Woodside Energy Third Quarter Report for Period Ended 30 September 2026

Woodside Energy Group (ASX: WDS) (NYSE: WDS):

2026 full-year guidance		Prior	Current	Comment
Total production volumes1	MMboe	174—185	174—181	Beaumont New Ammonia volumes revised to 1.5-2.5 MMboe Narrowing of window for Scarborough first LNG cargo Reduced production at Okha FPSO Completion of start-up and performance testing of Julimar Development Phase 3 in September
Gas hub exposure2	%	~30	No change
Capital expenditure3	$ million	4,000—4,500	No change
Abandonment expenditure	$ million	500—800	No change
Exploration expenditure	$ million	~200	No change
Production costs	$ million	1,500—1,800	No change
Feed gas, services and processing costs	$ million	500—600	No change
Property, plant and equipment depreciation and amortisation	$ million	4,200—4,700	No change

Woodside CEO Liz Westcott said the strong third quarter performance reflected the company’s highly reliable operations and disciplined execution of major growth projects.

“Amid ongoing volatility in global energy markets, we have remained a reliable supplier to our customers. Increased quarterly operating revenue reflected increased production and strong realised prices.

“We delivered quarterly production of 46.2 million barrels of oil equivalent, up 12% from the previous quarter following the successful completion of the Pluto LNG turnaround in the second quarter and the NWS turnaround in the third quarter.

“We maintained outstanding reliability across our global portfolio, with reliability of 99.8% at Pluto LNG and 99.3% at the NWS Project in Australia, and 99.2% at Sangomar in Senegal.

“We recorded three process safety events during the quarter. Safety remains our highest priority and we are focused on applying the lessons learned from these incidents and strengthening our controls in this vitally important area.

“We continued executing our major growth projects to budget and schedule. The Scarborough Energy Project is now 99% complete, with gas from the Scarborough reservoir introduced into the FPU and exported into the trunkline during the quarter. We remain on track for first LNG cargo this year.

“The Trion Project is now 71% complete and targeting first oil in 2028. Fabrication of the FPU is well advanced, with integration and pre-commissioning activities underway.

“Louisiana LNG is targeting first LNG in 2029, with construction progressing across all three trains and the project 32% complete.

“We continued to optimise our portfolio through the ongoing integration of the Gippsland Basin assets and divestment of our operated interest in the Calypso Project. Following completion of the Beaumont New Ammonia strategic review, we will now initiate a formal process to reduce our investment and achieve value for our shareholders. These actions demonstrate our disciplined approach to portfolio management and capital allocation, with a clear focus on investments that deliver long-term shareholder value.

“We remain committed to supplying Australia’s domestic gas market and are assessing our plans for four proposed development wells in the Bass Strait. Development will depend on technical assessments and the implications of the Federal Government’s domestic gas reservation scheme.”

Comparative performance at a glance

		Q3 2026	Q2 2026	Change %	Q3 2025	Change %	YTD 2026	YTD 2025	Change %
Operating revenue	$ million	4,281	4,185	2%	3,359	27%	11,727	9,949	18%
Production volumes4	MMboe	46.2	41.3	12%	50.8	(9%)	132.7	149.9	(11%)
Gas	MMscf/d	1,697	1,326	28%	1,827	(7%)	1,534	1,831	(16%)
Liquids	Mbbl/d	202	214	(6%)	231	(13%)	212	228	(7%)
Ammonia	kT/d	0.8	1.8	(56%)	—	—%	1.3	—	—%
Total	Mboe/d	503	454	11%	552	(9%)	486	549	(11%)
Sales volumes5	MMboe	51.1	48.0	6%	55.1	(7%)	150.9	159.9	(6%)
Gas	MMscf/d	2,043	1,672	22%	2,122	(4%)	1,910	2,049	(7%)
Liquids	Mbbl/d	193	227	(15%)	226	(15%)	213	226	(6%)
Ammonia	kT/d	1.0	2.1	(52%)	—	—%	1.3	—	—%
Total	Mboe/d	555	528	5%	599	(7%)	553	586	(6%)
Average realised price	$/boe	84	85	(1%)	60	40%	77	61	26%
Capital expenditure and acquisitions	$ million	722	784	(8%)	1,323	(45%)	2,829	3,881	(27%)
Capital expenditure6	$ million	722	784	(8%)	1,323	(45%)	2,359	3,881	(39%)
Acquisitions	$ million	—	—	—%	—	—%	470	—	—%

Operations

Pluto LNG

• Achieved quarterly LNG reliability of 99.8%.

• Preparation for the subsea tie-in and commissioning of the XNA-03 infill well continued ahead of targeted start-up in Q4 2026.

North West Shelf Project

• Achieved quarterly LNG reliability of 99.3%.

• Completed single LNG train planned turnaround campaign in September 2026 on budget and schedule.

