Second Quarter 2024 Report

Woodside Energy Group Ltd
23 July 2024
 

SECOND QUARTER REPORT FOR PERIOD ENDED 30 JUNE 2024

ASX: WDS | NYSE: WDS | LSE: WDS
Tuesday, 23 July 2024

Delivering on our growth strategy

Operations

·      Quarterly production of 44.4 MMboe (488 Mboe/day), down 1% from Q1 2024 due to planned maintenance activities, weather impacts at North West Shelf and unplanned outages at Wheatstone and Julimar, partly offset by higher seasonal demand at Bass Strait and first oil at Sangomar. Full year production guidance remains unchanged.

·      Quarterly revenue of $3,033 million, up 2% from Q1 2024 primarily due to timing of Pluto cargoes partially offset by lower realised prices.

·      Sold 22% of total equity production in the quarter on prices linked to gas hub indices.[1] Full year gas hub guidance remains unchanged.

 

Projects

·      The Sangomar Project achieved first oil in June and production continues to ramp up as planned. Subsequent to the quarter, the first cargo was loaded for delivery to Europe.

·      The Scarborough Energy Project was 67% complete at the end of the quarter, with first LNG cargo expected in 2026.[2]

 

·      The total estimated cost of the Scarborough Energy Project has increased by 4% to US$12.5 billion (US$8.2 billion Woodside share), significantly driven by scope maturation of the Pluto Train 1 modifications project.[3]

·      The Trion Project continued to progress engineering, procurement, and contracting activities in accordance with the execution plan.

·      Secured all primary environmental approvals for the Hydrogen Refueller @H2Perth and progressed offtake discussions for the H2OK Project.

 

Other

·      Signed a sale and purchase agreement (SPA) with CPC Corporation, Taiwan (CPC) for the long-term supply of LNG to Taiwan.

·      Secured $1 billion funding from Japan Bank for International Cooperation (JBIC) for the Scarborough Energy Project.

·      Subsequent to the quarter, Woodside entered into a definitive agreement to acquire Tellurian and its US Gulf Coast Driftwood LNG development opportunity for an all-cash payment of approximately $900 million.

 

Woodside CEO Meg O'Neill said the company is on track to achieve its full year production guidance of 185-195 million barrels of oil equivalent (MMboe), with output for the second quarter of 44.4 MMboe.

"The first oil from our Sangomar project offshore Senegal was a significant milestone, delivering against our growth strategy. Subsequent to the quarter, we achieved peak gross rate of 75,000 barrels per day and production ramp-up continues as planned.

"The addition of Sangomar to Woodside's portfolio will deliver enduring shareholder value and significant economic benefits for Senegal.

"Work on our other major growth projects continued at pace. The Scarborough Energy Project in Western Australia is now more than two-thirds complete and we remain on target for first LNG cargo in 2026.

"We are also progressing our opportunities in new energy, securing all primary environmental approvals for the Hydrogen Refueller @H2Perth, while continuing offtake discussions for H2OK in the US.

"We see ongoing demand for Woodside's LNG in Asian markets, as evidenced by our long-term sale and purchase agreement with CPC Corporation, Taiwan, and the $1 billion loan agreement executed with JBIC to fund Woodside's Scarborough Energy Project.

"The recent announcement of an agreement to acquire Tellurian and Driftwood LNG positions Woodside to be a global LNG powerhouse, adding scalable US LNG development exposure to our portfolio," she said.

Comparative performance at a glance



Q2

2024

Q1

2024

Change %

Q2

2023

Change %

YTD

2024

YTD

2023

Change %

Revenue

$ million

3,033

2,969

2%

3,084

(2%)

6,002

7,414

(19%)

Production[4]

MMboe

44.4

44.9

(1%)

44.5

-

89.3

91.3

(2%)


Gas

MMscf/d

1,885

1,929

(2%)

1,905

(1%)

1,907

1,999

(5%)


Liquids

Mbbl/d

157

155

1%

155

1%

156

154

1%


Total

Mboe/d

488

494

(1%)

489

-

491

504

(3%)

Sales

MMboe

48.0

45.9

5%

48.4

(1%)

93.9

98.8

(5%)


Gas

MMscf/d

2,103

1,967

7%

2,170

(3%)

2,035

2,268

(10%)


Liquids

Mbbl/d

159

159

-

151

5%

159

148

7%


Total

Mboe/d

528

504

5%

532

(1%)

516

546

(5%)

Average realised price

$/boe

62

63

(2%)

63

(2%)

63

74

(15%)

Capital expenditure[5]

$ million

1,233

1,179

5%

1,321

(7%)

2,412

2,637

(9%)

 

Operations

North West Shelf (NWS) Project

·      Achieved strong quarterly LNG reliability of 99.7%.

