Can COIN's Base App Power Web3 Growth and Revenue Diversification?
Notably, Coinbase becomes the first U.S.-based exchange to roll out a comprehensive super app that brings together key Web3 functionalities — wallet, DeFi, NFTs, and payments — within a single mobile platform. This move expands Coinbase's reach beyond its core trading business, allowing it to engage a wider consumer audience. The Base App serves as a key growth lever, deepening user participation in the on-chain ecosystem while opening up new monetization pathways.
Importantly, the app enhances and diversifies Coinbase's revenue streams. As users tap into Web3 services, Coinbase stands to earn from token swaps, staking
and other in-app offerings. Its integration with the Base network further allows the company to capture sequencer fees and benefit from rising on-chain activity. This strategic pivot reduces Coinbase's reliance on unpredictable trading volumes and fosters a more resilient, recurring revenue model centered on infrastructure usage and ecosystem expansion.
What About COIN's Competitors?
Robinhood Wallet drives Robinhood Markets ' HOOD expansion beyond traditional brokerage into self-custodial crypto, offering access to tokens, NFTs and future DeFi tools. By engaging crypto-native users, Robinhood diversifies its revenue streams. This positions Robinhood to capitalize on Web3 growth while reducing dependence on its core trading business.
Block Inc.'s XYZ Bitcoin Wallet drives Block's growth by enabling self-custodial crypto access and empowering users with financial control. By simplifying Bitcoin storage and peer-to-peer transfers, it aligns with Block's mission of economic empowerment and reinforces its strategic position within the Bitcoin ecosystem and emerging Web3 landscape.
COIN's Price Performance
Shares of COIN have gained 69.1% year to date, outperforming the industry.
Image Source: Zacks Investment Research
COIN's Expensive Valuation
COIN trades at a price-to-earnings value ratio of 75.03, above the industry average of 22.44. But it carries a Value Score of F.
Estimates for COIN Witness Southward Movement
The Zacks Consensus Estimate for COIN's second-quarter and third-quarter 2025 EPS has moved down 2 cents and 1 cent, respectively, over the past seven days. The same for full-year 2025 and 2026 EPS has decreased by 2 cents and 3 cents, respectively.
The consensus estimate for COIN's 2025 and 2026 revenues indicates year-over-year increases. While the consensus estimate for COIN's 2025 EPS indicates a decline, the same for 2026 EPS suggests an increase.
COIN stock currently carries a Zacks Rank #3 (Hold). You can see the complete list of today's Zacks #1 Rank (Strong Buy) stocks here.
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Globe and Mail
2 hours ago
- Globe and Mail
Woodside Energy Releases Second Quarter Report for Period Ended 30 June 2025
Woodside Energy Group (ASX: WDS) (NYSE: WDS): Woodside CEO Meg O'Neill said the company continued to demonstrate operational excellence and world-class project execution over the second quarter, with a focus on driving future growth and value. 'We delivered strong production of 50 million barrels of oil equivalent for the quarter from our diverse portfolio of high-quality assets. At the same time, ongoing focus on cost control has enabled us to lower our unit production cost guidance for 2025. 'As we marked the anniversary in June of first oil from Sangomar, the project's exceptional performance continued to make a strong contribution to quarterly results, with gross production reaching 101 thousand barrels per day at close to 100% reliability. Our outstanding safety record at Sangomar continued, with no recordable injuries during the project's first year of operations. 'Our announcement in April of a final investment decision to develop the Louisiana LNG Project positions Woodside as a global LNG powerhouse, complementing our established Australian LNG business and enabling us to meet growing global demand from a broader range of customers. 'Louisiana LNG's strategic advantages and value-generating potential were demonstrated by key infrastructure, offtake and gas supply agreements entered into during the quarter. 'In June, we completed the sell-down of a 40% interest in Louisiana LNG Infrastructure LLC to Stonepeak for $5.7 billion, with Stonepeak to contribute 75% of the project capital expenditure in both 2025 and 2026. 'We continue to receive strong interest from high-quality potential partners as we explore further sell-downs. With both the final investment decision and capital expenditure risk reduced through our transaction with Stonepeak, we will evaluate the most value-accretive opportunities and remain disciplined in our selection of strategic partners. 'Our collaboration agreement with Aramco signed in May also includes potential acquisition of an equity interest in, and LNG offtake from, Louisiana LNG. The agreement includes exploring potential collaboration opportunities in lower-carbon ammonia from our Beaumont New Ammonia Project. 'We remain focused on delivering our Scarborough and Trion projects on schedule and budget. In May, we connected the floating production unit hull and topsides for our Scarborough Energy Project, which is now 86% complete and on track for first LNG cargo in the second half of 2026. 