Woodside Energy Releases Fourth Quarter Report for Period Ended 31 December 2025

PERTH, Australia--( BUSINESS WIRE)--Woodside Energy Group (ASX: WDS) (NYSE: WDS):

2025 full-year guidance

Guidance

Preliminary

2025 full-

year result 1

Comments

Production

MMboe

192 - 197

198.8

Strong production performance across assets

Unit production cost

$/boe

7.6 - 8.1

~7.8

Property, plant and equipment depreciation and amortisation

$ million

4,800 - 5,100

~5,050

Exploration expenditure

$ million

200

~200

Payments for restoration

$ million

700 - 1,000

~850

Gas hub exposure 2

% of produced LNG

27 - 31

~30

Capital expenditure (excluding Louisiana LNG) 3

$ million

3,700 - 4,000

~3,780

Louisiana LNG capital expenditure 4

$ million

1,000 -1,200

~930

Preliminary full-year result includes the sell-down to Williams

Woodside Acting CEO Liz Westcott said the company delivered strongly against its 2025 business objectives, outperforming production guidance while advancing key growth projects.

“We achieved record annual production of 198.8 million barrels of oil equivalent in 2025. This performance was driven by sustained plateau production at Sangomar through late October and Pluto LNG operating at 100% reliability for the second half of the year.

“In recent days we marked a special milestone for the Scarborough Energy Project with the safe arrival of the floating production unit at the field and commencement of hook-up activities. The project was 94% complete at the end of the year and remains on budget and on target for first LNG cargo in Q4 2026.

“In late December first production was achieved at Beaumont New Ammonia. Final project commissioning will continue through early 2026 ahead of project completion and Woodside assuming operational control. Production will commence with conventional ammonia with lower-carbon ammonia planned for 2H 2026.

“Woodside has finalised agreements with leading global customers to supply conventional ammonia from Beaumont. These deliveries will commence in 2026 and continue through year-end, under contracts that reflect prevailing market prices.

“We also continued to progress our major development pipeline, with the three‑train foundation phase of the Louisiana LNG Project reaching 22% completion at quarter‑end, targeting first LNG in 2029.

“During the period Woodside entered a strategic partnership with leading US gas infrastructure company Williams, selling a 10% interest in the Louisiana LNG HoldCo and an 80% operating interest in PipelineCo, further demonstrating the quality of the project. Under the transaction, Williams will contribute approximately $1.9 billion in capital expenditure and assume offtake obligations for 10% of Louisiana LNG’s produced volumes.

“The Trion Project in Mexico was 50% complete at the end of the year, with hull assembly and installation of all critical equipment on the topside’s modules now completed.

“Also during the quarter, we took a final investment decision to develop the North West Shelf Project’s Greater Western Flank Phase 4. The project extends production from the North West Shelf by around one year and delivers an internal rate of return of approximately 30%. 5

“During the period we signed long term LNG sale and purchase agreements with SK Gas International and BOTAŞ, supplied from Woodside's global portfolio including LALNG, evidencing the value customers place on our product.

“Woodside strengthened its position in the Gulf of America as the successful bidder on eight exploration blocks. 6

“We are looking forward to first LNG from Scarborough in the fourth quarter of this year. Our 2026 volume guidance of 172 - 186 MMboe reflects planned down time at Pluto as we prepare the facility to begin processing Scarborough gas and for first LNG cargo in Q4 2026.

“Woodside continues to execute our strategy as outlined at our recent Capital Markets Day. The executive team and I remain focused on safely delivering our operations and projects while maintaining rigorous cost management during the CEO transition period."

Comparative performance at a glance

2025

Change

2024

Change

YTD

2025

YTD

2024

Change

Revenue 7,8

$ million

3,035

3,359

(10%)

3,484

(13%)

12,984

13,179

(1%)

Production 9

MMboe

48.9

50.8

(4%)

51.4

(5%)

198.8

193.9

Gas

MMscf/d

1,709

1,827

(6%)

1,909

(10%)

1,800

1,931

(7%)

Liquids

Mbbl/d

232

231

—

224

229

191

20%

Total

Mboe/d

531

552

(4%)

559

(5%)

545

530

Sales 10,11

MMboe

52.4

55.1

(5%)

54.1

(3%)

212.2

204.0

Gas

MMscf/d

1,924

2,122

(9%)