·      Successfully completed planned offshore maintenance at Goodwyn Alpha (GWA).

·      Progressed the proposed GWA infill development for potential final investment decision (FID) in 2025, which would involve tying back several fields via existing GWA subsea infrastructure.

 

Pluto LNG

·      Achieved quarterly LNG reliability of 97.7%.

·      Successfully completed a two-day turnaround at Pluto LNG to enable integration testing of the produced water handling unit into the Pluto A platform.

·      Increased Pluto domestic gas production through the Pluto-KGP interconnector at the NWS.

 

Wheatstone and Julimar-Brunello

·      Two separate unplanned outages occurred in the quarter, impacting the Julimar subsea production system and the Wheatstone facility respectively. Full production resumed in the quarter. 

 

Bass Strait

·      Completed offshore installation of the Kipper Compression modules, with the project progressing hook-up activities for a planned start-up in Q3 2024.

·      The Gippsland Basin Joint Venture (GBJV) continues to optimise its facilities through the Gippsland Asset Streamlining project with the Halibut platform ceasing production as planned following declining oil production from the facility.

 

Other Australia                                                  

·      Successfully completed the planned five-yearly maintenance turnaround at the Pyrenees floating production storage and offloading (FPSO) facility.

·      A produced-water leak identified in the subsea system at the Pyrenees facility in January was rectified and production recommenced, returning to normal rates this quarter.

 

Gulf of Mexico

·      Achieved quarterly reliability of 98.9% at Shenzi. 

·      Executed a planned major offshore facility turnaround at Atlantis.

·      Achieved first water injection at the Argos platform in April 2024.

Trinidad & Tobago

·      Safely completed a planned facility maintenance turnaround in June 2024 aimed at proactive risk and integrity management and control system upgrades.

 

Marketing

·      Signed a long-term LNG SPA with CPC for the supply of approximately 6 million tonnes of LNG on a delivered basis over 10 years, commencing in July 2024. LNG delivered under the SPA will be sourced from volumes across Woodside's global portfolio. 

·      Sold 45% of produced LNG at prices linked to gas hub indices in the quarter (34% year to date). This represents 22% of Woodside's total equity production (16% year to date). Full year gas hub guidance remains unchanged.

·      Took delivery of a new 174,000m3 long-term charter LNG vessel, the Woodside Scarlet Ibis, which will support efforts to lower the carbon intensity of Woodside's LNG deliveries.

·      Executed 14 PJ of Western Australian gas sales for delivery from May to the end of 2024. Woodside continues to support the Western Australian domestic market by offering additional supply for 2025, 2026 and 2027.

·      Achieved record trucked LNG deliveries of 525 TJ during the quarter to customers in northern Western Australia. Woodside has now delivered more than 2000 trailers of LNG since commencement of operations at the Pluto LNG Truck Loading Facility, offering a lower-carbon alternative to diesel.[6]

 

Projects

Scarborough Energy Project

·      A cost and schedule review was performed for the integrated Scarborough Energy Project. The schedule remains unchanged, with first LNG cargo targeted for 2026. The revised total project cost estimate is US$12.5 billion (US$8.2 billion Woodside share), a 4% increase from the previous cost estimate at FID of US$12 billion. The cost increase is significantly driven by scope maturation of the Pluto Train 1 modifications project.[7]

·      The Scarborough and Pluto Train 2 project was 67% complete at the end of the quarter.

·      29 Pluto Train 2 modules have been delivered to site, with 25 modules set in position at the end of the quarter and site works continuing to ramp up.

·      Fabrication of the floating production unit (FPU) hull and topsides progressed. The living quarters module was installed on the topsides, which has achieved structural completion.

·      Trunkline installation has transitioned from the 36" to 32" pipe and is now more than 50% complete.

·      Two development wells have been drilled, with one well completed and the other planned to be completed in H2 2024. Reservoir quality is aligned with pre-drill estimates.

·      Installation and testing of the three flowlines was completed.

·      All major engineering reviews for Pluto Train 1 modifications have been completed and approximately 80% of materials and equipment have been ordered. Mobilisation of personnel to both the module yard and Pluto site commenced.

 

Sangomar Field Development Phase 1

·      Achieved first oil from the Sangomar field in June 2024, marking the delivery of Senegal's first offshore oil project.

·      Finalised sales for initial Sangomar crude cargoes loading in July 2024, receiving interest from European and Asian refiners. The first cargo was loaded subsequent to the quarter.