'Our Trion Project offshore Mexico is now 35% complete and targeting first oil in 2028. Construction of the floating production unit is progressing well, and we are preparing for construction of the floating storage and offloading vessel to commence in the second half of 2025. 'This demonstrates that Woodside continues to deliver on our commitments, executing multiple major projects with strong safety performance and cost control. 'We are maintaining financial discipline during our current phase of capital expenditure and proactively managing our balance sheet. We issued $3.5 billion of unsecured bonds in the US market in an offering that was heavily oversubscribed, reaffirming the debt market's view of Woodside. 'The $1.9 billion closing payment received from Stonepeak in June, plus proceeds from the divestment of our Greater Angostura assets in Trinidad and Tobago, further de-risks our balance sheet and strengthens our ability to both fund our growth projects and provide shareholder returns. We have made the decision to exit the H2OK Project, demonstrating our disciplined approach to portfolio management. 'We are also executing multiple, complex decommissioning activities offshore Australia. We successfully completed the plugging of the Minerva and Stybarrow wells. Removal of other equipment at the legacy Minerva, Stybarrow and Griffin assets has been impacted by unexpected challenges, with further engineering and alternative solutions required. Whilst this has had some cost impacts, we are applying learnings to improve planning and execution. 'We are pleased to have received the Australian Government's proposed decision to grant environmental approval for the North West Shelf Project Extension. We are continuing constructive consultation with the Government. 'Conducting our business sustainably remains core to Woodside's success and we remain firmly on track to meet our target of reducing net equity Scope 1 and 2 greenhouse gas emissions by 15% by 2025.' Operations Pluto LNG Achieved quarterly LNG reliability of 94.9%. Commenced production from the PLA-08 subsea well, enhancing deliverability and extending plateau production. Secured secondary environmental approval enabling development of the XNA-03 well through existing infrastructure to support sustained production. North West Shelf (NWS) Project Achieved strong quarterly LNG reliability of 97.4%. Received the proposed approval from the Australian Government on the North West Shelf Project Extension and continued consultation on proposed conditions. Successfully completed planned maintenance offshore at Goodwyn Alpha and onshore at Karratha Gas Plant (KGP), with production recommencing as planned. Successfully drilled the Lambert West development well, with installation of the subsea infrastructure and startup expected in Q3 2025. The project will sustain production from the Angel platform. Completed the permanent retirement of LNG Train 2, resulting in a reduction of KGP's capacity from 16.9 Mtpa to 14.3 Mtpa. Wheatstone and Julimar-Brunello Progressed the Julimar Phase 3 Project, a four-well tieback to the existing Julimar field production system. Subsea construction commenced ahead of the drilling campaign scheduled for Q3 2025, with project startup expected in 2026. Completion of the asset swap with Chevron remains on track for 2026. 7 Bass Strait Completed preparatory activities and secured regulatory approvals for the Kipper 1B Project, with drilling expected to commence in Q3 2025. Progressed the Turrum Phase 3 Project with work commencing on the Marlin-B platform ahead of the drilling campaign, expected to commence in the second half of 2025. Through these projects, Woodside is expected to add more than 100 PJs (Woodside share) to the south-eastern Australian domestic gas market. Sangomar Achieved exceptional production of 101 Mbbl/d (100% basis, 81 Mbbl/d Woodside share) at 99.6% reliability. Production from the Sangomar field remained on plateau for the quarter, with the field expected to come off plateau in Q3 2025. Continuing to assess production performance to inform further development. United States of America Achieved strong quarterly production at Shenzi, supported by 97.7% reliability. Approved a final investment decision on the Atlantis Major Facility Expansion Project, which is expected to increase water injection capacity. First water injection is targeted for 2027. Greater Angostura Completed the divestment of the Greater Angostura assets to Perenco for $259 million, subsequent to the period. 8 The divestment includes Woodside's interest in the shallow water Angostura and Ruby offshore oil and gas fields, associated production facilities, and onshore terminal. Delivered safe and reliable operations while undertaking divestment transition activities. Marketing Supplied 23.1% of produced LNG at prices linked to gas hub indices in the quarter, realising a 14% premium compared to oil-linked pricing. This represents 9.1% of Woodside's total equity production. Full-year gas hub guidance remains unchanged. Signed two LNG sale and purchase agreements with Uniper, for the supply of: 1.0 Mtpa from Louisiana LNG LLC for up to 13 years from its commercial operations date (COD). Up to 1.0 Mtpa from Woodside's global portfolio, commencing with Louisiana LNG's COD over a term until 2039. Signed non-binding heads of agreements with: JERA Co., Inc. for the sale and purchase of three LNG cargoes (approximately 0.2 Mtpa) on a delivered ex-ship basis during Japan's winter months from 2027 for a period of five years. PETRONAS, through