• Hearings on three legal proceedings in the Federal Court of Australia associated with the NWS Project Extension Commonwealth environmental approvals were held in July 2026, with the decisions reserved. A separate proceeding concerning the State environmental approval remains before the Supreme Court of Western Australia, with a hearing scheduled for Q4 2026.

• The NWS Project is continuing with infrastructure retirement planning at Karratha Gas Plant (KGP) while maintaining the capacity to provide processing services for third-party gas. Planning is underway to retire a second LNG train in 2027 subject to relevant approvals.

Wheatstone and Julimar-Brunello

• Progressed towards asset swap transaction completion, including the satisfaction of certain conditions precedent relating to the following:
  • Completion of the Julimar Development Phase 3 project, with start-up and performance testing of the final development wells completed in September 2026.

  • Completion of decommissioning of three Julimar-Brunello exploration wells, and wellhead severance of a further two previously-abandoned exploration wells.

• Subject to the receipt of all regulatory approvals, the asset swap transaction continues to target completion in Q4 2026.⁷

Bass Strait

• Achieved quarterly reliability of 91%.

• Achieved completion of the five Turrum Phase 3 Project development wells with first production targeting H1 2027.

• Progressed integration of the Gippsland Basin assets into Woodside’s operated portfolio following transfer of operatorship from ExxonMobil on 1 July 2026.

Other Australia

• Following remediation of a subsea mooring system defect and successful FPSO reconnection, production resumed at Okha, with ongoing well assessment supporting further production restoration.

• Subsequent to the period, the Pyrenees floating production storage and offloading (FPSO) disconnected ahead of scheduled shipyard activity in Q4 2026.

Sangomar

• Achieved an average daily production rate of 94 Mbbl/d (100% basis, 73 Mbbl/d Woodside share) with reliability of 99.2%.

• Production rate reflects natural field decline and reduced production sharing contract (PSC) net entitlement following recovery of 100% Woodside-funded pre-FID costs.

Gulf of America

• Achieved quarterly reliability of 94.3% at Shenzi.

• Executed a planned shutdown at Shenzi in July 2026 and a three-well intervention campaign in August 2026.

• Atlantis achieved start-up of the Major Facility Expansion (MFX) project, bringing the first of two water injectors online. The project added subsea infrastructure, wells and upgraded water injection equipment.

Beaumont New Ammonia

• BNA suspended operations for approximately 30 days following a Tier 1 process safety event. There were no injuries to personnel or damage to equipment and no lasting impact to the environment. The facility was safely restarted following completion of an internal investigation and implementation of appropriate actions.

• Production during the quarter was constrained to 69% of nameplate capacity due to third-party feedstock availability and the 30 day shut down. Third-party cargoes were sourced to satisfy customer commitments on similar financial terms.

• Commencement of lower-carbon ammonia production remains targeted for 2027, subject to commissioning of Linde’s low-carbon hydrogen facilities and start-up of ExxonMobil’s carbon capture and storage (CCS) infrastructure. During the quarter, the Texas Railroad Commission voted to approve the permit for ExxonMobil’s Rose carbon storage project, moving it into the final stages of a multi-year regulatory process.

• Completed the strategic review of BNA. In light of the evolving pace of lower-carbon ammonia market development, Woodside will initiate a formal process to reduce its investment in BNA investment and achieve value for shareholders.

Marketing

Revenue and trading

• Strong marketing performance reflected the realisation of value from LNG portfolio optimisation undertaken in Q2 2026, with revenue recognised as cargoes were delivered in Q3 2026.

• Average realised LNG prices improved quarter-on-quarter, reflecting the realisation of price lags from Q2 2026 and stronger gas hub market pricing in the lead up to northern hemisphere winter months.

• Approximately 33% of LNG sold was linked to gas hub indices during the quarter.

• The impact of crude supply disruptions softened during the quarter as export flows recovered and market balances improved, resulting in lower market prices for crude oil and weaker realised premiums for the liquids portfolio (oil, condensate and liquids traded).

Pipeline gas

• Executed incremental pipeline gas sales of:
  • 12.9 PJ to be delivered to the Western Australian market from 2027 to 2029

  • 18.4 PJ to be delivered to the East Coast market from 2026 to 2028.

• Progressed expression of interest for 20 PJ of Bass Strait supply and finalised a number of 2027 and 2028 offers during the period.

Projects

Scarborough Energy Project

• The Scarborough and Pluto Train 2 projects remain on budget and were 99% complete at the end of the quarter (excluding Pluto Train 1 modifications).

• The FPU and subsea production system commissioning and start-up activities continued, including well clean-up and export of gas to pressurise the trunkline. Well clean-up results are in line with reservoir and well performance expectations.

• Completed all mechanical runs of Pluto Train 2 compressors and, subsequent to the period, Scarborough gas was introduced to the warm end (gas pre-treatment) of the LNG train. Activities in the cold end continue to progress, which will enable the commencement of gas liquefaction.

