.
In January 2024, Woodside became the first Australian company to join the Oil and Gas Methane Partnership (OGMP2.0) to voluntarily improve the accuracy and transparency of methane emissions reporting.
Woodside also committed to providing $12.5 million over a period of five years to fund the creation of the Woodside-Rice Decarbonisation Accelerator. This collaboration with Rice University in the United States aims to bring breakthrough decarbonisation technology to market.
Health, Safety and Environment
Woodside experienced two Tier 2 process safety events in H1 2024. The contributing factors to these events are understood, with corrective actions identified. Woodside is strengthening process safety management through an expanded company-wide Process Safety Critical Role competency development program in 2024. Woodside is targeting a 95% conformance to training and assessment requirements for senior roles.
At 30 June 2024, the year-to-date total recordable injury rate was 2.27 per million work hours compared with 1.86 recorded for full-year 2023. There were no fatalities or permanent injuries recorded in H1 2024.
To improve safety performance Woodside is focusing on simplifying safety processes, implementing improvements around safe hardware and engineering systems, and promoting a learning culture through implementation of its Field Leadership Program.
Environmental performance remained strong in H1 2024, with no events leading to any significant environmental impacts.
Supporting local suppliers
Woodside continues to identify opportunities in Australia to award contracts to local and Indigenous suppliers.
In H1 2024, 16 new local subcontracts were awarded in the Pilbara region for Pluto Train 2.
In Sangomar, Woodside has progressed work with key contractors to provide opportunities for Senegalese people and suppliers, whilst meeting the requirements of in-country local content legislation. Woodside has also continued to grow local contracting opportunities in Trinidad and Tobago and the Gulf of Mexico.
In support of the Trion Project's National Content program in Mexico, Woodside sponsored a second group of 33 small-to-medium-sized suppliers from the Tamaulipas state to participate in a program called BlueWave. The program supports the development of suppliers and provides an opportunity to assess capabilities according to global business standards.
Communities
Woodside released its 2023 Social Contribution Impact Report in April 2024, outlining its total global social contribution spend of A$33.3 million. This report was complemented by the North West Community Development Report which highlights the significant contribution Woodside continues to make in the Pilbara region of Western Australia as operator of the Karratha Gas Plant, Pluto LNG and Scarborough Energy Project.
Subsequent to the period, Woodside released its third Reconciliation Action Plan 2021 - 2025 (RAP) Report. The report reflects on Woodside's progress against the four pillars outlined in the RAP, namely:
· Respect for Culture and Heritage;
· Economic Participation;
· Capability and Capacity; and
· Stronger Communities.
The RAP demonstrates that although Woodside has made significant advancements towards our stated targets, continued focus is needed to achieve our goals relevant to the four pillars.
Principal risks and uncertainties
There are several risk factors or uncertainties that could result in a material effect on the company's results over the next six months. These risks and uncertainties may arise from Woodside's activities globally, including in connection with its operated (or non-operated) assets, and third parties engaged through the value chain.
Information on Woodside's risks and how they are managed can be found on pages 40-47 of the Annual Report 2023. There have been no material changes to the risk factors described in the Annual Report 2023 since the date of that report, but risk factors have been retitled and recategorised to align with Woodside's Risk Appetite Statement.
Key changes to the categorisation include the Health and Safety and Environment risk factors being split from Operations and Climate Change, to provide greater visibility of topics most relevant to our business activities and stakeholders and to reflect where our tolerance for uncertainty is low. Additionally, Finance and Market has been split into Finance Management and Commercial and Market to acknowledge a difference in risk appetite. The risks are summarised below.
|
Health and safety |
Our business is subject to risks related to safety or major hazard events in connection with our activities or facilities which may include unanticipated or unforeseeable adverse events that impact our ability to respond, manage and recover from such events. |
|
Environment |
Risks associated with major hazard events in connection with our activities or facilities, including potential incidents resulting in significant loss of hydrocarbon. We work to avoid incidents and prevent harm to the environment, by integrating environmental management into our activities. We are also subject to risks associated with progressing biodiversity positive outcomes and emission reductions in a timely manner, consistent with regulatory and stakeholder expectations. |
|
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. |
|
Social integrity |
Risks associated with actual or perceived deviation from social or business expectations of ethical behaviour (including breaches of laws or regulations) and social responsibility (including environmental impact and community contribution), particularly as these expectations evolve and as Woodside expands its global operations. |
|
Strategy and climate change |
The global response to climate change is changing the way the world produces and consumes energy. Our strategy requires us to take risk-based decisions and seek opportunities to continue to deliver energy solutions. The complex and pervasive nature of climate change means transition risks are interconnected with and may amplify other risks. Additionally, the inherent uncertainty of potential societal responses to climate change may create a systemic risk to the global economy. Climate change may also create significant physical risks, such as increased frequency and severity of storms, wildfires, floods and other climatic events, as well as chronic shifts in temperature and precipitation patterns. |
|
Growth |
Risks associated with delivery of both major and complex multi-year execution project activities and transactions (including acquisitions and divestments) across multiple global locations, including a reliance on third parties for materials, products, and services. |
|
Production and operations |
Due to the nature of our operations, Woodside and neighbouring communities are potentially exposed to a broad range of risks. This is a result of factors such as the geographical range, operational diversity and technical complexity of our assets. These types of risks include health and safety; commercial; regulation; and reserves and resources estimates. |
|
Financial management |
Risks associated with interest rate, commodity price and foreign exchange fluctuations and inflation. |
|
Commercial and market |
Risks associated with the ability to capture value whether markets are stable or volatile. |
|
Technology, innovation and systems |
Risks associated with adopting and implementing new technologies, whilst safeguarding our digital information and landscape (including from cyber threats) across our value chain. |
Directors' Report
The directors of Woodside Energy Group Ltd present their report (including the review of operations of Woodside Energy Group Ltd and its controlled entities (Group) set out on pages 1 - 16 which forms part of this report) together with the Half-Year Financial Statements of the Group.
Board of directors
The names of directors in office during or since the end of the 2024 half-year are as follows:
|
Mr Richard Goyder, AO (Chair) |
Ms Meg O'Neill (CEO and Managing Director) |
|
Mr Larry Archibald |
Mr Ashok Belani (appointed 29 January 2024) |
|
Mr Arnaud Breuillac |
Ms Swee Chen Goh |
|
Mr Ian Macfarlane |
Ms Angela Minas |
|
Mr Tony O'Neill (appointed 3 June 2024) |
Ms Ann Pickard |
|
Mr Ben Wyatt |
|
|
Mr Frank Cooper, AO (retired 24 April 2024) |
Mr Gene Tilbrook (retired 28 February 2024) |
Change of Group Company Secretary
Mr Warren Baillie ceased to be Group Company Secretary on 27 August 2024 and the Board appointed Mr Damien Gare as Group Company Secretary, effective 27 August 2024.
Rounding of amounts
Woodside Energy Group Ltd is an entity to which the Australian Securities and Investments Commission (ASIC) Corporations (Rounding in Financial/Directors' Reports) Instrument 2016/191 (ASIC Instrument 2016/191) applies. Amounts in this report have been rounded in accordance with ASIC Instrument 2016/191. This means that amounts contained in this report have been rounded to the nearest million dollars, unless otherwise stated.
Auditor's Independence Declaration
The Auditor's Independence Declaration, as required under section 307C of the Corporations Act 2001, is set out on page 18 and forms part of this report.
Signed in accordance with a resolution of the directors.
R J Goyder, AO
Chair
Perth, Western Australia
27 August 2024
Auditor's Independence Declaration to the Directors of Woodside Energy Group Ltd
Auditor's Independence Declaration
As lead auditor for the review of Woodside Energy Group Ltd for the half-year ended 30 June 2024, I declare that to the best of my knowledge and belief, there have been:
(a) no contraventions of the auditor independence requirements of the Corporations Act 2001 in relation to the review; and
(b) no contraventions of any applicable code of professional conduct in relation to the review.
This declaration is in respect of Woodside Energy Group Ltd and the entities it controlled during the period.
|
N M Henry |
Perth |
|
Partner PricewaterhouseCoopers
|
27 August 2024 |
PricewaterhouseCoopers, ABN 52 780 433 757
Brookfield Place, Level 15, 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.
|
HALF-YEAR FINANCIAL STATEMENTS
CONTENTS
CONDENSED CONSOLIDATED INCOME STATEMENT
CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
CONDENSED CONSOLIDATED STATEMENT OF FINANCIAL POSITION.
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
A.1 Segment revenue and expenses
A.3 Dividends paid and proposed
B. Production and growth assets
B.1 Exploration and evaluation
C.2 Interest-bearing liabilities and financing facilities
D. Other assets and liabilities
D.1 Segment assets and liabilities
D.3 Other financial assets and liabilities
E.1 Contingent liabilities and assets
E.2 Changes to the composition of the Group
E.3 New standards and interpretations
E.4 Events after the end of the reporting period
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 23 February 2024, the Group and JERA Scarborough Pty Ltd (JERA) entered into a sale and purchase agreement for JERA to acquire a 15.1% non-operating participating interest in the Scarborough Joint Venture. The transaction is expected to complete in the second half of 2024. As a result, $1,378 million of assets have been reclassified as assets held for sale and $119 million of liabilities have been reclassified as liabilities directly associated with assets held for sale (refer to Note B.4). This has also resulted in the recognition of a net tax benefit of $91 million (refer to Note A.5).
· On 26 March 2024, the Group completed the sell-down of a 10% non-operating participating interest in the Scarborough Joint Venture to LNG Japan. Proceeds from the sale were $910 million, including capital reimbursements and escalation. As a result, the Group recognised a pre-tax gain of $121 million on the transaction (refer to Note B.4).
· In June 2024, the Sangomar project in Senegal achieved first oil. During the half-year ended 30 June 2024, Sangomar produced 0.54 MMboe of crude oil. Production will continue to ramp up in 2024. The Group also recognised a net deferred tax asset of $305 million (refer to Note A.5).
CONDENSED CONSOLIDATED INCOME STATEMENT
for the half-year ended 30 June 2024
|
|
Notes |
2024 US$m |
2023 US$m |
|
Operating revenue |
A.1 |
5,988 |
7,400 |
|
Cost of sales |
A.1 |
(3,272) |
(3,872) |
|
Gross profit |
|
2,716 |
3,528 |
|
Other income |
A.1 |
315 |
134 |
|
Other expenses |
A.1 |
(669) |
(803) |
|
Impairment losses |
A.1 |
- |
(68) |
|
Profit before tax and net finance costs |
|
2,362 |
2,791 |
|
Finance income |
|
95 |
174 |
|
Finance costs |
A.2 |
(147) |
(137) |
|
Profit before tax |
|
2,310 |
2,828 |
|
Petroleum resource rent tax (PRRT) expense |
|
(192) |
(778) |
|
Income tax expense |
A.5 |
(146) |
(284) |
|
Profit after tax |
|
1,972 |
1,766 |
|
Profit attributable to: |
|
|
|
|
Equity holders of the parent |
|
1,937 |
1,740 |
|
Non-controlling interest |
|
35 |
26 |
|
Profit for the period |
|
1,972 |
1,766 |
|
Basic earnings per share attributable to equity holders of the parent (US cents) |
A.4 |
102.2 |
91.7 |
|
Diluted earnings per share attributable to equity holders of the parent |
A.4 |
101.4 |
91.1 |
The accompanying notes form part of the half-year financial statements.
CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
for the half-year ended 30 June 2024
|
|
2024 US$m |
2023 US$m |
|
Profit for the period |
1,972 |
1,766 |
|
Other comprehensive income |
|
|
|
Items that may be reclassified to the income statement in subsequent periods: |
|
|
|
(Losses)/gains on cash flow hedges |
(165) |
413 |
|
Losses on cash flow hedges reclassified to the income statement |
38 |
241 |
|
Tax recognised within other comprehensive income |
19 |
(76) |
|
Exchange fluctuations on translation of foreign operations taken to equity |
- |
1 |
|
Items that will not be reclassified to the income statement in subsequent periods: |
|
|
|
Remeasurement loss on defined benefit plan |
(15) |
- |
|
Net loss on financial instruments at fair value through other comprehensive income |
(11) |
(23) |
|
Other comprehensive (loss)/income for the period, net of tax |
(134) |
556 |
|
Total comprehensive income for the period |
1,838 |
2,322 |
|
Total comprehensive income attributable to: |
|
|
|
Equity holders of the parent |
1,803 |
2,296 |
|
Non-controlling interest |
35 |
26 |
|
Total comprehensive income for the period |
1,838 |
2,322 |
The accompanying notes form part of the half-year financial statements.