its subsidiary PETRONAS LNG Ltd, for the supply of 1.0 Mtpa of LNG to Malaysia from 2028 for a period of 15 years. Woodside's sale and purchase agreements with Commonwealth LNG, executed in September 2022, were terminated during the quarter following Commonwealth LNG's failure to achieve key milestones, including FID, by contractual long stop dates. Executed incremental Western Australian pipeline gas sales of 4.2 PJs for delivery in 2025. Woodside continues to engage with the Western Australian domestic market on additional supply requirements for 2025, 2026 and 2027. Projects Beaumont New Ammonia The Beaumont New Ammonia Project was 95% complete at the end of the quarter, with pre-commissioning activities for Train 1 underway. Achievements include the completion of the storage tank construction, completion of compressor alignment and insertion of the ammonia converter basket. First ammonia production is targeted for late 2025. Project completion and associated payment of the remaining 20% of the acquisition consideration is expected in 2026. Scarborough Energy Project The Scarborough and Pluto Train 2 projects were 86% complete at the end of the quarter (excluding Pluto Train 1 modifications). Connected the floating production unit hull and topsides together in May 2025. Activities are now focused on the remaining integration and pre-commissioning scope. Continued installation, testing and pre-commissioning of the subsea infrastructure, which is near completion. Subsequent to the quarter, the third development well was drilled and completed. Reservoir properties and anticipated well deliverability were in line with expectations. Continued installation of piping and cables and commenced electrical commissioning activities at the Pluto Train 2 site, with the construction workforce having reached peak numbers. Progressed construction activity at the Pluto Train 1 modifications module yard, with civil works continuing and structural/piping works underway at the Pluto site. Subsequent to the quarter, the Federal Court of Australia heard a legal challenge to the National Offshore Petroleum Safety and Environmental Management Authority's decision to accept the Scarborough Offshore Facility and Trunkline (Operations) Environment Plan. The decision is pending. First LNG cargo is targeted for the second half of 2026. Trion The Trion Project was 35% complete at the end of the quarter. Finalised the floating production unit detailed engineering and procured all equipment and bulk materials. Progressed the floating storage and offloading vessel detailed engineering, with fabrication scheduled to commence in the second half of 2025. Progressed the design, procurement and manufacturing of the subsea equipment. First oil is targeted for 2028. Louisiana LNG Approved FID to develop the three-train, 16.5 Mtpa Louisiana LNG Project and issued a full notice to proceed to Bechtel. Train 1 was 22% complete at the end of the quarter, with activities focused on progressing the marine offloading facility, marine dry excavation, and civil works. Completed the sell-down of a 40% interest in Louisiana LNG Infrastructure LLC to Stonepeak. The closing payment of approximately $1,900 million received by Woodside reflects Stonepeak's 75% share of capex funding incurred since the effective date of 1 January 2025. Signed a long-term gas supply agreement with bp for the purchase of up to 640 billion cubic feet of feedgas commencing in 2029. Received approval from the Federal Energy Regulatory Commission for the extension of the in-service date for the LNG terminal and Driftwood Mainline Pipeline to the end of 2029. Submitted an application to the Department of Energy to extend to 2029 the export commencement deadline for the non-free trade agreement LNG Export Authorisation permit. First LNG is targeted for 2029. Hydrogen Refueller @H2Perth Progressed construction activities with major equipment packages including electrolysers and compressors installed on site. Ready for startup is targeted for Q4 2025 and first hydrogen production is expected in the first half of 2026. 9 Decommissioning Successfully completed the plug and abandonment of the three remaining wells at the Minerva field, offshore Victoria. Recovered approximately 45% of the Minerva pipeline across State and Commonwealth waters. Challenges to pipeline recovery and adverse weather impeded progress, leading to the suspension of activities. Recommencement will be informed by vessel availability. Continued decommissioning activities in the Bass Strait, including the submission of environmental approvals and plugging of 22 wells. Successfully concluded the ten-well Stybarrow plugging campaign. Experienced a Tier 1 process safety event when unexpected fluids were released during flushing of a Griffin subsea flowline. Water quality monitoring identified no impact on the environment. Woodside is evaluating decommissioning work plans for Minerva, Stybarrow and Griffin. The as-left condition on some closed sites has continued to present challenges for safe and efficient execution of decommissioning. These challenges have resulted in an increase in spend and cost estimates, and is expected to lead to an expense of $400 - 500 million pre-tax ($120 - 320 million post-tax) being recognised in the profit and loss in the half-year results. Exploration and development Browse The Western Australian Environmental Protection Authority concluded a