2,129

(10%)

2,018

2,092

(4%)

Liquids

Mbbl/d

232

226

214

228

190

20%

Total

Mboe/d

569

599

(5%)

588

(3%)

581

557

Average realised price 7,8,10

$/boe

(5%)

(10%)

(5%)

Capital expenditure 8

$ million

822

1,323

(38%)

2,681

(69%)

4,703

8,104

(42%)

Capex excluding Louisiana LNG 12

$ million

954

1,047

(9%)

1,396

(32%)

3,774

4,919

(23%)

Louisiana LNG 13

$ million

(132)

276

(148%)

219

(160%)

929

219

324%

Acquisitions 14

$ million

—

1,066

(100%)

—

2,966

(100%)

Operations

Pluto LNG

North West Shelf (NWS) Project

Wheatstone and Julimar-Brunello

Bass Strait

Sangomar

United States of America

Marketing

Projects

Scarborough Energy Project

Beaumont New Ammonia

Trion

Louisiana LNG

Hydrogen Refueller @H2Perth

Decommissioning

Development and exploration

Browse

Sunrise

Calypso

Exploration

New energy and carbon solutions

Carbon capture and storage (CCS) opportunities

Carbon credit portfolio

Corporate activities

CEO succession

Climate and sustainability

Hedging 22

Funding and liquidity 22

Embedded commodity derivative 22

2025 Annual results and teleconference

Annual General Meeting

Upcoming events 2026

February

2025 Annual Report

March

Sustainability Briefing

April

Annual General Meeting

First Quarter Report

Additional 2025 full-year line-item guidance

Statutory

Underlying

Comments

Other income

$ million

850 - 1,050

Includes hedging gains of ~$200 million, profit on the divestment of the Greater Angostura assets of ~$160 million and a non-cash benefit for the Perdaman embedded derivative of ~ $140 million.

Restoration movement expense (other expense)

$ million

300 - 400

Other (other expense)

$ million

130 - 330

Includes costs in "Other” within the Other expenses line-item in Note A.1 of the Financial Statements. Excludes general, administrative and other costs, amortisation of intangible assets and depreciation of lease assets which are recognised separately within Other expenses.

Impairment losses

$ million

143

—

Impairment loss of $143 million pre-tax ($113 million post-tax) on the H2OK Project. Excluded from underlying NPAT.

Net finance costs

$ million

20 - 60

Includes ~$20 million in hedging gains relating to interest rate swaps.

Petroleum rent and resources (PRRT) expense

$ million

200 - 500

Income tax expense

$ million

560 - 960

770 - 1,170

A deferred tax asset (DTA) of $182 million for the Louisiana LNG Project was recognised on FID, within the 2025 half-year results. The Louisiana LNG DTA and tax impact of the H2OK impairment loss of $30 million are excluded from underlying NPAT.

The presentation of the above statutory line-items aligns to the consolidated income statement and Note A.1 segment revenue and expenses note in Woodside’s Annual Report. The line-item guidance provided above is preliminary, unaudited and subject to change prior to finalising the 2025 Financial Statements.

2026 full-year guidance

Guidance

172 - 186

~30

4,000 - 4,500

500 - 800

~200

1,500 - 1,800

500 - 600

Property, plant and equipment depreciation and amortisation

$ million

4,200 - 4,700

Note 1: Production volumes from hydrocarbons

The approximate split of production volumes from hydrocarbons by product type is:

LNG

~45%

Crude and condensate

~35%

Pipeline gas

~15%

Natural gas liquids

~5%

Note 2: Capital expenditure

The approximate split of capital expenditure by asset is:

Louisiana LNG (including contributions from non-controlling interests) 24

~25%

Scarborough 25

~20%

Trion 26

~20%

Australia Other 27

~20%

International Other

~15%

Production summary

2025

2024

YTD

2025

YTD

2024

Gas

MMscf/d

1,709

1,827

1,909

1,800

1,931

Liquids

Mbbl/d

232

231

224

229

191

Total

Mboe/d

531

552

559

545

530

2025

2024

YTD

2025

YTD

2024

AUSTRALIA

LNG

North West Shelf

Mboe

6,091

5,895

7,117

23,756

29,426

Pluto 28

Mboe

11,583

12,328

11,232

45,438

46,719

Wheatstone

Mboe

2,390

2,677

2,460

9,913

9,341

Total

Mboe

20,064

20,900

20,809

79,107

85,486

Pipeline gas

Bass Strait

Mboe

3,431

3,929

3,140

14,205

12,978

Other 29

Mboe

3,673

3,921

4,136

15,376

15,278

Total

Mboe

7,104

7,850

7,276

29,581

28,256

Crude oil and condensate

North West Shelf

Mbbl

1,083

1,093

1,250

4,194

5,187

Pluto 28

Mbbl

939

989

911

3,684

3,741

Wheatstone

Mbbl

436

471

423

1,767

1,739

Bass Strait

Mbbl

367

505

482

1,731

2,178

Macedon & Pyrenees

Mbbl

430

347

617

1,704

1,466

Ngujima-Yin

Mbbl

973

960

1,143

3,742

4,234

Okha

Mbbl

452

575

616

1,926

2,188

Total

Mboe

4,680

4,940

5,442

18,748

20,733

NGL

North West Shelf

Mbbl

247

258

274

942

1,131

Pluto 28

Mbbl

222

226

Bass Strait

Mbbl

631

842

740

2,894

3,665

Total

Mboe

931

1,165

1,072

4,058

5,022

Total Australia 30

Mboe

32,779

34,855

34,599

131,494

139,497

Mboe/d

356

379

376

360

381

2025

2024

YTD

2025

YTD

2024

INTERNATIONAL

Pipeline gas

USA

Mboe

408

491

305

1,686

1,316

Trinidad & Tobago

Mboe

242

2,425

4,863

8,953

Other 31

Mboe

Total

Mboe

408

739

2,730

6,583

10,269

Crude oil and condensate

Atlantis

Mbbl

2,761

2,783

2,238

10,620

9,049

Mad Dog

Mbbl

2,797

2,310

2,607

10,154

10,679

Shenzi

Mbbl

1,958

2,088

1,832

8,389

8,617

Trinidad & Tobago

Mbbl

140

205

503

Sangomar

Mbbl

7,781

7,516

6,901

29,703

13,343

Other 31

Mbbl

324

Total

Mboe

15,331

14,715

13,799

59,110

42,515

NGL

USA

Mbbl

363

442

320

1,601

1,583

Other 31

Mbbl

Total

Mboe

363

445

320

1,619

1,583

Total International

Mboe

16,102

15,899

16,849

67,312

54,367

Mboe/d

175

173

183

184

149

Total Production

Mboe

48,881

50,754

51,448

198,806

193,864

Mboe/d

531

552

559

545

530

Product sales

2025

2024

YTD

2025

YTD

2024

Gas

MMscf/d

1,924

2,122

2,129

2,018

2,092

Liquids

Mbbl/d

232

226

214

228

190

Total

Mboe/d

569

599

588

581

557

2025

2024

YTD

2025

YTD

2024

AUSTRALIA

LNG

North West Shelf

Mboe

5,797

4,743

6,753

22,486

29,195

Pluto

Mboe

11,703

13,609

10,490

46,957

45,766

Wheatstone 32

Mboe

2,974

1,623

2,504

10,160

10,608

Total

Mboe

20,474

19,975

19,747

79,603

85,569

Pipeline gas

Bass Strait

Mboe

3,456

4,070

3,320

14,445

13,561

Other 33

Mboe

3,440

4,028

4,058

14,885

14,203

Total

Mboe

6,896

8,098

7,378

29,330

27,764

Crude oil and condensate

North West Shelf

Mbbl

1,225

1,194

1,203

4,264

5,574

Pluto

Mbbl

661

1,338

1,093

3,354

3,874

Wheatstone

Mbbl

648

417