• Following the Pluto Train 1 planned major maintenance campaign in Q2, modifications to Pluto Train 1 which will allow processing of Scarborough gas continued. The final module arrived onsite with activities focused on module hook-up and integration.

• First LNG cargo is on track for Q4 2026.

Trion

• The Trion Project remains on budget and was 71% complete at the end of the quarter.

• Advanced the drilling campaign, with 10 of 24 wells drilled and the first subsea tree installed.

• Delivered subsea equipment and disconnectable turret mooring (DTM) buoy to Mexico and commenced offshore installation.

• The FPU fabrication reached 96% completion, with integration and pre-commissioning activities underway.

• Progressed floating storage and offloading vessel construction, including completion of DTM turret integration into the hull.

• The project is targeting first oil in 2028.

Louisiana LNG

• The Louisiana LNG Project remains on budget and was 32% complete at the end of the quarter.

• LNG terminal construction advanced across marine, site works and LNG tanks, with LNG Tank 1 wall concrete reaching 50% completion.

• Train 1 was 41% complete at the end of the quarter, with structural steel and above-ground piping installation progressed.

• Trains 2 and 3 were 27% and 22% complete respectively at the end of the quarter, with above-ground piping installation commenced for Train 2 and first concrete foundation poured for Train 3.

• Structural steel supply challenges associated with ongoing disruptions in the Middle East continue to be mitigated through alternative logistics routes and fabrication sources.

• Ongoing engagement with high-quality counterparties for equity participation and LNG offtake continues.

• The project is targeting first LNG in 2029.

Hydrogen Refueller @H2Perth

• Ready for start-up was achieved and commissioning activities continued onsite with first hydrogen production targeting Q4 2026.⁸

Decommissioning

• Completed the plug and abandonment (P&A) of five wells in the Julimar-Brunello and NWS gas fields.

• Commenced offshore wellhead severance across the NWS gas, NWS oil and Julimar-Brunello fields, with nine wellheads removed.

• Continued progress across the Gippsland Basin Joint Venture wells P&A campaign, including conductor recovery activities at the Cobia field, completion of preparatory work for the Snapper campaign and commencement of the Barracouta A P&A campaign.

• Progressed execution readiness for the offshore Echo Yodel pipeline removal campaign.

• Submitted and secured NOPSEMA acceptance of Enfield decommissioning project close-out documentation.

Development and exploration

Browse

• The Browse to North West Shelf Project continues to advance technical definition, regulatory approvals and commercial agreements as part of pre-front end engineering design activities.

• Continued engagement with regulators to progress environmental approvals. Following submission of the revised Environmental Protection and Biodiversity Conservation Act 1999 referral, the Commonwealth regulator has determined that the Browse Carbon Capture and Storage (CCS) Project will be assessed by Environmental Impact Statement.

• Progressed market engagement for the design and construction of the FPSO facilities and engineering studies of downstream modifications required for processing Browse gas at Karratha Gas Plant.

Sunrise

• The Sunrise Joint Venture reached alignment with the Governments of Timor-Leste and Australia on the key principles underpinning a new Greater Sunrise PSC and associated fiscal framework.

• The terms of the existing PSCs (JPDA PSC 03-19 and JPDA PSC 03-20) were extended to 31 March 2027 to facilitate implementation of the new PSC arrangements.

Calypso

• On 6 August 2026, Woodside entered an agreement to sell its 70% operated interest in the Calypso Project to bp.⁹

• All key conditions precedent have now been met, with completion of the transaction targeting Q4 2026.

Exploration

• The Nasim-1X well, operated by ENI, was spud on the Tiba license in Egypt in August 2026 and drilling activities are ongoing. Woodside holds a 40% non-operated interest.

• Woodside was awarded one lease in the US Gulf of America where Woodside was the successful bidder from the Big Beautiful Gulf 3 Lease Sale held in August 2026.

• Entered a non-binding memorandum of understanding with Petrόleos Mexicanos (PEMEX) to evaluate deepwater opportunities in the Gulf of Mexico.

Corporate activities

Cost reduction

• Woodside continued to progress the cost reduction program during the quarter, focused on improving efficiency and productivity.

• Initiatives underway include simplifying organisational structures, improving maintenance and contracting processes, and expanding the use of automation and AI.

• The program is targeting to deliver a US$350 million structurally lower recurring cost base against the 2025 baseline from 2028.

Climate and sustainability

• Three process safety events were recorded during the quarter.
  • A Tier 1 event at BNA (refer to the BNA section for details).

  • Two Tier 2 events involving:
    • a marine diesel oil release during flushing operations at Okha, which had no environmental impact as the release was contained.

    • a methane release from pipework during turnaround activities at KGP.

• The Sam Houston Jones State Park Project, a voluntary environmental and biodiversity restoration initiative located 15 miles from LALNG, has progressed, with approximately 50% of site preparation completed ahead of seedling planting.