four-week public comment period for an amendment to the Browse to North West Shelf Project proposal. The amendment reflects changes to the development footprint and introduces new environmental measures that further reduce the potential environmental impact of the development. The Browse CCS Project was referred to the Commonwealth regulator in October 2024 and declared valid in January 2025. The regulator has yet to determine if this is a controlled action under the Environment Protection and Biodiversity Conservation Act, and set a corresponding level of assessment. Calypso The Calypso joint venture continues to review development options. Concept select engineering studies and subsurface studies to mature the technical and commercial definition progressed in the quarter. Exploration There were no substantive exploration activities during the quarter. New energy and carbon solutions New energy Woodside formally joined the NeoSmelt Projec t as an equal equity participant and preferred energy supplier. 10 The proposed project is a pilot plant aiming to prove Pilbara iron ore can be used to produce lower-carbon emissions molten iron using direct reduced iron and electric smelting furnace technology. 11 Woodside made the decision to exit the proposed H2OK Project in Oklahoma due to ongoing challenges facing the lower-carbon hydrogen industry, including cost escalation and lower than anticipated hydrogen demand. The exit is expected to result in an impairment loss of approximately $140 million pre-tax (approximately $110 million post-tax) being recognised in the profit and loss in the half-year results. Carbon capture and storage (CCS) opportunities The Bonaparte CCS Assessment Joint Venture commenced pre-front end engineering design and, subsequent to the quarter, was awarded Major Project Status by the Australian Government. 12 Corporate activities Business development Entered into a non-binding collaboration agreement with Aramco to explore global opportunities, including Aramco's potential acquisition of an equity interest in and LNG offtake from the Louisiana LNG Project and opportunities for a potential collaboration in lower-carbon ammonia. Climate and sustainability On track to meet Woodside's target of reducing net equity Scope 1 and 2 greenhouse gas emissions by 15% by 2025. 13,14 Submitted the Oil and Gas Methane Partnership 2.0 Implementation Plan to the United Nations Environment Program. Quarterly activities include the initiation of a methane leak detection and reporting program at Goodwyn Alpha. Subsequent to the period, Woodside welcomed the inscription of the Murujuga Cultural Landscape on the World Heritage List by UNESCO's World Heritage Committee. Hedging Delivered as of 30 June 2025 approximately 58% of the 30 MMboe of 2025 oil production that was previously hedged at an average price of $78.7 per barrel. Hedged 10 MMboe of 2026 oil production at an average price of $70.1 per barrel. Continued hedging program for Corpus Christi LNG volumes involving Henry Hub (HH) and Title Transfer Facility (TTF) commodity swaps. Approximately 94% of 2025 and 87% of 2026 volumes have been hedged. The realised value of all hedged positions for the half-year ended 30 June 2025 is expected to be a pre-tax profit of $42 million, with a $58 million profit related to oil price hedges offset by a $18 million loss related to Corpus Christi hedges, and a $2 million profit related to other hedge positions. Hedging profits will be included in 'other income' except hedging profits related to interest rate swaps which will be included in 'finance income' in the half-year financial statements. Funding and liquidity Raised $3,500 million in the US market through multi-tranche SEC-registered bonds in May 2025, consisting of $500 million three-year bonds, $1,250 million five-year bonds, $500 million seven-year bonds and $1,250 million ten-year bonds. Cancelled two $1,500 million short-term liquidity facilities and repaid $1,900 million of drawn bi-lateral facilities. Refinanced $1,200 million of syndicated revolving facilities, with $600 million now maturing in June 2028 and the remaining $600 million in June 2030. As at 30 June 2025, Woodside had liquidity of approximately $8,400 million. Embedded commodity derivative In 2023, Woodside entered into a revised long-term gas sale and purchase contract with Perdaman. A component of the selling price is linked to the price of urea, creating an embedded commodity derivative in the contract. The fair value of the embedded derivative is estimated using a Monte Carlo simulation model. During the quarter, Woodside reassessed the embedded derivative calculation to factor in current market conditions and pricing inputs that reflect the long-term nature of the contract and associated market. Updates to the valuation model include: 30-day average pricing assumptions and longer-term external pricing forecasts to reflect the long-term nature of the contract; and longer-term historical data excluding extreme volatility periods, to reflect typical market conditions. As there is no long-term urea forward curve, TTF continues to be used as a proxy to simulate the value of the derivative over the life of the contract. For the half-year ended 30 June 2025, an unrealised gain of approximately $160 million is expected to be recognised through other income. 