319

2,050

1,674

Bass Strait

Mbbl

531

518

1,664

2,048

Ngujima-Yin

Mbbl

747

1,171

1,006

3,732

4,105

Okha

Mbbl

654

653

1,910

2,461

Macedon & Pyrenees

Mbbl

438

496

472

1,931

1,466

Total

Mboe

4,373

5,147

5,264

18,905

21,202

NGL

North West Shelf

Mbbl

223

430

252

1,130

1,022

Pluto

Mbbl

105

281

209

Bass Strait

Mbbl

598

374

303

2,208

2,591

Total

Mboe

887

909

608

3,619

3,822

Total Australia

Mboe

32,630

34,129

32,997

131,457

138,357

Mboe/d

355

371

359

360

378

2025

2024

YTD

2025

YTD

2024

INTERNATIONAL

Pipeline gas

USA 34

Mboe

331

438

231

1,577

1,139

Trinidad & Tobago

Mboe

243

2,802

4,750

8,869

Other 35

Mboe

Total

Mboe

336

685

3,039

6,344

10,027

Crude oil and condensate

Atlantis

Mbbl

2,729

2,801

2,108

10,630

8,983

Mad Dog

Mbbl

2,710

2,310

2,629

10,125

10,787

Shenzi

Mbbl

1,931

2,094

1,730

8,257

8,544

Trinidad & Tobago

Mbbl

181

345

Sangomar

Mbbl

7,603

6,833

6,793

28,462

12,863

Other 35

Mbbl

192

206

Total

Mboe

15,014

14,090

13,355

57,847

41,728

NGL

USA

Mbbl

350

440

303

1,546

1,558

Other 35

Mbbl

Total

Mboe

353

442

307

1,555

1,569

Total International

Mboe

15,703

15,217

16,701

65,746

53,324

Mboe/d

171

165

182

180

146

MARKETING 36

LNG

Mboe

3,341

5,492

4,196

13,920

10,952

Liquids

Mboe

695

249

160

1,112

1,323

Total

Mboe

4,036

5,741

4,356

15,032

12,275

Total Marketing

Mboe

4,036

5,741

4,356

15,032

12,275

Total sales

Mboe

52,369

55,087

54,054

212,235

203,956

Mboe/d

569

599

588

581

557

Revenue (US$ million) 37

2025

2024

YTD

2025

YTD

2024

AUSTRALIA

North West Shelf

381

323

497

1,534

2,133

Pluto

800

1,000

853

3,339

3,409

Wheatstone 38

230

135

213

819

889

Bass Strait

212

265

217

988

1,031

Macedon

202

196

Ngujima-Yin

279

361

Okha

134

197

Pyrenees

149

128

Total Australia

1,798

1,892

2,003

7,444

8,344

INTERNATIONAL

Atlantis

169

196

156

737

714

Mad Dog

159

150

183

660

828

Shenzi

117

142

124

564

679

Trinidad & Tobago 39

150

228

Sangomar

479

477

484

1,947

948

Other 40

Total International

926

973

1,015

4,069

3,412

Marketing revenue 41

273

452

410

1,269

1,187

Total sales revenue 42

2,997

3,317

3,428

12,782

12,943

Processing revenue

177

220

Shipping and other revenue

Total revenue

3,035

3,359

3,484

12,984

13,179

Realised prices 43

Units

2025

2024

Units

2025

2024

LNG produced

$/MMBtu

9.4

9.5

10.8

$/boe

LNG traded 44

$/MMBtu

9.9

11.2

12.6

$/boe

Pipeline gas

$/boe

Oil and condensate

$/bbl

$/boe

NGL

$/bbl

$/boe

Liquids traded 44

$/bbl

$/boe

Average realised price for pipeline gas:

Western Australia

A$/GJ

6.9

6.8

6.6

East Coast Australia

A$/GJ

12.6

12.9

12.7

International 45

$/Mcf

4.3

3.6

4.2

Average realised price

$/boe

Dated Brent

$/bbl

JCC (lagged three months)

$/bbl

WTI

$/bbl

JKM

$/MMBtu

11.2

12.5

13.5

TTF

$/MMBtu

10.8

11.7

12.8

Average realised price decreased 5% from the prior quarter reflecting a downward trend in oil-linked and gas pricing.