·      The project was 98% complete at the end of the quarter.

·      The development drilling program continued with 21 of 23 wells drilled and completed. An additional 24th well approved by the joint venture in May 2023 was also drilled and completed in the period.

·      Commissioning activities and the safe ramp up of production are expected to continue through 2024.

 

Trion

·      Awarded contracts for the FPU dry transportation, gas gathering line pipe and drilling equipment and consumables.

·      Progressed FPU engineering, procurement and construction activities with procurement of key equipment and the integration of vendor data into the design.

·      Completed floating, storage and offloading vessel (FSO) front-end engineering design (FEED).

 

Decommissioning

·      The Griffin, Stybarrow and Enfield decommissioning campaign continued with ~50km of flexible flowlines and umbilicals recovered in the quarter. 

·      The final two of 18 xmas trees were removed from Enfield and wellhead severance commenced, with four completed at the end of the quarter.  

·      At Bass Strait, offshore execution of the plug and abandonment of two subsea wells commenced, utilising the Q7000 light well intervention vessel.

·      The GBJV also progressed FEED of the facility preparation scope for removal of platforms no longer in use and continued to execute preparatory decommissioning activities.

 

Exploration and development

Calypso

·      Continued pre-FEED engineering studies to mature the technical definition and cost estimate for the deepwater infield host.

·      Continued fiscal and marketing negotiations with various counterparties to assess the commercial options to monetise the Calypso resource.

 

Browse

·      In June 2024, a Declaration of an Identified Greenhouse Gas Storage Formation was made by the Commonwealth Government over the Calliance Storage Formation within the G-8-AP Greenhouse Gas Assessment Permit (held by Woodside as Operator of Browse). This declaration supports the proposed carbon capture and storage solution incorporated into the Browse design.

 

Sunrise

·      The Sunrise Joint Venture participants continued to work with the Australian and Timor Leste governments to progress a new Production Sharing Contract, Petroleum Mining Code and fiscal regime.

 

Exploration

·      In Congo, the Niamou Marine-1 well spud in May 2024 under the Marine XX joint venture operated by TotalEnergies.

 

New energy and carbon solutions

H2OK

·      Continued to advance discussions with potential offtakers on pricing and volumes.

·      Woodside is awaiting final guidance for the 45V Clean Hydrogen Production Tax Credit.

 

Woodside Solar

·      Working with the Western Australian Government to progress its plans to develop common user transmission infrastructure required to support the proposed project.

·      FID readiness and first solar import will be subject to securing access to this new infrastructure.

 

Hydrogen Refueller @H2Perth

·      Secured primary environmental approvals for the Hydrogen Refueller @H2Perth.

·      Commenced factory acceptance testing for key project equipment packages.

·      Woodside is targeting supply of hydrogen to Western Australian industrial customers in 2025.

 

Carbon capture and storage (CCS) opportunities

·      Continued to progress engineering and marketing activities and required approvals for the Angel CCS project.

Carbon Credits Portfolio

·      Subsequent to the quarter, Woodside signed an agreement to fund the reforestation of 5000 hectares of land in the Chaco region in Paraguay. The Woodside portion of the project is expected to generate approximately 1.6 million carbon credits over 40 years.

 

Corporate activities

Hedging

·      Woodside hedged approximately 29.3 MMboe of 2024 oil production at an average price of approximately $75.6 per barrel, with approximately 49% delivered as of 30 June 2024.

·      Woodside additionally hedged approximately 15 MMboe of 2025 oil production at an average price of approximately $81.2 per barrel.

·      Woodside also has a hedging program for Corpus Christi LNG volumes designed to protect against downside pricing risk. These hedges are Henry Hub (HH) and Title Transfer Facility (TTF) commodity swaps. Approximately 70% of volumes for the remainder of 2024, 48% of 2025 and 9% of 2026 volumes have been hedged.

·      The realised value of all hedged positions for the half-year ended 30 June 2024 is a pre-tax expense of approximately $45 million, with $111 million related to oil price hedges offset by $65 million profit related to Corpus Christi hedges and $1 million related to other hedge positions. Hedging losses will be included in "other expenses" in the full-year financial statements.

 

Funding

·      In May 2024, Woodside secured a $1 billion, 10-year loan from JBIC to support the Scarborough Energy Project. This loan was secured at prevailing market rates associated with Woodside's credit rating.

 

Climate and sustainability

·      Woodside's Annual General Meeting (AGM) took place on 24 April 2024, where all resolutions were passed except for the Climate Transition Action Plan and 2023 Progress Report (CTAP), which received a vote of 58.36% against it. Management is reflecting on the results of the CTAP vote.