2025 half-year results and teleconference Woodside's Half-Year Report 2025 and associated investor briefing will be released to the market on Tuesday, 19 August 2025. These will also be available on Woodside's website at A teleconference providing an overview of the half-year 2025 results and a question and answer session will be hosted by Woodside CEO and Managing Director, Meg O'Neill, and Chief Financial Officer, Graham Tiver, on Tuesday, 19 August 2025 at 10:00 AEDT / 08:00 AWST / 19:00 CDT (Monday, 18 August 2025). We recommend participants pre-register 5 to 10 minutes prior to the event with one of the following links: to view the presentation and listen to a live stream of the question and answer session. to participate in the question and answer session. Following pre-registration, participants will receive the teleconference details and a unique passcode. Upcoming events 2025 August 19 Half-Year 2025 results October 22 Third quarter 2025 report 2025 full-year guidance Prior Current Comments Production MMboe 186 - 196 188 - 195 Includes the Greater Angostura assets divestment. Unit production cost $/boe 8.5 - 9.2 8.0 - 8.5 Strong production and cost performance in H1 2025. Property, plant and equipment depreciation and amortisation $ million 4,500 - 5,000 4,700 - 5,000 Exploration expense $ million 200 No change Payments for restoration $ million 700 - 1,000 No change $ million 4,500 - 5,000 4,000 - 4,500 Beaumont New Ammonia Project completion payment is expected in 2026, first ammonia production is planned for late 2025. 2025 half-year line-item guidance Production costs $ million 740 -780 Other income $ million 340 - 420 Includes approximately $160 million non-cash benefit for the Perdaman embedded derivative and approximately $30 million in hedging gains. Restoration movement expense (other expense) $ million 400 - 500 Includes decommissioning cost updates to Stybarrow, Griffin and Minerva. There is no change to the payments for restoration 2025 full-year guidance. Impairment losses $ million ~140 — Impairment loss of approximately $140 million pre-tax (approximately $110 million post-tax) on the H2OK Project, following the decision to exit the project. Excluded from underlying NPAT. Net finance costs $ million 50 - 80 Includes approximately $10 million in hedging gains relating to interest rate swaps. PRRT expense $ million 40 - 100 Income tax expense $ million 280 - 480 490 - 690 2025 half-year statutory income tax includes a deferred tax asset (DTA) of approximately $180 million for the Louisiana LNG Project recognised on FID. The Louisiana LNG DTA and tax impact of the H2OK impairment loss are excluded from underlying NPAT. Woodside's 2025 half-year statutory and underlying effective income tax rate is expected to be higher than 2024 full-year. The presentation of these line-item aligns to the consolidated income statement (page 146) or note A.1 segment revenue and expenses note (pages 157-160) within the 2024 Annual Report. The line-item guidance provided above is indicative and subject to external auditor review process. Production summary Q2 2025 Q1 2025 Q2 2024 YTD 2025 YTD 2024 Gas MMscf/d 1,825 1,841 1,885 1,833 1,907 Liquids Mbbl/d 230 223 157 226 156 Total Mboe/d 550 546 488 548 491 Q2 2025 Q1 2025 Q2 2024 YTD 2025 YTD 2024 AUSTRALIA LNG North West Shelf Mboe 5,375 6,395 7,088 11,770 15,280 Pluto 17 Mboe 11,097 10,430 11,726 21,527 23,480 Wheatstone Mboe 2,424 2,422 1,959 4,846 4,316 Total Mboe 18,896 19,247 20,773 38,143 43,076 Pipeline gas Bass Strait Mboe 3,653 3,192 3,410 6,845 5,769 Other 18 Mboe 3,975 3,807 3,848 7,782 7,126 Total Mboe 7,628 6,999 7,258 14,627 12,895 Crude oil and condensate North West Shelf Mbbl 912 1,106 1,260 2,018 2,672 Pluto 17 Mbbl 899 857 933 1,756 1,864 Wheatstone Mbbl 419 441 380 860 842 Bass Strait Mbbl 457 402 503 859 995 Macedon & Pyrenees Mbbl 558 369 107 927 216 Ngujima-Yin Mbbl 1,084 725 974 1,809 1,860 Okha Mbbl 587 312 491 899 957 Total Mboe 4,916 4,212 4,648 9,128 9,406 NGL North West Shelf Mbbl 207 230 279 437 569 Pluto 17 Mbbl 52 52 59 104 113 Bass Strait Mbbl 753 668 941 1,421 1,773 Total Mboe 1,012 950 1,279 1,962 2,455 Total Australia 19 Mboe 32,452 31,408 33,958 63,860 67,832 Mboe/d 357 349 373 353 373 Q2 2025 Q1 2025 Q2 2024 YTD 2025 YTD 2024 INTERNATIONAL Pipeline gas USA Mboe 409 378 324 787 684 Trinidad & Tobago Mboe 2,205 2,416 1,736 4,621 4,239 Other 20 Mboe 5 23 - 28 - Total Mboe 2,619 2,817 2,060 5,436 4,923 Crude oil and condensate Atlantis Mbbl 2,604 2,472 2,019 5,076 4,460 Mad Dog Mbbl 2,470 2,577 2,944 5,047 5,709 Shenzi Mbbl 2,021 2,322 2,333 4,343 4,738 Trinidad & Tobago Mbbl 93 99 94 192 220 Sangomar Mbbl 7,396 7,010 540 14,406 540 Other 20 Mbbl - - 81 - 162 Total Mboe 14,584 14,480 8,011 29,064 15,829 NGL USA Mbbl 398 398 355 796 748 Other 20 Mbbl 3 12 - 15 - Total Mboe 401 410 355 811 748 Total International Mboe 17,604 17,707 10,426 35,311 21,500 Mboe/d 193 197 115 195 118 Mboe/d 550 546 488 548 491 Product sales Q2 2025 Q1 2025 Q2 2024 YTD 2025 YTD 2024 Gas MMscf/d 2,050 1,962 2,115 2,006 2,032 Liquids Mbbl/d 238 213 159 226 159 Total Mboe/d 598 558 530 578 516 Q2 2025 Q1 2025 Q2 2024 YTD 2025 YTD 2024 AUSTRALIA LNG North West Shelf Mboe 5,059 6,887 7,081 11,946 15,089 Pluto Mboe 11,969 9,676 12,749 21,645 23,262 Wheatstone 21 Mboe 3,346 2,217 2,451 5,563 4,759 Total Mboe 20,374 18,780 22,281 39,154 43,110 Pipeline gas Bass Strait Mboe 3,620 3,299 3,508 6,919 6,078 Other 22 Mboe 3,833 3,584 3,435 7,417 6,329 Total Mboe 7,453 6,883 6,943 14,336 12,407 Crude oil and condensate North West Shelf