Capital expenditure (US$ million) 46

2025

2024

YTD

2025

YTD

2024

Evaluation capitalised 47

Property plant & equipment

938

1,032

1,315

3,687

4,616

Other 48

226

Capital expenditure excluding Louisiana LNG

954

1,047

1,396

3,774

4,919

Louisiana LNG capital expenditure 49

505

498

219

3,658

219

Cash contributions from participants 50

(600)

(222)

(2,692)

Other 51

(37)

Total Louisiana LNG capital expenditure

(132)

276

219

929

219

Total capital expenditure

822

1,323

1,615

4,703

5,138

Acquisitions 52

1,066

2,966

Total

822

1,323

2,681

4,703

8,104

2025

2024

YTD

2025

YTD

2024

Scarborough

389

361

664

1,405

2,239

Trion

186

291

299

884

758

Sangomar

112

601

Other

373

395

321

1,462

1,321

Capital expenditure excluding Louisiana LNG

954

1,047

1,396

3,774

4,919

Other expenditure (US$ million) 46

2025

2024

YTD

2025

YTD

2024

Exploration capitalised 47,53

Exploration and evaluation expensed 54

140

183

330

Permit amortisation

Total

142

228

362

Trading costs

290

445

290

1,145

695

Exploration or appraisal wells drilled

Region

Permit area

Well

Target

Interest (%)

Spud date

Water depth (m)

Planned well depth (m) 55

Remarks

United States

GC 680

Bandit-1

Oil

17.5% Non-operator

2 September 2025

1,555

10,811

Drilling

Australia

WA-49-L

JUB1B

Gas

65% Operator

21 July 2025

170

3,736

Productive

WA-49-L

JUA1C

Gas

65% Operator

4 August 2025

174

4,717 planned,

4,644.5 actual

Not commercial

Permits and licences

Key changes to permit and licence holdings during the quarter ended 31 December 2025 are noted below.

Region

Permits or licence areas

Change in interest (%)

Current interest (%)

Remarks

United States

MC 368, MC 369, MC 455, MC 456

(25.0%)

—

Licence assignment 56

GC 436

(44%)

—

Licence relinquished

GC 480

(44%)

—

Licence expired

MC 798, MC 842

(45%)

—

Licence relinquished

AC 82

(45%)

—

Licence expired

AC 34, AC 78

(70%)

—

Licence expired

GC 168

(75%)

—

Licence relinquished

GB 574, GB 575, GB 619

(100%)

—

Licence relinquished

Production rates

Average daily production rates (100% project) for the quarter ended 31 December 2025:

Woodside share 57

Production rate (100% project, Mboe/d)

Remarks

Dec

2025

Sep

2025

AUSTRALIA

NWS Project

LNG

30.10%

220

218

LNG production was higher due to production optimisation.

Crude oil and condensate

30.18%

NGL

30.21%

Pluto LNG

LNG

90.00%

118

123

Production lower in Q4 due to higher ambient temperatures.

Crude oil and condensate

90.00%

Pluto-KGP Interconnector

LNG

100.00%

Production was lower due to reduced feed gas to Karratha Gas Plant.

Crude oil and condensate

100.00%

NGL

100.00%

Wheatstone 58

LNG

11.07%

235

Crude oil and condensate

15.37%

Bass Strait

Pipeline gas

51.11%

Production was lower due to lower seasonal demand.

Crude oil and condensate

42.77%

NGL

44.86%

Australia Oil

Ngujima-Yin

60.00%

Production was lower due to Okha planned shutdown and reliability.

Okha

50.00%

Pyrenees

63.81%

Other

Pipeline gas 59

Production was lower due to reduced nominations

Woodside share 60

Production rate (100% project, Mboe/d)

Remarks

Dec

2025

Sep

2025

INTERNATIONAL

Atlantis

Crude oil and condensate

38.50%

Production was lower due to midstream curtailment events and planned downtime.

NGL

38.50%

Pipeline gas

38.50%

Mad Dog

Crude oil and condensate

20.86%

146

120

Production was higher due to new wells online.

NGL

20.86%

Pipeline gas

20.86%

Shenzi

Crude oil and condensate

64.64%

Production was lower due to midstream curtailment and unplanned downtime.

NGL

64.67%

Pipeline gas

64.69%

Trinidad & Tobago

Crude oil and condensate

—% 61

–

Greater Angostura divestment completed in July.

Pipeline gas

—% 61

–

Sangomar

Crude oil

85.31% 61

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, gas hub exposure and expectations regarding the achievement of Woodside’s net equity Scope 1 and 2 greenhouse gas emissions reduction 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 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 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.

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 31 December 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).

Notes to petroleum reserves and resources

Additional information for US investors concerning resource estimates

Woodside is an Australian company with securities listed on the Australian Securities Exchange and the New York Stock Exchange. As noted above, Woodside estimates and reports its proved reserves in accordance with SEC regulations, which are also compliant with SPE-PRMS guidelines, and estimates and reports its proved plus probable reserves and 2C contingent resources in accordance with SPE-PRMS guidelines. Woodside reports all petroleum resource estimates using definitions consistent with SPE-PRMS.