CONDENSED CONSOLIDATED STATEMENT OF FINANCIAL POSITION
as at 30 June 2024
|
Notes |
30 June 2024 US$m |
31 December 2023 US$m |
|
|
Current assets |
|
|
|
|
Cash and cash equivalents |
|
1,979 |
1,740 |
|
Receivables |
|
1,459 |
1,517 |
|
Inventories |
|
719 |
616 |
|
Other financial assets |
D.3 |
154 |
209 |
|
Assets held for sale |
B.4 |
1,378 |
826 |
|
Tax receivable |
|
306 |
118 |
|
Other assets |
|
57 |
92 |
|
Total current assets |
6,052 |
5,118 |
|
|
Non-current assets |
|
|
|
|
Receivables |
|
790 |
839 |
|
Inventories |
|
183 |
120 |
|
Other financial assets |
D.3 |
106 |
120 |
|
Exploration and evaluation assets |
B.1 |
714 |
668 |
|
Oil and gas properties |
B.2 |
40,125 |
40,791 |
|
Deferred tax assets |
|
1,969 |
1,717 |
|
Lease assets |
|
1,187 |
1,230 |
|
Investments accounted for using the equity method |
|
248 |
249 |
|
Goodwill |
B.3 |
3,697 |
3,995 |
|
Other assets |
|
571 |
514 |
|
Total non-current assets |
49,590 |
50,243 |
|
|
Total assets |
55,642 |
55,361 |
|
|
Current liabilities |
|
|
|
|
Payables |
|
1,597 |
1,724 |
|
Interest-bearing liabilities |
|
992 |
- |
|
Other financial liabilities |
D.3 |
152 |
67 |
|
Liabilities directly associated with assets held for sale |
B.4 |
119 |
94 |
|
Provisions |
D.2 |
1,223 |
1,506 |
|
Tax payable |
|
416 |
1,108 |
|
Lease liabilities |
|
217 |
298 |
|
Other liabilities |
|
165 |
185 |
|
Total current liabilities |
4,881 |
4,982 |
|
|
Non-current liabilities |
|
|
|
|
Interest-bearing liabilities |
|
4,830 |
4,883 |
|
Deferred tax liabilities |
|
1,312 |
1,627 |
|
Other financial liabilities |
D.3 |
203 |
42 |
|
Provisions |
D.2 |
6,454 |
6,451 |
|
Tax payable |
|
39 |
40 |
|
Lease liabilities |
|
1,328 |
1,317 |
|
Other liabilities |
|
766 |
849 |
|
Total non-current liabilities |
14,932 |
15,209 |
|
|
Total liabilities |
19,813 |
20,191 |
|
|
Net assets |
35,829 |
35,170 |
|
|
Equity |
|
|
|
|
Issued and fully paid shares |
C.1 |
29,001 |
29,001 |
|
Shares reserved for employee share plans |
C.1 |
(65) |
(49) |
|
Other reserves |
|
4,726 |
5,261 |
|
Retained earnings |
|
1,408 |
186 |
|
Equity attributable to equity holders of the parent |
35,070 |
34,399 |
|
|
Non-controlling interest |
759 |
771 |
|
|
Total equity |
35,829 |
35,170 |
|
The accompanying notes form part of the half-year financial statements.
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
for the half-year ended 30 June 2024
|
|
Notes |
2024 US$m |
2023 US$m |
|
Cash flows from operating activities |
|
|
|
|
Profit after tax for the period |
|
1,972 |
1,766 |
|
Adjustments for: |
|
|
|
|
Non-cash items |
|
|
|
|
Depreciation and amortisation |
|
1,908 |
1,948 |
|
Depreciation of lease assets |
|
101 |
81 |
|
Change in fair value of derivative financial instruments |
|
205 |
269 |
|
Net finance costs/(income) |
|
52 |
(37) |
|
Tax expense |
|
338 |
1,062 |
|
Exploration and evaluation written off |
|
- |
1 |
|
Impairment losses |
|
- |
68 |
|
Restoration movement |
|
15 |
20 |
|
Gain on disposal of oil and gas properties |
|
(143) |
- |
|
Other |
|
(66) |
(180) |
|
Changes in assets and liabilities |
|
|
|
|
Decrease in trade and other receivables |
|
113 |
488 |
|
Increase in inventories |
|
(166) |
(72) |
|
Decrease in provisions |
|
(31) |
(110) |
|
Decrease in lease liabilities |
|
- |
(8) |
|
Decrease/(increase) in other assets and liabilities |
|
39 |
(234) |
|
Increase/(decrease) in trade and other payables |
|
6 |
(220) |
|
Cash generated from operations |
|
4,343 |
4,842 |
|
Interest received |
|
77 |
174 |
|
Dividends received |
|
- |
6 |
|
Borrowing costs relating to operating activities |
|
(2) |
(8) |
|
Income tax and PRRT paid |
|
(1,700) |
(2,233) |
|
Payments for restoration |
|
(325) |
(162) |
|
Receipts from hedge collateral |
|
- |
332 |
|
Net cash from operating activities1 |
|
2,393 |
2,951 |
|
Cash flows used in investing activities |
|
|
|
|
Payments for capital and exploration expenditure |
|
(2,418) |
(2,457) |
|
Borrowing costs relating to investing activities |
|
(155) |
(181) |
|
Proceeds from disposal of non-current assets |
|
920 |
3 |
|
Funding of equity accounted investments |
|
- |
(2) |
|
Net cash used in investing activities |
|
(1,653) |
(2,637) |
|
Cash flows used in financing activities |
|
|
|
|
Proceeds from borrowings |
C.2 |
950 |
- |
|
Repayment of borrowings |
C.2 |
- |
(41) |
|
Purchases of shares relating to employee share plans1 |
|
(25) |
(20) |
|
Repayment of the principal portion of lease liabilities |
|
(213) |
(168) |
|
Borrowing costs relating to lease liabilities |
|
(21) |
(3) |
|
Contributions to non-controlling interests |
|
(48) |
(51) |
|
Dividends paid |
|
(1,139) |
(2,738) |
|
Net cash used in financing activities1 |
|
(496) |
(3,021) |
|
Net increase/(decrease) in cash held |
|
244 |
(2,707) |
|
Cash and cash equivalents at the beginning of the period |
|
1,740 |
6,201 |
|
Effects of exchange rate changes |
|
(5) |
(25) |
|
Cash and cash equivalents at the end of the period |
|
1,979 |
3,469 |
1. Purchases of shares relating to employee share plans, which were previously classified within cash flows used in operating activities, has been classified within cash flows used in financing activities for the half-year ended 2024. The 2023 comparatives have been reclassified to be presented on the same basis.
The accompanying notes form part of the half-year financial statements.
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
for the half-year ended 30 June 2024
|
|
Issued and fully paid shares |
Reserved shares |
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 2024 |
29,001 |
(49) |
290 |
795 |
88 |
4,118 |
(30) |
186 |
34,399 |
771 |
35,170 |
|
Profit for the period |
- |
- |
- |
- |
- |
- |
- |
1,937 |
1,937 |
35 |
1,972 |
|
Other comprehensive loss |
- |
- |
- |
- |
(108) |
- |
(11) |
(15) |
(134) |
- |
(134) |
|
Total comprehensive (loss)/income for the period |
- |
- |
- |
- |
(108) |
- |
(11) |
1,922 |
1,803 |
35 |
1,838 |
|
Transfers |
- |
- |
- |
- |
- |
700 |
- |
(700) |
- |
- |
- |
|
Employee share plan purchases |
- |
(25) |
- |
- |
- |
- |
- |
- |
(25) |
- |
(25) |
|
Employee share plan redemptions |
- |
9 |
(9) |
- |
- |
- |
- |
- |
- |
- |
- |
|
Share-based payments (net of tax) |
- |
- |
32 |
- |
- |
- |
- |
- |
32 |
- |
32 |
|
Dividends paid |
- |
- |
- |
- |
- |
(1,139) |
- |
- |
(1,139) |
(47) |
(1,186) |
|
At 30 June 2024 |
29,001 |
(65) |
313 |
795 |
(20) |
3,679 |
(41) |
1,408 |
35,070 |
759 |
35,829 |
|
At 1 January 2023 |
29,001 |
(38) |
278 |
796 |
(586) |
3,541 |
2 |
3,342 |
36,336 |
791 |
37,127 |
|
Profit for the period |
- |
- |
- |
- |
- |
- |
- |
1,740 |
1,740 |
26 |
1,766 |
|
Other comprehensive income/(loss) |
- |
- |
- |
1 |
578 |
- |
(23) |
- |
556 |
- |
556 |
|
Total comprehensive income/(loss) for the period |
- |
- |
- |
1 |
578 |
- |
(23) |
1,740 |
2,296 |
26 |
2,322 |
|
Transfers |
- |
- |
- |
- |
- |
4,700 |
- |
(4,700) |
- |
- |
- |
|
Employee share plan purchases |
- |
(20) |
- |
- |
- |
- |
- |
- |
(20) |
- |
(20) |
|
Employee share plan redemptions |
- |
8 |
(8) |
- |
- |
- |
- |
- |
- |
- |
- |
|
Share-based payments (net of tax) |
- |
- |
31 |
- |
- |
- |
- |
- |
31 |
- |
31 |
|
Dividends paid |
- |
- |
- |
- |
- |
(2,734) |
- |
- |
(2,734) |
(42) |
(2,776) |
|
At 30 June 2023 |
29,001 |
(50) |
301 |
797 |
(8) |
5,507 |
(21) |
382 |
35,909 |
775 |
36,684 |
The accompanying notes form part of the half-year financial statements.
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
for the half-year ended 30 June 2024
About these statements
Woodside Energy Group Ltd (Woodside or the Group) is a for-profit entity limited by shares, incorporated and domiciled in Australia. Its shares are publicly traded on the Australian Securities Exchange (ASX), on the Main Market for listed securities of the London Stock Exchange (LSE) (with trades settled in the form of UK Depository Interests) and on the New York Stock Exchange (NYSE) (in the form of Woodside American Depositary Shares). The nature of the operations and principal activities of the Group are described in the Australia Operations, International Operations, Marketing and Trading, Projects, Decommissioning, Exploration and Development and New energy and Carbon solutions 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 27 August 2024.
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. These condensed consolidated half-year financial statements also comply 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 2023 (2023 Financial Statements) and any public announcements made by Woodside during the period ended 30 June 2024 in accordance with the continuous disclosure requirements of the Australian Corporations Act 2001 and the relevant ASX, LSE and NYSE Listing Rules.
The Group's accounting policies are materially consistent with those disclosed in the Group's 2023 Financial Statements. Adoption of new or amended standards and interpretations effective 1 January 2024 did not result in any significant changes to the Group's accounting policies. Refer to Note E.3 for more details.
The significant accounting estimates and judgements are consistent with those disclosed in the 2023 Financial Statements. Estimates have been revised, where required, to reflect current market conditions including the impact of climate change. Updated estimates used for the sell-down of the Scarborough Joint Venture and embedded commodity derivatives are disclosed in Notes B.4 and D.3 respectively; these assumptions could change in the future.
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.
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
for the half-year ended 30 June 2024
Basis of preparation
The condensed consolidated half-year financial statements have been prepared on an 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.
The condensed consolidated half-year financial statements comprise the financial results of the Group and its subsidiaries for the period ended 30 June 2024. Subsidiaries are fully consolidated from the date on which control is obtained by the Group and cease to be consolidated from the date at which the Group ceases to have control.
The material subsidiaries of the Group apply the same reporting period and accounting policies as the parent company in 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
Refer to the 2023 Financial Statements for details of the Group's operating segment information.