Hedging

• As at 30 September 2026, approximately 87% of the 30 MMboe of 2026 oil-linked production previously hedged (at an average price of $74.23 per barrel) had been cash settled. No additional oil-linked corporate hedges were entered during the quarter and the 2027 hedge position of 10 MMboe remains unchanged.

• Continued to utilise Henry Hub and TTF commodity swaps in connection with overall management of Corpus Christi LNG volumes.

• For 2026 year to date, hedge settlements resulted in a net cash outflow of approximately $565 million, and a reduction to pre-tax profit of $519 million. Cash settlements on oil-linked hedges occur in advance of the related profit and loss impact, resulting in temporary differences.

Embedded commodity derivative

• In 2023, Woodside entered 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.

• 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 2026 year to date, an unrealised pre-tax loss of approximately $179 million is expected to be recognised through other expense.

Funding and liquidity

• During the quarter Woodside paid a fully franked dividend of $1,084 million and an $800 million bond maturity in September.

• As at 30 September 2026, Woodside had liquidity of approximately $7,800 million and net debt (including lease liabilities) of approximately $8,900 million.

Capital Markets Day

• Woodside’s 2026 Capital Markets Day will be held on Thursday, 5 November 2026, commencing at 10:00 am AEDT/7:00 am AWST/5:00 pm CST (Wednesday, 4 November 2026).

• A live webcast of the Australian event will be available on Woodside’s website at https://meetings.lumiconnect.com/300-191-159-742.

• This will be followed by a US Capital Markets Day on 12 November 2026 in New York.

Upcoming events 2026-2027

November	5	2026 Capital Markets Day (Australia)
	12	2026 Capital Markets Day (United States)
January	28	Fourth Quarter Report
February	23	2026 Annual Report
April	21	First Quarter Report

Production volumes

		Q3 2026	Q2 2026	Q3 2025	YTD 2026	YTD 2025
Gas	MMscf/d	1,697	1,326	1,827	1,534	1,831
Liquids	Mbbl/d	202	214	231	212	228
Ammonia	kT/d	0.8	1.8	–	1.3	–
Total production volumes	Mboe/d	503	454	552	486	549

Production (reserves)

		Q3 2026	Q2 2026	Q3 2025	YTD 2026	YTD 2025
AUSTRALIA
LNG
North West Shelf	Mboe	5,646	5,491	5,895	16,815	17,665
Pluto10	Mboe	12,516	7,701	12,118	31,208	33,272
Wheatstone	Mboe	1,338	1,454	2,677	5,078	7,523
Total	Mboe	19,500	14,646	20,690	53,101	58,460
Pipeline gas
Bass Strait	Mboe	4,416	3,440	3,929	10,612	10,774
Other10,11	Mboe	2,862	2,510	3,830	7,880	11,450
Total	Mboe	7,278	5,950	7,759	18,492	22,224
Crude oil and condensate
North West Shelf	Mbbl	1,054	949	1,093	2,956	3,111
Pluto10	Mbbl	889	602	980	2,336	2,717
Wheatstone	Mbbl	239	271	471	937	1,331
Bass Strait	Mbbl	552	477	505	1,371	1,364
Macedon & Pyrenees	Mbbl	263	169	347	793	1,274
Ngujima-Yin	Mbbl	659	684	960	1,996	2,769
Okha	Mbbl	7	–	575	318	1,474
Total	Mboe	3,663	3,152	4,931	10,707	14,040
NGL
North West Shelf	Mbbl	216	191	258	588	695
Pluto10	Mbbl	45	28	58	112	152
Bass Strait	Mbbl	772	761	842	2,163	2,263
Total	Mboe	1,033	980	1,158	2,863	3,110
Total Australia	Mboe	31,474	24,728	34,538	85,163	97,834
	Mboe/d	342	272	375	312	358

		Q3 2026	Q2 2026	Q3 2025	YTD 2026	YTD 2025
INTERNATIONAL
Pipeline gas
USA	Mboe	358	405	491	1,209	1,278
Trinidad & Tobago	Mboe	–	–	242	–	4,863
Other12	Mboe	–	–	6	9	34
Total	Mboe	358	405	739	1,218	6,175
Crude oil and condensate
Atlantis	Mbbl	2,424	2,526	2,783	7,671	7,859
Mad Dog	Mbbl	2,710	2,704	2,310	8,172	7,357
Shenzi	Mbbl	1,667	1,859	2,088	5,422	6,431
Trinidad & Tobago	Mbbl	–	–	13	–	205
Sangomar	Mbbl	6,758	7,854	7,516	21,764	21,922
Other12	Mbbl	35	35	5	124	5
Total	Mboe	13,594	14,978	14,715	43,153	43,779
NGL
USA	Mbbl	276	370	442	1,159	1,238
Other12	Mbbl	–	–	3	5	18
Total	Mboe	276	370	445	1,164	1,256
Total International	Mboe	14,228	15,753	15,899	45,535	51,210
	Mboe/d	155	173	173	167	188
Total production (reserves) volumes	Mboe	45,702	40,481	50,437	130,698	149,044
	Mboe/d	497	445	548	479	546