The SEC prohibits oil and gas companies, in their filings with the SEC, from disclosing estimates of oil or gas resources other than ‘reserves’ (as that term is defined by the SEC). In this announcement, Woodside includes estimates of quantities of oil and gas using certain terms, such as ‘proved plus probable (2P) reserves’, ‘best estimate (2C) contingent resources’, ‘reserves and contingent resources’, ‘proved plus probable’, ‘developed and undeveloped’, ‘probable developed’, ‘probable undeveloped’, ‘contingent resources’ or other descriptions of volumes of reserves, which terms include quantities of oil and gas that may not meet the SEC’s definitions of proved, probable and possible reserves, and which the SEC’s guidelines strictly prohibit Woodside from including in filings with the SEC. These types of estimates do not represent, and are not intended to represent, any category of reserves based on SEC definitions, and may differ from and may not be comparable to the same or similarly-named measures used by other companies. These estimates are by their nature more speculative than estimates of proved reserves and would require substantial capital spending over a significant number of years to implement recovery, and accordingly are subject to substantially greater risk of not being recovered by Woodside. In addition, actual locations drilled and quantities that may be ultimately recovered from Woodside’s properties may differ substantially. Woodside has made no commitment to drill, and likely will not drill, all drilling locations that have been attributable to these quantities. The Reserves Statement presenting Woodside’s proved oil and gas reserves in accordance with the regulations of the SEC is filed with the SEC as part of Woodside’s annual report on Form 20-F. US investors are urged to consider closely the disclosures in Woodside’s most recent Annual Report on Form 20-F filed with the SEC and available on the Woodside website at https://www.woodside.com/investors/reports-investor-briefings and its other filings with the SEC, which are available at www.sec.gov.

Glossary, units of measure and conversion factors

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

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

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

petajoule

scf

standard cubic feet of gas

terajoule

Glossary

Please refer to the Glossary in the Annual Report 2024 for definitions, including carbon related definitions.

1 The line-item guidance provided above is preliminary, unaudited and subject to change prior to finalising the 2025 Financial Statements.

2 Gas hub indices include Japan Korea Marker (JKM), Title Transfer Facility (TTF) and National Balancing Point (NBP). It excludes Henry Hub.

3 Capital expenditure includes the following participating interests; Scarborough (74.9%), Pluto Train 2 (51%) and Trion (60%). It excludes the payment of Beaumont New Ammonia acquisition consideration and Louisiana LNG expenditure.

4 Louisiana LNG guidance assumed 100% Louisiana LNG LLC, 60% Louisiana LNG Infrastructure LLC and 100% Driftwood Pipeline LLC. The preliminary 2025 results reflect the additional sell-down to Williams of 10% Louisiana LNG LLC and 80% of Driftwood Pipeline LLC.

5 Figures are Woodside share, 50% interest. Capital expenditure is post final investment decision. Subject to the completion of the Woodside and Chevron asset swap. Refer to the announcement titled ‘Woodside simplifies portfolio and unlocks long-term value’, dated 19 December 2024. IRR and the payback period are a look forward from January 2025. Payback period is calculated from undiscounted cash flows, RFSU + approximately 2 years.

6 Lease issuance is pending final payment and regulatory approval.

7 Results are preliminary, unaudited and subject to change prior to finalising the 2025 Financial Statements.

8 Restated to exclude periodic adjustments reflecting the arrangements governing Wheatstone LNG sales of $14 million in Q4 2024 and $28 million in YTD 2024. These amounts are 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.

9 Q4 2025 includes 0.27 MMboe primarily from feed gas purchased from Pluto non-operating participants processed through the Pluto-KGP Interconnector. Percent change in total production may differ from percent change in daily production due to the number of days in each quarter.

10 Restated to exclude periodic adjustments reflecting the arrangements governing Wheatstone LNG sales of 0.23 MMboe in Q4 2024 and 0.43 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.

11 Restated additional volumes of 0.09 MMboe in Q1 2025, 0.10 MMboe in Q2 2025 and 0.09 MMboe in Q3 2025 to reflect a revised MMBtu to boe conversion factor.