Mbbl 616 1,229 1,904 1,845 3,118 Pluto Mbbl 650 705 1,283 1,355 1,923 Wheatstone Mbbl 651 334 666 985 995 Bass Strait Mbbl 599 534 271 1,133 868 Ngujima-Yin Mbbl 1,151 663 1,018 1,814 2,017 Okha Mbbl 1,256 - 572 1,256 1,190 Macedon & Pyrenees Mbbl 498 499 - 997 496 Total Mboe 5,421 3,964 5,714 9,385 10,607 NGL North West Shelf Mbbl - 477 266 477 521 Pluto Mbbl - 110 49 110 104 Bass Strait Mbbl 1,010 226 361 1,236 1,146 Total Mboe 1,010 813 676 1,823 1,771 Total Australia Mboe 34,258 30,440 35,614 64,698 67,895 Mboe/d 376 338 391 357 373 Q2 2025 Q1 2025 Q2 2024 YTD 2025 YTD 2024 INTERNATIONAL Pipeline gas USA Mboe 324 294 336 618 622 Trinidad & Tobago Mboe 2,233 2,274 1,606 4,507 4,063 Other 23 Mboe 4 4 5 8 11 Total Mboe 2,561 2,572 1,947 5,133 4,696 Crude oil and condensate Atlantis Mbbl 2,606 2,494 2,013 5,100 4,439 Mad Dog Mbbl 2,485 2,620 3,043 5,105 5,669 Shenzi Mbbl 2,030 2,202 2,430 4,232 4,782 Trinidad & Tobago Mbbl 133 43 19 176 71 Sangomar Mbbl 7,505 6,521 - 14,026 - Other 23 Mbbl 47 57 59 104 119 Total Mboe 14,806 13,937 7,564 28,743 15,080 NGL USA Mbbl 385 371 454 756 867 Other 23 Mbbl 2 2 3 4 6 Total Mboe 387 373 457 760 873 Total International Mboe 17,754 16,882 9,968 34,636 20,649 Mboe/d 195 188 110 191 113 MARKETING 24 LNG Mboe 2,337 2,750 2,593 5,087 4,679 Liquids Mboe 64 104 37 168 608 Total Mboe 2,401 2,854 2,630 5,255 5,287 Total Marketing Mboe 2,401 2,854 2,630 5,255 5,287 Total sales Mboe 54,413 50,176 48,212 104,589 93,831 Mboe/d 598 558 530 578 516 Revenue (US$ million) Q2 2025 Q1 2025 Q2 2024 YTD 2025 YTD 2024 AUSTRALIA North West Shelf 295 535 524 830 1,116 Pluto 827 712 891 1,539 1,636 Wheatstone 25 255 199 212 454 411 Bass Strait 283 228 247 511 470 Macedon 52 52 48 104 99 Ngujima-Yin 86 57 91 143 183 Okha 90 - 46 90 96 Pyrenees 39 44 - 83 44 Total Australia 1,927 1,827 2,059 3,754 4,055 INTERNATIONAL Atlantis 181 191 168 372 364 Mad Dog 161 190 249 351 453 Shenzi 138 167 205 305 395 Trinidad & Tobago 26 78 66 38 144 99 Sangomar 510 481 - 991 - Other 27 4 3 5 7 10 Total International 1,072 1,098 665 2,170 1,321 Marketing revenue 28 232 312 265 544 492 Total sales revenue 29 3,231 3,237 2,989 6,468 5,868 Processing revenue 35 74 52 109 113 Shipping and other revenue 9 4 2 13 7 Total revenue 3,275 3,315 3,043 6,590 5,988 Units Q2 2025 Q1 2025 Q2 2024 Units Q2 2025 Q1 2025 Q2 2024 LNG produced $/MMBtu 9.8 10.6 9.6 $/boe 62 67 60 LNG traded 30 $/MMBtu 11.4 13.7 9.1 $/boe 72 86 58 Pipeline gas $/boe 36 36 38 Oil and condensate $/bbl 68 74 83 $/boe 68 74 83 NGL $/bbl 43 47 44 $/boe 43 47 44 Liquids traded 30 $/bbl 68 70 79 $/boe 68 70 79 Average realised price for pipeline gas: Western Australia A$/GJ 6.8 6.9 6.5 East Coast Australia A$/GJ 13.4 14.0 14.3 International $/Mcf 4.7 5.0 3.9 Average realised price $/boe 59 65 62 Dated Brent $/bbl 68 76 85 JCC (lagged three months) $/bbl 79 78 84 WTI $/bbl 64 71 81 JKM $/MMBtu 12.5 14.7 9.6 TTF $/MMBtu 12.2 14.6 9.2 Average realised price decreased 9% from the prior quarter reflecting lower Dated Brent, WTI, JKM and TTF. Q2 2025 Q1 2025 Q2 2024 YTD 2025 YTD 2024 Evaluation capitalised 31 17 12 37 29 54 Property plant & equipment 828 889 1,135 1,717 2,225 Other 32 23 4 60 27 111 Sub Total (excluding Louisiana LNG) 868 905 1,232 1,773 2,390 Louisiana LNG 33 1,754 901 - 2,655 - Cash contribution from Stonepeak 34 (1,870 ) - - (1,870 ) - Total 752 1,806 1,232 2,558 2,390 Q2 2025 Q1 2025 Q2 2024 YTD 2025 YTD 2024 Scarborough 333 322 563 655 1,137 Trion 92 315 137 407 234 Sangomar 10 7 206 17 416 Other 433 261 326 694 603 Sub Total (excluding Louisiana LNG) 868 905 1,232 1,773 2,390 Louisiana LNG 33 1,754 901 - 2,655 - Cash contribution from Stonepeak 34 (1,870 ) - - (1,870 ) - Total 752 1,806 1,232 2,558 2,390 Other expenditure (US$ million) Q2 2025 Q1 2025 Q2 2024 YTD 2025 YTD 2024 Exploration capitalised 31,35 - 5 1 5 22 Exploration and evaluation expensed 36 46 35 46 81 100 Permit amortisation - 3 3 3 6 Total 46 43 50 89 128 Trading costs 178 232 128 410 273 Exploration or appraisal wells drilled No exploration or appraisal wells were drilled in the quarter. Permits and licences Key changes to permit and licence holdings during the quarter ended 30 June 2025 are noted below. Production rates Average daily production rates (100% project) for the quarter ended 30 June 2025: Jun 2025 Mar 2025 AUSTRALIA NWS Project LNG 29.25% 202 235 Production was lower due to planned maintenance. Crude oil and condensate 29.29% 34 40 NGL 29.45% 8 8 Pluto LNG LNG 90.00% 115 104 Production was higher due to increased reliability. Crude oil and condensate 90.00% 10 9 Pluto-KGP Interconnector LNG 100.00% 19 23 Production was lower due to planned maintenance at the Karratha Gas Plant. Crude oil and condensate 100.00% 1 1 NGL 100.00% 1 1 Wheatstone 38 LNG 11.55% 231 224 Production was higher due to increased plant throughput. Crude oil and condensate 14.86% 31 31 Bass Strait Pipeline gas 47.53% 84 76 Production was higher due to increased seasonal demand. Crude oil and condensate 43.88% 11 10 NGL 45.48% 18 16 Australia Oil Ngujima-Yin 60.00% 20 13 Production was higher due to weather events in Q1 2025. Okha 50.00% 13 7 Pyrenees 64.80% 9 6 Other Pipeline gas 39 44 42 Woodside share 40 Production rate (100% project, Mboe/d) Remarks Jun 2025 Mar 2025 INTERNATIONAL Atlantis Crude oil and condensate 38.50% 74 71 Production was higher due to an infill well brought online. NGL 38.50% 6 4 Pipeline gas 38.50% 8 8 Mad Dog Crude oil and condensate 