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
for the half-year ended 30 June 2024
A. Earnings for the period
A.1 Segment revenue and expenses
|
|
Australia |
International |
Marketing |
Corporate/Other |
Consolidated |
|||||
|
|
2024 US$m |
2023 US$m |
2024 US$m |
2023 US$m |
2024 US$m |
2023 US$m |
2024 US$m |
2023 US$m |
2024 US$m |
2023 US$m |
|
Liquified natural gas |
2,595 |
3,894 |
- |
- |
412 |
785 |
- |
- |
3,007 |
4,679 |
|
Pipeline gas |
512 |
515 |
107 |
198 |
- |
- |
- |
- |
619 |
713 |
|
Crude oil and condensate |
861 |
715 |
1,190 |
1,028 |
40 |
15 |
- |
- |
2,091 |
1,758 |
|
Natural gas liquids |
87 |
120 |
24 |
16 |
40 |
23 |
- |
- |
151 |
159 |
|
Revenue from sale of hydrocarbons |
4,055 |
5,244 |
1,321 |
1,242 |
492 |
823 |
- |
- |
5,868 |
7,309 |
|
Intersegment revenue1 |
(12) |
(120) |
(2) |
(6) |
14 |
126 |
- |
- |
- |
- |
|
Processing and services revenue |
113 |
85 |
- |
- |
- |
- |
- |
- |
113 |
85 |
|
Shipping and other revenue |
- |
- |
- |
- |
7 |
6 |
- |
- |
7 |
6 |
|
Other revenue |
101 |
(35) |
(2) |
(6) |
21 |
132 |
- |
- |
120 |
91 |
|
Operating revenue2 |
4,156 |
5,209 |
1,319 |
1,236 |
513 |
955 |
- |
- |
5,988 |
7,400 |
|
Production costs |
(511) |
(614) |
(234) |
(193) |
- |
- |
- |
- |
(745) |
(807) |
|
Royalties, excise and levies |
(185) |
(285) |
(11) |
(31) |
- |
- |
- |
- |
(196) |
(316) |
|
Insurance |
(13) |
(20) |
(2) |
(5) |
- |
- |
(11) |
(9) |
(26) |
(34) |
|
Inventory movement |
15 |
31 |
47 |
2 |
- |
- |
- |
- |
62 |
33 |
|
Costs of production |
(694) |
(888) |
(200) |
(227) |
- |
- |
(11) |
(9) |
(905) |
(1,124) |
|
Land and buildings |
(26) |
(31) |
- |
(2) |
- |
- |
(2) |
- |
(28) |
(33) |
|
Transferred exploration and evaluation |
(41) |
(51) |
(45) |
(2) |
- |
- |
- |
- |
(86) |
(53) |
|
Plant and equipment |
(1,189) |
(1,298) |
(567) |
(543) |
- |
- |
(23) |
(17) |
(1,779) |
(1,858) |
|
Oil and gas properties depreciation and amortisation |
(1,256) |
(1,380) |
(612) |
(547) |
- |
- |
(25) |
(17) |
(1,893) |
(1,944) |
|
Shipping and direct sales costs |
(61) |
(107) |
(43) |
(38) |
(50) |
(30) |
- |
- |
(154) |
(175) |
|
Trading costs |
- |
(4) |
- |
- |
(273) |
(618) |
- |
- |
(273) |
(622) |
|
Other hydrocarbon costs |
(26) |
(7) |
- |
- |
- |
- |
- |
- |
(26) |
(7) |
|
Other cost of sales |
(17) |
- |
- |
- |
- |
- |
(4) |
- |
(21) |
- |
|
Other cost of sales |
(104) |
(118) |
(43) |
(38) |
(323) |
(648) |
(4) |
- |
(474) |
(804) |
|
Cost of sales |
(2,054) |
(2,386) |
(855) |
(812) |
(323) |
(648) |
(40) |
(26) |
(3,272) |
(3,872) |
|
Gross profit/(loss) |
2,102 |
2,823 |
464 |
424 |
190 |
307 |
(40) |
(26) |
2,716 |
3,528 |
|
Other income3 |
242 |
106 |
20 |
- |
20 |
1 |
33 |
27 |
315 |
134 |
|
Exploration and evaluation expenditure |
(12) |
(9) |
(86) |
(123) |
- |
- |
- |
(1) |
(98) |
(133) |
|
Amortisation of permit acquisitions |
- |
- |
(5) |
(4) |
- |
- |
- |
- |
(5) |
(4) |
|
Write-offs |
- |
- |
- |
(1) |
- |
- |
- |
- |
- |
(1) |
|
Exploration and evaluation |
(12) |
(9) |
(91) |
(128) |
- |
- |
- |
(1) |
(103) |
(138) |
|
General, administration and |
- |
- |
- |
(3) |
- |
(10) |
(214) |
(224) |
(214) |
(237) |
|
Amortisation of intangible assets |
- |
- |
- |
- |
- |
- |
(10) |
- |
(10) |
- |
|
Depreciation of lease assets |
(28) |
(22) |
(1) |
(7) |
(50) |
(34) |
(22) |
(18) |
(101) |
(81) |
|
Restoration movement |
(14) |
(8) |
(1) |
(12) |
- |
- |
- |
- |
(15) |
(20) |
|
Other4 |
16 |
(27) |
- |
(1) |
58 |
(99) |
(300) |
(200) |
(226) |
(327) |
|
Other costs |
(26) |
(57) |
(2) |
(23) |
8 |
(143) |
(546) |
(442) |
(566) |
(665) |
|
Other expenses |
(38) |
(66) |
(93) |
(151) |
8 |
(143) |
(546) |
(443) |
(669) |
(803) |
|
Impairment losses |
- |
(68) |
- |
- |
- |
- |
- |
- |
- |
(68) |
|
Profit/(loss) before tax and net finance costs |
2,306 |
2,795 |
391 |
273 |
218 |
165 |
(553) |
(442) |
2,362 |
2,791 |
1. Intersegment revenue comprises the incremental income net of all incremental associated expenses generated by the Marketing segment's optimisation of the oil and gas portfolio.
2. Operating revenue includes revenue from contracts with customers of $5,981 million (2023: $7,394 million) and sub-lease income of $7 million (2023: $6 million) disclosed within shipping and other revenue.
3. Includes fees, recoveries and other income not associated with the ongoing operations of the business. The 2024 amount includes the gain on the Scarborough sell-down to LNG Japan of $121 million.
4. Includes gains and losses on foreign exchange and hedging activities, fair value losses on embedded derivatives and other items not associated with the ongoing operations of the business.
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
for the half-year ended 30 June 2024
A.2 Finance costs
|
|
2024 US$m |
2023 US$m |
|
Interest on interest-bearing liabilities |
125 |
112 |
|
Interest on lease liabilities |
51 |
54 |
|
Accretion charge |
145 |
134 |
|
Other finance costs |
13 |
21 |
|
Less: Finance costs capitalised against qualifying assets |
(187) |
(184) |
|
|
147 |
137 |
A.3 Dividends paid and proposed
Woodside Energy Group Ltd, the parent entity, paid and proposed dividends as set out below:
|
|
2024 US$m |
2023 US$m |
|
(a) Dividends paid during the financial period Prior year fully franked final dividend US$0.60, paid on 4 April 2024 |
1,139 |
2,734 |
|
(b) Dividend declared subsequent to the reporting period Current year fully franked interim dividend US$0.69 to be paid on |
1,310 |
1,519 |
A.4 Earnings per share
|
|
2024 |
2023 |
|
Profit attributable to equity holders of the parent (US$m) |
1,937 |
1,740 |
|
Weighted average number of shares on issue for basic earnings per share |
1,896,041,815 |
1,896,624,636 |
|
Effect of dilution from contingently issuable shares |
14,691,983 |
12,981,487 |
|
Weighted average number of shares on issue adjusted for the effect of dilution |
1,910,733,798 |
1,909,606,123 |
|
Basic earnings per share (US cents) |
102.2 |
91.7 |
|
Diluted earnings per share (US cents) |
101.4 |
91.1 |
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.
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
for the half-year ended 30 June 2024
A.5 Taxes
|
|
2024 US$m |
2023 US$m |
|
Reconciliation of income tax expense |
|
|
|
Profit before tax |
2,310 |
2,828 |
|
PRRT expense |
(192) |
(778) |
|
Profit before income tax |
2,118 |
2,050 |
|
Income tax expense calculated at 30% |
635 |
615 |
|
Effect of tax rate differentials |
(15) |
30 |
|
Effect of deferred tax assets not recognised |
35 |
67 |
|
Effect of tax benefits previously unrecognised1 |
(366) |
(340) |
|
Reduction in deferred tax liability due to held for sale basis1 |
(91) |
- |
|
Foreign exchange impact on tax benefit |
(11) |
(83) |
|
Adjustment to prior years |
(52) |
(16) |
|
Other |
11 |
11 |
|
Income tax expense |
146 |
284 |
1. Subsequent to achieving first oil on the Sangomar project in June 2024, the Group has recognised a net deferred tax asset of $305 million. The remaining $61 million relates to other tax benefits previously unrecognised. The expected sale of Woodside's 15.1% share in the Scarborough Joint Venture resulted in the recognition of a net tax benefit of $91 million. These events have resulted in a reduction of the global effective income tax rate from 25.6% to 6.9%. In the prior period, as a result of the final investment decision to develop the Trion resource, the Group recognised deferred tax assets of $319 million, resulting in a reduction of the global effective income tax rate from 29.6% to 13.9%.
In May 2024, the Parliament of Australia enacted the Treasury Laws Amendment (Tax Accountability and Fairness) Act 2024 for the PRRT deductions cap which takes effect from 1 July 2023. If an entity is an LNG producer and its petroleum projects meet the criteria of the deduction cap, the entity will have a taxable profit of 10% of the projects' assessable receipts in the year of tax.
The new legislation has impacted the Pluto and Wheatstone projects resulting in the Group recognising a $124 million current tax payable as at 30 June 2024.
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
for the half-year ended 30 June 2024
B. Production and growth assets
B.1 Exploration and evaluation
|
|
Asia Pacific US$m |
Americas US$m |
Africa US$m |
Total US$m |
|
Half-year ended 30 June 2024 |
|
|
|
|
|
Carrying amount at 1 January 2024 |
568 |
76 |
24 |
668 |
|
Additions |
11 |
52 |
14 |
77 |
|
Amortisation of licence acquisition costs |
- |
(5) |
- |
(5) |
|
Transferred exploration and evaluation |
(8) |
- |
(18) |
(26) |
|
Carrying amount at 30 June 2024 |
571 |
123 |
20 |
714 |
|
Year ended 31 December 2023 |
|
|
|
|
|
Carrying amount at 1 January 2023 |
529 |
240 |
38 |
807 |
|
Additions |
79 |
161 |
6 |
246 |
|
Amortisation of licence acquisition costs |
- |
(2) |
(2) |
(4) |
|
Expensed |
(31) |
(28) |
(18) |
(77) |
|
Transferred exploration and evaluation1 |
(9) |
(295) |
- |
(304) |
|
Carrying amount at 31 December 2023 |
568 |
76 |
24 |
668 |
1. On 20 June 2023, the Group made a final investment decision to develop the Trion resource in Mexico. Related exploration and evaluation assets of $274 million were transferred to oil and gas properties.
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
for the half-year ended 30 June 2024
B.2 Oil and gas properties
|
|
Land and buildings US$m |
Transferred exploration and evaluation US$m |
Plant and equipment US$m |
Projects in development1 US$m |
Total US$m |
|
Half-year ended 30 June 2024 |
|
|
|
|
|
|
Carrying amount at 1 January 2024 |
701 |
777 |
23,589 |
15,724 |
40,791 |
|
Additions2 |
- |
- |
(127) |
2,447 |
2,320 |
|
Disposals at written down value |
(2) |
- |
- |
(47) |
(49) |
|
Depreciation and amortisation |
(28) |
(86) |
(1,779) |
- |
(1,893) |
|
Completions and transfers3 |
- |
341 |
5,391 |
(5,706) |
26 |
|
Transfer to assets held for sale4 |
- |
- |
(4) |
(1,066) |
(1,070) |
|
Carrying amount at 30 June 2024 |
671 |
1,032 |
27,070 |
11,352 |
40,125 |
|
At 30 June 2024 |
|
|
|
|
|
|
Historical cost |
1,743 |
2,320 |
55,533 |
12,072 |
71,668 |
|
Accumulated depreciation and impairment |
(1,072) |
(1,288) |
(28,463) |
(720) |
(31,543) |
|
Net carrying amount |
671 |
1,032 |
27,070 |
11,352 |
40,125 |
|
Year ended 31 December 2023 |
|
|
|
|
|
|
Carrying amount at 1 January 2023 |
840 |
481 |
23,057 |
15,541 |
39,919 |
|
Additions |
- |
- |
836 |
5,759 |
6,595 |
|
Disposals at written down value |
(8) |
- |
(2) |
- |
(10) |
|
Depreciation and amortisation |
(67) |
(125) |
(3,764) |
- |
(3,956) |
|
Impairment losses |
(64) |
(20) |
(1,028) |
(328) |
(1,440) |
|
Completions and transfers |
- |
441 |
4,496 |
(4,633) |
304 |
|
Transfer to assets held for sale |
- |
- |
(6) |
(615) |
(621) |
|
Carrying amount at 31 December 2023 |
701 |
777 |
23,589 |
15,724 |
40,791 |
|
At 31 December 2023 |
|
|
|
|
|
|
Historical cost |
1,745 |
1,979 |
50,272 |
16,443 |
70,439 |
|
Accumulated depreciation and impairment |
(1,044) |
(1,202) |
(26,683) |
(719) |
(29,648) |
|
Net carrying amount |
701 |
777 |
23,589 |
15,724 |
40,791 |
1. Projects in development include the fair value ascribed to future phases of certain projects acquired through business combinations.
2. Includes $2,212 million of capital additions and $187 million of capitalised borrowing costs offset by $79 million relating to changes in restoration provision assumptions. The $127 million of additions reducing plant and equipment relates to changes in restoration provision assumptions.
3. Upon first oil in June 2024, the carrying value of the Sangomar project in projects in development has been transferred to plant and equipment.
4. Refer to Note B.4 for details of the sell-downs of the Scarborough Joint Venture.
The Group has capital expenditure commitments contracted for, but not provided for in the financial statements, of
$3,017 million (31 December 2023: $4,245 million).
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
for the half-year ended 30 June 2024
B.3 Goodwill
|
|
US$m |
|
Half-year ended 30 June 2024 |
|
|
Carrying amount at 1 January 2024 |
3,995 |
|
Transfer to assets held for sale1 |
(298) |
|
Carrying amount at 30 June 2024 |
3,697 |
|
At 30 June 2024 |
|
|
Cost |
4,174 |
|
Accumulated impairment |
(477) |
|
Net carrying amount |
3,697 |
|
Year ended 31 December 2023 |
|
|
Carrying amount at 1 January 2023 |
4,614 |
|
Adjustment to purchase price allocation |
55 |
|
Impairment |
(477) |
|
Transfer to assets held for sale |
(197) |
|
Carrying amount at 31 December 2023 |
3,995 |
|
At 31 December 2023 |
|
|
Cost |
4,472 |
|
Accumulated impairment |
(477) |
|
Net carrying amount |
3,995 |
1. Refer to Note B.4(a) for details of the sell-downs of the Scarborough Joint Venture.
B.4 Disposal of assets
(a) Sell-down of Scarborough Joint Venture to JERA
On 23 February 2024, the Group entered into a sale and purchase agreement with JERA for the sale of a 15.1% non-operating participating interest in the Scarborough Joint Venture.