·      Woodside published its 2023 Social Contribution Impact Report in April 2024 and its 2023 Modern Slavery Statement in June 2024.

·      Woodside hosted a methane masterclass during the Australian Energy Producers (AEP) conference as part of its commitment to the decarbonisation of its activities and to share Woodside's best practices on methane emissions reduction.

2024 half-year results and teleconference

·      Woodside's Half-Year Report 2024 and associated investor briefing will be released to the market on Tuesday, 27 August 2024. It will also be available on Woodside's website at http://www.woodside.com/.

Upcoming events 2024 

August

27

Half-Year 2024 report

September

16

US investor event

October

16

Third quarter 2024 report

 

2024 full-year guidance

 

 

Prior

Current

Production

MMboe

185 - 195

(505 - 533 Mboe/day)

No change

Capital expenditure[8]

$ billion

5.0 - 5.5

No change

Gas hub exposure[9]

% of produced LNG

26 - 33

No change

 

Contacts:

 

 

INVESTORS

MEDIA

REGISTERED ADDRESS

Marcela Louzada

M: +61 456 994 243

E: investor@woodside.com

Christine Forster

M: +61 484 112 469

E: christine.forster@woodside.com

Woodside Energy Group Ltd

ACN 004 898 962

Mia Yellagonga

11 Mount Street

Perth WA 6000

Australia

T +61 8 9348 4000

www.woodside.com

 

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

 



Production summary

 



Q2

2024

Q1

2024

Q2

2023

YTD

2024

YTD

2023

Gas

MMscf/d

1,885

1,929

1,905

1,907

1,999

Liquids

Mbbl/d

157

155

155

156

154

Total

Mboe/d

488

494

489

491

504

 

 



Q2

2024

Q1

2024

Q2

2023

YTD

2024

YTD

2023

AUSTRALIA







LNG







North West Shelf

Mboe

7,088

8,192

8,746

15,280

18,419

Pluto[10]

Mboe

11,726

11,754

8,765

23,480

20,919

Wheatstone

Mboe

1,959

2,357

2,588

4,316

5,044

Total

Mboe

20,773

22,303

20,099

43,076

44,382

 







Pipeline gas

 






Bass Strait

Mboe

3,410

2,359

4,170

5,769

7,303

Other[11]

Mboe

3,848

3,278

3,080

7,126

6,117

Total

Mboe

7,258

5,637

7,250

12,895

13,420








Crude oil and condensate







North West Shelf

Mbbl

1,260

1,412

1,546

2,672

3,230

Pluto10

Mbbl

933

931

699

1,864

1,660

Wheatstone

Mbbl

380

462

425

842

833

Bass Strait

Mbbl

503

492

904

995

1,681

Macedon & Pyrenees

Mbbl

107

109

759

216

1,390

Ngujima-Yin

Mbbl

974

886

-

1,860

869

Okha

Mbbl

491

466

421

957

852

Total

Mboe

4,648

4,758

4,754

9,406

10,515








NGL







North West Shelf

Mbbl

279

290

339

569

631

Pluto10

Mbbl

59

54

45

113

95

Bass Strait

Mbbl

941

832

1,191

1,773

1,914

Total

Mboe

1,279

1,176

1,575

2,455

2,640








Total Australia[12]

Mboe

33,958

33,874

33,678

67,832

70,957

Mboe/d

373

372

370

373

392

 

 

 






 



Q2

2024

Q1

2024

Q2

2023

YTD

2024

YTD

2023

INTERNATIONAL

 

 

 

 

 

 

Pipeline gas


 





Gulf of Mexico

Mboe

324

360

349

684

679

Trinidad & Tobago

Mboe

1,736

2,503

2,723

4,239

4,959

Other[13]

Mboe

-

-

-

-

30

Total

Mboe

2,060

2,863

3,072

4,923

5,668

 

 






Crude oil and condensate







Atlantis

Mbbl

2,019

2,441

2,792

4,460

5,488

Mad Dog

Mbbl

2,944

2,765

1,627

5,709

2,566

Shenzi

Mbbl

2,333

2,405

2,599

4,738

5,195

Trinidad & Tobago

Mbbl

94

126

294

220

591

Sangomar

Mbbl

540

-

-

540

-

Other13

Mbbl

81

81

81

162

120

Total

Mboe

8,011

7,818

7,393

15,829

13,960








NGL







Gulf of Mexico

Mbbl

355

393

350

748

681

Other13

Mbbl

-

-

-

-

17

Total

Mboe

355

393

350

748

698

 

 