20.86% 130 137 Production was lower due to reservoir decline. NGL 20.86% 4 6 Pipeline gas 20.86% 2 3 Shenzi Crude oil and condensate 64.71% 34 40 Production was lower due to planned maintenance, offset by increased reliability. NGL 64.76% 2 2 Pipeline gas 64.76% 1 1 Trinidad & Tobago Crude oil and condensate 69.26% 41 1 1 Pipeline gas 47.50% 41 51 53 Sangomar Crude oil 80.43% 41 101 99 Disclaimer and important notice Forward looking statements This report contains forward-looking statements with respect to Woodside's business and operations, market conditions, results of operations and financial condition, including for example, but not limited to, outcomes of transactions, statements regarding long-term demand for Woodside's products, potential investment decisions, 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, income, expenses, costs, losses, capital and exploration expenditure and gas hub exposure. 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 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, contingencies 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 and assumptions on which they are based 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, sustainability and environmental risks, climate related transition and physical risks, 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 conflicts in Ukraine and in the Middle East) on economic activity and oil and gas supply and demand, cost estimates, legislative, fiscal and regulatory developments, including but not limited to those related to the imposition of tariffs and other trade restrictions, and the effect of future regulatory or legislative actions on Woodside or the industries in which it operates, including potential changes to tax laws, and 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, divestitures and joint ventures, including difficulties integrating or separating businesses, uncertainty associated with financial projections, restructuring, increased costs and adverse tax consequences, and uncertainties and liabilities associated with acquired and divested properties and businesses. A more detailed summary of the key risks relating to Woodside and its business can be found in the 'Risk' section of Woodside's most recent Annual Report released to the Australian Securities 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 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. 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. 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. 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. Other important information All figures are Woodside share for the quarter ending 30 June 2025, unless otherwise stated. All references to dollars, cents or $ in this report are to US currency, unless otherwise stated. References to 'Woodside' may be references to Woodside Energy Group Ltd and/or its applicable subsidiaries (as the context requires). Refer to the Glossary in the Annual Report 2024 for definitions, including carbon related definitions. 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 LNG 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. Term Definition bbl barrel bcf billion cubic feet of gas boe barrel of oil equivalent GJ gigajoule 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/d million standard cubic feet of gas per day Mtpa million tonnes per annum PJ petajoules scf standard cubic feet of gas TJ terajoule 1 Includes a base purchase price of $206 million plus working capital completion adjustments, based on an effective date of 1 January 2025. 2 Restated to exclude periodic adjustments reflecting the arrangements governing Wheatstone LNG sales of $10 million in Q2 2024 and -$14 million in YTD 2024. These amounts will be included within other income/(expenses) in the Financial Statements. Restatement allows for revenue presented in this quarterly report to reconcile to operating revenue, the IFRS measure presented in Woodside Financial Statements. 3 Q2 2025 includes 0.28 MMboe primarily from feed gas purchased from Pluto non-operating participants processed through the Pluto-KGP Interconnector. 4 Restated to exclude periodic adjustments reflecting the arrangements governing Wheatstone LNG sales of 0.19 MMboe in Q2 2024 and -0.09 MMboe in YTD 2024. Restatement allows for revenue presented in this quarterly report to reconcile to operating revenue, the IFRS measure presented in Woodside Financial Statements. 5 Includes capital additions on property plant and equipment, evaluation capitalised and other corporate spend. Exploration capitalised has been reclassified from capital expenditure to other expenditure. 6 Capital expenditure for Louisiana LNG is presented as a net figure inclusive of cash contributions received from Stonepeak representing their share of the project's capital expenditure to date. Q2 2025 includes a $1,870 million cash contribution. 7 Completion of the transaction is subject to conditions precedent. 8 Includes a base purchase price of $206 million plus working capital completion adjustments, based on an effective date of 1 January 2025. 9 The project has received funding from the Hydrogen Fuelled Transport Project Funding Process as part of the Western Australian Government's Renewable Hydrogen Strategy. 10 Energy supply may include hydrogen, natural gas and/or electricity. 