12 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.

13 Capital expenditure for Louisiana LNG is presented as a net figure inclusive of capital contributions received from Stonepeak and Williams for the development of Louisiana LNG. Q4 2025 includes a $600 million cash contribution.

14 Purchase consideration for Beaumont New Ammonia and Louisiana LNG.

15 Figures are Woodside share, 50% interest. Capital expenditure is post final investment decision. Subject to the completion of the Woodside and Chevron asset swap. Refer to the announcement titled ‘Woodside simplifies portfolio and unlocks long-term value’, dated 19 December 2024. IRR and the payback period are a look forward from January 2025. Payback period is calculated from undiscounted cash flows, RFSU + approximately 2 years.

16 Gross proved plus probable undeveloped reserves includes 7 MMboe of fuel consumed in operations. Woodside share is shown at current equity of ~31% and includes 2 MMboe of fuel consumed in operations.

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

18 Completion of the transaction is subject to conditions precedent. See "Woodside strengthens its Australian Operations" announced on 29 July 2025.

19 Production of lower-carbon ammonia is targeted to start in the second half of 2026. See “Production milestone at Beaumont New Ammonia”, announced on 29 December 2025.

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

21 2025 Oil & Gas Methane Partnership (OGMP) 2.0 Company Factsheets, Pg 137.

22 Results are preliminary, unaudited and subject to change prior to finalising the 2025 Financial Statements.

23 Consistent with 2025 Capital Markets Day, 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.

24 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 and Williams.

25 Scarborough at 74.9% participating interest, Pluto Train 2 at 51% participating interest.

26 Trion at 60% participating interest.

27 Completion of the asset swap with Chevron assumed in H2 2026. Woodside’s equity interests at current participating interests prior to the completion for NWS Project, NWS Oil Project, Wheatstone, Julimar-Brunello and Angel CCS assets.

28 Q4 2025 includes 1.80 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.

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

30 Q4 2025 includes 0.27 MMboe primarily from feed gas purchased from Pluto non-operating participants processed through the Pluto-KGP Interconnector.

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

32 Restated to exclude periodic adjustments reflecting the arrangements governing Wheatstone LNG sales of 0.23 MMboe in Q4 2024 and 0.43 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.

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

34 Restated additional volumes of 0.09 MMboe in Q1 2025, 0.10 MMboe in Q2 2025 and 0.09 MMboe in Q3 2025 to reflect a revised MMBtu to boe conversion factor.

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

36 Purchased volumes sourced from third parties.

37 Results are preliminary, unaudited and subject to change prior to finalising the 2025 Financial Statements.

38 Restated to exclude periodic adjustments reflecting the arrangements governing Wheatstone LNG sales of $14 million in Q4 2024 and $28 million in YTD 2024. These amounts are 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.

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

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

41 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 intersegment revenue of $44 million in Q4 2025 and $120 million in YTD 2025, 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.

42 Referred to as ‘Revenue from sale of hydrocarbons’ in Woodside financial statements. Total sales revenue excludes all hedging impacts.

43 Results are preliminary, unaudited and subject to change prior to finalising the 2025 Financial Statements.

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

45 Sales volumes have been restated to reflect volumes sold in MMBtu at a revised boe conversion factor impacting realised price by -$0.2/Mcf in Q1 2025, -$0.2/Mcf in Q2 2025 and -$0.6/Mcf in Q3 2025.

46 Results are preliminary, unaudited and subject to change prior to finalising the 2025 Financial Statements.

47 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.

48 Other primarily incorporates corporate spend including SAP build costs, other investments and other capital expenditure.

49 Capital expenditure for Louisiana LNG is presented at 100% working interest equity.

50 Capital contributions received from Stonepeak and Williams for the development of Louisiana LNG.

51 Net payments to/from Williams for Driftwood Pipeline LLC associated with 2025 capital reimbursement included in sell-down proceeds and ongoing cash call payments.

52 Acquisition of Louisiana LNG of $1,066m and OCI’s Clean Ammonia Project in Beaumont, Texas of $1,900m.

53 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.

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

55 Well depths are referenced to the rig rotary table.

56 Awaiting Bureau of Ocean Energy Management approval.

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

58 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.

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

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

61 Operations governed by production sharing contracts.

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