Total International

Mboe

10,426

11,074

10,815

21,500

20,326

Mboe/d

115

122

119

118

112



 

 


 


Total production

Mboe

44,384

44,948

44,493

89,332

91,283

Mboe/d

488

494

489

491

504

 

 

Product sales

 



Q2

2024

Q1

2024

Q2

2023

YTD

2024

YTD

2023

Gas

MMscf/d

2,103

1,967

2,170

2,035

2,268

Liquids

Mbbl/d

159

159

151

159

148

Total

Mboe/d

528

504

532

516

546

 

 



Q2

2024

Q1

2024

Q2

2023

YTD

2024

YTD

2023

AUSTRALIA


 

 

 

 

 

LNG


 

 

 

 

 

North West Shelf

Mboe

7,081

8,008

9,003

15,089

19,567

Pluto5

Mboe

12,749

10,513

9,592

23,262

20,902

Wheatstone[14]

Mboe

2,264

2,589

2,312

4,853

4,662

Total

Mboe

22,094

21,110

20,907

43,204

45,131

 






 

Pipeline gas

 





 

Bass Strait

Mboe

3,508

2,570

4,113

6,078

7,195

Other[15]

Mboe

3,435

2,894

3,040

6,329

5,979

Total

Mboe

6,943

5,464

7,153

12,407

13,174







 

Crude oil and condensate







North West Shelf[16]

Mbbl

1,904

1,214

1,595

3,118

2,684

Pluto

Mbbl

1,283

640

614

1,923

1,228

Wheatstone

Mbbl

666

329

309

995

659

Bass Strait

Mbbl

271

597

1,035

868

1,117

Ngujima-Yin

Mbbl

1,018

999

-

2,017

1,141

Okha

Mbbl

572

618

-

1,190

653

Macedon & Pyrenees

 

Mbbl

-

496

1,032

496

1,550

Total

Mboe

5,714

4,893

4,585

10,607

9,032







 

NGL






 

North West Shelf

Mbbl

266

255

255

521

425

Pluto

Mbbl

49

55

73

104

255

Bass Strait

Mbbl

361

785

903

1,146

2,012

Total

Mboe

676

1,095

1,231

1,771

2,692



 

 

 

 

 

Total Australia

Mboe

35,427

32,562

33,876

67,989

70,029

Mboe/d

389

358

372

374

387

 

 

 

 

 

 

 

 

 



Q2

2024

Q1

2024

Q2

2023

YTD

2024

YTD

2023

INTERNATIONAL

 

 

 

 

 

 

Pipeline gas


 

 

 

 

 

Gulf of Mexico

Mboe

336

286

341

622

684

Trinidad & Tobago

Mboe

1,606

2,457

2,700

4,063

4,995

Other[17]

Mboe

5

6

6

11

13

Total

Mboe

1,947

2,749

3,047

4,696

5,692

 

 





 

Crude oil and condensate






 

Atlantis

Mbbl

2,013

2,426

2,710

4,439

5,378

Mad Dog

Mbbl

3,043

2,626

1,628

5,669

2,569

Shenzi

Mbbl

2,430

2,352

2,652

4,782

5,325

Trinidad & Tobago

Mbbl

19

52

248

71

661

Sangomar

Mbbl

-

-

-

-

-

Other17

Mbbl

59

60

65

119

128

Total

Mboe

7,564

7,516

7,303

15,080

14,061







 

NGL






 

Gulf of Mexico

Mbbl

454

413

363

867

705

Other17

Mbbl

3

3

3

6

7

Total

Mboe

457

416

366

873

712







 

Total International

Mboe

9,968

10,681

10,716

20,649

20,465

Mboe/d

110

117

118

113

113

 

 

 

 

 

 

 

MARKETING[18]

 

 

 

 

 

 

LNG

Mboe

2,593

2,086

3,532

4,679

8,015

Liquids[19]

Mboe

37

571

260

608

260

Total

Mboe

2,630

2,657

3,792

5,287

8,275

 


 

 

 

 

 

Total Marketing

Mboe

2,630

2,657

3,792

5,287

8,275


 

 

 

 

 

 

Total sales

Mboe

48,025

45,900

48,384

93,925

98,769

Mboe/d

528

504

532

516

546

 

Revenue


Q2

2024

Q1

2024

Q2

2023

YTD

2024

YTD

2023

AUSTRALIA

 

 

 

 

 

   North West Shelf

524

592

667

1,116

1,937

   Pluto

891

745

724

1,636

1,855

   Wheatstone[20]

202

223

204

425

528

   Bass Strait

247

223

328

470

539

   Macedon

48

51

53

99

104

   Ngujima-Yin

91

92

-

183

100

   Okha

46

50

-

96

56

   Pyrenees

-

44

89

44

139

 