Production (processing)

		Q3 2026	Q2 2026	Q3 2025	YTD 2026	YTD 2025
AUSTRALIA
Pluto-KGP Interconnector13
LNG	Mboe	254	171	210	667	583
Pipeline gas	Mboe	–	–	91	–	253
Crude oil and condensate	Mbbl	8	6	9	23	28
NGL	Mbbl	5	3	7	12	17
Total Australia	Mboe	267	180	317	702	881
	Mboe/d	3	2	3	3	3
INTERNATIONAL
Beaumont New Ammonia14	Mboe	266	609	–	1,292	–
Total International	Mboe	266	609	–	1,292	–
	Mboe/d	3	7	–	5	–
Total production (processing) volumes	Mboe	533	789	317	1,994	881
	Mboe/d	6	9	3	7	3
Total production volumes	Mboe	46,235	41,270	50,754	132,692	149,925
	Mboe/d	503	454	552	486	549

Sales volumes

		Q3 2026	Q2 2026	Q3 2025	YTD 2026	YTD 2025
Gas	MMscf/d	2,043	1,672	2,122	1,910	2,049
Liquids	Mbbl/d	193	227	226	213	226
Ammonia	kT/d	1.0	2.1	–	1.3	–
Total sales volumes	Mboe/d	555	528	599	553	586

		Q3 2026	Q2 2026	Q3 2025	YTD 2026	YTD 2025
AUSTRALIA
LNG
North West Shelf	Mboe	5,630	3,922	4,743	17,016	16,689
Pluto	Mboe	13,146	9,011	13,609	34,062	35,254
Wheatstone	Mboe	1,967	1,995	1,623	6,578	7,186
Total	Mboe	20,743	14,928	19,975	57,656	59,129
Pipeline gas
Bass Strait	Mboe	4,277	3,736	4,070	10,579	10,989
Other15	Mboe	3,152	2,756	4,028	8,406	11,445
Total	Mboe	7,429	6,492	8,098	18,985	22,434
Crude oil and condensate
North West Shelf	Mbbl	651	1,300	1,194	2,633	3,039
Pluto	Mbbl	775	1,011	1,338	2,978	2,693
Wheatstone	Mbbl	92	427	417	787	1,402
Bass Strait	Mbbl	593	619	531	1,740	1,664
Ngujima-Yin	Mbbl	690	963	1,171	2,322	2,985
Okha	Mbbl	–	–	–	251	1,256
Macedon & Pyrenees	Mbbl	–	511	496	512	1,493
Total	Mboe	2,801	4,831	5,147	11,223	14,532
NGL
North West Shelf	Mbbl	–	473	430	473	907
Pluto	Mbbl	–	93	105	93	215
Bass Strait	Mbbl	874	437	374	2,177	1,610
Total	Mboe	874	1,003	909	2,743	2,732
Total Australia	Mboe	31,847	27,254	34,129	90,607	98,827
	Mboe/d	346	299	371	332	362

		Q3 2026	Q2 2026	Q3 2025	YTD 2026	YTD 2025
INTERNATIONAL
Pipeline gas
USA16	Mboe	361	413	438	1,160	1,246
Trinidad & Tobago	Mboe	–	–	243	–	4,750
Other17	Mboe	45	3	4	51	12
Total	Mboe	406	416	685	1,211	6,008
Crude oil and condensate
Atlantis	Mbbl	2,400	2,544	2,801	7,672	7,901
Mad Dog	Mbbl	2,605	2,780	2,310	8,118	7,415
Shenzi	Mbbl	1,415	1,870	2,094	5,179	6,326
Trinidad & Tobago	Mbbl	–	–	5	–	181
Sangomar	Mbbl	6,932	6,865	6,833	20,619	20,859
Other17	Mbbl	130	67	47	286	151
Total	Mboe	13,482	14,126	14,090	41,874	42,833
NGL
USA	Mbbl	254	389	440	1,165	1,196
Other17	Mbbl	29	1	2	32	6
Total	Mboe	283	390	442	1,197	1,202
Ammonia
Beaumont New Ammonia18	Mboe	346	702	–	1,297	–
Total	Mboe	346	702	–	1,297	–
Total International	Mboe	14,517	15,634	15,217	45,579	50,043
	Mboe/d	158	172	165	167	183
MARKETING19
LNG	Mboe	4,389	4,856	5,492	13,645	10,579
Liquids	Mboe	341	298	249	1,023	417
Total	Mboe	4,730	5,154	5,741	14,668	10,996
Total Marketing	Mboe	4,730	5,154	5,741	14,668	10,996
Total sales volumes	Mboe	51,094	48,042	55,087	150,854	159,866
	Mboe/d	555	528	599	553	586

Operating revenue (US$ million)