As at 30 June 2024, the Group has reclassified $1,378 million of assets, being the carrying value of the 15.1% interest in the Scarborough Joint Venture within the Australia segment, to assets held for sale. Liabilities of $119 million have been reclassified to liabilities directly associated with assets held for sale. No impairment of assets occurred on reclassification to held for sale.
The following assets and liabilities were reclassified as held for sale as at 30 June 2024:
|
|
US$m |
|
Assets classified as held for sale |
|
|
Oil and gas properties |
1,070 |
|
Inventories |
6 |
|
Lease assets |
2 |
|
Goodwill |
298 |
|
Other assets |
2 |
|
Total assets held for sale |
1,378 |
|
|
|
|
Liabilities directly associated with assets held for sale |
|
|
Payables |
(28) |
|
Deferred tax liabilities |
(75) |
|
Lease liabilities |
(8) |
|
Provisions |
(8) |
|
Total liabilities directly associated with assets held for sale |
(119) |
The purchase price is $740 million, subject to adjustments which includes the reimbursement to Woodside for JERA's share of expenditure for the Scarborough project from the effective date of 1 January 2022. The total proceeds from the sale are expected to exceed the net carrying value of the assets and liabilities classified as held for sale. The transaction is expected to complete in the second half of 2024. Completion of the transaction is subject to conditions precedent including Western Australia Government approval.
This has also resulted in the recognition of a net tax benefit of $91 million. After completion, the Group's participating interest in the Scarborough Joint Venture will reduce from 90% to 74.9%.
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
for the half-year ended 30 June 2024
B.4 Disposal of assets (continued)
(a) Sell-down of Scarborough Joint Venture to JERA (continued)
Key estimates and judgements
Goodwill allocation on Scarborough sell-down
In accordance with AASB 136/IAS 36 Impairment of assets, if goodwill has been allocated to a CGU and the entity disposes of an operation within that unit, the goodwill associated with the operation disposed shall be included in the carrying value of the operation when determining the gain or loss on disposal and measured on the basis of the relative values of the operation disposed of and the portion of the CGU retained.
The Pluto-Scarborough CGU includes goodwill allocated from the merger with BHP Petroleum in 2022. Judgement is required to determine the amount of goodwill allocated to the 15.1% participating interest in the Scarborough assets being disposed.
The Group used fair value measurements of Pluto and Scarborough assets within the CGU as the basis to allocate goodwill between the Pluto and Scarborough assets. The goodwill associated with the participating interest of the Scarborough assets being disposed of was determined based on the percentage participating interest disposed of in proportion to the participating interest being retained.
(b) Sell-down of Scarborough Joint Venture to LNG Japan
On 8 August 2023 the Group entered into a sale and purchase agreement with LNG Japan for the sale of a 10% non-operating participating interest in the Scarborough Joint Venture.
As at 31 December 2023, the Group reclassified $823 million of assets, being the carrying value of the 10% interest in the Scarborough Joint Venture, to assets held for sale. Liabilities of $94 million were reclassified to liabilities directly associated with assets held for sale.
The transaction completed on 26 March 2024, reducing the Group's participating interest from 100% to 90%. Proceeds from the sale were $910 million, including capital reimbursements and escalation. Delays to the first cargo or cost overruns in specific circumstances may result in payments by Woodside to LNG Japan of up to a maximum of $50 million. For the half-year ended 30 June 2024, the Group recognised a pre-tax gain on sale of $121 million.
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
for the half-year ended 30 June 2024
C. Debt and capital
C.1 Contributed equity
Issued and fully paid shares
|
|
Number of shares |
US$m |
|
Half-year ended 30 June 2024 |
|
|
|
Opening balance |
1,898,749,771 |
29,001 |
|
Amounts as at 30 June 2024 |
1,898,749,771 |
29,001 |
|
Year ended 31 December 2023 |
|
|
|
Opening balance |
1,898,749,771 |
29,001 |
|
Amounts as at 31 December 2023 |
1,898,749,771 |
29,001 |
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.
Reserved shares
Reserved shares are the Group's own equity instruments, which are used in employee share-based payment arrangements or the Dividend Reinvestment Plan (DRP). The DRP was suspended on 27 February 2023. These shares are deducted from equity.
|
|
Number of shares |
US$m |
|
Half-year ended 30 June 2024 |
|
|
|
Opening balance |
2,140,927 |
(49) |
|
Purchases during the period |
1,262,082 |
(25) |
|
Vested/allocated during the period |
(424,959) |
9 |
|
Amounts as at 30 June 2024 |
2,978,050 |
(65) |
|
Year ended 31 December 2023 |
|
|
|
Opening balance |
1,873,777 |
(38) |
|
Purchases during the year |
2,332,121 |
(57) |
|
Vested/allocated during the year |
(2,064,971) |
46 |
|
Amounts as at 31 December 2023 |
2,140,927 |
(49) |
C.2 Interest-bearing liabilities and financing facilities
During the period, the Group completed the drawdown of $500 million from bilateral loan facilities. In addition, the Group entered into the following facilities during the period:
· $1,000 million loan facility with Japan Bank for International Cooperation (JBIC) with a term of 10 years. Interest is based on daily Secured Overnight Financing Rate (SOFR) plus margin. This facility was fully drawn subsequent to the period on 22 July 2024.
· $450 million syndicated term loan facility with a tenor of 10 years. Interest is based on daily SOFR plus credit adjustment spread (CAS) and margin. This facility was fully drawn in June 2024.
There were no other material changes to interest-bearing liabilities and financing facilities. As at 30 June 2024, the Group had $6,500 million (31 December 2023: $6,050 million) of available undrawn facilities. Subsequent to 30 June 2024, the Group cancelled $1,550 million of undrawn facilities.
For the year ended 31 December 2023, the Group repaid $201 million of the CHF Medium Term Note and $83 million of the JBIC facility which was settled in July 2023.
Fair value
The carrying amounts of interest-bearing liabilities approximate their fair values, with the exception of the Group's unsecured bonds and the medium-term notes. The unsecured bonds have a carrying amount of $4,087 million (31 December 2023: $4,087 million) and a fair value of $3,958 million (31 December 2023: $3,936 million). The medium-term notes have a carrying amount of $200 million (31 December 2023: $200 million) and a fair value of $188 million (31 December 2023: $188 million). Fair value is calculated based on the present value of future principal and interest cash flows, discounted at the market rate of interest at the reporting date and classified as Level 1 on the fair value hierarchy.
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
for the half-year ended 30 June 2024
D. Other assets and liabilities
D.1 Segment assets and liabilities
|
|
30 June 2024 US$m |
31 December 2023 US$m |
|
(a) Segment assets |
|
|
|
Australia |
30,895 |
31,602 |
|
International |
18,083 |
17,923 |
|
Marketing |
798 |
835 |
|
Corporate/Other |
5,866 |
5,001 |
|
|
55,642 |
55,361 |
|
|
30 June 2024 US$m |
31 December 2023 US$m |
|
(b) Segment liabilities |
|
|
|
Australia |
7,312 |
7,833 |
|
International |
2,434 |
2,624 |
|
Marketing |
890 |
751 |
|
Corporate/Other |
9,177 |
8,983 |
|
|
19,813 |
20,191 |
Corporate/Other assets mainly comprise cash and cash equivalents, lease assets and deferred tax assets. Corporate/Other liabilities mainly comprise interest-bearing liabilities, lease liabilities and deferred tax liabilities.
D.2 Provisions
|
|
Restoration1 US$m |
Employee benefits US$m |
Other US$m |
Total US$m |
|
Half-year ended 30 June 2024 |
|
|
|
|
|
At 1 January 2024 |
7,154 |
522 |
281 |
7,957 |
|
Change in provision |
(449) |
(31) |
55 |
(425) |
|
Unwinding of present value discount |
144 |
- |
1 |
145 |
|
Carrying amount at 30 June 2024 |
6,849 |
491 |
337 |
7,677 |
|
Current |
698 |
302 |
223 |
1,223 |
|
Non-current |
6,151 |
189 |
114 |
6,454 |
|
Net carrying amount |
6,849 |
491 |
337 |
7,677 |
|
Year ended 31 December 2023 |
|
|
|
|
|
At 1 January 2023 |
6,253 |
517 |
409 |
7,179 |
|
Change in provision |
664 |
5 |
(128) |
541 |
|
Unwinding of present value discount |
237 |
- |
- |
237 |
|
Carrying amount at 31 December 2023 |
7,154 |
522 |
281 |
7,957 |
|
Current |
1,011 |
351 |
144 |
1,506 |
|
Non-current |
6,143 |
171 |
137 |
6,451 |
|
Net carrying amount |
7,154 |
522 |
281 |
7,957 |
1. 2024 change in provision is due to a revision of discount rates of $147 million (primarily due to an increase in risk-free rates), changes in foreign exchange rates of $84 million and provisions used of $358 million, offset by changes in estimates of $140 million.
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
for the half-year ended 30 June 2024
D.3 Other financial assets and liabilities
|
|
30 June 2024 US$m |
31 December 2023 US$m |
|
Other financial assets |
|
|
|
Financial instruments at fair value through profit and loss |
|
|
|
Derivative financial instruments designated as hedges |
160 |
248 |
|
Other financial assets |
100 |
53 |
|
Financial instruments at fair value through other comprehensive income |
|
|
|
Other financial assets |
- |
28 |
|
Total other financial assets |
260 |
329 |
|
Current |
154 |
209 |
|
Non-current |
106 |
120 |
|
Net carrying amount |
260 |
329 |
|
Other financial liabilities |
|
|
|
Financial instruments at fair value through profit and loss |
|
|
|
Derivative financial instruments designated as hedges |
126 |
74 |
|
Embedded derivative |
188 |
35 |
|
Other financial liabilities |
41 |
- |
|
Total other financial liabilities |
355 |
109 |
|
Current |
152 |
67 |
|
Non-current |
203 |
42 |
|
Net carrying amount |
355 |
109 |
Hedging activities
During the period, the following hedging activities were undertaken:
· The Group had hedged approximately 29.3 MMboe of 2024 oil production at an average price of approximately $75.6 per barrel, of which approximately 49% was delivered as at 30 June 2024.
· The Group additionally hedged approximately 15 MMboe of 2025 oil production at an average price of approximately $81.2 per barrel.
· The Group also has a hedging program for Corpus Christi LNG volumes designed to protect against downside pricing risk. These hedges are Henry Hub (HH) and Title Transfer Facility (TTF) commodity swaps. Approximately 70% of volumes for the remainder of 2024, 48% of 2025 and 9% of 2026 volumes have been hedged.
· Through foreign exchange forward contracts, the Group hedged the Australian dollar to US dollar exchange rate for a portion of the Australian dollar denominated capital expenditure expected to be incurred for the Scarborough development.
The following table presents the Group's derivative financial instruments designated as hedges, measured and recognised at fair value:
|
|
30 June 2024 US$m |
31 December 2023 US$m |
|
Oil swaps (cash flow hedges) |
(53) |
(14) |
|
HH Corpus Christi commodity swaps (cash flow hedges) |
(24) |
(44) |
|
TTF Corpus Christi commodity swaps (cash flow hedges) |
72 |
181 |
|
Interest rate swaps (cash flow hedges) |
48 |
43 |
|
Foreign exchange forwards (cash flow hedges) |
(9) |
8 |
|
Total derivative financial instruments asset designated as hedges |
34 |
174 |
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
for the half-year ended 30 June 2024
D.3 Other financial assets and liabilities (continued)
Embedded commodity derivative
In 2023, the Group entered into a revised long-term gas sale and purchase contract (GSPA) with Perdaman, where a component of the selling price is linked to the price of urea. The contract was assessed to contain an embedded commodity derivative that is required to be separated and recognised at fair value through profit and loss. The carrying value of the embedded derivative at 30 June 2024 amounted to a net liability of $188 million (31 December 2023: net liability of $35 million). The derivative is remeasured to fair value at each reporting date in accordance with the urea price at that date. For the six-month period ended 30 June 2024, an unrealised loss of $153 million (30 June 2023: unrealised loss of $52 million) has been recognised through other expenses.
Fair value
Except for the other financial assets and other financial liabilities set out in this note, there are no other 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, with the exception of the embedded commodity derivative which has been classified as Level 3 on the fair value hierarchy with no market observable inputs. Refer to key estimates and judgements for further details. 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 2023 Financial Statements. There have been no significant changes in risk management policies since 31 December 2023. Refer to the embedded commodity derivative key estimates and judgements section for the sensitivity assessment on discount rates and pricing.