11 Woodside uses this term to describe the characteristic of having lower levels of associated potential greenhouse gas emissions when compared to historical and/or current conventions or analogues, for example relating to an otherwise similar resource, process, production facility, product or service, or activity. When applied to Woodside's strategy, please see the definition of lower-carbon portfolio in Woodside's 2024 Annual Report. 12 Major Project Status is the Australian Government's recognition of a project's national significance through its contribution to strategic priorities, economic growth, employment, or to regional Australia. 13 Targets are for net equity Scope 1 and 2 greenhouse gas emissions relative to a starting base of 6.32 Mt CO 2 -e which is representative of the gross annual average equity Scope 1 and 2 greenhouse gas emissions over 2016-2020 and which may be adjusted (up or down) for potential equity changes in producing or sanctioned assets with a final investment decision prior to 2021. Net equity emissions include the utilisation of carbon credits as offsets. 14 This means net equity for the 12-month period ending 31 December 2025 are targeted to be 15% lower than the starting base. 15 Gas hub indices include Japan Korea Marker (JKM), TTF and National Balancing Point (NBP). It excludes Henry Hub. 16 Capital expenditure includes the following participating interests; Scarborough (74.9%), Pluto Train 2 (51%) and Trion (60%). It excludes the remaining Beaumont New Ammonia acquisition expenditure and Louisiana LNG expenditure. This guidance assumes no change to these participating interests in 2025. This excludes the impact of any subsequent asset sell-downs, future acquisitions or other changes in equity. 17 Q2 2025 includes 1.69 MMboe of LNG, 0.09 MMboe of condensate and 0.05 MMboe of NGL processed at the Karratha Gas Plant (KGP) through the Pluto-KGP Interconnector. 18 Includes the aggregate Woodside equity domestic gas production from all Western Australian projects. 19 Q2 2025 includes 0.28 MMboe primarily from feed gas purchased from Pluto non-operating participants processed through the Pluto-KGP Interconnector. 20 Overriding royalty interests held in the USA for several producing wells. 21 Restated to exclude periodic adjustments reflecting the arrangements governing Wheatstone LNG sales of 0.19 MMboe in Q2 2024 and -0.09 MMboe in YTD 2024. Restatement allows for revenue presented in this quarterly report to reconcile to operating revenue, the IFRS measure presented in Woodside Financial Statements. 22 Includes the aggregate Woodside equity domestic gas production from all Western Australian projects. 23 Overriding royalty interests held in the USA for several producing wells. 24 Purchased volumes sourced from third parties. 25 Restated to exclude periodic adjustments reflecting the arrangements governing Wheatstone LNG sales of $10 million in Q2 2024 and -$14 million in YTD 2024. These amounts will be included within other income/(expenses) in the financial statements. Restatement allows for revenue presented in this quarterly report to reconcile to operating revenue, the IFRS measure presented in Woodside Financial Statements. 26 Includes the impact of periodic adjustments related to the production sharing contract (PSC). 27 Overriding royalty interests held in the USA for several producing wells. 28 Values include revenue generated from purchased LNG and Liquids volumes, as well as the marketing margin on the sale of Woodside's produced LNG and Liquids portfolio. Marketing revenue excludes hedging impacts and cargo swaps where a Woodside produced cargo is sold and repurchased from the same counterparty to optimise the portfolio. The margin for these cargo swaps is recognised net in other income. 29 Referred to as 'Revenue from sale of hydrocarbons' in Woodside financial statements. Total sales revenue excludes all hedging impacts. 30 Excludes any additional benefit attributed to produced volumes through third-party trading activities. 31 Project final investment decisions result in amounts of previously capitalised exploration and evaluation expense (from current and prior years) being transferred to property plant & equipment. This table does not reflect the impact of such transfers. 32 Other primarily incorporates corporate spend including SAP build costs, other investments and other capital expenditure. 33 Capital expenditure for Louisiana LNG is presented at 100% working interest equity. 34 Cash contributions received from Stonepeak represent their share of the project's capital expenditure since the effective date of 1 January 2025. 35 Exploration capitalised has been reclassified from capital expenditure to other expenditure. Exploration capitalised represents expenditure on successful and pending wells, plus permit acquisition costs during the period and is net of well costs reclassified to expense on finalisation of well results. 36 Includes seismic and general permit activities and other exploration costs. 37 Woodside share reflects the net realised interest for the period. 38 The Wheatstone asset processes gas from several offshore gas fields, including the Julimar and Brunello fields, for which Woodside has a 65% participating interest and is the operator. 39 Includes the aggregate Woodside equity domestic gas production from all Western Australian projects. 40 Woodside share reflects the net realised interest for the period. 41 Operations governed by production sharing contracts.
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