INTERNATIONAL






   Atlantis

168

196

203

364

402

   Mad Dog

249

204

116

453

184

   Shenzi

205

190

200

395

399

   Trinidad & Tobago[21]

38

61

112

99

248

   Sangomar

-

-

-

-

-

   Other[22]

5

5

4

10

9

 






Marketing revenue[23]

265

227

344

492

823

 






Total sales revenue[24]

2,979

2,903

3,044

5,882

7,323

 






Processing revenue

52

61

38

113

85

Shipping and other revenue

2

5

2

7

6







Total revenue

3,033

2,969

3,084

6,002

7,414

 

 

Realised prices

 

Units

Q2

2024

Q1

2024

Q2

2023

Units

Q2

2024

Q1

2024

Q2

2023

LNG produced[25]

$/MMBtu

9.6

10.4

10.9

$/boe

60

67

69

LNG traded[26]

$/MMBtu

9.1

9.1

11.0

$/boe

58

59

70

Pipeline gas





$/boe

38

34

37

Oil and condensate

$/bbl

83

79

75

$/boe

83

79

75

NGL

$/bbl

44

47

41

$/boe

44

47

41

Liquids traded26

$/bbl

79

60

70

$/boe

79

60

70









Average realised price for pipeline gas:









Western Australia





A$/GJ

6.5

6.4

6.1


East coast Australia





A$/GJ

14.3

13.7

12.6


International





$/Mcf

3.9

4.6

6.7

Average realised price





$/boe

62

63

63










Dated Brent





$/bbl

85

83

78

JCC (lagged three months)





$/bbl

84

92

87

WTI





$/bbl

81

77

74

JKM





$/MMBtu

9.6

11.9

12.6

TTF





$/MMBtu

9.2

9.8

12.6

 

Average realised price decreased 2% from the prior quarter reflecting lower JKM, TTF and JCC.

 

Capital expenditure (US$ million)


Q2

2024

Q1

2024

Q2

2023

YTD

2024

YTD

2023

Exploration and evaluation capitalised[27],[28]

38

38

92

76

129

Oil and gas properties

1,135

1,090

1,229

2,225

2,508

Other[29]

60

51

51

111

138

Total

1,233

1,179

1,372

2,412

2,775

 


Q2

2024

Q1

2024

Q2

2023

YTD

2024

YTD

2023

Sangomar

206

210

272

416

551

Scarborough

563

574

578

1,137

1,204

Trion

137

97

-

234

-

Other

327

298

522

625

1,020

Total

1,233

1,179

1,372

2,412

2,775

 



 Other expenditure (US$ million)

Q2

2024

Q1

2024

Q2

2023

YTD

2024

YTD

2023

Exploration and evaluation expensed[30]

46

54

81

100

133

Permit amortisation

3

3

2

6

4

Total

49

57

83

106

137

 

Trading costs

128

145

237

273

622

 

Exploration or appraisal wells drilled

Region

Permit Area

Well

Target

Interest (%)

Spud Date

Water       depth (m)

Planned well depth (m)[31]

Remarks

Congo

Marine XX

Niamou Marine 1

Oil

22.5%

Non-Operator

24 May 2024

2,094

7,015

Drilling

 

Permits and licences

Key changes to permit and licence holdings during the quarter ended 30 June 2024 are noted below.

 

Region

Permits or licence areas

Change in interest (%)

Current interest (%)

Remarks

Australia

WA-356-P

(65%)

0

License exit as part of portfolio optimisation

Gulf of Mexico

GC 738

(23.9%)

0

License expiry

Egypt - Herodotus Basin

North Sidi Barani Offshore (Block 2)

(27%)

0

License expiry

 

Production rates

 

Average daily production rates (100% project) for the quarter ended 30 June 2024:

 

Woodside
share
[32]

Production rate
(100% project, Mboe/d)

Remarks

 



June

2024

Mar

2024


AUSTRALIA


 

 


NWS Project





LNG

30.37%

256

293

Production was lower due to weather event impacts and planned offshore maintenance at Goodwyn Alpha.

Crude oil and condensate

30.21%

46

56

NGL

30.44%

10

10






Pluto LNG

 

 

 

 

LNG

90.00%

116

112

Production was higher primarily due to improved reliability.

Crude oil and condensate

90.00%

10

10






Pluto-KGP Interconnector





LNG

100.00%

24

29

LNG production lower due to increased domestic gas production.