Key estimates and judgements
Embedded commodity derivative
The fair value of the Perdaman embedded derivative has been estimated using a Monte Carlo simulation model. The assessment requires management to make certain assumptions about the model inputs, including forecast cash flows, discount rate, credit risk and volatility. These assumptions require significant management judgement and are subject to risk and uncertainty, and hence changes in economic conditions can affect the assumptions. The present value of the embedded derivative was estimated using the assumptions set out below.
· Inflation rate - 2.5%.
· Discount rate - a pre-tax interest rate curve (range: 5.8% to 6.95%).
· Domestic gas pricing - forecast sales are subject to urea pricing. Price assumptions are based on the best market information available at measurement date and derived from short- and long-term views of global supply and demand, building upon past experience of the industry and consistent with external sources. The long-term urea price is determined with reference to the prevailing gas hub (TTF) prices available in the market at reporting date.
The embedded derivative is most sensitive to changes in discount rates and pricing, which may result in unrealised gains or losses recognised in other income/expenses. The nominal impact of the effects of changes to discount rate and long-term price assumptions are estimated as follows:
|
Change in assumption1 |
US$m |
|
Urea sales price: increase of 10% |
137 |
|
Urea sales price: decrease of 10% |
(137) |
|
Discount rate: increase of 1.5%2 |
(186) |
|
Discount rate: decrease of 1.5%2 |
230 |
1. Amounts shown represent the change of the present value of the contract keeping all other variables constant.
2. A change of 1.5% represents 150 basis points.
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
for the half-year ended 30 June 2024
E. Other items
E.1 Contingent liabilities and assets
|
|
30 June 2024 US$m |
31 December 2023 US$m |
|
Contingent liabilities at reporting date |
|
|
|
Not otherwise provided for in the financial statements: |
|
|
|
Contingent liabilities |
226 |
260 |
|
Guarantees |
3 |
2 |
|
|
229 |
262 |
Contingent liabilities relate predominantly to possible obligations whose existence will only be confirmed by the occurrence or non-occurrence of uncertain future events, and therefore the Group has not provided for such amounts in these financial statements. The Group operates in complex tax and legislative regimes. The amounts disclosed above include estimates made in relation to ongoing disputes with various tax and government authorities. Assessing a value of contingent liabilities requires a high degree of judgement. The contingent liabilities relating to tax matters are estimated based on notices received from authorities before interest and penalties. The possibility of further claims related to the same matters cannot be ruled out and the judicial processes may take extended periods to conclude. Additionally, there are a number of other claims and possible claims that have arisen in the course of business against entities in the Group, the outcome of which cannot be estimated at present and for which no amounts have been included in the table above.
The Group has contingent assets of $56 million as at 30 June 2024 (31 December 2023: $47 million).
E.2 Changes to the composition of the Group
Since the last annual reporting, Koolbardi Pte Ltd, a wholly owned subsidiary, was incorporated in Singapore on 21 February 2024.
E.3 New standards and interpretations
New and amended accounting standards adopted
A number of amended standards became applicable for the current reporting period. The Group did not make any significant changes to its accounting policies and did not make retrospective adjustments as a result of adopting these amended standards. These amendments did not materially impact the accounting policies or amounts disclosed in the half-year financial statements of the Group.
New standards and interpretations not yet adopted
Certain new accounting standards, amendments to accounting standards and interpretations have been published that are not mandatory for the 30 June 2024 reporting period and have not been early adopted by the Group. These standards, amendments or interpretations are not expected to have a material impact to the Group in the current or future reporting periods and on foreseeable future transactions with the exception of AASB 18/ IFRS 18 Presentation and Disclosure in Financial Statements and the amendments to AASB 112/ IAS 12 Income Taxes where the impact is under assessment.
Pillar Two tax reform
In December 2021, the Organisation for Economic Co-operation and Development (OECD) published its Pillar Two model rules. The Pillar Two model rules:
· aim to ensure that large multinational groups pay a minimum amount of tax on income arising in each jurisdiction in which they operate; and
· would achieve a minimum effective tax rate in each jurisdiction of 15% from the reporting period commencing
1 January 2024.
For the half-year ended 30 June 2024, the Group paid $1,700 million of income tax and PRRT.
The Group's impact assessment will depend on the extent to which the Pillar Two legislation has been enacted in the various jurisdictions the Group operates in and when it comes into effect. As at reporting date, Australia has not enacted the Pillar Two legislation. The Group will continue to monitor and assess the expected impact of the Pillar Two reform.
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
for the half-year ended 30 June 2024
E.4 Events after the end of the reporting period
Acquisition of Tellurian Inc
On 22 July 2024, the Group entered into a definitive agreement to acquire all the issued and outstanding common stock of Tellurian Inc (Tellurian) for a cash payment of approximately $900 million (the transaction). As part of the agreement, the Group has provided a loan facility of up to $230 million to Tellurian to ensure site activity maintains momentum prior to the completion of the transaction. The loan is secured by a first priority lien over the Tellurian assets, subject to customary exclusions. The latest maturity date of the loan is 15 December 2024 or the date of transaction completion.
The transaction is subject to Tellurian shareholder approval, satisfaction of customary conditions precedent, and is expected to complete in the fourth quarter of 2024. The financial effect of the transaction is still being assessed.
Acquisition of OCI Clean Ammonia Holding B.V.
On 5 August 2024, Woodside entered into a binding agreement to acquire 100% of OCI Clean Ammonia Holding B.V. (OCI) and its Clean Ammonia Project for an all-cash consideration of approximately $2.35 billion. The project is under construction and is subject to cost, schedule, and performance guarantees from OCI.
The transaction is subject to OCI shareholder approval, satisfaction of customary conditions precedent, and is expected to complete in the second half of 2024. The financial effect of the transaction is still being assessed.
DIRECTORS' DECLARATION
For the half-year ended 30 June 2024
In accordance with a resolution of directors of Woodside Energy Group Ltd, we state that:
In the opinion of the directors:
a) the financial statements and notes of the Group are in accordance with the Australian Corporations Act 2001, including:
i. giving a true and fair view of the Group's financial position as at 30 June 2024 and of its performance for the half-year ended on that date; and
ii. complying with Australian Accounting Standard AASB 134 Interim Financial Reporting and the Corporations Regulations 2001;
b) 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:
a) the financial statements, prepared in accordance with International Accounting Standard IAS 34 Interim Financial Reporting, give a true and fair view of the assets, liabilities, financial position and profit or loss of Woodside Energy Group Ltd and the undertakings included in the consolidation taken as a whole; and
b) the half-year report includes a fair review of the:
i. 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
|
|
|
|
R J Goyder, AO Chair Perth, Western Australia 27 August 2024
|
M E O'Neill Chief Executive Officer and Managing Director Sydney, New South Wales 27 August 2024 |
INDEPENDENT REVIEW REPORT
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 during the half-year (together the Group), which comprises the condensed consolidated statement of financial position as at 30 June 2024, the condensed consolidated income statement, condensed consolidated statement of comprehensive income, condensed consolidated statement of cash flows and condensed consolidated statement of changes in equity for the half-year ended on that date, selected 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:
1. The Corporations Act 2001 including:
a. giving a true and fair view of the Group's financial position as at 30 June 2024 and of its performance for the half-year ended on that date
b. complying with Australian Accounting Standard AASB 134 Interim Financial Reporting, and the Corporations Regulations 2001.
2. International Accounting Standard IAS 34 Interim Financial Reporting as issued by the International Accounting Standards Board (IASB).
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) and ISRE 2410 Review of Interim Financial Information Performed by the Independent Auditor of the Entity (ISRE 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) and the International Code of Ethics for Professional Accountants (including International Independence Standards) issued by the International Ethics Standards Board for Accountants (IESBA 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 and the IESBA Code.
PricewaterhouseCoopers, ABN 52 780 433 757
Brookfield Place, Level 15, 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.
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, the Corporations Act 2001 and International Financial Reporting Standards. The directors are also responsible for such internal control as they 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.
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 2024 and of its performance for the half-year ended on that date, and complying with Australian Accounting Standard AASB 134 Interim Financial Reporting and the Corporations Regulations 2001.
ISRE 2410 requires us to conclude whether anything has come to our attention that causes us to believe that the half-year financial statements, taken as a whole, are not prepared in all material respects in accordance with International Accounting Standard IAS 34 Interim Financial Reporting.
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 International Standards on Auditing 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.
PricewaterhouseCoopers
|
N M Henry Partner Perth, Western Australia 27 August 2024 |
A G B Hodge Partner Perth, Western Australia 27 August 2024
|
Appendix 4D
Dividends
|
Ex-dividend date |
5 September 2024 |
|
|
|
Record date for the interim dividend |
6 September 2024 |
|
|
|
|
|
|
|
|
Date the dividend is payable |
3 October 2024 |
|
|
|
|
|
Current period |
Previous corresponding period[29] |
|
Interim dividend - fully franked |
US cents per share |
69 |
80 |
|
None of these dividends are foreign sourced. |
|||
Woodside dividends are determined and declared in US dollars. However, shareholders will receive their dividend in Australian dollars unless their registered address is in the United Kingdom (in which case they will receive their dividend in British pounds), in the United States of America (in which case they will receive their dividend in US dollars) or in New Zealand (in which case they will receive their dividend in NZ dollars).
Shareholders who reside outside of the United States can elect to receive their dividend electronically in US dollars, payable into a US financial institution account. Shareholders who reside outside of the United States, the United Kingdom, New Zealand and Australia may elect to receive their dividend electronically in their local currency using Global Wire Payment Service from the Company's share registry, Computershare Investor Services Pty Ltd.
Shareholders should contact the Company's share registry if they wish to alter their dividend currency for future dividend payments. Contact details are available on Woodside's website on the Shareholder Information section of the Investors page. Shareholders must make an election to alter their dividend currency on or before 5.00pm AWST on 9 September 2024.
Net Tangible Assets per ordinary security
|
|
Current period US$ |
Previous corresponding period29 US$ |
|
Net Tangible Assets (US$ per ordinary security)[30] |
16.42 |
16.40 |
|
|
|
|
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 period29 |
|
North West Shelf Gas Pty Ltd |
33.33% |
33.33% |
|
North West Shelf Liaison Company Pty Ltd |
33.33% |
33.33% |
|
China Administration Company Pty Ltd |
33.33% |
33.33% |
|
International Gas Transportation Company Limited |
33.33% |
33.33% |
|
North West Shelf Shipping Service Company Pty Ltd |
33.33% |
33.33% |
|
North West Shelf Lifting Coordinator Pty Ltd |
33.33% |
33.33% |
|
Blue Ocean Seismic Services Limited |
16.17% |
28.50% |
|
Iwilei District Participating Parties, LLC |
14.96% |
14.96% |
|
Caesar Oil Pipeline Company, LLC |
25.00% |
25.00% |
|
Cleopatra Gas Gathering Company LLC |
22.00% |
22.00% |
|
Marine Well Containment Company LLC |
10.00% |
10.00% |
Shareholder information
Key announcements 2024
|
January |
Fourth quarter 2023 report |
|
Appointment of Director and changes to Committee Membership |
|
|
February |
Woodside concludes discussions with Santos |
|
Woodside releases Reserves Statement and financial updates |
|
|
Woodside to sell 15.1% Scarborough interest to JERA |
|
|
Full-year 2023 results and briefing |
|
|
Annual Report 2023 and US Annual Report 2023 (Form 20-F) |
|
|
Climate Transition Action Plan and 2023 Progress Report |
|
|
March |
Thriving through the energy transition investor presentation |
|
Woodside completes sale of 10% Scarborough interest |
|
|
April |
Chair's letter to shareholders |
|
First quarter 2024 report |
|
|
2024 Annual General Meeting |
|
|
June |
Appointment of Director to Woodside Board |
|
Woodside achieves first oil at Sangomar field in Senegal |
|
|
Report on payments to governments 2023 |
|
|
July |
Woodside to acquire Tellurian and Driftwood LNG |
|
Second quarter 2024 report |
|
|
August |
Woodside to acquire OCI's Clean Ammonia Project |
|
Half-Year 2024 line-item guidance |
|
|
Half-Year 2024 results |
Events calendar 2024-2025
Key calendar dates for Woodside shareholders in 2024-25. Please note dates are subject to review.
|
August |
27 |
Half-year 2024 results |
|
September |
5 |
Ex-dividend date for interim dividend (Australian Securities Exchange and London Stock Exchange) |
|
6 |
Ex-dividend date for interim dividend (New York Stock Exchange) |
|
|
6 |
Record date for interim dividend |
|
|
16 |
US investor event |
|
|
October |
3 |
Payment date for interim dividend |
|
16 |
Third quarter 2024 report |
|
|
December |
31 |
Year-end 2024 |
|
January |
|
Fourth quarter 2024 report |
Business directory
|
Registered office: |
Postal address: |
|
Woodside Energy Group Ltd Mia Yellagonga 11 Mount Street Perth WA 6000 Australia |
GPO Box D188 Perth WA 6840 Australia
T: +61 8 9348 4000 |
Investor enquiries
Investors seeking information on the company should contact Investor Relations at:
|
Postal address: |
|
|
Investor Relations GPO Box D188 Perth WA 6840 Australia |
T: +61 8 9348 4000 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 account details.