	Q3 2026	Q2 2026	Q3 2025	YTD 2026	YTD 2025
AUSTRALIA
North West Shelf	479	378	323	1,305	1,153
Pluto	1,121	795	1,000	2,682	2,539
Wheatstone	189	167	135	536	589
Bass Strait	380	352	265	964	776
Macedon	56	57	44	169	148
Ngujima-Yin	73	102	88	223	231
Okha	–	2	–	27	90
Pyrenees	–	45	37	45	120
Revenue from sale of products	2,298	1,898	1,892	5,951	5,646
Intersegment revenue	(53)	(51)	(67)	(154)	(76)
Processing and services revenue	34	35	39	122	148
Total Australia	2,279	1,882	1,864	5,919	5,718
INTERNATIONAL
Atlantis	215	258	196	672	568
Mad Dog	227	272	150	689	501
Shenzi	120	192	142	450	447
Trinidad & Tobago20	–	–	6	–	150
Sangomar	659	763	477	1,946	1,468
Other21	44	145	2	231	9
Revenue from sale of products	1,265	1,630	973	3,988	3,143
Total International	1,265	1,630	973	3,988	3,143
MARKETING
Revenue from sale of products	672	620	452	1,652	996
Intersegment revenue	53	51	67	154	76
Shipping and other revenue	12	2	3	14	16
Total Marketing22	737	673	522	1,820	1,088
Operating revenue23	4,281	4,185	3,359	11,727	9,949

Realised prices

	Units	Q3 2026	Q2 2026	Q3 2025	Units	Q3 2026	Q2 2026	Q3 2025
LNG produced	$/MMBtu	13.3	10.5	9.5	$/boe	84	66	60
LNG traded24	$/MMBtu	16.6	15.2	11.2	$/boe	108	99	71
Pipeline gas:
Western Australia	A$/GJ	6.9	6.9	6.8
East Coast Australia	A$/GJ	15.3	15.7	12.9
International25	$/Mcf	2.6	3.0	3.6
Pipeline gas					$/boe	49	50	38
Oil and condensate	$/bbl	93	107	68	$/boe	93	107	68
NGL	$/bbl	52	57	41	$/boe	52	57	41
Liquids traded24	$/bbl	71	110	60	$/boe	71	110	60
Average realised price	$/boe	84	85	60
Dated Brent	$/bbl	97	105	69
JCC (lagged three months)	$/bbl	111	67	75
WTI	$/bbl	86	93	65
JKM	$/MMBtu	18.9	17.5	12.5
TTF	$/MMBtu	18.0	16.4	11.7

Capital expenditure (US$ million)

	Q3 2026	Q2 2026	Q3 2025	YTD 2026	YTD 2025
Evaluation capitalised26	12	15	8	36	37
Property plant & equipment	1,738	1,557	1,530	4,981	5,902
Cash contributions from participants	(1,029)	(878)	(222)	(2,754)	(2,092)
Other27	1	90	7	96	34
Capital expenditure	722	784	1,323	2,359	3,881
Acquisitions	–	–	–	470	–
Total capital expenditure and acquisitions	722	784	1,323	2,829	3,881

	Q3 2026	Q2 2026	Q3 2025	YTD 2026	YTD 2025
Scarborough	186	290	361	751	1,016
Trion	267	275	291	713	698
Louisiana LNG capital expenditure	967	723	498	2,562	3,153
Cash contributions from participants	(1,029)	(878)	(222)	(2,754)	(2,092)
Louisiana LNG other27	7	26	–	38	–
Louisiana LNG28	(55)	(129)	276	(154)	1,061
Other	324	348	395	1,049	1,106
Capital expenditure	722	784	1,323	2,359	3,881

Other expenditure (US$ million)

Exploration and evaluation expenditure	Q3 2026	Q2 2026	Q3 2025	YTD 2026	YTD 2025
Exploration capitalised26,29	3	2	17	45	22
Exploration and evaluation expensed30	63	50	46	163	127
Permit amortisation	2	2	2	6	5
Total	68	54	65	214	154
Trading costs	Q3 2026	Q2 2026	Q3 2025	YTD 2026	YTD 2025
Australia	83	52	71	184	159
International	14	–	–	14	–
Marketing	407	533	374	1,278	696
Total	504	585	445	1,476	855
Abandonment expenditure	Q3 2026	Q2 2026	Q3 2025	YTD 2026	YTD 2025
Total	172	139	141	427	658

Exploration or appraisal wells drilled

Region	Permit area	Well	Target	Interest (%)	Spud date	Water depth (m)	Actual well depth (m)31	Remarks
Egypt	Tiba	Nasim-1X	Gas	40% Non-operator	25 August 2026	-1	2,650	Drilling, onshore

Permits and licences

Key changes to permit and licence holdings during the quarter ended 30 September 2026 are noted below.