Crude oil and condensate

100.00%

1

1

NGL

100.00%

1

1






Wheatstone[33]





LNG

10.18%

212

224

Production was lower due to two separate unplanned outages, impacting the Julimar subsea system and the Wheatstone facility respectively.

Crude oil and condensate

13.85%

30

31






Bass Strait





Pipeline gas

43.70%

86

61

Production was higher due to increased seasonal domestic gas demand.

Crude oil and condensate

46.17%

12

12

NGL

47.13%

23

19






Australia Oil





Ngujima-Yin

60.00%

18

13

Production at Ngujima-Yin and Okha was higher due to less weather downtime.

 

Production at Pyrenees was low due to a subsea produced-water leak and the planned turnaround.

Okha

50.00%

11

8

Pyrenees

62.90%

2

2






Other





Pipeline gas25F[34]


42

33

Production was higher due to increased pipeline gas deliveries from KGP, including from Pluto via the Pluto-KGP Interconnector.







 

 

Woodside
share
[35]

Production rate
(100% project, Mboe/d)

Remarks



June

2024

Mar

2024


INTERNATIONAL


 

 


Atlantis





Crude oil and condensate

38.50%

58

70

Production was lower due to the planned turnaround.

NGL

38.50%

4

4

Pipeline Gas

38.50%

5

6






Mad Dog





Crude oil and condensate

20.86%

155

146


NGL

20.86%

5

5

Pipeline Gas

20.86%

3

3






Shenzi





Crude oil and condensate

65.09%

39

41


NGL

65.20%

2

2

Pipeline Gas

65.19%

1

2





Trinidad & Tobago





Crude oil and condensate

58.75%[36]

2

2

Production was lower due to planned maintenance activities.

Pipeline gas

48.90%36

39

54






Sangomar

 

 

 

 

Crude Oil[37]

78.74%

8

-

Field achieved first oil in June.

 

 

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, statements regarding development, completion and execution of Woodside's projects, guidance with respect to production, expectations regarding future capital commitment, future cash flows, future results of projects, operating activities, new energy products, accounting decisions including impairments, commencement dates under supply arrangements, construction and delivery dates, expectations and plans for renewables production capacity and investments in, and development of, renewables projects. All statements, other than statements of historical or present facts, are forward-looking statements and generally may be identified by the use of forward-looking words such as 'guidance', 'foresee', 'likely', 'potential', 'anticipate', 'believe', 'aim', 'estimate', 'expect', 'intend', 'may', 'target', 'plan', 'strategy', 'forecast', 'outlook', 'project', 'schedule', 'will', 'should', 'seek' and other similar words or expressions. Similarly, statements that describe the objectives, plans, goals or expectations of Woodside are forward-looking statements.

Forward-looking statements in this report are not guidance, forecasts, guarantees or predictions of future events or performance, but are in the nature of future expectations that are based on management's current expectations and assumptions. Those statements and any assumptions on which they are based are only opinions and are subject to change without notice and are subject to inherent known and unknown risks, uncertainties, assumptions and other factors, many of which are beyond the control of Woodside, its related bodies corporate and their respective officers, directors, employees, advisers or representatives. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, fluctuations in commodity prices, actual demand, currency fluctuations, geotechnical factors, drilling and production results, gas commercialisation, development progress, operating results, engineering estimates, reserve and resource estimates, loss of market, industry competition, environmental risks, climate related risks, physical risks, legislative, fiscal and regulatory developments, changes in accounting standards, economic and financial markets conditions in various countries and regions, political risks, project delay or advancement, regulatory approvals, the impact of armed conflict and political instability (such as the ongoing conflicts in Ukraine and the Middle East) on economic activity and oil and gas supply and demand, cost estimates, the effect of future regulatory or legislative actions on Woodside or the industries in which it operates, including potential changes to tax laws, and the impact of general economic conditions, inflationary conditions, prevailing exchange rates and interest rates and conditions in financial markets.

A more detailed summary of the key risks relating to Woodside and its business can be found in the "Risk" section of Woodside's most recent Annual Report released to the Australian Securities Exchange and the London Stock Exchange and in Woodside's most recent Annual Report on Form 20-F filed with the United States Securities and Exchange Commission and available on the Woodside website at https://www.woodside.com/investors/reports-investor-briefings. You should review and have regard to these risks when considering the information contained in this report.

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

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 2024, 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). 

 

Units of measure and conversion factors

 

Product

Unit

Conversion factor

Natural gas

5,700 scf

1 boe

Condensate

1 bbl

1 boe

Oil

1 bbl

1 boe

Natural gas liquids

1 bbl

1 boe




Facility

Unit

LNG conversion factor

Karratha Gas Plant

1 tonne

8.08 boe

Pluto Gas Plant

1 tonne

8.34 boe

Wheatstone

1 tonne

8.27 boe

 

The LNG conversion factor from tonne to boe is specific to volumes produced at each facility and is based on gas composition which may change over time.