Details of shareholdings can be checked 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.
Assets
Producing facilities
Australia
|
Asset |
Role |
Equity |
Product |
|
Pluto LNG |
Operator |
90% |
LNG, pipeline gas and condensate |
|
North West Shelf1 |
Operator |
33.33% |
LNG, pipeline gas, condensate and NGLs |
|
Wheatstone |
Non-operator |
13% |
LNG, pipeline gas and condensate |
|
Julimar-Brunello |
Operator |
65% |
|
|
Okha FPSO |
Operator |
50% |
Crude oil |
|
Ngujima-Yin FPSO |
Operator |
60% |
Crude oil |
|
Bass Strait |
Non-operator |
32.5-50% |
Crude oil, pipeline gas, condensate and NGLs |
|
Pyrenees FPSO |
Operator |
40-71.4% |
Crude oil |
|
Macedon |
Operator |
71.4% |
Pipeline gas |
|
International
|
Asset |
Role |
Equity |
Product |
|
Sangomar |
Operator |
82% |
Crude oil |
|
Greater Angostura |
Operator |
45-68.46% |
Crude oil and pipeline gas |
|
Greater Shenzi |
Operator |
72% |
Crude oil, pipeline gas, condensate and NGLs |
|
Atlantis |
Non-operator |
44% |
Crude oil, pipeline gas, condensate and NGLs |
|
Mad Dog |
Non-operator |
23.9% |
Crude oil, pipeline gas, condensate and NGLs |
Projects1
Post FID
|
Asset |
Role |
Equity |
Product |
|
Scarborough |
Operator |
90%2 |
LNG, pipeline gas and condensate |
|
Trion |
Operator |
60% |
Crude oil |
|
Developments
|
Asset |
Role |
Equity |
Product |
|
|
Calypso |
Operator |
70% |
Gas |
|
|
Browse |
Operator |
30.6% |
LNG, pipeline gas and condensate |
|
|
Greater Scarborough1 |
Operator |
100% |
Gas |
|
|
Liard |
Non-operator |
50% |
Gas |
|
|
Sunrise |
Operator |
33.44% |
LNG, pipeline gas and condensate |
|
|
New energy opportunities1,2
|
Asset |
Role |
Equity |
Product |
|
H2OK |
Operator |
100% |
Hydrogen |
|
H2Perth |
Operator |
100% |
Hydrogen |
|
Hydrogen Refueller@H2Perth |
Operator |
100% |
Hydrogen |
|
H2TAS |
Operator |
100% |
Hydrogen and ammonia |
|
Woodside Solar |
Proponent2 |
100% |
Solar energy |
|
Southern Green Hydrogen3 |
Preferred partner |
- |
Hydrogen and ammonia |
|
Capella |
Non-operating participant |
N/A |
Solar energy |
|
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 |
|
G-8-AP |
Operator |
Browse Joint Venture |
For carbon capture and storage evaluation for Browse |
|
|
G-10-AP |
Operator |
Angel CCS Joint Venture |
Located in the Northern Carnarvon basin off the north west coast of Western Australia |
Exploration
|
Country |
Permit |
Role |
Equity |
Product |
|
Asia - Pacific |
|
|
|
|
|
Australia |
WA-404-P |
Operator |
100% |
Gas prone basin |
|
WA-536-P |
Operator |
65% |
Gas prone basin |
|
|
WA-550-P |
Operator |
100% |
Gas prone basin |
|
|
NT/P86 |
Operator |
100% |
Gas prone basin |
|
|
WA-28-P |
Operator |
15.78%-33.3% |
Oil and gas prone basin |
|
|
WA-93-R |
Operator |
70% |
Gas prone basin |
|
|
WA-94-R |
Operator |
70% |
Gas prone basin |
|
|
Europe |
|
|
|
|
|
Ireland |
FEL 5/13 |
Operator |
Exit initiated |
Oil or gas prone basin |
|
Africa |
|
|
|
|
|
Senegal |
Rufisque, Sangomar and Sangomar Deep (RSSD) |
Operator |
Exit initiated |
Oil prone basin |
|
Congo |
Marine XX |
Non-operator |
22.5% |
Oil or gas prone basin |
|
Egypt |
Red Sea Block 1 |
Non-operator |
45% |
Oil or gas prone basin |
|
Red Sea Block 3 |
Non-operator |
30% |
Oil and gas prone basin |
|
|
Red Sea Block 4 |
Non-operator |
25% |
Oil and gas prone basin |
|
|
North El Dabaa Offshore (Block 4) |
Non-operator |
27% |
Oil and gas prone basin |
|
|
Caribbean |
|
|
|
|
|
Barbados |
Bimshire Bay |
Operator |
60% - Exit initiated |
Oil or gas prone basin |
|
North America |
|
|
|
|
|
US Gulf of Mexico |
GB 780, GB 824, GB 825, GB 821, GB 866, EB 636, EB 637, EB 550, EB 594, EB 638, KC 859, KC 903, KC 904, KC 905, KC 948, KC 949, WR 795, WR 796 |
Operator
|
100%
|
Oil prone basin
|
|
GB 640, GB 641, GB 685, GB 555, GB 726, GB 770, GB 771, GB 604, GB 605, GB 647, GB 648, GB 772, GB 728, GB 729, GB 773, GB 774, GB 421, GB 464, GB 465, GB 508, GB 509, GC 598 |
Non-operator |
40% |
Oil prone basin |
|
|
GB 574, GB 575, GB 619, GB 529, GB 530, GB 531 |
Operator |
40% |
Oil prone basin |
|
|
GC 436, GC 480 |
Non-operator |
44% |
Oil prone basin |
|
|
GB 501, GB 502, GB 545, GB 630, GB 672, GB 676, GB 677, GB 716, GB 719, GB 720, GB 721, GB 760, GB 762, GB 763, GB 805, GB 806, GB 807, GB 851, GB 852, GB 895 |
Operator |
60% |
Oil prone basin |
|
|
GC 282, GC 237 |
Non-operator |
50% |
Oil prone basin |
|
|
GB 663, GB 664, GB 678, GC 210, GC 211 |
Operator |
100% |
Oil prone basin |
|
|
EB 655, EB 656, EB 699, EB 700, EB 701, EB 566, EB 567, AC 78, AC 80, EB 914 |
Operator |
70% |
Oil prone basin |
|
|
MC 798, MC 842 |
Non-operator |
45% |
Oil prone basin |
|
|
AC 125, AC 126, AC 81, AC 82 |
Operator |
45% |
Oil prone basin |
|
|
GC 679, GC 768 |
Non-operator |
31.9% |
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 870 |
Non-operator |
23.9% |
Oil prone basin |
|
|
AT 228, AT 273, AT 274, AT 409, AT 452, AT 453, AT 454, AT 424, AT 425, AT 469, AT 470 |
Non-operator |
30% |
Oil prone basin |
Alternative Performance Measures
Woodside uses various alternative performance measures (APM) which are non-IFRS measures that are unaudited but derived from our Half-Year Financial Statements. Although certain non-IFRS data has been extracted or derived from the Half-Year financial statements, this data has not been audited or reviewed by Woodside's independent auditors. These measures are presented to provide further insight into Woodside's performance. See Non-IFRS Measures on page 57 for more information.
APMs and their nearest respective IFRS measure.
|
APMs derived from the condensed consolidated income statement |
30 June 2024 US$m |
30 June 2023 US$m |
|
EBIT/EBITDA excluding impairment |
|
|
|
Net profit after tax |
1,972 |
1,766 |
|
Adjusted for: |
|
|
|
Finance income |
(95) |
(174) |
|
Finance costs |
147 |
137 |
|
PRRT expense |
192 |
778 |
|
Income tax expense |
146 |
284 |
|
EBIT |
2,362 |
2,791 |
|
Adjusted for: |
|
|
|
Oil and gas properties depreciation and amortisation |
1,893 |
1,944 |
|
Amortisation of licence acquisition costs |
5 |
4 |
|
Amortisation of intangible assets |
10 |
- |
|
Depreciation of lease assets |
101 |
81 |
|
Impairment losses |
- |
68 |
|
EBITDA excluding impairment |
4,371 |
4,888 |
|
|
|
|
|
Underlying NPAT |
|
|
|
Net profit after tax attributable to equity holders of the parent |
1,937 |
1,740 |
|
Adjusted for the following exceptional items: |
|
|
|
Add: Derecognition of Pluto PRRT (post-tax) |
- |
446 |
|
Add: Impairment losses (post-tax) |
- |
29 |
|
Less: Sangomar DTA recognition |
(305) |
- |
|
Less: Trion DTA recognition |
- |
(319) |
|
Underlying NPAT |
1,632 |
1,896 |
|
|
|
|
|
APMs derived from the condensed consolidated statement of cash flows and other notes |
30 June 2024 US$m |
30 June 2023 US$m |
|
Capital expenditure |
|
|
|
Capital additions on evaluation |
42 |
76 |
|
Capital additions on oil and gas properties |
2,212 |
2,555 |
|
Capital additions on other1 |
111 |
138 |
|
Capital expenditure |
2,365 |
2,769 |
|
1. Includes capital additions on other corporate spend. The 2023 amounts have been restated to be presented on the same basis. |
||
|
APMs derived from the condensed consolidated statement of cash flows and other notes (continued) |
30 June 2024 US$m |
30 June 2023 US$m |
|
Exploration expenditure |
|
|
|
Exploration and evaluation expenditure |
103 |
138 |
|
Adjusted for: |
|
|
|
Amortisation expense |
(5) |
(4) |
|
Prior year expense written off |
- |
(1) |
|
Exploration capitalised |
14 |
54 |
|
Exploration expenditure |
112 |
187 |
|
Capital and exploration expenditure |
2,477 |
2,956 |
|
|
|
|
|
Free cash flow |
|
|
|
Cash flow from operating activities2 |
2,393 |
2,951 |
|
Cash flow used in investing activities |
(1,653) |
(2,637) |
|
Free cash flow |
740 |
314 |
|
|
|
|
|
Liquidity |
|
|
|
Cash and cash equivalents |
1,979 |
3,469 |
|
Add: Available undrawn facilities |
6,500 |
4,050 |
|
Less: Restricted cash |
- |
(10) |
|
Liquidity |
8,479 |
7,509 |
|
2. Purchases of shares relating to employee share plans, which were previously classified within cash flows used in operating activities, has been classified within cash flows used in financing activities for the half-year ended 2024. The 2023 amounts have been restated to be presented on the same basis. |
||
|
|
||
|
APMs derived from the condensed consolidated statement of financial position |
30 June 2024 US$m |
30 June 2023 US$m |
|
Net tangible assets per ordinary security |
|
|
|
Net assets |
35,829 |
36,684 |
|
Adjusted for: |
|
|
|
Goodwill |
(3,697) |
(4,669) |
|
Non-controlling interest |
(759) |
(775) |
|
Intangible assets |
(205) |
(103) |
|
Net tangible assets |
31,168 |
31,137 |
|
Number of issued and fully paid shares |
1,898,749,771 |
1,898,749,771 |
|
Net tangible assets per ordinary security |
16.42 |
16.40 |
|
|
|
|
|
Gearing |
|
|
|
Interest-bearing liabilities (Current and non-current) |
5,822 |
5,109 |
|
Lease liabilities (Current and non-current) |
1,545 |
1,570 |
|
Adjusted for: |
|
|
|
Cash and cash equivalents |
(1,979) |
(3,469) |
|
Add: Restricted cash |
- |
10 |
|
Net debt |
5,388 |
3,220 |
|
Equity attributable to equity holders of the parent |
35,070 |
35,909 |
|
Total net debt and equity attributable to equity holders of the parent |
40,458 |
39,129 |
|
Gearing (%) |
13.3 |
8.2 |
|
|
|
|
|
APMs derived from the condensed consolidated income statement and statement of financial position |
30 June 2024 US$m |
30 June 2023 US$m |
|
Return on equity |
|
|
|
Net profit after tax attributable to equity holders of the parent |
1,937 |
1,740 |
|
Equity attributable to equity holders of the parent |
35,070 |
35,909 |
|
Return on equity (%) |
5.5 |
4.8 |
|
|
|
|
|
Return on average capital employed |
|
|
|
Profit before tax and net finance costs |
2,362 |
2,791 |
|
Opening non-current liabilities |
15,209 |
15,586 |
|
Closing non-current liabilities |
14,932 |
15,109 |
|
Average non-current liabilities |
15,071 |
15,348 |
|
Opening equity attributable to equity holders of the parent |
34,399 |
36,336 |
|
Closing equity attributable to equity holders of the parent |
35,070 |
35,909 |
|
Average equity attributable to equity holders of the parent |
34,735 |
36,123 |
|
Total average non-current liabilities and equity attributable to equity holders of the parent |
49,806 |
51,471 |
|
Return on average capital employed (%) |
4.7 |
5.4 |
|
|
|
|
|
APMs derived from other notes |
30 June 2024 US$m |
30 June 2023 US$m |
|
Revenue from sale of hydrocarbons (excluding marketing segment) |
5,376 |
6,486 |
|
|
|
|
|
Cash margin (excluding marketing segment) |
|
|
|
Gross profit/(loss) |
2,526 |
3,221 |
|
Adjusted for: |
|
|
|
Other cost of sales |
21 |
- |
|
Trading costs |
- |
4 |
|
Oil and gas properties depreciation and amortisation |
1,893 |
1,944 |
|
Other revenue |
(99) |
41 |
|
Cash margin (excluding marketing segment) |
4,341 |
5,210 |
|
Cash margin % |
81% |
80% |
|
|
|
|
|
Production costs (excluding marketing segment) |
745 |
807 |
|
Production cost margin % |
14% |
13% |
|
|
|
|
|
Other cash costs (excluding marketing segment): |
|
|
|
Royalties, excise and levies |
196 |
316 |
|
Insurance |
26 |
34 |
|
Inventory movement |
(62) |
(33) |
|
Shipping and direct sales costs |
104 |
145 |
|
Other hydrocarbon costs |
26 |
7 |
|
Total other cash costs (excluding marketing segment) |
290 |
469 |
|
Other cash cost margin % |
5% |
7% |
Notes
Glossary
|
Term |
Definition |
|
$, $m |
US dollars unless otherwise stated, millions of dollars |
|
1P |
Proved reserves |
|
2C |
Best Estimate of Contingent resources |
|
2P |
Proved plus Probable reserves |
|
Abate/abatement |
Avoidance, reduction or removal of an amount of carbon dioxide or equivalent. |
|
ASX |
Australian Securities Exchange |
|
A$, AUD |
Australian dollars |
|
BHP Petroleum |
Woodside Energy Global Holdings Pty Ltd ACN 006 923 897 (formerly known as BHP Petroleum International Pty Ltd) and, unless context otherwise requires, its subsidiaries. References to "Woodside Energy Global Holdings Pty Ltd" or "BHP Petroleum International Pty Ltd" are references to Woodside Energy Global Holdings Pty Ltd ACN 006 923 897 (formerly known as BHP Petroleum International Pty Ltd) excluding its subsidiaries. |