Region	Permits or licence areas	Change in interest (%)	Current interest (%)	Remarks
United States	AC 125, AC 126	(45%)	—%	Assigned
	GB 721, GC 598, AC 36, AC 80, AC 81	(100%)	—%	Relinquished
	EB 682	100%	100%	Awarded

Production rates

Average daily production rates (100% project) for the quarter ended 30 September 2026:

	Woodside share32	Production rate (100% project, Mboe/d)		Remarks
		Q3 2026	Q2 2026
AUSTRALIA
NWS Project
LNG	29.17%	210	203	Increased production driven by reliability and wells returned to service.
Crude oil and condensate	29.26%	39	35
NGL	29.36%	8	7
Pluto LNG
LNG	90.00%	124	75	Production higher following planned maintenance turnaround in Q2.
Crude oil and condensate	90.00%	10	7
Pluto-KGP Interconnector
LNG	100.00%	28	19	Production higher due to major turnaround in Q2 which impacted feed gas.
Crude oil and condensate	100.00%	1	1
NGL	100.00%	1	–
Wheatstone33
LNG	6.00%	243	204	Julimar Brunello production lower due to impact of offshore project activities.
Crude oil and condensate	8.12%	32	28
Bass Strait
Pipeline gas	48.95%	98	83	Production higher due to seasonal increases in demand.
Crude oil and condensate	43.61%	14	12
NGL	44.96%	19	18
Australia Oil
Ngujima-Yin	60.00%	12	13	Okha reconnected late in Q3.
Okha	50.00%	–	–
Pyrenees	71.43%	4	3
Other
Pipeline gas34		31	28

	Woodside share35	Production rate (100% project, Mboe/d)		Remarks
		Q3 2026	Q2 2026
INTERNATIONAL
Atlantis
Crude oil and condensate	38.50%	68	72	Production lower due to higher planned and unplanned events.
NGL	38.50%	3	5
Pipeline gas	38.50%	7	8
Mad Dog
Crude oil and condensate	20.86%	141	142
NGL	20.86%	5	5
Pipeline gas	20.86%	4	3
Shenzi
Crude oil and condensate	64.55%	28	32	Production lower because of planned shutdown and well interventions.
NGL	64.65%	1	2
Pipeline gas	64.64%	1	1
Sangomar
Crude oil	78.01%36	94	99	Production lower due to natural field decline.
Beaumont New Ammonia
Ammonia37	100.00%	3	7	Production lower due to unplanned event.

Disclaimer and important notice

Forward looking statements

This report contains forward-looking statements. These statements may relate to Woodside’s business, goals, targets, aspirations, plans, expectations, market conditions, results of operations and financial condition, including but not limited to, statements regarding the timing, completion and outcomes of transactions, construction costs and capital expenditures, supply and demand for Woodside’s products, development, completion and execution of Woodside’s projects, the expected benefits, cash flows and rates of return or other future results of investments, strategies and transactions, 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, production costs and other costs, capital expenditure, abandonment expenditure, exploration expenditure and gas hub exposure, trends in commodity prices and currency exchange rates, adoption and implementation of new technologies and expectations regarding the achievement of Woodside’s Scope 1 and 2 greenhouse gas emissions target (in each case on a net equity or gross equity basis as specified) 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 “aim”, “anticipate”, “aspire”, “believe”, “enable”, “estimate”, “expect”, “forecast”, “foresee”, “guidance”, “intend”, “likely”, “may”, “objective”, “outlook”, “pathway”, “plan”, “position”, “potential”, “project”, “schedule”, “seek”, “should”, “strategy”, “strive”, “target”, “will” and other similar words or expressions.

Forward-looking statements in this report are not guarantees 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 the assumptions on which they are based include, but are not limited to, fluctuations in commodity prices, actual demand for Woodside products, currency fluctuations, geotechnical factors, drilling and production results, gas commercialisation, development progress, operating results, engineering estimates, reserve and resource estimates, loss of market, industry competition, pace of technology developments, sustainability and environmental risks, climate related transition and physical risks, safety and personnel risks, changes in accounting standards, economic and financial markets conditions in various countries and regions, the actions of third parties, project delay or advancement, regulatory approvals, political risks and 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 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, 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 factors” 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 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 that forward-looking statements are subject to significant uncertainties and may not prove to be correct. 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, neither Woodside, 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 intends to, undertakes to, or assumes any obligation to, provide any additional information or update or revise any of these statements after the date of this report, either to make them conform to actual results or as a result of new information, future events or results, changes in Woodside’s expectations or otherwise. Past performance (including historical financial and operational information) is given for illustrative purposes only. It is not necessarily a reliable indicator of future performance, including future security prices.

Other important information

Unless otherwise stated, all:

• figures are Woodside share for the quarter ending 30 September 2026;

• references to dollars, cents or $ in this report are to US currency; and

• references to ‘Woodside’, ‘the company’, ‘the Group’, ‘we’, ‘us’ and ‘our’ refer to Woodside Energy Group Ltd and its controlled entities as a whole.