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

PJ

petajoules

scf

standard cubic feet of gas

TJ

terajoule

 



[1] 45% of produced LNG cargoes in the quarter were sold on prices linked to gas hub indices.

[2] The completion % excludes the Pluto Train 1 modifications project.

[3] The total project cost includes the cost for the Scarborough project, the Pluto Train 2 project and the Pluto Train 1 modifications project. Refer to page 3 for additional information.

[4] Q2 2024 includes 0.30 MMboe, Q1 2024 includes 0.29 MMboe and Q2 2023 includes 0.23 MMboe primarily from feed gas purchased from Pluto non-operating participants processed through the Pluto-KGP Interconnector.

[5] Includes capital additions on oil and gas properties, exploration and evaluation capitalised and other corporate spend.

[6] 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 product.

[7] The total project cost includes the cost for the Scarborough project, the Pluto Train 2 project and the Pluto Train 1 modifications project. Woodside share is based on a participating interest in the Scarborough Joint Venture (SJV) of 74.9% (compared to 73.5% at FID) and assumes completion of the sell-down of a 15.1% participating interest in the SJV to JERA. Woodside share excludes the impact of GIP's additional contribution to Pluto Train 2 ($0.8 billion).

[8] Capital expenditure includes the following participating interests; Sangomar (82%); Scarborough (90% following completion of the transaction with LNG Japan in March 2024 and 74.9% following completion of the transaction with JERA, expected in the second half of 2024), Pluto Train 2 (51%) and Trion (60%). Trion capital expenditure includes Pemex carry. This guidance assumes no change to these participating interests in 2024. This excludes the impact of any future asset sell-downs, acquisitions or other changes in equity.

[9] Gas hub indices include Japan Korea Marker (JKM), TTF and National Balancing Point (NBP). It excludes HH.

[10] Q2 2024 includes 2.18 MMboe of LNG, 0.10 MMboe of condensate and 0.06 MMboe of NGL, Q1 2024 includes 2.60 MMboe of LNG, 0.10 MMboe of condensate and 0.05 MMboe of NGL and Q2 2023 includes 1.96 MMboe of LNG and 0.08 MMboe of condensate and 0.04 MMboe of NGL processed at the Karratha Gas Plant (KGP) through the Pluto-KGP Interconnector.

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

[12] Q2 2024 includes 0.30 MMboe, Q1 2024 includes 0.29 MMboe and Q2 2023 includes 0.23 MMboe primarily from feed gas purchased from Pluto non-operating participants processed through the Pluto-KGP Interconnector.

[13] Overriding royalty interests held in the GoM for several producing wells.

[14] Includes periodic adjustments reflecting the arrangements governing Wheatstone LNG sales of 0.19 MMboe in Q2 2024, 0.28 MMboe in Q1 2024 and 0.15 MMboe in Q2 2023.

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

[16] Includes reclassification of purchased condensate volumes from NWS JV Participants to Marketing liquids of 0.26 MMboe in Q2 2023.

[17] Overriding royalty interests held in the GoM for several producing wells.

[18] Purchased volumes sourced from third parties.

[19] Includes reclassification of purchased condensate volumes from NWS JV Participants of 0.26 MMboe in Q2 2023.

[20] Q2 2024 includes -$10 million, Q1 2024 includes $24 million and Q2 2023 includes $11 million recognised in relation to periodic adjustments reflecting the arrangements governing Wheatstone LNG sales. These amounts will be included within other income/(expenses) in the financial statements rather than operating revenue.

[21] Includes the impact of periodic adjustments related to the production sharing contract (PSC).

[22] Overriding royalty interests held in the GoM for several producing wells.

[23] 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.

[24] Total sales revenue excludes all hedging impacts.

[25] Realised prices include the impact of periodic adjustments reflecting the arrangements governing Wheatstone LNG sales.

[26] Excludes any additional benefit attributed to produced volumes through third-party trading activities.

[27] 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.

[28] Project final investment decisions result in amounts of previously capitalised exploration and evaluation expense (from current and prior years) being transferred to oil and gas properties. This table does not reflect the impact of such transfers.

[29] Other primarily incorporates corporate spend including SAP build costs, carbon costs and other investments.

[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 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, Woodside share changes monthly.

[37] Sangomar production rate per day reflects total production in Q2 2024 divided by total number of days in the quarter.

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