|
Biodiversity |
Biological diversity means the variability among living organisms from all sources including, inter alia, terrestrial, marine and other aquatic ecosystems and the ecological complexes of which they are a part; this includes diversity within species, between species and of ecosystems.1 |
|
Board |
The Board of Directors of Woodside Energy Group Ltd |
|
Brent |
Intercontinental Exchange (ICE) Brent Crude deliverable futures contract (oil price) |
|
Capital expenditure |
Includes capital additions on oil and gas properties and evaluation capitalised. |
|
Carbon credit |
A tradeable financial instrument that is issued by a carbon-crediting program. A carbon credit represents a greenhouse gas emission reduction to, or removal from, the atmosphere equivalent to 1 tCO2-e, calculated as the difference in emissions from a baseline scenario to a project scenario. Carbon credits are uniquely serialised, issued, tracked and retired or administratively cancelled by means of an electronic registry operated by an administrative body, such as a carbon-crediting program. |
|
Cash margin |
Gross profit/loss adjusted for other cost of sales, trading costs, oil and gas properties depreciation and amortisation and other revenue. Excludes the marketing segment. Cash margin % is calculated as cash margin divided by revenue from sale of hydrocarbons (excluding marketing segment). |
|
CCS |
Carbon capture and storage |
|
CCUS |
Carbon capture utilisation and storage |
|
CHF |
Swiss francs |
|
CO2 |
Carbon dioxide |
|
CO2-e |
CO2 equivalent. The universal unit of measurement to indicate the global warming potential of each of the seven greenhouse gases, expressed in terms of the global warming potential of one unit of carbon dioxide. It is used to evaluate releasing (or avoiding releasing) any greenhouse gas against a common basis.2 |
|
Condensate |
Hydrocarbons that are gaseous in a reservoir but that condense to form liquids as they rise to the surface. |
|
cps |
Cents per share |
|
Decarbonisation |
Woodside uses this term to describe activities or pathways that have the effect of moving towards a state that is lower carbon, as defined in this glossary. |
|
DRP |
Dividend reinvestment plan |
|
EBIT |
Calculated as profit before income tax, PRRT and net finance costs |
|
EBITDA excluding impairment |
Calculated as profit before income tax, PRRT, net finance costs, depreciation and amortisation, impairment losses, impairment reversals |
|
Emissions |
Emissions refers to emissions of greenhouse gases unless otherwise stated. |
|
EPS |
Earnings per share |
|
Exploration expenditure |
Includes exploration and evaluation expenditure less amortisation of licence acquisition costs and prior year exploration expense written off. |
|
Extended Interest Joint Ventures or Extended Interest JVs |
The Extended Interest Joint Ventures commenced on 1 August 2020 and cover the relevant joint venturers' production entitlement for equity lifted LNG and pipeline gas from the North West Shelf Project. Woodside' participating interest in the Extended Interest Joint Ventures is 31.567%. |
|
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 |
|
GAAP |
Generally Accepted Accounting Principles |
|
Gearing |
Net debt divided by the total of net debt and equity attributable to equity holders of the parent. |
|
GHG or greenhouse gas |
The seven greenhouse gases listed in the Kyoto Protocol are: carbon dioxide (CO2); methane (CH4); nitrous oxide (N2O); hydrofluorocarbons (HFCs); nitrogen trifluoride (NF3); perfluorocarbons (PFCs); and sulphur hexafluoride (SF6).2 |
|
Goal |
Woodside uses this term to broadly encompass its targets and aspirations. |
|
Gross margin |
Gross profit divided by operating revenue. Gross profit excludes income tax, PRRT, net finance costs, other income and other expenses. |
|
H1, H2 |
Halves of the calendar year (H1 is 1 January to 30 June and H2 is 1 July to 31 December). |
|
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 less restricted cash. |
|
LNG |
Liquified natural gas |
|
Lower carbon |
Woodside uses this term to describe the characteristic of having lower levels of associated potential GHG emissions when compared to historical and/or current conventions or analogues, for example relating to an otherwise similar resource, process, production facility, product or service, or activity. |
|
Lower carbon ammonia |
Lower carbon ammonia is characterised here by the use of hydrogen with emissions abated by carbon, capture, and storage (CCS), with an expected ammonia lifecycle (Scope 1, 2 and 3) carbon emissions intensity of 0.8 tCO2/tNH3 (based on contracted intensity threshold with Linde) relative to unabated ammonia with a lifecycle (Scope 1, 2 and 3) carbon emissions intensity of 2.3 tCO2/tNH3 (Hydrogen Europe, 2023). |
|
Lower carbon portfolio |
For Woodside, a lower carbon portfolio is one from which the net equity Scope 1 and 2 greenhouse gas emissions, which includes the use of offsets, are being reduced towards targets, and into which new energy products and lower carbon services are planned to be introduced as a complement to existing and new investments in oil and gas. Our Climate Policy sets out the principles that we believe will assist us achieve this aim. |
|
Lower carbon services |
Woodside uses this term to describe technologies, such as CCUS or offsets that could be used by customers to reduce their net greenhouse gas emissions. |
|
LSE |
London Stock Exchange |
|
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. |
|
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 or ammonia, that are emerging in scale but which are expected to grow during the energy transition due to having lower greenhouse gas emissions at the point of use than conventional fossil fuels. |
|
NGLs |
Natural gas liquids |
|
NPAT |
Net profit after tax attributable to equity holders of the parent |
|
NWS |
North West Shelf |
|
NYSE |
New York Stock Exchange |
|
Offsets |
The compensation for an entity's greenhouse gas emissions within its scope by achieving an equivalent amount of emission reductions or removals outside the boundary or value chain of that entity. |
|
Other cash cost margin |
Other cash costs include royalties, excise and levies, insurance, inventory movement, shipping and direct sales costs and other hydrocarbon costs. Excludes the marketing segment. Other cash cost margin % is calculated as other cash costs divided by revenue from sale of hydrocarbons (excluding marketing segment). |
|
Production cost margin |
Production cost margin % is calculated as production costs divided by revenue from sale of hydrocarbons. Excludes the marketing segment. |
|
PRRT |
Petroleum resources rent tax |
|
PSC |
Production sharing contract |
|
PSE |
Process safety event |
|
Revenue from ordinary activities |
Revenue from the sale of hydrocarbons, processing and services revenue and shipping and other revenue. |
|
RFSU |
Ready for start up |
|
RSSD |
Rufisque Offshore, Sangomar Offshore and Sangomar Deep Offshore. |
|
Scope 1 GHG emissions |
Direct GHG emissions. These occur from sources that are owned or controlled by the company, for example, emissions from combustion in owned or controlled boilers, furnaces, vehicles, etc.; emissions from chemical production in owned or controlled process equipment. Woodside estimates greenhouse gas emissions, energy values and global warming potentials are estimated in accordance with the relevant reporting regulations in the jurisdiction where the emissions occur (e.g. Australian national Greenhouse and Energy Reporting (nGER), US EPA Greenhouse Gas Reporting Program (GHGRP)). Australian regulatory reporting principles have been used for emissions in jurisdictions where regulations do not yet exist.3 |
|
Scope 2 GHG emissions |
Electricity indirect GHG emissions. Scope 2 accounts for GHG emissions from the generation of purchased electricity consumed by the company. Purchased electricity is defined as electricity that is purchased or otherwise brought into the organisational boundary of the company. Scope 2 emissions physically occur at the facility where electricity is generated. Woodside estimates greenhouse gas emissions, energy values and global warming potentials are estimated in accordance with the relevant reporting regulations in the jurisdiction where the emissions occur (e.g. Australian national Greenhouse and Energy Reporting (nGER), US EPA Greenhouse Gas Reporting Program (GHGRP)). Australian regulatory reporting principles have been used for emissions in jurisdictions where regulations do not yet exist.3 |
|
Scope 3 GHG emissions |
Other indirect GHG emissions. Scope 3 is a reporting category that allows for the treatment of all other indirect emissions. Scope 3 emissions are a consequence of the activities of the company but occur from sources not owned or controlled by the company. Some examples of Scope 3 activities are extraction and production of purchased materials; transportation of purchased fuels; and use of sold products and services. Please refer to the data table on page 72 of the Climate Transition Action Plan and 2023 Progress Report for further information on the Scope 3 emissions categories reported by Woodside.3 |
|
Significant environmental event |
Unplanned or undesired event resulting in a moderate, medium-term impact on ecosystem, species, habitat or physical or biological attributes. |
|
Sustainably (including sustainable and sustainably) |
References to sustainability (including sustainable and sustainably) are used with reference to Woodside's Sustainability Committee and sustainability related Board policies, as well as in the context of Woodside's aim to ensure its business is sustainable from a long-term perspective, considering a range of factors including economic (including being able to sustain our business in the long term by being low cost and profitable), environmental (including considering our environmental impact and striving for a lower carbon portfolio), social (including supporting our license to operate), and regulatory (including ongoing compliance with relevant legal obligations). Use of the terms 'sustainability', 'sustainable' and 'sustainably' is not intended to imply that Woodside will have no adverse impact on the economy, environment, or society, or that Woodside will achieve any particular economic, environmental, or social outcomes. |
|
Target |
Woodside uses this term to describe an intention to seek the achievement of an outcome, where Woodside considers that it has developed a suitably defined plan or pathway to achieve that outcome |
|
TCFD |
Taskforce on Climate-related Financial Disclosures |
|
Tier 1 PSE |
A typical Tier 1 process safety event is loss of containment of hydrocarbons greater than 500 kg (in any one-hour period). |
|
Tier 2 PSE |
A typical Tier 2 process safety event is loss of containment of hydrocarbons greater than 50 kg but less than 500 kg (in any one-hour period). |
|
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 cost or UPC |
Production costs ($ million) divided by production volume (MMboe) |
|
US, USA |
United States of America |
|
USD |
US dollars |
|
WA |
Western Australia |
1. UNEP,1992. "Convention on Biological Diversity' https://www.cbd.int/doc/legal/cbd-en.pdf.
2. See IFRS Foundation 2021: Climate Related Disclosures Prototype. Appendix A. The IFRS published a further consultation document subsequent to the 2021 prototype. As it did not contain an updated definition of Paris-Aligned scenarios Woodside has retained use of the previous edition.
3. World Resources Institute and World Business Council for Sustainable Development 2004. "GHG Protocol: a corporate accounting and reporting standard".
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 |
1 bbl |
1 boe |
|
|
|
|
|
Facility |
Unit |
LNG conversion factor |
|
Karratha Gas Plant |
1 tonne |
8.08 boe |
|
Pluto Gas Plant |
1 tonne |
8.34 boe |
|
Wheatstone |
1 tonne |
8.27 boe |
The LNG conversion factor from tonne to boe is specific to volumes produced at each facility and is based on gas composition which may change over time.