Glossary, units of measure and conversion factors

Refer to the Glossary in the Half-Year Report 2026 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
Ammonia	1 metric tonne	3.68 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
kT	thousand metric tonnes
kT/d	thousand metric tonnes per day
NGL	natural gas liquid
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	petajoule
scf	standard cubic feet of gas
TJ	terajoule

¹ Total production volumes includes 1.5—2.5 MMboe from Beaumont New Ammonia (prior guidance included 2—3 MMboe).

² Gas hub indices include Japan Korea Marker (JKM), Title Transfer Facility (TTF) and National Balancing Point. It excludes Henry Hub. Presented on a 3-year average for 2026—2028. Includes binding sales and purchases agreements only, Woodside’s equity share of Scarborough and Pluto LNG, Corpus Christi offtake volumes and assumes the Chevron asset swap is completed.

³ Capital expenditure is reported on the basis of Woodside’s net ownership interests for each project as at 30 September 2026. Louisiana LNG (90% Louisiana LNG LLC, 60% Louisiana LNG Infrastructure LLC and 20% Driftwood Pipeline LLC) capital expenditure adjusted for the cash contributions from Stonepeak Wallaby I Acquiror LP (Stonepeak) and Williams Louisiana LNG LLC (Williams). Scarborough (74.9% participating interest) and Pluto Train 2 (51% participating interest). Trion (60% participating interest). Excludes the final acquisition completion payment for Beaumont New Ammonia of $470 million. Completion of the asset swap with Chevron assumed to occur in Q4 2026.

⁴ Percent change in total production may differ from percent change in daily production due to the number of days in each quarter.

⁵ Restated additional volumes of 0.09 MMboe in Q3 2025 and 0.28 MMboe in YTD 2025 to reflect a revised MMBtu to boe conversion factor.

⁶ Louisiana LNG YTD 2026 project spend includes $185 million of prepayments recognised in investing cash flow that are recoverable through partner cash calls but are not yet recognised as capital expenditure.

⁷ Completion of the transaction is subject to the remaining conditions precedent. See “Woodside simplifies portfolio and unlocks long-term value” announced on 19 December 2024.

⁸ The project has received funding from the Hydrogen Fuelled Transport Project Funding Process as part of the Western Australian Government’s Renewable Hydrogen Strategy.

⁹ Completion of the transaction is subject to the remaining conditions precedent. See “Woodside rationalises global portfolio with Calypso divestment”.

¹⁰ Feed gas volumes purchased from Pluto non-operating participants processed through the Pluto-KGP Interconnector are reported under Production (processing). Comparatives have been restated on the same basis.

¹¹ Includes the aggregate Woodside equity domestic gas production from all Western Australian projects.

¹² Overriding royalty interests held in the USA for several producing wells.

¹³ Feed gas volumes purchased from Pluto non-operating participants processed through the Pluto-KGP Interconnector, and represents 10% of Pluto-KGP Interconnector volumes.

¹⁴ Beaumont New Ammonia production volume is 72.4 kT in Q3 2026 and 351.3 kT in YTD 2026.

¹⁵ Includes the aggregate Woodside equity domestic gas production from all Western Australian projects.

¹⁶ Restated additional volumes of 0.09 MMboe in Q3 2025 and 0.28 MMboe in YTD 2025 to reflect a revised MMBtu to boe conversion factor.

¹⁷ Overriding royalty interests held in the USA for several producing wells.

¹⁸ Beaumont New Ammonia sales volumes are 94.2 kT in Q3 2026 and 352.5 kT YTD 2026.

¹⁹ Purchased volumes sourced from third parties.

²⁰ Includes the impact of periodic adjustments related to the production sharing contract (PSC).

²¹ Includes revenue from Beaumont New Ammonia and overriding royalty interests held in the USA for several producing wells.

²² 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.

²³ Operating revenue excludes all hedging impacts.

²⁴ Excludes any additional benefit attributed to produced volumes through third-party trading activities.

²⁵ Sales volumes have been restated to reflect volumes sold in MMBtu at a revised boe conversion factor impacting realised price by -$0.6/Mcf for International pipeline gas in Q3 2025.

²⁶ 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.

²⁷ Other incorporates Louisiana LNG cash call payments to Williams for Driftwood Pipeline LLC, corporate spend, other investments and other capital expenditure.

²⁸ Louisiana LNG YTD 2026 project spend includes $185 million of prepayments recognised in investing cash flow that are recoverable through partner cash calls but are not yet recognised as capital expenditure.

²⁹ 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.

³⁰ Includes seismic and general permit activities and other exploration costs.

³¹ Well depths are referenced to the rig rotary table.

³² Woodside share reflects the net realised interest for the period.

³³ 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.

³⁴ Includes the aggregate Woodside equity domestic gas production from all Western Australian projects.

³⁵ Woodside share reflects the net realised interest for the period.

³⁶ Operations governed by production sharing contracts.

³⁷ Beaumont New Ammonia production rate was 0.8 kT/d in Q3 2026.

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

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