Units of measure
|
Term |
Definition |
|
bbl |
barrel |
|
bcf |
billion cubic feet of gas |
|
boe |
barrel of oil equivalent |
|
CO2-e |
carbon dioxide equivalent |
|
GJ |
gigajoule |
|
ha |
hectare |
|
Mbbl |
thousand barrels |
|
Mbbl/d |
thousand barrels per day |
|
Mboe |
thousand barrels of oil equivalent |
|
Mboe/d |
thousand barrels of oil equivalent per day |
|
Mcf |
thousand cubic feet of gas |
|
MMboe |
million barrels of oil equivalent |
|
MMBtu |
million British thermal units |
|
MMscf |
million standard cubic feet of gas |
|
MMscf/d |
million standard cubic feet of gas per day |
|
Mtpa |
million tonnes per annum |
|
MW |
megawatt |
|
PJ |
petajoules |
|
scf |
standard cubic feet of gas |
|
TJ |
terajoule |
|
tpd |
tonnes per day |
About this report
This Half-Year Report 2024 is a summary of Woodside's operations, activities and financial position as at 30 June 2024. 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 2024 and 30 June 2024. 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 53 - 55.
This report should be read in conjunction with the Annual Report 2023 and the Climate Transition Action Plan and 2023 Progress Report available at woodside.com.
Forward looking statements
This report contains forward-looking statements with respect to Woodside's business and operations, market conditions, results of operations and financial condition, including, for example, but not limited to, outcomes of transactions, including the timing, terms and potential benefits of the proposed acquisition of Tellurian and OCI's Clean Ammonia Project, statements regarding long-term demand for Woodside's products, development, completion and execution of Woodside's projects, expectations regarding future capital expenditures, the payment of future dividends and the amount thereof, future results of projects, operating activities and new energy products, expectations and plans for renewables production capacity and investments in, and development of, renewables projects expectations and guidance with respect to production, capital and exploration expenditure and gas hub exposure, and expectations regarding the achievement of Woodside's net equity Scope 1 and 2 greenhouse gas emissions reduction and new energy investment targets and other climate and sustainability goals.
All statements, other than statements of historical or present facts, are forward-looking statements and generally may be identified by the use of forward-looking words such as 'guidance', 'foresee', 'likely', 'potential', 'anticipate', 'believe', 'aim', 'aspire', 'estimate', 'expect', 'intend', 'may', 'target', 'plan', 'strategy', 'forecast', 'outlook', 'project', 'schedule', 'will', 'should', 'seek' and other similar words or expressions. Similarly, statements that describe the objectives, plans, goals or expectations of Woodside are forward-looking statements.
Forward-looking statements in this report are not guidance, forecasts, guarantees or predictions of future events or performance, but are in the nature of future expectations that are based on management's current expectations and assumptions.
Those statements and any assumptions on which they are based are subject to change without notice and are subject to inherent known and unknown risks, uncertainties, assumptions and other factors, many of which are beyond the control of Woodside, its related bodies corporate and their respective officers, directors, employees, advisers or representatives.
Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, fluctuations in commodity prices, actual demand for Woodside's products, currency fluctuations, geotechnical factors, drilling and production results, gas commercialisation, development progress, operating results, engineering estimates, reserve and resource estimates, loss of market, industry competition, environmental risks, climate related risks, physical risks, legislative, fiscal and regulatory developments, changes in accounting standards, economic and financial markets conditions in various countries and regions, political risks, the actions of third parties, project delay or advancement, regulatory approvals, the impact of armed conflict and political instability (such as the ongoing conflict in Ukraine and in the Middle East) on economic activity and oil and gas supply and demand, cost estimates, the effect of future regulatory or legislative actions on Woodside or the industries in which it operates, including potential changes to tax laws, the impact of general economic conditions, inflationary conditions, prevailing exchange rates and interest rates and conditions in financial markets, and risks associated with acquisitions, mergers and joint ventures, including difficulties integrating businesses, uncertainty associated with financial projections, restructuring, increased costs and adverse tax consequences, and uncertainties and liabilities associated with acquired and divested properties and businesses.
In addition to the summary of 'Principal risks and uncertainties' on page 16 of this report, a more detailed summary 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 the London Stock Exchange and in Woodside's most recent Annual Report on Form 20-F filed with the United States Securities and Exchange Commission and available on the Woodside website at https://www.woodside.com/investors/reports-investor-briefings. You should review and have regard to these risks when considering the information contained in this report.
If any of the assumptions on which a forward-looking statement is based were to change or be found to be incorrect, this would likely cause outcomes to differ from the statements made in this report.
Investors are strongly cautioned not to place undue reliance on any forward-looking statements. Actual results or performance may vary materially from those expressed in, or implied by, any forward-looking statements. None of Woodside nor any of its related bodies corporate, nor any of their respective officers, directors, employees, advisers or representatives, nor any person named in this report or involved in the preparation of the information in this report, makes any representation, assurance, guarantee or warranty (either express or implied) as to the accuracy or likelihood of fulfilment of any forward-looking statement, or any outcomes, events or results expressed or implied in any forward-looking statement in this report.
All forward-looking statements contained in this report reflect Woodside's views held as at the date of this report and, except as required by applicable law, Woodside does not intend to, undertake to, or assume any obligation to, provide any additional information or update or revise any of these statements after the date of this report, either to make them conform to actual results or as a result of new information, future events, changes in Woodside's expectations or otherwise.
Past performance (including historical financial and operational information) is given for illustrative purposes only. It should not be relied on as, and is not necessarily, a reliable indicator of future performance, including future security prices.
Non-IFRS Measures
Throughout this report, 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 in, and have not been prepared in accordance with, International Financial Reporting Standards (IFRS) and are not recognised measures of financial performance or liquidity under IFRS (Non-IFRS Financial Measures). These measures include EBIT, EBITDA excluding impairment, Gearing, Underlying NPAT, Net debt, Liquidity, Free cash flow, Capital expenditure, Exploration expenditure, Return on Equity, Return on average capital employed, Cash margin, Production cost margin, Other cash cost margin, Net tangible assets and Net tangible assets per ordinary security. These Non-IFRS Financial Measures are defined in the glossary on pages 53 - 55 of this report. A quantitative reconciliation of these measures to the most directly comparable financial measure calculated and presented in accordance with IFRS can be found in the Alternative Performance Measures section of this report on pages 50 - 52.
Woodside's management uses these measures to monitor Woodside's financial performance alongside IFRS measures to improve the comparability of information between reporting periods and business units and Woodside believes that the Non-IFRS Financial Measures it presents provide a useful means through which to examine the underlying performance of its business.
Undue reliance should not be placed on the Non-IFRS Financial Measures contained in this report and 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.
Climate strategy and emissions data
All greenhouse gas emissions data in this report are estimates, due to the inherent uncertainty and limitations in measuring or quantifying greenhouse gas emissions, and our methodologies for measuring or quantifying greenhouse gas emissions may evolve as best practices continue to develop and data quality and quantity continue to improve.
Woodside "greenhouse gas" or "emissions" information reported are net equity Scope 1 greenhouse emissions, Scope 2 greenhouse emissions, and/or Scope 3 greenhouse emissions, unless otherwise stated.
For more information on Woodside's climate strategy, including references to 'lower carbon' and 'lower carbon services' as part of that strategy, and emissions data, refer to Woodside's Climate Transition Action Plan and 2023 Progress Report available at woodside.com.
No express or implied prices
This report does not include any express or implied prices at which Woodside will buy or sell financial products.
|
Contacts: |
|
|
|
INVESTORS |
MEDIA |
REGISTERED ADDRESS |
|
Marcela Louzada M: +61 456 994 243 |
Dan Pagoda (Australia) M: +61 482 675 731
Rob Young (United States) M: +1 281 790 2805
|
Woodside Energy Group Ltd ACN 004 898 962 Mia Yellagonga 11 Mount Street Perth WA 6000 Australia T +61 8 9348 4000
|
This announcement was approved and authorised for release by Woodside's Disclosure Committee.
[1] Non-IFRS measure. Refer to pages 50 - 52 for further information.
[2] Woodside cancelled $1,550 million of undrawn facilities in July 2024. This cancellation has the effect of reducing our liquidity by $1,550 million.
[3] Calculated based on Woodside's closing share price on 28 June 2024 of A$28.21 and a US$:A$ exchange rate of 0.67.
[4] The completion % excludes the Pluto Train 1 modifications project.
[5] The SPA is with JERA Scarborough Pty Ltd which is a wholly owned subsidiary of JERA Co., Inc. Subject to completion of the transaction, targeted for the second half of 2024. See "Woodside to sell 15.1% Scarborough interest to JERA", announced 23 February 2024.
[6] LJ Scarborough Pty Ltd (LNG Japan) is a jointly owned subsidiary of LNG Japan Corporation (which is a 50:50 joint venture between Sumitomo Corporation and Sojitz Corporation) and Japan Organization for Metals and Energy Security (JOGMEC). JOGMEC has a 49.9% interest in LJ Scarborough Pty Ltd. See "Woodside completes sale of 10% Scarborough interest", announced 26 March 2024.
[7] See "Woodside to acquire Tellurian and Driftwood LNG", announced 22 July 2024 and "Woodside to acquire OCI's Clean Ammonia Project", announced 5 August 2024.
[8] This is an alternative performance measure (APM) which is a non-IFRS measure that is unaudited. Woodside believes this non-IFRS measure provides useful performance information, but it should not be considered as an indication of, or as a substitute for, statutory measures as an indicator of actual operating performance (such as net profit after tax or net cash from operating activities) or any other measure of financial performance or position presented in accordance with IFRS. Refer to Alternative Performance Measures on pages 50 - 52 for a reconciliation for these measures to Woodside's financial statements and Non-IFRS Measures on page 57 for more information about non-IFRS measures.
[9] Net profit after tax attributable to equity holders of the parent.
[10] Subsequent to achieving first oil on the Sangomar project in June 2024, the Group has recognised a net deferred tax asset of $305 million. The expected sale of Woodside's 15.1% share in the Scarborough Joint Venture resulted in the recognition of a net tax benefit of $91 million. These events have resulted in a reduction of the global effective income tax rate from 25.6% to 6.9%. In the prior period, as a result of the final investment decision to develop the Trion resource, the Group recognised deferred tax assets of $319 million, resulting in a reduction of the global effective income tax rate from 29.6% to 13.9%.
[11] Purchases of shares relating to employee share plans, which were previously classified within cash flows used in operating activities, has been classified within cash flows used in financing activities for the half-year ended 2024. The 2023 comparatives have been reclassified to be presented on the same basis.
[12] Capital additions on oil and gas properties, evaluation capitalised and other corporate spend. Excludes exploration capitalised and the effect of Global Infrastructure Partners' (GIP) additional contribution to Pluto Train 2. The H1 2023 capital expenditure has been restated to include other corporate spend.
[13] Exploration and evaluation expenditure less amortisation costs and prior year exploration expense written off.
[14] Cash flow from operating activities less cash flow from investing activities.
[15] Includes production of 88.7 MMboe from Woodside reserves and 0.6 MMboe primarily from feed gas purchased from Pluto non-operating participants processed through the Pluto-KGP Interconnector.
[16] The conversion factors used throughout this report are set out on page 55, unless otherwise stated. Sales volumes differ from production volumes primarily due to the timing of liftings and the exclusion of third-party purchased volumes.
[17] Comparisons are to half-year ended 30 June 2023.
[18] Calculated based on Woodside's closing share price on 28 June 2024 of A$28.21 and a US$:A$ exchange rate of 0.67.
[19] These are non-IFRS measures. Refer to Alternative Performance Measures for a reconciliation for these measures to Woodside's financial statements on pages 50 - 52 and Non-IFRS Measures on page 57 for more information about non-IFRS measures.
[20] Cash flow from operating activities less cash flow from investing activities.
[21] The 22nd well was drilled subsequent to the period.
[22] Subject to conditions and agreements on terms for this period.
[23] Woodside uses the term "lower-carbon" to describe the characteristic of having lower levels of associated potential GHG emissions when compared to historical and/or current conventions or analogues, for example relating to an otherwise similar product. Refer to 'Climate strategy and emissions data' on page 57 for more information.
[24] The completion % excludes the Pluto Train 1 modifications project.
[25] The SPA is with JERA Scarborough Pty Ltd which is a wholly owned subsidiary of JERA Co., Inc.
[26] LJ Scarborough Pty Ltd (LNG Japan) is a jointly owned subsidiary of LNG Japan Corporation (which is a 50:50 joint venture between Sumitomo Corporation and Sojitz Corporation) and Japan Organization for Metals and Energy Security (JOGMEC). JOGMEC has a 49.9% interest in LJ Scarborough Pty Ltd. The sale proceeds received by Woodside of US$910 million for equity in the Scarborough Joint Venture comprises the purchase price, reimbursed expenditure and escalation.
[27] Woodside's 90% participating interest in the Scarborough Joint Venture is prior to the completion of the sell-down of 15.1% interest to JERA.
[28] The supply of carbon abated hydrogen is dependent on ExxonMobil's CCS facility becoming operational.
[29] Comparisons are to half-year ended 30 June 2023.
[30] Includes lease assets and liabilities as a result of AASB 16 Leases. Net Tangible Assets per ordinary security is a non-IFRS measure. Refer to Alternative Performance Measures for a reconciliation for these measures to Woodside's financial statements on pages 50 - 52.
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